September 13, Dr. Harry Swain Joint Review Panel Chair. Mr. James S. Mattison Joint Review Panel Member

Transcription

1 September 13, 2013 Dr. Harry Swain Joint Review Panel Chair Mr. James S. Mattison Joint Review Panel Member Ms. Jocelyne Beaudet Joint Review Panel Member In c/o Ms. Courtney Trevis Panel Co-Manager Canadian Environmental Assessment Agency 22 nd Floor, 160 Elgin Street Ottawa, ON K1A 0H3 Mr. Brian Murphy Panel Co-Manager British Columbia Environmental Assessment Office 4 th Floor, 836 Yates Street Victoria, BC V8W 9V1 By Dear Joint Review Panel Members: RE: BC Hydro Site C Clean Energy Project Evidentiary Update I am pleased to provide an Evidentiary Update to the EIS as amended which reflects information contained in BC Hydro s recently filed Integrated Resource Plan (IRP). The purpose of this Evidentiary Update is to provide an update to the EIS as amended and to address additional comments made by the public and Aboriginal groups. The changes update Section 5 of the EIS as amended, with 2 associated updates to Sections and The changes are black-lined and attached for your convenience. The information provided in this update does not change any of the conclusions of the EIS as amended. The IRP and this evidentiary update confirm that BC Hydro requires the energy and capacity resources provided by the Project to meet future customer demand, and that the Project remains the preferred option to meet this need. For ease of reference, please find enclosed the following reference documents that may be helpful in conducting your review of the Evidentiary Update that have been filed previously with the Panel: PO Box Vancouver BC V7X 1V5 Toll-free: Community Consultation Office th Avenue Fort St. John BC V1J 1Y5 Tel: sitec@bchydro.com bchydro.com/sitec

2 -2-1. Section 5 Need for, Purpose of, and Alternatives to the Project as Amended. 2. Technical Memos Integrating documents Section 5 Need for, Purpose of, and Alternatives to the Project Amendments (CEA Agency Registry #1519) and Section 5 Need for, Purpose of, and Alternatives to the Project Original Submission (CEA Agency Registry # 421) - Alternatives to the Project (CEA Agency Registry #1458) - Project Need (CEA Agency Registry # 1460) - Demand Side Management (CEA Agency Registry #1446) 3. Volume 1 Appendix D Need for and Alternatives to the Project Supporting Documentation Part 3: British Columbia Utilities Commission Resource Planning Guidelines (CEA Agency Registry # 421) 4. Volume 1 Appendix D Need for and Alternatives to the Project Supporting Documentation: Part 4 - Portfolio Attributes (CEA Agency Registry #1519) 5. Volume 2 Appendix T Technical Data Report: Climate Change Summary Report - Executive Summary (CEA Agency Registry #421) If you have any questions, or require further information, please contact me directly at Sincerely, Danielle Melchior Director, Environmental Assessment and Regulatory Site C Clean Energy Project Encl. 1. Evidentiary Update 2. Previously Filed Information

3 Site C Clean Energy Project Evidentiary Update September 13, 2013

4 Evidentiary Update September 13, Part 1 - INTRODUCTION 1.1 Background On January 26, 2013, BC Hydro filed its Environmental Impact Statement (EIS) for the Site C Clean Energy Project (the Project) with the Canadian Environmental Assessment Agency (CEA Agency) and the British Columbia Environmental Assessment Office (BCEAO). The EIS was subject to a review by a government-appointed Working Group which included Aboriginal groups and local governments and a 60-day public comment period, including open houses. BC Hydro responded to information requests that followed these public comment periods as well as additional comments provided on BC Hydro responses. The CEA Agency and BCEAO adjudicated comments and responses on the EIS and directed BC Hydro to amend the EIS. On August 1, 2013, BC Hydro submitted an amended EIS to the CEA Agency and BCEAO, which the agencies determined to be satisfactory and directed BC Hydro to submit the amended EIS to the Joint Review Panel (Panel), as required by Section 3.14 of the BC/Canada Agreement. In compliance with that direction, the Panel has been provided with the EIS dated January 26, 2013, and a set of amendments to the EIS dated July 19, 2013, which includes a set of Technical Memos. The references to the EIS as amended in this Evidentiary Update refer to all materials provided to the Panel in accordance with the agencies direction of August 1, On August 8, 2013, BC Hydro informed the Panel that BC Hydro would provide an Evidentiary Update to the EIS as amended by September 13, 2013, to reflect information contained in BC Hydro s Integrated Resource Plan (IRP) that was submitted to B.C. s Minister of Energy and Mines on August 2, 2013, in accordance with British Columbia s Clean Energy Act. In keeping with good utility practice, BC Hydro undertakes detailed long-term planning every two to three years to ensure it can reliably and cost effectively meet its customers future electricity needs. BC Hydro s IRP is a long-term resource plan to meet B.C. s growth in electricity demand and includes BC Hydro s recommended actions to meet the province s Page 1

5 Evidentiary Update September 13, 2013 electricity requirements over the next 20 years. In developing the IRP, BC Hydro consulted with the public, stakeholders and First Nations in both 2011 and Purpose and Structure of Evidentiary Update The purpose of this Evidentiary Update is to provide an update to the EIS as amended and to address additional comments made by the public and Aboriginal groups. The changes update Section 5 of the EIS as amended, with two associated updates to Section and It is important to note that the updated information included in the IRP and this Evidentiary Update does not change the conclusions of the EIS as amended. The IRP confirms that BC Hydro requires the energy and capacity resources provided by the Project to meet future customer demand, and the Project remains the preferred option to meet this need. This Evidentiary Update is organized as follows: Part 1: Introduction Part 2: Analysis for the Project Need Part 3: Analysis for the Alternatives to the Project Part 4: Sensitivity analysis Appendix A: Consideration of comments to EIS Section 5 Appendix B: Associated updates to Sections and of the EIS as amended These are summarized in the following sections of this introduction. 1.3 Project Need Part 2 provides an update to the analysis of Project need (Section 5.2 of the EIS) to reflect information from the IRP. BC Hydro s December 2012 Load Forecast as presented in the EIS as amended has not changed and remains the most recent BC Hydro load forecast 1. The Demand Side Management (DSM) target of 7,800 gigawatt hours per year (GWh/year) 1 The load forecast is discussed in Section of the EIS as amended Page 2

6 Evidentiary Update September 13, 2013 of energy savings with 1,400 megawatts (MW) of associated capacity savings by F remains BC Hydro s DSM target 3. Updates provided in the IRP compared to the EIS as amended include: An increase in committed independent power producer (IPP) energy supply of approximately 800 GWh/year in F2022, largely due to an increased probability of delivery 4 Designation of the Revelstoke Unit 6 project as a contingency resource to be reviewed in the analysis of alternatives to the Project (previously included in the base loadresource balance). Revelstoke Unit 6 becomes a potential alternative to the Project when combined with other available resources. Updated in-service date for the Project (all six generating units in service by F2024 rather than F2023). Information regarding the potential for climate change to affect BC Hydro s hydro-electric facilities 5 The conclusion of the analysis of Project need remains unchanged compared to the EIS as amended. There is a need for the Project based on the updated load-resource balance (LRB) analysis, even after taking into account the DSM target and without taking into account the potential demand from LNG. With the implementation of the DSM target and IPP contract renewals (referred to as electricity purchase agreements or EPAs), new resources are required to meet the energy and capacity needs of BC Hydro s customers. There is an energy gap beginning in F2027 and a capacity gap beginning in F2021. Both the energy and capacity gaps as described exclude any potential load from LNG. 2 All years in this Evidentiary Update are stated in fiscal years (F20xx) ending 31 March, except where otherwise noted. 3 The DSM target is discussed in Section of the EIS as amended. 4 IPP energy capability is described in section of the EIS as amended 5 Note: The EIS as amended includes analysis of Climate Change and is included in Volume 2, AppendixT Page 3

7 Evidentiary Update September 13, Analysis of Alternatives to the Project Part 3 provides an update to the analysis of alternatives to the Project, reflecting information in the IRP. Further changes compared to the analysis provided in the EIS as amended are as follows: Amendment of the candidate portfolios to include three additional potential alternative resources, specifically: o DSM Option 3 o Revelstoke Unit 6 o G.M. Shrum (GMS) Units 1-5 Capacity Increase Change to BC Hydro s Weighted Average Cost of Capital (WACC) from 6 per cent real to 5 per cent real and a commensurate reduction in the IPP cost of capital from 8 per cent to 7 per cent The updated portfolio analysis presented in this chapter utilizes the same portfolio analysis methodology described in the EIS as amended 6. The conclusion of this portfolio analysis is unchanged. The Project continues to provide the best combination of financial, technical, environmental and economic development attributes, and remains the preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. 1.5 Sensitivity Analysis Part 4 provides sensitivity analysis conducted as part of the IRP. Part 4 reviews the analysis of the alternatives to the Project with respect to variability in the following five factors: Variability from the mid-load forecast to large gap (i.e., high load growth with low DSM savings level) and small gap (low load growth with low DSM savings level) scenarios Variability from mid-market prices to high and low market price scenarios A reduced cost of capital for IPP projects from 7 per cent real to 6 per cent real 6 As described in Section of the EIS as amended, and the Technical Memo on Alternatives to the Project Page 4

8 Evidentiary Update September 13, 2013 Sensitivity in Project capital costs Variability from a $10/MWh wind integration cost to wind integration costs of $5/MWh and $15/MWh. In the majority of the sensitivity analysis scenarios, the Project continues to provide financial benefits compared to the portfolios of alternative resource options. The scenarios in which alternative portfolios provide benefits compared to the Project are generally lower probability, and are associated with long-term low load growth or market prices. Given the wide range of potential scenarios in which the Project provides benefits compared to alternatives, and given the low likelihood of the scenarios in which it does not, BC Hydro maintains that the Project is the preferred resource option to meet BC Hydro s forecast customer demand. 1.6 Summary and Conclusion This Evidentiary Update provides updated analysis to reflect the most current information available on the Need for and Alternatives to the Project, and provides sensitivity analysis undertaken as part of BC Hydro s IRP. The conclusion on Project need and alternatives reached in the EIS as amended has not changed. The IRP and Evidentiary Update confirm that there is a need for new sources of energy and capacity within BC Hydro s planning horizon, and that the Project offers the best combination of financial, technical, environmental and economic development attributes to meet this need. Page 5

9 Evidentiary Update September 13, PART 2 PROJECT NEED This part updates the analysis of the need for the Project (as described in section 5.2 of the EIS as amended) based on updated information from the IRP. Supplemental information related to the potential impacts of climate change on the capability of BC Hydro s hydroelectric facilities is also provided at the end of this part of the Evidentiary Update. 2.1 Updates to Load-Resource Balance Gap The need for the Project is based on BC Hydro s LRB, which is the difference between BC Hydro s customer demand (load) and the supply from existing and committed resources 7. There is a gap (i.e., shortfall) if forecasted customer demand exceeds the existing and committed resources available to serve such load. Consistent with the B.C. Utility Commission s (BCUC) Resource Planning Guidelines (found at Appendix D of the EIS as amended and provided as an attachment to this Evidentiary Update), and as described in the Technical Memo on Project Need (a copy of which is attached to this Evidentiary Update), there are three main steps to the determination of need: Step 1: Forecasting load, in this case the 2012 Load Forecast dated December 2012, the most recent BC Hydro load forecast (see Section of the EIS as amended) Step 2: Estimating the energy and capacity available from existing and committed supply side resources (see Section of the EIS as amended) Step 3: Determining the level of future DSM savings that are achievable and costeffective (see Section of the EIS as amended) BC Hydro s 20-year planning period for the determination of need has been updated in the IRP to F2014 F2033 from F2012 F2031. There have also been two updates to the information used in estimating the energy and capacity available from existing and committed supply side resources as described in Part and of this Evidentiary Update. 7 Committed supply-side resources are resources for which material regulatory and BC Hydro executive approvals have been secured. Page 6

10 Evidentiary Update September 13, 2013 The information used in Steps 1 and 3, specifically the December 2012 Load Forecast and the DSM target, remains unchanged 8. Updated LRB tables based on these changes are provided in Part Increase in the forecast independent power producer (IPP) energy supply A component of the evaluation of project need is the estimate of how much energy will be available to BC Hydro from IPPs. This includes both operating IPPs as well as IPP projects that are expected to enter operations in the future. BC Hydro has updated the assessment of the likelihood of completion of pre-commercial operation IPP projects as some of these projects have reached or are nearing completion. BC Hydro has reduced the forecast attrition rate associated with these future projects, which has resulted in approximately 800 GWh of additional energy being available to BC Hydro in the planning horizon. While energy from future IPP renewed EPAs is included in the analysis of Project need, IPP projects will be individually assessed as EPAs come up for renewal, and are not yet truly committed resources. Consistent with the EIS as amended, for planning purposes, BC Hydro assumes that approximately 50 per cent of the bioenergy EPAs will be renewed, about 75 per cent of the run-of-river hydroelectric EPAs that are up for the renewal in the next five years will be renewed, and the renewal of all other EPAs. These EPA renewal planning assumptions result in about 4,700 GWh/year of firm energy in F2024 and about 6,400 GWh/year of firm energy in F2033 at the end of the planning horizon Designation of the Revelstoke 6 project as a contingency resource to be reviewed in the analysis of alternatives to the Project Revelstoke Unit 6 is a potential future BC Hydro project that could add about 500 MW of long-term (50+ years) dependable capacity to the BC Hydro system. Revelstoke Unit 6 would provide very little energy (about 26 GWh/year). For purposes of the EIS as amended, BC Hydro included Revelstoke Unit 6 in F2019 in its LRBs even though it is not a committed 8 BC Hydro has updated the annual DSM savings in the years prior to F2021; however, the DSM target itself remains unchanged and as a result these changes do not impact the need for the Project. Page 7

11 Evidentiary Update September 13, 2013 resource. Revelstoke Unit 6 is a potential future resource requiring BC Hydro Board of Directors approval, review under the B.C. Environmental Assessment Act 9 (BCEAA) and First Nation consultation. BC Hydro s recommendation for Revelstoke Unit 6 in the LRB has changed. The IRP now recommends pursuing Revelstoke Unit 6 as a contingency resource that would only be advanced to implementation if customer demand significantly exceeds expected customer demand for a sustained period. BC Hydro believes that the unique requirements of potential LNG customers may be better served by north coast supply. BC Hydro is also planning to rely on the market, backed up by the Canadian Entitlement for a specified period of time and up to a certain amount as a cost-effective alternative to Revelstoke Unit 6 as described below (Please see the supplemental information at the end of this Part for a description of the Canadian Entitlement). As discussed in part 2.2 below, the Project s earliest ISD is F2024. If the Project is built, there would be a five-year capacity gap, without taking into account potential LNG load from F2019 to F2023 (refer to Table 10 in Part 2.4 below). Rather than advancing Revelstoke Unit 6 solely to meet a five year gap in capacity, at a capital cost in excess of $400 million (loaded dollars) 10, BC Hydro proposes in the IRP to rely on the market backed up by the Canadian Entitlement provided under the Columbia River Treaty to meet any system capacity shortages during a period of shortfall. This reliance for approximately 300 MW until the Project comes into service is a cost effective strategy to meet this short term system capacity gap. However, there is uncertainty with respect to the Canadian Entitlement. While the Columbia River Treaty has no termination date, either Canada or the U.S. can unilaterally terminate most of the provisions of the Columbia River Treaty any time after 16 September 2024, providing at least 10 years notice is given. In addition, planning to rely on the market for the five-year F2019 to F2023 period does not meet the self-sufficiency requirement set out in subsection 6(2) of the Clean Energy Act. Lieutenant Governor-in-Council authorization is required. For these reasons, market and Canadian Entitlement cannot be relied upon to meet long term energy and capacity needs. 9 S.B.C. 2002, c The project is at an early phase of definition, and as a result this cost estimate may change. Page 8

12 Evidentiary Update September 13, 2013 As described in part 3 of this Evidentiary Update, Revelstoke Unit 6 is an available alternative to the Project in combination with other resources. 2.2 Update to Project In-service Date BC Hydro has conducted a review of the Project construction schedule and has revisited the Project s earliest ISD of F2023 (for all six generating units; the first generating unit was expected to be in service by F2022). Based on this review, BC Hydro revised the expected earliest ISD to F2024 for all six generating units. BC Hydro has also included analysis using a F2026 ISD to provide a basis for evaluating alternatives. 2.3 Conclusion Updated LRB tables reflecting the changes discussed above are provided in Part 0 of this Evidentiary Update. Based on these updated tables, the conclusion of the analysis of Project need has not changed compared to the EIS as amended. There is a need for the Project based on the updated LRB analysis, even after taking into account the pursuit of the DSM target. With the implementation of the DSM target and EPA renewal and other expectations, new resources are required to meet the energy and capacity needs of BC Hydro s customers. There is an energy gap beginning in F2027 and a capacity gap beginning in F2019 without LNG load. It is difficult to precisely time the addition of any new electricity resource with the exact year of forecasted energy or capacity gaps, particularly large hydroelectric facilities such as the Project. There are a number of uncertainties that could result in higher or lower customer demand, and lower or higher resource delivery 11. These uncertainties underscore the need to review a range of future resource requirements, rather than solely single point estimates for LRB energy and capacity gaps. In Part 4 below BC Hydro examines a number of sensitivity cases to further test the need for the Project. 11 Refer to Section of the EIS as amended for further discussion. Page 9

13 Evidentiary Update September 13, Updated LRB Tables The following supporting evidence and information is related to the IRP s updates to the LRBs. The LRB tables are presented for the period of F2017 to F2033. Years F2014-F2016 are part of BC Hydro s current operational horizon and are not part of the long-term planning period. LRB gaps during the operational horizon are managed through reliance on existing resources given near-term market conditions, system constraints, planned outages and inflows. Energy and Capacity Capability for Existing and Committed Supply Table 1 and Table 2 update the F2022 information provided in Table 5.4 and Table 5.5 of the EIS as amended based on the change in the IPP attrition. Table 1 Energy Capability for Existing and Committed Supply Gigawatt Hours (GWh) EIS Table 5.4 F2022 Evidentiary Update F2022 Heritage hydroelectric (a) 48,500 48,500 Heritage thermal (Prince Rupert) (b) Existing and committed IPP supply (c) 14,200 15,000 Total supply (d) = a + b + c 62,900 63,700 Table 2 Dependable Capacity for Existing and Committed Supply Megawatts (MW) EIS Table 5.5 F2022 Evidentiary Update F2022 Heritage hydroelectric (a) 11,400 11,400 a Heritage thermal (Prince Rupert) (b) Existing and committed IPP supply (c) 1,200 1,200 Reserves b Supply requiring reserves (d) = a + b + c 12,700 12,700 14% of supply requiring reserves (e) = d * ,800 1,800 Supply not requiring reserves Alcan 2007 EPA (f) Page 10

14 Evidentiary Update September 13, 2013 Megawatts (MW) EIS Table 5.5 F2022 Evidentiary Update F2022 Total supply (g) = d e + f 11,050 c 11,050 NOTE: a b c The Heritage hydroelectric value has been updated from the IRP to reflect minor errata correcting an approximately 100 MW overstatement. System generating capacity beyond that required to meet peak demand, ensuring sufficient generation is available if some generating units are not available; necessary to meet reliability criteria for planning and operation. Errata. Energy and Capacity LRBs before DSM Target Table 3 and Table 4 demonstrate the resulting changes to the LRBs provided in Table 5.6 and Table 5.7 of the EIS as amended. Tables 3 and 4 start with the first year of the planning period, which is F2017. Bracketed numbers indicate a surplus, while un-bracketed numbers indicate a gap. Table 3 shows a need for energy in F2018 and Table 4 shows a need for capacity in F2017. Table 3 Energy Deficit/Surplus without DSM (GWh) (No LNG) Year EIS Table 5.6 LRB without DSM Evidentiary Update LRB without DSM F (700) F2018 2,300 1,200 F2019 4,300 3,100 F2020 5,400 4,500 F2021 6,400 5,600 F2022 7,200 6,400 F2023 8,200 7,300 F2024 9,100 8,300 F2025 9,900 8,900 F ,400 9,300 F ,000 10,000 F ,100 11,100 F ,000 12,000 F ,000 13,100 F ,000 14,100 F2032 n/a 15,100 F2033 n/a 15,900 Page 11

15 Evidentiary Update September 13, 2013 Table 4 Capacity Deficit/Surplus without DSM (MW) (No LNG) Year EIS Table 5.7 LRB without DSM Evidentiary Update LRB without DSM F F F2019 1,150 1,100 F2020 1,300 1,300 F2021 1,500 1,450 F2022 1,650 1,650 F2023 1,850 1,850 F2024 2,000 2,000 F2025 2,200 2,150 F2026 2,350 2,300 F2027 2,500 2,500 F2028 2,700 2,700 F2029 2,950 2,950 F2030 3,200 3,150 F2031 3,400 3,400 F2032 n/a 3,600 F2033 n/a 3,800 Energy and Capacity LRBs with DSM Target Table 5 and Table 6 demonstrate the effects of adding DSM to the energy and capacity LRB values presented in Table 3 and Table 4 and provide a comparison to Table 5.8 and Table 5.9 of the EIS as amended. These tables also reflect the change associated with the treatment of Revelstoke Unit 6 as an available alternative to the Project. Without future additional resources there is a need for new energy in F2027 and a need for new capacity in F2019. Table 5 Energy Deficit/Surplus with DSM (GWh) (No LNG) Year EIS Table 5.8 LRB with DSM and Rev 6 Evidentiary Update LRB with DSM F2017 (4,700) (5,000) F2018 (3,400) (3,700) F2019 (2,200) (2,800) F2020 (1,900) (2,400) F2021 (1,400) (2,200) F2022 (1,000) (1,800) F2023 (200) (1,100) F (700) Page 12

16 Evidentiary Update September 13, 2013 Year EIS Table 5.8 LRB with DSM and Rev 6 Evidentiary Update LRB with DSM F (300) F (300) F2027 1, F2028 1, F2029 2,400 1,800 F2030 3,100 2,600 F2031 3,800 3,300 F2032 n/a 4,200 F2033 n/a 4,900 Table 6 Capacity Deficit/Surplus with DSM (MW) (No LNG) Year EIS Table 5.9 LRB with DSM and Rev 6 Evidentiary Update LRB with DSM F2017 (200) (250) F2018 (100) (100) F2019 (400) - F2020 (350) 100 F2021 (250) 100 F2022 (250) 150 F2023 (100) 300 F F F F F F ,000 F ,150 F ,350 F2032 n/a 1,550 F2033 n/a 1,750 Energy and Capacity LRBs reflecting potential LNG load Section of the EIS as amended discusses a number of uncertainties that result in risks that could have significant consequences in terms of BC Hydro being able to reliably meet customer demand. One of these uncertainties is potential LNG load. Page 13

17 Evidentiary Update September 13, 2013 As stated in the IRP, currently there are 12 publicly-announced LNG projects for Kitimat, Prince Rupert and other areas of the B.C. North Coast, Howe Sound in the Lower Mainland and Campbell River on Vancouver Island. Potential LNG load consists of: (1) compression load, which is the energy required by the main liquefaction compressors that cool natural gas into liquid form and represents the majority of LNG facility requirements; and (2) non-compression load, which refers to the rest of LNG facility power demand including other compressors, pumps, control systems, loading terminal equipment, lighting and office requirements. Non-compression load typically accounts for about 15 per cent of overall LNG facility energy requirements. LNG projects typically require export licences from the National Energy Board and environmental assessment-related authorization through BCEAA and/or Canadian Environmental Assessment Act. 12 In addition to the status of regulatory approvals, important LNG project decision-making steps that will inform BC Hydro's plans are the status of front-end engineering design and feasibility studies and final investment decisions. To date, no LNG project proponent in B.C. has made a final investment decision. After discussions with LNG proponents and review of LNG project descriptions submitted to the B.C. and Canadian environment assessment agencies, BC Hydro understands that proponents of the larger LNG projects generally will not be requesting electricity service for compression loads. Larger scale LNG proponents may request service from BC Hydro for non-compression load, 13 while smaller scale LNG projects such as the Woodfibre LNG project proposed for an industrial site near Squamish, B.C. may take service for both compression and non-compression load. For purposes of the EIS as amended, BC Hydro set out a range of potential non-compression load of about 800 GWh/year to 6,600 GWh/year of additional energy demand, corresponding to about 100 MW to 800 MW of additional peak demand. The timing assumed for these LNG loads has been delayed one year from F2019 in the EIS as amended to F2020 in both the IRP and the Evidentiary Update S.C. 2012, c.19, section 52. See, for example, Project Description (section 5.9) for LNG Canada dated March 21, 2013: Each LNG liquefaction train will utilize natural gas-fired direct drive for the main refrigeration compressors to produce LNG. The LNG facility and marine terminal will require electrical power to operate all other supporting facilities and infrastructure. Approximately 90 MW of electrical power will be required for Phase 1 and approximately 150 MW will be required at full build-out. There are currently two options being considered for the electrical power requirements including: power supply option 1 electrical power sourced from the BC Hydro electrical grid; and power supply option 2 new electrical generation installed at the LNG facility site. Page 14

18 Evidentiary Update September 13, 2013 For purposes of completeness BC Hydro updates EIS as amended Tables 5.10 and 5.11 in Table 7 and Table 8 below. Table 7 indicates a need for new energy resources in F2024 with low LNG demand and in F2021 with high LNG demand. Table 8 indicates a need for new dependable capacity resources in F2019 with Low and High LNG demand. Table 7 Energy Deficit/Surplus with DSM and LNG (GWh) Year EIS Table 5.10 LRB with DSM and Rev 6 and Low LNG EIS Table 5.10 LRB with DSM and Rev 6 and High LNG Evidentiary Update LRB with DSM and Low LNG F2017 (4,700) (4,700) (5,000) (5,000) F2018 (3,400) (3,400) (3,700) (3,700) F2019 (1,400) 300 (2,800) (2,800) F2020 (1,000) 4,700 (1,500) (400) F2021 (600) 5,200 (1,400) 1,800 F2022 (100) 5,600 (1,000) 4,800 F ,400 (300) 5,500 F2024 1,000 6, ,900 F2025 1,600 7, ,300 F2026 1,600 7, ,300 F2027 2,000 7,700 1,000 6,700 F2028 2,700 8,400 1,700 7,500 F2029 3,300 9,000 2,600 8,400 F2030 4,000 9,700 3,400 9,200 F2031 4,600 10,400 4,100 9,900 F2032 n/a n/a 5,000 10,800 F2033 n/a n/a 5,700 11,500 Evidentiary Update LRB with DSM and High LNG Table 8 Capacity Deficit/Surplus with DSM and LNG (MW) Year EIS Table 5.11 LRB with DSM and Rev 6 and Low LNG EIS Table 5.11 LRB with DSM and Rev 6 and High LNG Evidentiary Update LRB with DSM and Low LNG F2017 (200) (200) (250) (250) F2018 (100) (100) (100) (100) F2019 (300) (100) - - F2020 (200) F2021 (200) F2022 (200) F ,100 F ,200 Evidentiary Update LRB with DSM and High LNG Page 15

19 Evidentiary Update September 13, 2013 Year EIS Table 5.11 LRB with DSM and Rev 6 and Low LNG EIS Table 5.11 LRB with DSM and Rev 6 and High LNG Evidentiary Update LRB with DSM and Low LNG F ,300 F , ,350 F , ,500 F , ,650 F ,400 1,100 1,800 F ,600 1,250 1,950 F2031 1,000 1,700 1,450 2,150 F2032 n/a n/a 1,650 2,350 F2033 n/a n/a 1,850 2,550 Evidentiary Update LRB with DSM and High LNG Energy and Capacity LRBs including the Project Table 9 and Table 10 compare the energy and capacity LRBs presented in Table 5.13 and Table 5.14 of the EIS as amended to update LRBs including DSM and the Project. Table 9 shows that the Project is expected to meet the updated energy requirements shown in Table 5 for the duration of the planning horizon. Table 10 shows that the Project is expected to meet the updated capacity requirements shown in Table 6 until F2029. Table 9 Energy Deficit/Surplus with DSM and the Project (GWh) (No LNG) Year EIS Table 5.13 LRB with DSM, Rev 6 & Site C Evidentiary Update LRB with DSM & Site C F2017 (4,700) (5,000) F2018 (3,400) (3,700) F2019 (2,200) (2,800) F2020 (1,900) (2,400) F2021 (1,400) (2,200) F2022 (1,400) (1,800) F2023 (4,600) (1,500) F2024 (4,900) (5,100) F2025 (4,400) (5,400) F2026 (4,300) (5,400) F2027 (3,900) (4,900) F2028 (3,300) (4,200) F2029 (2,700) (3,300) F2030 (2,000) (2,500) F2031 (1,300) (1,800) F2032 n/a (900) F2033 n/a (200) Page 16

20 Evidentiary Update September 13, 2013 Table 10 Capacity Deficit/Surplus with DSM and the Project (MW) (No LNG) Year EIS Table 5.14 LRB with DSM, Rev 6 & Site C Evidentiary Update LRB with DSM & Site C F2017 (200) (250) F2018 (100) (100) F2019 (400) - F2020 (350) 100 F2021 (250) 100 F2022 (250) 150 F2023 (1,050) 300 F2024 (950) (550) F2025 (850) (450) F2026 (750) (350) F2027 (650) (250) F2028 (500) (100) F2029 (300) 50 F2030 (150) 250 F F2032 n/a 600 F2033 n/a 800 Page 17

21 Evidentiary Update September 13, 2013 SUPPLEMENTAL INFORMATION TO PART 2 Heritage Hydro Output and Climate Change Both the IRP and the EIS as amended provide that the annual average water capability of BC Hydro s Heritage hydroelectric resources is 48,500 GWh/year (in F2022). Although BC Hydro is planning to meet load under average Heritage hydro water conditions, the amount of energy in a given year is dependent on weather conditions, including the inflows into the Heritage and non-heritage hydroelectric system; and on the dispatch of both Heritage and dispatchable non-heritage resources to meet load given market prices and system conditions and constraints. Figure 1 shows the frequency distribution of the Heritage hydro generation for the 60-year inflow record using the current resource mix. The existing Heritage hydroelectric system is capable of providing between 43,000 and 56,000 GWh/year of energy. Figure 1 Frequency Distribution of Heritage Hydro Generation 4,100 GWh/year Page 18

22 Evidentiary Update September 13, 2013 BC Hydro notes that Special Direction No to BCUC provides in subsection 2(2) that for purposes of adjudicating BC Hydro s applications to the BCUC, the BCUC must use 48,200 GWh/year as the maximum amount of annual energy that the [BC Hydro] hydroelectric system can produce under average water conditions. Hydroelectric power generation depends on stream flow as a power source, and hence has the potential to be affected by changes in the hydrological cycle as a result of climate variation. BC Hydro developed a climate change adaptation strategy framework to understand and address the potential impacts of climate change on BC Hydro s operations and long-term planning. As part of the first step of BC Hydro s climate change adaptation strategy, BC Hydro has been involved in a number of studies identifying both historical and future impacts of climate change on the water cycle and water availability in watersheds managed by BC Hydro. As concluded in section of the IRP, [n]one of the studies thus far have identified a need to change the way Heritage hydroelectric facilities are planned or relied upon. The IRP includes in Appendix 2C a paper written by BC Hydro titled Hydrologic Impacts of Climate Change that summarizes the work done to date on assessing climate change. 15 The paper reviews climate changes for several BC Hydro watersheds, including the Williston basin (with the others being Upper Columbia, Kootenay River and Coastal regions). As stated in the Executive Summary of the paper, page 2 of 58, When working with climate change scenarios, it is important to realize that the goal of working with the scenarios is not to predict the future, but to better understand uncertainties in order to reach decisions that are robust under a wide range of future scenarios. Hence, while the paper concludes at page 3 of 58 that A modest increase in water availability is likely for BC Hydro s hydroelectric system [emphasis added], it does not mean that BC Hydro should plan on increases to the expected output from its system: There appears to be little change to historical inflows. The paper concludes that historical trends in annual reservoir inflows are small and not significant (paper, page 50 of 58). The paper at page 33 of 58 observes that [T]he short records length 14 B.C. Reg , amending B.C. Reg. 245/ Note that Volume 2 Appendix T of the EIS as amended (Climate Change Summary Report) is based on the same climate and hydrological modeling but it relates specifically to the Peace River. Page 19

23 Evidentiary Update September 13, 2013 and data quality issues combined with possibly a low-amplitude climate change signal that is superimposed on comparatively high-amplitude year-to-year fluctuations, create challenges in providing an adequate[ly] picture of long-term trends ; The general circulation model (GCM) predicts stream flows in the mid-2050s ( ) versus the baseline period. The GCM predicts that a modest increase in annual water availability over an 80 year span is likely for BC Hydro s hydroelectric system. The predictions do not say that this likely modest increase will be there in the next 10 years. There is also a range of GCMs some suggest than annual water availability will remain unchanged while other GCMs project that water supply will increase by 15 per cent by the 2050s (paper, page 50 of 58); From a resource planning perspective, resource reliance is based upon observable inflow data and not what may happen in the future between 2041 and Page 20

24 Evidentiary Update September 13, 2013 Columbia River Treaty The Columbia River Treaty between Canada and the United States was signed in 1961 and ratified in The Treaty required that three dams Duncan, Keenleyside (Arrow) and Mica (Kinbasket) be built in British Columbia for flood control and to increase hydroelectric power generating potential in both countries. The Treaty also gave the U.S. the right to build Libby Dam on the Kootenai River, forming Koocanusa Reservoir. All four of these dams were completed between 1964 and The earliest expiration date for the Columbia River Treaty is September 2024, subject to either country giving 10 years' notice of its intent to terminate the Treaty. Canada's share (one-half) of the extra power produced in the U.S. as a result of the Treaty called the "Canadian Entitlement to downstream benefits" is owned by the province of B.C. This Canadian Entitlement was initially sold to a group of U.S. utilities for 30-year periods beginning with the scheduled completion of each of the three Treaty dams in B.C. The last of the 30-year sale periods ended in March 2003 and the province is now receiving the Canadian Entitlement for all of the Treaty dams, equal to 537 average MW of energy and 1176 MW of capacity for the operating year. The Canadian Entitlement is not a viable alternative to the Project because it does not meet the self-sufficiency requirement set out in Section 6 of the Clean Energy Act. Refer to section of the EIS as amended. Page 21

25 Evidentiary Update September 13, Part 3 ANALYSIS OF ALTERNATIVES This part updates the analysis of the alternatives for the Project (as described in sections 5.4 and 5.5 of the EIS as amended) based on information from the IRP. Consistent with Section 4.2 of the EIS Guidelines and good utility practice, and as detailed in the Technical Memo on Alternatives to the Project, BC Hydro identified and undertook a review of electricity resources which could be alternatives to the Project. As described in the EIS as amended, this consisted of: Identification of potential resource options that could meet the forecasted need for energy and dependable capacity (Section of the EIS as amended) Screening resources to determine if the resources are economically and technically feasible (Section 5.4.2) Development of financial, technical, environmental and economic development attributes to assess available resources and portfolios (Sections and 5.5.2) Assessment of the available alternatives based on the developed attributes: o On an individual basis (section 5.5.2) o In combination within portfolios (Section 5.5.4), specifically: Clean Generation portfolios using a combination of clean or renewable resources including wind, biomass and run-of-river hydro Clean + Thermal Generation portfolios using a combination of clean or renewable resources as well as natural gas-fired generation (in the form of SCGTs) within the prescribed allowance of the Clean Energy Act This portfolio analysis is conducted using two methods: Block Analysis, comparing portfolios of resources that make up the same 5,100 GWh of energy and 1,100 MW of dependable capacity as the Project Portfolio Modelling analysis using System Optimizer, which is a model that captures variability in timing of resources as well as effects of resource on the BC Hydro system and trade benefits. Portfolios created using System Optimizer will not necessarily provide the same energy and capacity as the Page 22

26 Evidentiary Update September 13, 2013 Project on an annual basis, and may therefore produce a different surplus/deficit on an annual basis. As a result of this analysis, BC Hydro concluded in the EIS as amended that the Project provides the best combination of financial, technical, environmental and economic development attributes and is therefore the preferred alternative to meet the need for energy and capacity within BC Hydro s planning horizon. BC Hydro has updated the information used in the analysis of alternatives in the EIS as amended. These consist of: Changes to the cost of capital for BC Hydro and IPP projects Amendment of the candidate portfolios to include additional potential alternative resources. These updates are described in parts 3.1 and 3.2 below. Part 3.3 presents updated block analysis and portfolio modelling results based on this updated information. Both the block analysis and the portfolio modelling utilize the same methodology and portfolio categories as in the EIS as amended. BC Hydro has also included versions of the Clean Generation and Clean + Thermal Generation portfolios that include additional DSM activity (DSM Option 3). The conclusion of this portfolio analysis is unchanged compared to the EIS as amended. The Project continues to provide the best combination of financial, technical, environmental, and economic development attributes, and remains the preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. 3.1 Updates to Cost of Capital The weighted average cost of capital (WACC) is the overall cost of combined debt and equity capital used to finance an acquisition. BC Hydro s WACC has been updated from the EIS as amended to: Page 23

27 Evidentiary Update September 13, 2013 a 5 per cent real cost of capital rates used to determine the unit energy costs (UECs) 16 of BC Hydro resources (such as the Project, Revelstoke Unit 6 and GMS Units 1-5 Capacity Increase) and; a 7 per cent real cost of capital for IPP resources. In April 2013, the 6 per cent real cost of capital used in the EIS as amended 17 was revised to a 5 per cent real rate to reflect an expected long-term reduction in BC Hydro s WACC. The BC Hydro WACC is calculated using a deemed capital structure of a 70/30 debt to equity ratio. The forecasted cost of debt is provided by the B.C. Ministry of Finance and the cost of equity is based on BC Hydro s allowed rate of return. The 5 per cent real rate corresponds to a 7 per cent nominal rate, using an average rate of inflation of 2.0 per cent. 18 As set out in section of the EIS as amended, Policy Action #13 of the B.C. Government s 2002 BC Energy Plan 19 provides that the private sector (i.e., IPPs) will develop new electricity generation, with BC Hydro restricted to improvements at existing plants and the Project. A 2 per cent WACC differential was established in the EIS as amended, which resulted in an 8 per cent real WACC for IPPs (BC Hydro s WACC was 6 per cent real). The WACC differential is attributable to BC Hydro s role as an agent of Her Majesty the Queen in the right of the Province of British Columbia. BC Hydro s borrowing is guaranteed by the Province and BC Hydro can also borrow directly from the Province. The BCUC has found that IPPs cost of debt is higher than BC Hydro s: the [BCUC] panel agrees with BC Hydro [and the customer intervenors] that project evaluation methodology must consider the actual costs, benefits, risks and other characteristics of individual projects that may be relevant to cost-effectiveness, and should not seek to artificially compensate for real differences in projects costs, including possible differences in the cost of capital between BC Hydro and other developers. With respect to the cost of capital, BC Hydro 16 The unit energy cost of a resource option is a representation of the cost per megawatt hour of energy delivered over the resource option s economic life 17 BC Hydro revised its F2014 WACC by 50 basis points in April Prior to the F2014 change, BC Hydro s WACC was at 5.5 per cent (real), which was rounded up to 6 per cent for the purpose of long-term planning and in the EIS as amended. 18 Financial forecasts of Consumer Price Index and Canadian long-term interest rate are provided by the Treasury Board of the Province of B.C. 19 Energy for Our Future: A Plan for BC, page 30. Page 24

28 Evidentiary Update September 13, 2013 projects will clearly have an advantage as a result of access to the Province s high credit rating. 20 This BCUC finding is supported by BC Hydro s observations based on open-book 21 EPA negotiations. In a study for the Western Electricity Coordinating Council (WECC), the region in which BC Hydro operates, an after-tax WACC for IPPs of 8.25 per cent was used. 22 Given that the recent reduction in borrowing costs is applicable to both the public and private sectors, the estimated IPP WACC has been reduced from 8 per cent real in the EIS as amended to 7 per cent real. Refer also to section 4.2 of this Evidentiary Update where a sensitivity test is performed assuming a lower IPP WACC of 6 per cent, effectively reducing the WACC differential from 2 per cent to 1 per cent. Aside from the change to BC Hydro s WACC from 6 per cent real to 5 per cent real, the only other change to the key financial parameters used in the portfolio analysis described in section of the EIS as amended is a lowering of BC Hydro s discount rate from 6 per cent (real) to 5 per cent (real) for the portfolio PV cost assessments. The reasons set out above with respect to BC Hydro s WACC apply to this discount rate change as well. 3.2 Updates to Available Alternative Resource Options BC Hydro reviewed the identified resource options and included three additional options as available in the portfolio analysis. These additional resource options, in general, provide less expensive dependable capacity supply or energy than other dependable capacity supply alternatives and therefore provide a more stringent test of the Project s cost-effectiveness Additional Resource Smart Projects In the Matter of British Columbia Hydro and Power Authority: 2006 Integrated Electricity Plan and 2006 Long Term Acquisition Plan, Decision, 11 May 2007, page 205. Open book negotiations with IPPs typically occur when BC Hydro is negotiating an EPA as opposed to conducting a competitive power acquisition process, and permit BC Hydro to probe the IPP supplier s pricing decisions and cost drivers, including cost of capital. Cost and Performance Review of Generation Technologies Recommendations for WECC 10- and 20-Year Study Process, 2012, Energy + Environmental Economics, page 55-56; copy available at draft.pdf. Page 25

29 Evidentiary Update September 13, 2013 Revelstoke Unit 6 and GMS Units 1-5 Capacity Increase were not used as alternatives in the section EIS Clean Generation Portfolios because: Revelstoke Unit 6 was treated as a committed resource in BC Hydro s LRBs and thus not an alternative GMS Units 1-5 Capacity Increase was not sufficiently developed at the time of the EIS The portfolio analysis for the EIS as amended instead relied on higher cost pumped storage as the marginal clean capacity resource. Analysis in the IRP concludes that Revelstoke Unit 6 and GMS Units 1-5 capacity increase are the only large remaining BC Hydro Resource Smart 23 projects available the other potential Resource Smart projects are higher cost; refer to table 5.36 of the EIS as amended. The IRP sets out the respective UCCs for: Revelstoke Unit 6 (in $F2013) at $50 per kilowatt year (/kw-year) at the point of interconnection (POI) with the BC Hydro system; GMS Units 1-5 Capacity Increase at $35/kW-year at POI; and for pumped storage at between $100/kW-year to $630/kW-year 24 depending on location and installed capacity. Thus the avoided capacity cost is now a combination of Revelstoke Unit 6, GMS Units 1-5 Capacity Increase and either pumped storage or natural gas-fired Simple Cycle Gas Turbine facilities (SCGTs). These values update the capacity values set out in section of the amended EIS. In addition, the UECs set out in Section have been updated from $131/MWh to $ /MWh for clean or renewable energy resources as the avoided energy cost based on the Resource Options Report contained in the IRP. The rationale for the inclusion of Revelstoke Unit 6 as an alternative to the Project is described in part of this Evidentiary Update. BC Hydro has also advanced the GMS Units 1-5 Capacity Increase to a sufficient stage to be included in the analysis of alternatives DSM Option 3 23 Resource Smart is a BC Hydro program that promotes the identification, study, and implementation of projects that provide cost-effective energy and capacity gains at existing BC Hydro facilities. 24 These pumped storage UCCs do not account for fuel costs associated with energy losses. Page 26

30 Evidentiary Update September 13, 2013 In the base portfolio analysis, all portfolios assume that BC Hydro will be successful in achieving its DSM target. However, BC Hydro has identified further DSM potential that may be considered as an alternative to the Project. DSM Option 3 represents a scenario where BC Hydro achieves energy savings beyond the DSM target. DSM Option 3 on its own would only defer the need for the Project s energy output for two years (from F2027 to F2029, without potential LNG load). As a result, DSM Option 3 is not an alternative to the Project on its own and needs to be combined with other clean or renewable alternatives and/or natural gas-fired generation. BC Hydro has included analysis in this Evidentiary Update of portfolios that include DSM Option Updated Block and Portfolio Modelling Analysis This part updates the block and portfolio modelling analysis provided in Section of the EIS as amended. The methodology used in both the Block Analysis and System Optimizer analysis is summarized in each section, but remains as described in the section of the EIS as amended Block Analysis The alternatives to the Project are composed of multiple available resources, as most alternatives are not capable of delivering comparable amounts of energy and dependable capacity on their own. To facilitate a unit cost comparison with the Project, an adjusted UEC representing the cost per megawatt hour of energy delivered over the economic life was calculated for two comparable blocks of resources which were created to make up the Project s 5,100 GWh/year of energy and 1,100 MW of dependable capacity: (1) Clean Generation Block; and (2) Clean + Thermal Generation Block. Note: Two variations of the Clean + Thermal Generation Block are considered. One variation uses six SCGTs together with Revelstoke Unit 6 to meet the 1,100 MW Page 27

31 Evidentiary Update September 13, 2013 capacity requirement 25. The other variation replaces two of the SCGTs with the GMS Units 1-5 Capacity Increase. The tables provided in section show the resources that make up the Clean Generation and Clean + Thermal Generation portfolio blocks, and their associated costs. These blocks predominately consist of wind resources to provide energy. In the Clean Generation Portfolio block, Revelstoke Unit 6, GMS Units 1-5 Capacity Increase and pumped storage are added to the block to make the capacity equivalent to the Project. To account for the energy losses associated with pumped storage, this block requires about 400 GWh/year of additional energy resources. In the Clean + Thermal Generation Portfolio blocks, SCGTs partly make up the capacity need comparable to the Project. The adjusted UEC costs for all four portfolios are listed in Table 11, which updates Table 5.42 of the EIS as amended. Table 11 shows that the Project remains lower cost than the alternative portfolios. The UEC values are lower than provided in the EIS, primarily due to the decrease in the discount rate used in the analysis. However, the differences between the portfolios are similar to those provided in the EIS as amended. Table 11 Adjusted Unit Energy Cost Comparison Adjusted UEC ($F2013/MWh) Clean Generation Block Clean + Thermal Generation Block #1 (Revelstoke Unit 6 and 6 SCGTs) Block #2 (Revelstoke Unit 6, GMS and 4 SCGTs) Project As many of the resources in the Clean and Clean + Thermal portfolios are not significantly different than in the EIS as amended, the environmental and economic development attributes of the portfolios have not changed significantly. However, for completeness BC Hydro has provided the environmental and economic development attributes in section The scenario with six SCGT represents one where BC Hydro is as the limit of the 93% clean or renewable energy target in the Clean Energy Act i.e. no further gas generation is permitted. Page 28

32 Evidentiary Update September 13, Portfolio Modelling using System Optimizer This analysis evaluates the cost competitiveness of the Project by comparing the present value cost of portfolios with and without the Project using the System Optimizer. As described in Section of the EIS as amended, System Optimizer is a model that selects a resource expansion sequence (i.e. the order in which new projects are built) that minimizes the present value (PV) of net system costs. The analysis using System Optimizer is a more sophisticated approach than the Block Analysis and provides additional information not captured by the block analysis, including: Timing of resource additions including transmission additions or upgrades and associated capital and operating expenditures; Effects of resource additions to the overall system and the system load resource balance over the planning horizon; Economic dispatch reflecting the manner in which dispatchable resources will be operated; Electricity market trade benefits that vary with the flexibility of the overall portfolio. Two key advantages of portfolio modelling, including modelling the expected operation, are: (1) it captures most of the economical dispatch value (for dispatchable resources such as the Project, natural gas-fired generation) which provides value to BC Hydro s customers and is a point of differentiation of the Project from intermittent clean or renewable resources such as wind and run-of-river; and (2) the lumpiness of resources by modeling timing of resources and the net cost of energy imbalances by comparing acquisition costs to value in the electricity markets. As a result of this additional detail the resources selected by System Optimizer and the resulting annual energy surplus or deficit will differ depending on the portfolio i.e. projects that do not include the Project will not produce the same annual surplus / deficit as portfolios with the Project. Figure 2 shows the base assumptions/conditions used for the portfolios presented in this section. Page 29

33 Evidentiary Update September 13, 2013 Uncertainties/Scenarios Market Prices Figure 2 Base Modelling Assumptions Used for the Portfolio Modelling Analysis Scenario 2 Low Scenario 1 Mid Scenario 3 High Load Forecast Low Mid High DSM deliverability Low Mid High LNG Load Scenarios Prior to LNG 800 GWh/year 3,000 GWh/year 6,600 GWh/year Resource choices Usage of 7% non-clean for non LNG load Yes No DSM Options DSM Option 1 DSM Target/ Option 2 DSM Option 3 Site C (all units in) timing F2024 F2026 No Site C Modelling Assumptions and Parameters BCH/IPP Cost of Capital 5/7 5/6 Pumped Storage as Option Yes No Site C Capital Cost Base Base plus 10% Wind Integration Cost $5/MWh $10/MWh $15/MWh shows the modeling assumptions As discussed later in this section, BC Hydro also conducted further analysis that included DSM Option 3 as an available resource and of scenarios with a Project ISD of F2026. The sensitivity analysis in part 4 of this Evidentiary Update varies some of these base assumptions further. Portfolio Modelling Analysis Results Table 12 updates Table 5.41 of the EIS, and shows the difference in the PV cost between the portfolios without the Project versus portfolios with the Project. Positive values indicate that the portfolio with the Project is lower cost than the alternative portfolio. Table 12 shows that the Project has a cost advantage at its earliest ISD, saving approximately $630 million and $150 million in PV as compared to the Clean Generation and Clean + Thermal Generation portfolios, respectively. The Project s cost advantage increases with a F2026 Page 30

34 Evidentiary Update September 13, 2013 ISD. These cost advantages are higher than estimated in the EIS as amended, primarily due to the decrease in the discount rate used in the PV analysis. Table 12 Portfolio Present Value Comparison Portfolio Comparison Site C portfolio compared to Clean Generation portfolio Site C portfolio compared to Clean + Thermal Generation portfolio Project In- Service Date Portfolio Present Value Differential (Portfolio without the Project minus Portfolio with the Project) ($F2013 million) F F F F It should be noted that the partial replacement of the dependable capacity provided by the Project with SCGTs would cause BC Hydro to reach the limit of the 93 per cent clean and renewable target under the Clean Energy Act. As a result, BC Hydro s ability to use natural gas-fired generation for contingency resource planning purposes is forgone. This forgone value is not captured in the portfolio analysis undertaken above. Portfolios including DSM Option 3 BC Hydro conducted analysis in the IRP to determine if DSM Option 3 would be a lower cost potential alternative to the Project. This was done through a variation of the Clean + Thermal portfolios (as the alternative to the Project with the lowest PV cost) that included DSM Option 3. The results in Table 13 show that the portfolio with the DSM target and the Project with an ISD of F2024 has a PV cost benefit of $320 million compared to the portfolio with Option 3, natural gas-fired generation within the Clean Energy Act Clean and Renewable target, low cost Revelstoke Unit 6 and GMS Units 1-5 Capacity Increase capacity resources but without the Project. Table 13 Portfolio Present Value Comparison DSM Option 3 Page 31

35 Evidentiary Update September 13, 2013 Portfolio Type DSM Analysis Difference in PV Cost (Portfolio without the Project minus portfolio with the Project) ($F2013 million) Clean + Thermal Generation Portfolio DSM Option 3 without the Project vs. DSM target with the Project Summary and Conclusion The conclusion of the analysis of alternatives to the Project has not changed compared to the EIS as amended, because the differences in financial, technical, environmental, and economic development attributes between portfolios with and without the Project have not changed significantly. The Project remains the most cost-effective way in which BC Hydro can meet the need for energy and dependable capacity. In addition, the Project provides additional benefits of economic development and employment and would generate electricity with comparatively low GHG emissions per unit energy. The IRP and the Evidentiary Update confirm that the Project provides the best combination of financial, technical, environmental, and economic development attributes and remains the preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. Page 32

36 Evidentiary Update September 13, Updated Block Analysis Tables Composition of Portfolios for Block Analysis Page 33

37 Evidentiary Update September 13, 2013 Clean Generation Energy Costs Table 14 Project Name Details and UEC Calculations for Clean Generation Block Dependable Capacity (MW) Annual Firm Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013M) MSW2_LM Wind_PC Wind_PC Wind_PC MSW1_VI Wind_PC Wind_PC Wind_PC Wind_PC Wind_PC Wind_PC Wind_VI Wind_VI REV6 Variable Costs (see note 1) n/a GMS Variable Costs (see note 2) n/a PS Variable Costs (see note 3) n/a (364) 19 7 Weighted Average excluding capacity resources n/a n/a 125 n/a Weighted Average including capacity resources n/a n/a 135 n/a Capacity Costs Sub-total n/a 688 Dependable Capacity (MW) Annual Firm Energy (GWh) Unit Capacity Cost ($F2013/kWyear) Total Cost ($F2013M) REV6 Fixed Costs 488 n/a GMS Fixed Costs 220 n/a 35 8 PS Fixed Costs 500 n/a Sub-total 1208 n/a Dependable Capacity (MW) Annual Firm Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013M) Total Note: 1. REV6 variable cost include variable OMA and water rentals. 2. GMS variable cost include variable OMA and water rentals. 3. Pumped Storage variable cost include variable OMA and water rentals. The cost of energy losses is included in the total cost of the clean resources that would be used to serve those losses. 4. UECs include a soft cost adder of 5%, wind integration cost where applicable, adjustment for time of delivery, a regional transmission cost adder of $6/MWh, and the cost of delivery to the lower mainland. Page 34

38 Evidentiary Update September 13, 2013 Table 15 Details and UEC Calculations for Clean + Thermal Generation Block #1 (Revelstoke Unit 6 and 6 SCGTs) Clean + Thermal Generation (No GMS, 6 SCGTs) Energy Costs Project Name Dependable Capacity (MW) Annual Firm/Effective Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($1000) MSW2_LM Wind_PC Wind_PC Wind_PC MSW1_VI Wind_PC Wind_PC Wind_PC Wind_PC Wind_PC REV6 Variable Costs (see note 1) n/a SCGT Variable Costs (see note 2) n/a Weighted Average excluding capacity resources n/a n/a 124 n/a Weighted Average including capacity resources n/a n/a 113 n/a Sub-total n/a 575 Capacity Costs Dependable Capacity (MW) Annual Firm Energy (GWh) Unit Capacity Cost ($F2013/kWyear) Total Cost ($F2013M) REV6 Fixed Costs 488 n/a SCGT Fixed Costs 588 n/a Sub-total 1076 n/a Dependable Capacity (MW) Annual Firm Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013M) Total Note: 1. REV6 variable cost include variable OMA and water rentals. 2. SCGT variable costs include variable OMA, fuel cost and GHG cost. 3. UECs include a soft cost adder of 5%, wind integration cost where applicable, adjustment for time of delivery, a regional transmission cost adder of $6/MWh, and the cost of delivery to the lower mainland. Page 35

39 Evidentiary Update September 13, 2013 Table 16 Clean + Thermal Generation (With GMS, 4 SCGTs) Energy Costs Project Name Details and UEC Calculations for Clean + Thermal Generation Block #2 (Revelstoke Unit 6, GMS and 4 SCGTs) Dependable Capacity (MW) Annual Firm/Effective Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($1000) MSW2_LM Wind_PC Wind_PC Wind_PC MSW1_VI Wind_PC Wind_PC Wind_PC Wind_VI Wind_PC Wind_PC REV6 Variable Costs (see note 1) n/a GMS Variable Costs (see note 2) n/a SCGT Variable Costs (see note 3) n/a Weighted Average excluding capacity resources n/a n/a 125 n/a Weighted Average including capacity resources n/a n/a 117 n/a Capacity Costs Sub-total n/a 598 Dependable Capacity (MW) Annual Firm Energy (GWh) Unit Capacity Cost ($F2013/kWyear) Total Cost ($F2013M) REV6 Fixed Costs 488 n/a GMS Fixed Costs 220 n/a 35 8 SCGT Fixed Costs 392 n/a Sub-total 1100 n/a Dependable Capacity (MW) Annual Firm Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013M) Total Note: 1. REV6 variable cost include variable OMA and water rentals. 2. GMS variable cost include variable OMA and water rentals. 3. SCGT variable costs include variable OMA, fuel cost and GHG cost. 4. UECs include a soft cost adder of 5%, wind integration cost where applicable, adjustment for time of delivery, a regional transmission cost adder of $6/MWh, and the cost of delivery to the lower mainland. Page 36

40 Evidentiary Update September 13, Updated Environmental and Economic Development Attributes Table 17 Environmental Attributes for Site C Vs Supply Side Alternatives Category Indicator Units Classification Clean Portfolio Clean + Thermal (6 SCGT) Clean + Thermal (4 SCGT) Site C Portfolio Land Footprint hectares n/a Freshwater Marine Net Primary productivity Remoteness linear disturbance density (km/km2) High priority species count (percentile) Affected Stream Length Priority fish species (number per watershed) Reservoir Aquatic Area Valued ecological features Key commercial bottom fishing areas Atmosphere GHG emissions tonnes/year, thousands Air contaminant tonnes/year, emissions thousands ha per class Low (0 to < 69) Medium (69 to < ) High (> 369) ha per class Wilderness (< 0.2) Remote (0.2 to < ) Rural (0.66 to 2.2) Urban (> 2.2) ha per class 0 to < to < to < to > kilometers n/a ha per class No priority species (0) Low species diversity (1 to 12) Moderate species diversity (13 to 23) High species diversity (24 to 38) ha n/a ha per class None (0) n/a n/a n/a n/a Low (1 to 2) Medium (3 to 5) High (> 5) ha per class No bottom fisheries n/a n/a n/a n/a 1 bottom fishery to 3 bottom fisheries > 3 bottom fisheries Carbon dioxide equivalent Sulphur dioxide Oxides of nitrogen Carbon monoxide Volatile organic compounds Fine particulates Page 37

41 Evidentiary Update September 13, PM2.5 Fine particulates PM10 Fine particulates PM total Mercury Table 18 Economic Development Attributes for Site C Vs Supply Side Alternatives Category Indicator Units Classification Clean Portfolio Clean + Thermal (6 SCGT) Clean + Thermal (4 SCGT) Site C Portfolio Provincial GDP Employment Provincial Government Revenue Construction period GDP Operations period GDP Construction period employment Operations period employment Construction period revenue Operations period revenue dollars, millions dollars, millions per year Direct Indirect 1,670 1,069 1,133 2,336 Induced Total 2,513 1,616 1,706 3,676 Direct Indirect Induced jobs Direct 5,777 3,767 3,927 9,754 Indirect 20,578 13,253 14,025 27,997 Induced 4,434 2,852 3,012 6,497 Total 30,788 19,872 20,963 44,249 jobs per year dollars, millions dollars, millions per year Direct Indirect Induced Total Direct Indirect Induced Direct Indirect Induced Page 38

42 Evidentiary Update September 13, Part 4 SENSITIVITY ANALYSIS This part of the Evidentiary Update describes sensitivity analysis to key assumptions to evaluate which factors most affect the cost of the candidate portfolios. Sensitivity analysis is a way of assessing the outcome of a decision if a situation turns out to be different compared to, in this case, the base assumptions/conditions analyzed in the EIS as amended and in part 3 of this Evidentiary Update. Sensitivity analysis typically involves varying one input at a time. By creating a given set of scenarios, BC Hydro can determine how changes in one variable will impact the base assumption/condition. In this section, the cost effectiveness of the Project is tested for: 1) performance in large gap (i.e., high load growth with low DSM savings level) and small gap (low load growth with low DSM savings level) conditions; 2) high and low electricity spot market price scenarios; 3) a lower cost of capital assumption for IPP projects; 4) higher capital costs for the Project; and 5) different wind integration costs. 4.1 Large and Small Gaps As described in both part 3 of this Evidentiary Update and in section of the EIS as amended, BC Hydro uses its mid-load forecast of both energy and capacity requirements for purposes of determining the need for new resources. As stated at page 5-5 of the EIS as amended, the mid-level load forecast represents the expected future load, in which actual realized loads will be higher than forecast 50% of the time, and lower than forecast 50% of the time. For this reason the mid-level load can be referred to as a P50 load forecast. The EIS as amended at section discusses how BC Hydro addresses load forecast uncertainty by developing a high forecast band with approximately a 10 percent exceedance probability (referred to as a high load forecast) and a low forecast band with approximately a 90 per Page 39

43 Evidentiary Update September 13, 2013 cent exceedance probability (referred to as a low load forecast). These high and low bands are used in the large and small gap sensitivity analysis described in this section. Another base assumption / condition for the Project need analysis is that the DSM target will deliver 7,800 GWh/year of energy savings and 1,400 MW of associated capacity savings. However, as described in section of the EIS as amended, the DSM target is aggressive and entails delivery risks. Precise forecasting of DSM savings for long-term planning purposes is challenging for several reasons, including: Limited experience with respect to targeting cumulative savings above current levels; Difficulty in distinguishing between load growth and DSM effects; Difficulty linking customer response to DSM actions, and forecasting the timing and efficacy of regulatory changes; Difficulty of incenting customer behaviour changes in a low electricity cost jurisdiction. For purposes of the IRP BC Hydro did an uncertainty assessment of the DSM plan and developed high and low DSM delivery bands. The low band is of particular importance for a lower than expected load forecast: A prolonged period of low load growth would likely not be accompanied by BC Hydro continuing to pursue the same level of DSM savings. Rather, efforts would likely be scaled back in the face of a prolonged period of slow economic growth For purposes of the IRP, BC Hydro updated DSM savings potential to reflect new information, including economic/market conditions, customer participation and a reduced 2012 mid-level Load Forecast as compared to the 2011 mid Load Forecast. In the 2008 Long-Term Acquisition Plan (LTAP) proceeding before the BCUC, BC Hydro provided evidence that a reduced load forecast impacts DSM economic potential. 26 For example, it is generally acknowledged that industrial DSM participation and energy efficiency will decrease in recessionary periods. 27 While the strength of the relationship between both participation and the savings potential for Exhibit B-10 in the 2008 LTAP proceeding, section See, for example, T.Ernst and O.Dancel, Macroeconomc Impacts on DSM Program Participation, 2011 ACEEE Summer Study on Energy Efficiency in Industry), page Page 40

44 Evidentiary Update September 13, 2013 DSM participants and economic growth and also the nature of this relationship when growth starts to rebound is an unknown, in a downturn, DSM program savings potential is likely reduced. This combination of scaled back efforts paired with lower than expected DSM savings conditions was modelled using a low level of DSM savings. This approach is a rough approximation to capture dynamic decision-making within a static modelling framework and so some care must be taken when interpreting results involving the low gap (large surplus) scenarios. It should be noted that a distinction must be drawn between what load forecast a public utility plans to, and how a public utility factors in load forecast uncertainty. BC Hydro can report that it has found no public utilities in the WECC which produce IRPs that plan resource acquisitions based on a low load forecast scenario. Comments received subsequent to the end of the public comment period have referenced the Northwest Power Planning Council (NPCC) 28, however the NPCC does not advocate use of a low load scenario as the scenario to plan for. In addition, the NPCC is not a public utility. The use of a low load scenario as a sensitivity test varies among public utilities in the WECC region, and only about half of the public utilities that produce IRPs in the WECC appear to assign probabilities to load scenarios. In this analysis, the cost competitiveness of the Project under large gap and small gap conditions both assuming no LNG is tested: Large gap conditions are defined as high load forecast with low level of DSM savings; Small gap conditions are defined as low load forecast and low level of DSM savings. As discussed below, a reduced load forecast impacts DSM economic potential. Figure 3 and Figure 4 show the load-resource gap for both of these conditions prior to adding the Project. Table 19 summarizes the PV benefits for portfolios with the Project over portfolios without the Project under these conditions. The PV benefits of the Project increase 28 Treaty 8 Tribal Association, 31 May 2013 Environmental Impact Statement Addendum Comments, Comment 13c, d and e, CEAR #1468. Page 41

45 Evidentiary Update September 13, 2013 with the size of the gap. The Project is at a cost disadvantage to alternative portfolios in the small gap conditions due to its large size; however, the small gap scenario has almost no load growth after DSM for most of the 30-year planning horizon and is therefore unlikely. Figure 3 Energy Load Resource Balance for Large, Mid and Small Gap Page 42

46 Evidentiary Update September 13, 2013 Figure 4 Capacity Load Resource Balance for Large, Mid and Small Gap Table 19 Sensitivity of Project PV Benefit to Gap Condition Difference in PV Cost (Portfolio without the Project minus portfolio with the Project) ($F2013 million) Clean Generation Portfolio Clean + Thermal Generation Portfolio Large-Gap (~10% likelihood) Base Case: Mid-Gap (~80% likelihood) Small-Gap (~10% likelihood) F2024 See Note (1,040) F (705) F2024 2, (1,280) F2026 See Note (907) Note 1: The benefits for the Project are expected to be higher than the Clean + Thermal Generation Portfolio with the Project in-service in F2024. While LNG proponents have the choice of whether to self-serve or request service from BC Hydro, to the extent that LNG proponents take service, BC Hydro reviewed LNG load in the context of the Project. To the extent that LNG loads are supplied by BC Hydro the benefits of the portfolio with the Project are expected to increase. This is because LNG load Page 43

47 Evidentiary Update September 13, 2013 advances the need for new energy resources after implementation of the DSM target and EPA adjustments from F2027 to F2021 for High LNG load (6,600 GWh) and to F2024 for Low LNG (800 GWh). There is no change to the timing of requirement of capacity resources under any LNG scenarios, but the magnitude of capacity requirement increases by 100 MW (Low LNG) to 800 MW (High LNG) in the F2020 to F2022 timeframe. 4.2 Cost of Capital Differential As described in section 3.1 above the base assumption for cost of capital is 5 per cent for BC Hydro and 7 per cent for clean or renewable IPPs. A sensitivity test was performed assuming 6 per cent WACC for IPPs, effectively reducing the cost of capital differential between BC Hydro and IPPs from 2 per cent to 1 per cent. In this sensitivity test, the Site C portfolio maintains a cost advantage although the benefit of the Site C portfolio is reduced from $630 million to $420 million for the Clean Generation alternative portfolio and from $150 million to $20 million for the Clean + Thermal alternative portfolio. Refer to Table 20. Table 20 Portfolio PV for Project Sensitivities: Cost of Capital Differential of 1 Per Cent Portfolio type Cost of Capital for IPP (%) Project In- Service Date Difference in PV Cost (Portfolio without the Project minus portfolio with the Project) ($F2013 million) Clean Generation 6 F F Clean + Thermal Generation 6 F Market Prices F The spot market price assumption for the EIS portfolio analysis is described in section of the EIS as amended where BC Hydro used the Ventyx Spring 2012 market price forecast in the portfolio analysis. This scenario is referred to as Market Scenario 1 in the IRP and is the base assumption used in both the IRP and the EIS as amended analysis. Four Page 44

48 Evidentiary Update September 13, 2013 additional market scenarios were identified for sensitivity analysis in the IRP. This section tests the cost-effectiveness of the Project in a high market (Market Scenario 3) and a low market (Market Scenario 2) price scenario. These 3 market scenarios are the most likely with a combined likelihood of 95%. It can also be noted that market prices are the primary way in which foreign exchange rates can influence the portfolio analysis the market price scenarios used in this sensitivity analysis are sufficiently broad to also effectively cover potential fluctuations in exchange rates. A description of the five market scenarios is provided in the supplemental information at the end of this part of the Evidentiary Update. The PV benefits of the Project over the Clean Generation and Clean + Thermal Generation portfolios are shown in Table 21. In comparison to the base case of Market Scenario 1, the benefits of the Project are larger in the high market (with a projected spot market forecast of about $43/MWh in F2024) and smaller in the low market scenario (with a projected spot market price of about $24/MWh in F2024). In the Market Scenario 2 low market sensitivity case 29 (a lower probability scenario with 20 per cent likelihood), the Project is still more cost competitive than the Clean Generation Portfolio for both the F2024 and F2026 ISD, is marginally less cost competitive than the Clean + Thermal Generation Portfolio for the F2024 ISD, and is more cost competitive than the Clean + Thermal Generation Portfolio for a F2026 ISD. In the F2024 ISD case, lower gas prices favour the natural gas-fired alternative while the energy surplus that comes with the Project in its early years is now sold at a lower market price. It is important to note that BC Hydro has conservatively assigned no value to surplus capacity. However, surplus capacity has value. In the recent John Hart Generating Station Replacement Project Certificate of Public Convenience and Necessity (CPCN) application proceeding before the BCUC, BC Hydro provided evidence that while the market value of capacity is uncertain because the current market in the WECC region is illiquid, BC Hydro estimated a range of market values of $75/kW-year to about $110/kW-year, based on recent Bonneville Power Administration tariffs, transaction and market analysis. BC Hydro further estimates that U.S. market access transmission constraints could reduce the market value 29 No GHG regulation and natural gas prices at $3 MMBTu (one million British Thermal Units) continue for the entire forecast period. Page 45

49 Evidentiary Update September 13, 2013 of capacity to $37/kW-year for the low end of the market range. These benefits are in addition to cost advantage described above. Table 21 Sensitivity of Project Benefit to Market Prices Difference in PV Cost (Portfolio without Site C minus with Site C in F2024) ($F2013 million) Project ISD Market Scenario 3 - high market prices (15% likelihood) Base Case: Market Scenario 1 mid market prices (60% likelihood) Market Scenario 2 low market prices (20% likelihood) Clean Generation Portfolio F Clean + Thermal Generation Portfolio 4.4 Project Capital Cost F2026 1, F (90) F As outlined in Appendix F, Part 1 of the EIS as amended, the Project cost estimate is a Class 3 cost estimate (based on the definitions of the Association for the Advancement of Cost Engineering), and includes an appropriate level of contingency to reflect uncertainty in future conditions. To test the sensitivity of the Project to capital costs, BC Hydro evaluated a set of portfolios with the Project capital cost plus 10 per cent, consistent with the capital cost sensitivities in BC Hydro s generation project CPCN applications with the BCUC. It should be noted that in these scenarios the costs of all other resources are held constant. Table 22 shows that with the plus 10 per cent capital cost sensitivity, the Project with an ISD of F2026 remains more cost competitive than the Clean Generation Portfolio and the Clean + Thermal Generation Portfolio both without the Project. For an ISD of F2024, the Project is still more cost competitive than the Clean Generation Portfolio without the Project but at a disadvantage to the Clean + Thermal Generation Portfolio without the Project. Page 46

50 Evidentiary Update September 13, 2013 Table 22 Sensitivity of Project Benefit to 10 per cent Capital Cost Increase Portfolio Type Project ISD Difference in PV Cost (Portfolio without Site C minus with Site C) ($F2013 million) Clean Generation Portfolio Clean + Thermal Generation Portfolio 4.5 Wind Integration Cost F F F2024 (120) F As described in section of the EIS as amended, the base assumption for wind integration cost is $10/MWh. For the purpose of testing the sensitivity of the cost competitiveness of the Project, wind integration costs of $5/MWh and $15/MWh were also modelled. The analysis shows that based on an ISD of F2024, the PV benefits of the Project for the Clean Generation Portfolio would decrease from $630 million to $530 million for a wind integration cost of $5/MWh, and increase from $630 million to $720 million for a wind integration cost of $15/MWh. Refer to Table 23. Table 23 Portfolio PV for Project Sensitivities: Wind Integration Cost Portfolio Type Clean Generation Portfolio Clean + Thermal Generation Portfolio Note: Wind Integration costs Difference in PV Cost (Portfolio without Site C minus with Site C in F2024) ($F2013 million) Difference in PV Cost (Portfolio without Site C minus with Site C in F2026) ($F2013 million) $5/MWh 530 See Note 1 $10/MWh $15/MWh 720 See Note 1 $5/MWh 92 See Note 1 $10/MWh $15/MWh 222 See Note 1 1. The benefits for the Project are expected to be higher in portfolios with the Project in-service in F2026. Page 47

51 Evidentiary Update September 13, Sensitivity Analysis Conclusion This sensitivity analysis provided in this Part reviews a range of potential future scenarios and evaluates the financial benefits of the Project under these scenarios. Table 24 summarizes the results of this sensitivity analysis conducted. Table 24 Benefit of the Project: Sensitivity Analysis Summary Difference in PV Cost (Portfolio without Site C minus with Site C) ($F2013 million) Base Case (Mid Gap, Mid-Market Price [Scenario 1], WACC Differential = 2%, Wind Integration Cost = $10/MWh Clean Generation Portfolios Clean + Thermal Generation Portfolios F2024 F2026 F2024 F Large Gap Note 1 Note 1 2,260 Note 1 Small Gap (1,040) (705) (1,280) (907) WACC Differential = 1% High Market Price (Scenario 3) 830 1, Low Market Price (Scenario 2) (90) 217 Project Capital Cost +10% (120) 170 Wind Integration Cost ($15/MWh) 720 Note Note 1 Wind Integration Cost ($5/MWh) 530 Note 1 92 Note 1 Note 1. The benefit of the Project in this scenario is expected to be higher than the comparative portfolio for the same sensitivity. In the majority of the scenarios, the Project continues to provide financial benefits compared to the portfolios of alternative resource options. The scenarios in which alternative portfolios provide benefits compared to the Project are generally lower probability, and are associated with long-term low load growth or market prices. Given the wide range of potential scenarios in which the Project provides benefits compared to alternatives, and given the low likelihood of the scenarios in which it does not, BC Hydro maintains that the Project is the preferred resource option to meet BC Hydro s forecast customer demand. Page 48

52 Evidentiary Update September 13, 2013 SUPPLEMENTAL INFORMATION TO PART 4 Description of Market Price Scenarios This part sets out a high level description of the five Market Scenarios developed for the IRP. Market Scenario 1: Mid Electricity Prices, with Regional Mid GHG and Mid Gas Prices Slow, but steady, global economic growth leads to lack of National GHG regulation in favour of regional regulation - Regional initiatives similar to Western Climate Initiative 30 (WCI) take the lead in establishing GHG regulatory markets in California, B.C. and Alberta, and national U.S. and Canadian governments do not follow suit in the 25-year forecast period. Medium levels of economic growth reduce federal governments ability to advance environmental initiatives. Market Scenario 1 has a relative likelihood 31 of 60 per cent. Market Scenario 2: Low Electricity Prices, with Regional Low GHG and Low Gas Prices Low economic growth delays national GHG market development - With slow economic growth and activity, this scenario envisions that GHG emissions start to fall worldwide, impacting the climate change debate and lowering public and government interest in GHG regulation. Lower natural gas prices and flat electricity load growth delay spending on renewable energy development and U.S. state Renewable Portfolio Standard 32 (RPS) implementation. Investments in research and development (R&D) and conservation are also down. Market Scenario 2 has a relative likelihood of 20 per cent. Market Scenario 3: High Electricity Prices, with Regional Mid GHG and High Gas Prices High economic growth and lower international cooperation stifles national environmental initiatives, leaving regions to regulate - Although this scenario features high global economic growth, no international agreements on GHG regulation are reached due to low levels of public support for GHG regulation in the U.S. In addition to low GHG support, there is even The WCI is a collaboration of California and Quebec, with several other western U.S. states and Canadian Provinces including B.C. as observers, to identify, evaluate and implement GHG emission trading policies at a regional level. Likelihoods are not to be taken as the probability that one scenario will occur. Given the infinite ways market prices can unfold, the chance that any one of these five Market Scenarios will exactly occur is essentially zero. The term relative likelihood emphasizes that these judgments are made in relation to the other scenarios. Page 49

53 Evidentiary Update September 13, 2013 lower public spending on renewable energy R&D. As with Market Scenario 1, California, B.C. and Alberta continue to move forward with GHG emission trading. Market Scenario 3 has a relative likelihood of 15 per cent. Market Scenario 4: Mid Electricity Prices, Regional/National Mid GHG and Mid Gas Prices Mid global economic growth sees regional leaders paving the way for national GHG markets by Mid global growth with regional initiatives similar to WCI take the lead in establishing GHG regional regulatory markets, with national U.S. and Canadian governments following suit by Although there are delays in national renewable energy standards, development is strong in later years (post-2024), with the electricity prices the same as Scenario 1 for the first 10 years but diverging thereafter. Market Scenario 4 has a relative likelihood of 4 per cent. Market Scenario 5: High Electricity Prices, Regional/National High GHG and Mid Gas Prices Delayed high economic growth and lower international cooperation stifles national environmental initiatives, leaving regions to regulate - Although this scenario sees high global economic growth, a national GHG cap-and-trade program is delayed until at least International agreements on GHG regulation are not reached for at least 10 years due to low levels of public support for GHG regulation in the U.S., and there is lower public spending on renewable energy R&D. As with Scenario 3, California, B.C. and Alberta continue to move forward with emission trading, albeit under higher cost pressures for market participants, and accordingly electricity prices are the same as Scenario 3 for the first 10 years but diverge after that period. Market Scenario 5 has a relative likelihood of 1 per cent. Table 25 lists the high level assumptions that informed the five Market Scenarios described above. 32 A RPS requires increased production of energy from qualifying renewable energy resources such as wind, solar, and biomass. The RPS generally place an obligation on public utilities and other electricity supply entities to produce a specified fraction of their electricity from qualifying renewable energy resources. RPS Regulations vary from U.S. state to state. Page 50

54 Evidentiary Update September 13, 2013 Market Scenario Table 25 Market Scenario Assumptions Mid Electricity Mid GHG (Regional) Mid Gas Low Electricity Low GHG (Regional) Low Gas High Electricity High GHG (Regional) High Gas Mid Electricity Mid GHG (Regional/Nat l) Mid Gas GHG Actor Regional Regional Regional Regional then National National GHG Cap-and-Trade Date 33 GHG Price Level Natural Gas Price Level 34 High Electricity High GHG (Regional/Nat l) High Gas Regional then National Post-2040 Post-2040 Post Mid (Regional) Mid (Regional) Low High Mid (Env.) High Low High Mid (Env.) High Global Mid Low High Mid High Growth 35 Load Growth 36 Expected Flat High Expected High WECC Resource Build 37 Expected Mix More Gas, Less Coal and Renewable Less Coal, more Renewable Less Coal, more Renewable Less Coal, more Renewable RPS Targets 38 Met Met Met Met Met The electricity price forecasts for the spot market trading hub at Mid-Columbia (Mid-C) in Canadian dollars are provided in Figure 5 and Table National Cap-and-Trade Date is the assumed year for the introduction of a national cap-and-trade system. A three-year period was used to transition from a regional scenario to a national cap-and-trade scenario. Mid (Regional) is B&V s 2012 spring reference case. Mid (Env.) is Black & Veatch s (B&V) 2012 spring environmental case. High and Low refers to B&V s spring 2012 high and low natural gas price scenarios, respectively. Global Growth Mid means expected U.S. and Canada global demand. High means almost double the expected year over year compound global growth. Low means a flat global growth over the forecast period. Load Growth Mid means expected U.S. and Canada and regional electric load growth per B&V s spring 2012 reference case. High load growth is about two times higher than the expected scenario. WECC resource build indicates the type of long-term supply mix changes assumed by B&V in each scenario. U.S. state RPS targets are met in all scenarios. Page 51

55 Evidentiary Update September 13, 2013 Figure 5 Electricity Price Scenarios at Mid-C Page 52

56 Forecast Historical Evidentiary Update September 13, 2013 Table 26 Electricity Price Forecasts by Market Scenario (Real F2013 CAD$/MWh at Mid-C) Market Scenario Mid Electricity Mid GHG (Regional) Mid Gas Low Electricity Low GHG (Regional) Low Gas High Electricity High GHG (Regional) High Gas Mid Electricity Mid GHG (Region/Nat l) Mid Gas High Electricity High GHG (Region/Nat l) High Gas 2007 $57.42 $57.42 $57.42 $57.42 $ $64.85 $64.85 $64.85 $64.85 $ $34.95 $34.95 $34.95 $34.95 $ $34.54 $34.54 $34.54 $34.54 $ $23.92 $23.92 $23.92 $23.92 $ $19.18 $19.18 $19.18 $19.18 $ $22.47 $22.47 $22.47 $22.47 $ $25.77 $22.58 $32.06 $25.77 $ $26.29 $22.37 $32.89 $26.29 $ $26.60 $21.86 $32.99 $26.60 $ $28.87 $22.58 $37.11 $28.87 $ $35.26 $24.74 $46.80 $51.86 $ $38.76 $24.54 $54.33 $61.96 $ Market Scenario 1 is BC Hydro s reference scenario and reflects current market conditions being prolonged over the long term. Market Scenario 1 aligns with the NPCC Mid-C electricity price forecast No Federal CO 2 Policy scenario. 39 In interpreting these results, it is important to note that BC Hydro s Electricity price forecasts are based on spot market price forecasts, and do not necessarily reflect the cost of building new supply. 39 NPCC, Draft Sixth Power Plan Mid-Term Assessment Report; NPCC is a regional organization (Idaho, Montana, Oregon and Washington) that develops a 20-year regional power plan to balance energy and environmental needs. Mid-C electricity prices under the NPCC s Delayed Federal CO 2 Policy scenario return to a $50/MWh to $60/MWh level from 2020 onward. Page 53

57 Evidentiary Update September 13, 2013 Appendix A Consideration of Comments with Respect to Chapter 5, Need for, Purpose of, and Alternatives to the Project, Received Subsequent to the Comment Period During the agency-led comment period for the Project s Environmental Impact Statement (EIS), BC Hydro received and responded to approximately 2,600 public and agency Information Requests (IRs), as well as approximately 1,500 IRs from Aboriginal groups. BC Hydro submitted responses to the public and government agency IRs on April 29 to the CEA Agency and BCEAO. BC Hydro responses to Aboriginal groups were submitted on May 8, in accordance with a deadline extension of April 14 for Aboriginal groups to submit their information requests. Subsequent to the close of the comment period, further submissions were received from Aboriginal groups, including the Treaty 8 Tribal Association. Some of these submissions included questions and comments on Chapter 5, Need for, Propose of, and Alternatives to the Project. While this Evidentiary Update addresses the issues raised in these submissions, this Appendix provides a high-level summary of the issues raised by interested parties. BC Hydro has summarized the responses provided in the Evidentiary Update here for convenience. a) Summary of Issue: Demand Side Management (DSM) targets: BC Hydro should analyze the possibility of DSM targets/performance being higher than expected, which would lead to an oversupply and affect the need for the Project. Summary of BC Hydro Response: The Evidentiary Update added DSM Option 3 as a portfolio resource in candidate portfolios to determine if DSM Option 3 would be a lower cost potential alternative to the Project. This addresses the suggestion that scenarios with higher DSM performance be taken into account in the analysis of alternatives. Page 54

58 Evidentiary Update September 13, 2013 It should be noted that DSM Option 3 on its own would only defer the need for the Project s energy output for two years. To be an alternative to the Project, DSM Option 3 must be augmented with additional supply side resources as part of a portfolio. This additional analysis is provided in Part of the Evidentiary Update. The portfolio analysis including DSM Option 3 found that the Project has a cost benefit when compared on a present-value basis against Clean Generation Portfolios including DSM Option 3, as well as Clean + Thermal Generation Portfolios including DSM Option 3. As discussed in Section of the EIS as amended, higher levels of DSM as represented by Options 4 and 5 are not considered to be viable resources due to, among other things, the significant level of uncertainty associated with achieving these levels of DSM. b) Summary of Issue: Load growth / use of mid-load forecast: BC Hydro should analyze the possibility of load growth being lower than anticipated, and reconsider whether planning should be based exclusively on the mid-load forecast. The use of low-load scenarios by other jurisdictions should be considered. A single forecast should not be relied upon given the possibility that actual load could be lower than expected. Summary of BC Hydro Response: BC Hydro plans to a mid-level forecast, which represents the expected future load, in which actual realized loads will be higher than forecast 50 per cent of the time, and lower than forecast 50 per cent of the time. BC Hydro addresses this load forecast uncertainty by developing a high forecast band (with a 10 per cent exceedance probability) and a low forecast band (with a 90 per cent exceedance probability). The Evidentiary Update provides additional sensitivity analysis based on the high and low bands of forecast uncertainty (please refer to Part 4.1). This sensitivity analysis tests the cost-effectiveness of the Project for performance in different scenarios that take into account the probability of the gap being smaller or larger than expected. Page 55

59 Evidentiary Update September 13, 2013 The sensitivity analysis undertaken by BC Hydro addresses the concern that high and low scenarios be examined.bc Hydro does not, however, plan to either the high or low scenarios. Planning to the low scenario would result in insufficient resources to meet the electricity needs of customers. The sensitivity analysis conducted against the high and low gap scenarios results in a present value advantage for the Project as compared to viable alternatives, except the low probability small gap scenario. BC Hydro can also advise that BC Hydro s review of public utilities in the Western Electricity Coordinating Council (WECC) found no public utilities that plan resource acquisitions based on a low load forecast scenario. c) Summary of Issue: Portfolio analysis methodology / alternatives to the Project: BC Hydro s portfolio analysis of alternatives to the Project should consider that other resource options would not necessarily produce the same surplus as the Project. This would allow the analysis to better account for low market price forecasts as they relate to the sale of surplus energy. Summary of BC Hydro Response: As discussed in Part of the Evidentiary Update, in addition to the block analysis referred to in the issue above (which looks at comparable blocks of energy and capacity to that which would be provided by the Project), alternatives to the Project are also explored through a portfolio modelling approach. Portfolio modelling is a more sophisticated approach that selects optimal combinations of resources over a 30-year planning horizon considering both capital and operating costs under different assumptions and constraints. Portfolio modelling provides additional information not captured by the block analysis, including: Timing of resource additions and associated capital expenditures Effects of resource additions to the overall system and the system load resource balance over the planning horizon Expected operating costs and economic dispatches reflecting the manner in which the resources will be operated Page 56

60 Evidentiary Update September 13, 2013 Electricity market trade benefits that vary with the flexibility of the overall portfolio The portfolio modelling approach used by BC Hydro addresses the issues raised, because it accounts for the lumpiness of resources. It models the timing of resources and the net cost of energy imbalances by comparing the cost of resource alternatives to value in the electricity markets. The amount of energy produced differs depending on the portfolio. As such, the Clean and Clean + Thermal portfolios are not constructed to produce the same surplus as the Project does. The portfolio modelling approach also captures economic benefits associated with dispatchable resources like the Project and natural gas-fired generation. Dispatchability provides significant value for BC Hydro customers and is a point of differentiation from intermittent resources such as wind and run-of-river. d) Summary of Issue: Treatment of Liquefied Natural Gas (LNG): BC Hydro should not justify the need for the Project based on load from LNG development, because there is uncertainty associated with the development of these facilities, and, if built, they are likely to generate their own electricity using natural gas. Summary of BC Hydro Response: The EIS as amended and the Evidentiary Update both review the need for the Project with respect to scenarios that do not include any load associated with new LNG facilities. The EIS as amended and the Evidentiary Update also review the potential for LNG load in the context of the Project as part of the discussion on potential uncertainty in the LRB. This analysis of need for the Project shows that the electricity that the Project would generate is required whether or not LNG facilities require power from BC Hydro. The addition of load from LNG facilities into the analysis would increase the benefits of the portfolios including the Project. To address the interest in the load associated with LNG, the Evidentiary Update provides additional information regarding potential LNG load in the discussion of LRBs with LNG in Part 0 of the Evidentiary Update. Page 57

61 Evidentiary Update September 13, 2013 e) Summary of Issue: Assessing climate change impacts on energy capability of heritage resources BC Hydro should not assume that historic flows are representative of the range of inflows that may occur in the future, because inflows in the Williston Basin are projected to increase. The assessment of the need for the Project should take into account the potential for energy production to increase from BC Hydro s existing resources due to the higher levels of inflows. Summary of BC Hydro Response: The Evidentiary Update provides a discussion of the potential impact of climate change on BC Hydro s long-term planning process as supplemental information to Part 2 of the Evidentiary Update. This section discusses a paper provided as part of the IRP, titled Hydrologic Impacts of Climate Change. The paper reviews climate changes for several BC Hydro watersheds, including the Williston basin. Based on the paper, BC Hydro concludes that, while a modest increase in water availability is likely for BC Hydro s hydroelectric system, it does not mean that BC Hydro should plan on increases to the expected output from its system. From a resource planning perspective, resource reliance is based upon observable inflow data and not what may be expected to happen 30 to 50 years into the future. f) Summary of Issue: Market pricing / exchange rate sensitivity analysis BC Hydro must acknowledge uncertainty related to exchange rates and/or external markets in order for the portfolio analysis to be valid. Exchange rate uncertainty is an important consideration, since revenues associated with the sale of surplus energy are assumed in the analysis used for the Project. Summary of BC Hydro Response: The Evidentiary Update provides additional sensitivity analysis with respect to different market price scenarios in Part 4.3 of the Evidentiary Update. This analysis tests the cost- Page 58

62 Evidentiary Update September 13, 2013 effectiveness of the Project against the two additional market scenarios representing high and low electricity spot market price scenarios. The main impact of exchange rates on the portfolio analysis is through its effect on market prices as a result the market scenarios explored in the sensitivity analysis are broad enough to cover exchange rate fluctuations. In the high market and mid (base) market scenarios, the Project maintains its present value advantage as compared to viable alternatives. The only exception is the low-probability, low market scenario, in which case the Project with a F2024 ISD is still more cost competitive than the Clean Generation Portfolio without the Project but is marginally less cost competitive than the Clean + Thermal Generation Portfolio without the Project. The Project remains more cost competitive than both the Clean Generation and Clean + Thermal Generation portfolios with a F2026 ISD. However, it is important to emphasize that this low market scenario case, at a 20 per cent probability, has a much lower likelihood of occurring than the current planning scenario. Page 59

63 Evidentiary Update September 13, 2013 Appendix B Associated updates to Sections and of the EIS as amended Capacity Capacity represents the instantaneous power output of a generating facility at any given time. As described in Volume 1 Section 5.2, BC Hydro plans its system to ensure that there is sufficient dependable capacity to meet customer needs, which represents the maximum generation output that can be reliably supplied coincident with system peak load, taking into account the physical state and availability of the equipment and water or fuel constraints. The Utilities Commission Act service obligation discussed in Volume 1 Section 5.2 means that BC Hydro must make sure customer demand is met at the peak load every day. The dependable capacity of the Project is established as part of the project design. The dependable capacity of the Project is 1,100 MW, as discussed in Section in Volume 1 Section 4 Project Description. As described in Volume 1 Section 5.2, after BC Hydro implements Revelstoke Unit 6, there are limited dependable capacity resource options available to BC Hydro. Proceeding with the Project avoids dependable capacity resources such as natural gas-fired SCGTs and/or pumped storage facilities. Therefore, the long-term value of the Project s dependable capacity is the avoided cost of a combination of Revelstoke Unit 6 (with a unit capacity cost of $50/kW-year), GMS Units 1-5 (with a unit capacity cost of $35/kW-year), and either a SCGT (within the 93% Clean Energy Act clean or renewable target) and/or pumped storage, which have unit capacity costs of between $89100/kW-year up to $440630/kW-year (refer to Table 5.38, Volume 1 Section 5). These capacity costs are reflected in the value of the avoided costs of energy presented in Section below Energy Energy represents the cumulative amount of electricity produced or consumed over a specific period of time. For the Project, the amount of energy that can be produced is driven by the water inflows into the proposed Project reservoir from the Peace Canyon generating station and from local tributaries. To determine the average annual energy produced by the Project, BC Hydro modeled the BC Hydro generation and transmission system in HYSIM for 60 different water inflow scenarios, for portfolios (as defined in Volume 1 Section 5 Need for, Purpose of, and Alternatives to the Project) with the Project and without the Project. (Please see Volume 2 Section 11.4 Surface Water Regime for a more detailed discussion of the HYSIM model.)the difference between the annual energy in these two portfolios represents the energy contributed to the system by the Project. Variability in weather conditions (most importantly, variability in precipitation amounts) will result in variability in the energy contributed by the Project from year to year. To quantify this variability in annual generation, the HYSIM analysis (Volume 2 Section 11.4 Surface Water Regime) calculated the energy contribution across the range of 60 water inflow scenarios. Table 7.1shows the average annual energy contributed by the Project, as well as the firm Page 60

64 Evidentiary Update September 13, 2013 energy, which represents the average energy contributed in the worst three-year sequence of inflows out of the 60 water inflow scenarios. Table 7.1 Annual Energy Contribution of the Project Annual Energy Contribution Average annual energy: Average annual energy contribution across all modelled inflow scenarios Firm energy: Average annual energy contribution in worst three-year sequence of inflows GWh 5,100 4,700 The timing of this energy generation throughout the year is also a key benefit to BC Hydro ratepayers, as generation can be timed to match customer demand. See Section for further discussion. Proceeding with the Project avoids higher cost clean or renewable intermittent resources (referred to as Available Resources in Volume 1 Section 5). The long-term value of the Project s 5,100 GWh/year of average energy is based on the avoided cost of alternative resources, and falls into the following range ($F2013): $135/MWh ($F2013), which is the adjusted weighted average price resulting from the most recent, broadly-based BC Hydro energy acquisition process, the Clean Power Call (about 3,000 GWh/year of firm energy) $ /MWh ($F2013), which is the adjusted weighted average price of the clean energy resources that make up the portfolios shown in Table 5.42, Volume 1 Section 5, based on pricing from the 2010 Resource Options Report Page 61

65 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project NEED FOR, PURPOSE OF, AND ALTERNATIVES TO THE PROJECT 5.1 Introduction This section describes the need for, purpose of, and alternatives to the Project. The need for establishes the fundamental justification or rationale for the Project. The purpose of is defined as what is to be achieved by carrying out the Project. The alternatives to are the functionally different ways to meet the Project need. The alternative means of carrying out the Project are considered in Volume 1 Section 6 Alternative Means of Carrying Out the Project. The definitions of need for, purpose of and alternatives to, and the following discussions, are consistent with the Agency s Policy Statement Addressing the Need for, Purpose of, Alternatives to and Alternative Means under the Canadian Environmental Assessment Act (Agency Need/Alternatives Operational Policy Statement). In particular, the need for and the purpose of the Project are established from the perspective of BC Hydro and provide the context for consideration of alternatives. This section reviews both demand side management (DSM) and supply-side resources in the context of both need for and alternatives to the Project: The need for the Project is established using two reliability requirements firm energy and dependable capacity: o o o o Energy is the amount of electricity required over a period of time, measured in gigawatt hours per year (GWh/year) Peak demand, which is the maximum hourly demand on BC Hydro s system, is measured in megawatts (MW) and is met with dependable capacity. Securing dependable capacity resources to address future dependable capacity needs described in this section is becoming more of a challenge. Over the last seven years, BC Hydro purchased large quantities of intermittent clean or renewable energy resources such as run-of-river and wind that have minimal dependable capacity. Intermittent resources are not dispatchable that is, their electricity output cannot be controlled to respond to variations in customer demand. Intermittent clean or renewable resources require dependable capacity backup resources. To address growth in the demand for dependable capacity in recent years, BC Hydro has benefited from being able to install additional generating units at each of its two Heritage hydroelectric facilities (Mica and Revelstoke Generating Stations). With one of these generating units now in operation (Revelstoke Unit 5), two more under construction (Mica Units 5 and 6) and the fourth (Revelstoke Unit 6) included in this EIS with an earliest in-service date of F2019, these additional capacity resources will be exhausted. (All year marks in this section are stated in fiscal years (F20XX) ending March 31, except where otherwise noted.) There are limited dependable capacity resource options available to BC Hydro after implementation of Revelstoke Unit 6, and this is 5-1

66 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project compounded by increased system reliance on non-dispatchable intermittent clean or renewable energy resources. There are two broad categories of potential alternatives to the Project. Demand-side management consists of measures such as conserving energy, promoting energy efficiency, and shifting the use of energy to periods of lower demand that BC Hydro can take to reduce the customer demand that BC Hydro must serve. Supply-side resources are electricity generating facility resources that are consistent with the objectives of the B.C. Government, including those specified in the B.C. Clean Energy Act (S.B.C., 2010, c.22). The remainder of this section is structured as follows: Section 5.2 sets out the need for the Project. The Project addresses BC Hydro s need for firm energy and dependable capacity within the context of meeting the self-sufficiency requirement set out in Subsection 6(2)(a) of the Clean Energy Act. To determine the need for the Project, BC Hydro s energy and capacity load-resource balances (LRBs) are analyzed for the BC Hydro integrated system, taking into account the current level of DSM targeted by BC Hydro. The result is a gap that must be filled with supply-side resources. Section 5.3 outlines the purpose of the Project. In addition to meeting BC Hydro s need for firm energy and dependable capacity, the Project advances and aligns with the B.C. Government s objectives set out in the Clean Energy Act and in its 2007 Energy Plan (provided in Volume 1 Appendix D Need for and Alternatives to the Project Supporting Documentation, Part 1). Sections 5.4 and 5.5 examine the potential alternatives to the Project: o Section 5.4 describes the process for identifying and reviewing potential alternatives to the Project. Section 5.4 also surveys the potential alternatives that were screened out on the basis that they are not viable (defined as meaning not practicable or not capable of being implemented) because 1) in the case of certain supply-side resources, they are not permitted by or are inconsistent with B.C. Government legal requirements, or are not technically or economically feasible, and 2) in the case of increased DSM levels, cannot reasonably be relied on because of delivery risk. o Section 5.5 characterizes the remaining available supply-side resources which, when combined into portfolios, are viable alternatives to the Project. Section describes the major financial, technical, environmental, and economic development attributes applied to the available supply-side resources. Section presents a qualitative assessment of the available supply-side resources. Section sets out the portfolio analysis parameters, while Section compares the available supply-side resources through portfolio and other analysis. In Section 5.5.5, BC Hydro concludes that the Project is the preferred alternative to meet the need identified in Section 5.2, based on the review of the financial, technical, environmental, and economic development attributes, and taking into account B.C. Government legal and policy requirements. 5-2

67 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Need for the Project The Environmental Impact Statement (EIS) Guidelines provide that the EIS will set out the fundamental rationale for proceeding with the development of the Project at this time within the relevant legal and policy context. The need for the Project is to address future customer demand (sometimes referred to as load in this EIS; load and demand are used interchangeably) for firm energy and dependable capacity in BC Hydro s service area. The Project would provide long-term generation services for more than 100 years. This section of the EIS contains a description of methodologies, assumptions, and conclusions used in the need for the Project analysis through an evaluation of the following: Current and forecasted BC Hydro customer demand Existing and committed supply-side resources The BC Hydro demand-side management target To begin this discussion, it is important to underscore BC Hydro s obligation to serve its customers in accordance with standards established by the British Columbia Utilities Commission (BCUC) pursuant to a number of sections in the B.C. Utilities Commission Act (R.S.B.C., 1996, c.473), including Sections 25, 28, 29, and 30. This service obligation drives BC Hydro s long-term resource planning process. The long-term view is required, as most new resources require significant lead times to obtain approvals and build. All electric utilities like BC Hydro must plan ahead to be sure that the required resources will be in place when needed by customers. As a business planning tool, BC Hydro s long-term resource planning process supports informed decision-making on resource acquisition by providing an analytical framework for assessing resource investment trade-offs: The first step in the analytical framework is for BC Hydro to forecast its future electricity demand requirements. As with any potential resource available to BC Hydro, energy and capacity LRBs are analyzed for the BC Hydro integrated system to determine the need for the Project s generating capability. A load-resource balance is the difference between BC Hydro s Load Forecast which projects BC Hydro customer load over a 20-year period and the supply from existing and committed resources. There is a gap if forecasted customer load exceeds the supply available to serve such load. The analytical framework is then used to evaluate different solutions for filling the load-resource gap. BC Hydro employs this analytical framework in this section to assess the Project and potential alternatives. BC Hydro continues to face considerable uncertainty in its long-term resource planning environment, including: Load growth and the risk that load growth exceeds or falls below expectations DSM delivery risk the risk that the response to DSM is less than planned or required Supply-side development uncertainty, including the type and location of resources supplied to BC Hydro, and the risk that the type and location of resources require 5-3

68 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project significant dependable capacity (for example, for intermittent clean or renewable resources such as wind) and transmission support These uncertainties and the +20-year planning time frame underscore the need to de-emphasize single point estimates for forecasting load and the load-resource balance; rather, uncertainties with load forecasting and the capabilities of existing supply-side resources and DSM can be translated into a range of future resource requirements. The key uncertainties in load growth and resource delivery are discussed in Section The remainder of this section is organized as follows: Section reviews the assumptions underlying the two inputs to the energy and capacity LRBs: 1) BC Hydro s most recent (2012) Load Forecast, and 2) BC Hydro s existing and committed resources. In addition, the legal requirement for BC Hydro to achieve electricity self-sufficiency by 2016 and each year after, pursuant to Subsection 6(2)(a) of the Clean Energy Act is explained. In Section 5.2.2, the resulting energy and capacity LRBs are provided. First, the LRBs are shown without the current BC Hydro DSM target. Second, the LRBs are depicted with the DSM target and Revelstoke Unit 6, as this is a project that BC Hydro proposes to undertake in advance of the Project, due to the need for dependable capacity. It is this second set of LRBs that provides the basis for demonstrating the need for the Project and sets the context for potential alternatives to the Project. BC Hydro summarizes some loads and LRBs with respect to the following years: F2017, F2022, F2026, and F2031. All values shown include electricity losses from the transmission and distribution systems, unless otherwise stated. Section summarizes the risks and uncertainties with respect to the LRBs, focusing on the Load Forecast and delivery of anticipated DSM savings. Some of these such as potential large and uncertain loads from liquefied natural gas (LNG) and mining, or lower than anticipated levels of DSM savings would result in a larger LRB gap, while others, such as lower commodity prices, would result in a smaller LRB gap. Section also describes BC Hydro s Contingency Resource Plan to address dependable capacity shortfall risks. Section contains BC Hydro s conclusions with respect to the need for the Project Load-Resource Balance Assumptions This section explores the energy and capacity LRBs by first reviewing the 2012 Load Forecast in Section , and then examining existing and committed resources in Section The resulting energy and capacity LRBs are presented in Section Throughout Section 5.2 and Section 5.3, capacity MW values have been rounded to the nearest 50 MW and energy GWh values have been rounded to the nearest 100 GWh BC Hydro s 2012 Load Forecast Load is the amount of electricity required by a BC Hydro customer or group of customers. This section presents BC Hydro s 2012 Load Forecast of energy and peak (capacity) load requirements for the BC Hydro integrated system. Some of BC Hydro s customers live in areas too remote to be served by the integrated system. Local 5-4

69 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project generation serves these non-integrated communities. Unless otherwise indicated, this EIS does not address the non-integrated areas. On an annual basis, BC Hydro prepares 20-year load forecasts for both energy and peak demand. The energy forecast represents the forecasted total annual electricity demand for the integrated system and the peak forecast represents the one-hour maximum demand on the integrated system. The 2012 Load Forecast has been prepared in accordance with the BCUC s Resource Planning Guidelines (copy in Volume 1 Appendix D Need for and Alternatives to the Project Supporting Documentation, Part 2), using the same methodological approach for the mid-forecast accepted by the BCUC in long-term resource plan proceedings, including a sector-by-sector analysis of load. The 2012 Load Forecast incorporates the most current third-party economic indicators available to be incorporated, including gross domestic product (GDP) forecasts from the B.C. Ministry of Finance, external economic consultants and customer-by-customer information included in the industrial customer forecast. Use of Mid-Load Forecast The values discussed in this EIS reflect BC Hydro s mid-load forecast for both energy and peak demand. The mid-load forecast represents the expected future load, in which actual realized loads will be higher than forecast 50% of the time, and lower than forecast 50% of the time. The EIS is based on BC Hydro s mid-load forecast because: The B.C. Electricity Self-Sufficiency Regulation (B.C. Reg. 315/2010) enacted under the Clean Energy Act prescribes the mid-load forecast as the forecast to be used for the purpose of determining the self-sufficiency requirement The mid-load forecast is the forecast that BC Hydro uses to determine the need for capital projects, both internally and in applications to the BCUC. The BCUC endorsed the use of the mid-load forecast for purposes of determining need in its 2008 Long-Term Acquisition Plan Decision (BCUC Order G-91-09, Reasons for Decision, page 54 and Directive 6). Use of the mid-load forecast is consistent with other public electric utilities Liquefied Natural Gas Load The 2012 mid-load forecast presented in this section does not include potential LNG load, which is discussed in Section Energy and Peak (Capacity) Load Forecasts The 2012 Load Forecast reflects the impact of savings from DSM (i.e., energy efficiency and conservation) initiatives achieved through F2012, but does not include future targeted savings in F2013 and beyond. DSM targeted savings for F2013 and beyond are described in Section Table 5.1 and Table 5.2 present the 2012 Load Forecast energy and peak demand requirements before anticipated DSM savings (resulting from DSM initiatives after F2012) without potential LNG load. 5-5

70 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project 1 Table 5.1 Mid-Energy Load Forecast Before DSM (GWh) F2017 F2022 F2026 F2031 Mid-energy Load Forecast (No LNG) Average Annual Growth Rate F F ,200 70,800 73,800 78, % 1.7% 2 Table 5.2 Mid-Peak Demand Load Forecast Before DSM (MW) F2017 F2022 F2026 F2031 Mid-peak Load Forecast (No LNG) Energy Load Forecast Components and Drivers Average Annual Growth Rate F F ,700 12,750 13,450 14, % 1.8% The three main components of the energy load forecast, each of which has its own primary drivers, are as follows. (Note that other small categories of load not included in residential, commercial, or industrial such as sales to other electric utilities such as FortisBC Inc. provide the balance of the total load forecast.) Residential: BC Hydro s residential sector currently consumes about 35% of BC Hydro s total sales. Sales to the residential sector are weather sensitive, primarily to winter heating demand, and can fluctuate significantly year to year. The drivers of the residential forecast are the average annual use of electricity per account and the number of accounts, which is driven by population growth and housing starts. The average use per account is developed using an end use model that includes economic drivers such as disposable income, people per account, and efficiency trends for the primary residential end uses of electricity. BC Hydro s long-term forecast of housing starts is expected to be on average about 26,000 units per year, a reduction over pre-recession levels. In addition, trends in residential electricity use per account have been slowing. This is due to several factors that include recent slower economic growth, the effects of conservation, BC Hydro s electricity rate changes, and an increasingly efficient appliance fleet. The average use per account is expected to grow slowly at less than 1% per year. This reflects a number of factors, including housing sizes and types, the demand for electronic, entertainment, and telecommunication devices in the home, and general improvements in the energy efficiency of major electrical appliances. With the current forecasts of housing starts and residential end use rate, the overall sales to the residential sector before DSM are expected to grow by about 1.8%, 2.0%, and 1.9% over the next five, 10, and 20 years, respectively. Commercial: BC Hydro s commercial sector currently consumes about 31% of its total sales. The electricity consumption of the commercial sector can vary considerably from year to year, reflecting the level of activity in B.C. s service sector. The commercial sector is made up of two categories: commercial distribution (94% of the total commercial sales) and commercial transmission (6% of total commercial sales). 5-6

71 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project The forecast of commercial distribution sales is developed with an end use model. The drivers of the forecast include average commercial end use efficiencies trends and projections of retail sales, employment, and commercial output. Sales to the commercial distribution sector before DSM are expected to grow by about 2.0%, 1.9%, and 1.8% over the next five, 10, and 20 years, respectively. This growth reflects relatively stable provincial economic growth and no significant changes in average commercial end use efficiency. The overall commercial distribution load has been revised downwards since the onset of the recent recession, consistent with the lower projections of economic drivers. Slower economic growth projections for the U.S. and global economies impact tourism and retail spending in B.C. Sales to larger commercial customers such as ports and pipelines are projected to grow over the first five years of the forecast; after these expansions are completed, commercial sales are expected to remain relatively stable. Industrial: BC Hydro s industrial sector currently represents about 32% of its total sales. The industrial sector is made up of customers served at distribution voltages (20% of total industrial sales) and those served at transmission voltages (80% of total industrial sales, at voltage of over 69 kilovolts). BC Hydro prepares its industrial transmission load forecast on a customer-by-customer basis, considering the sector-specific issues that customers in each sector face. A projection for industrial distribution sales is developed for key sectors, including forestry (including pulp and paper), mining (coal), and oil and gas. The remaining industrial distribution sales are developed using an econometric model and provincial GDP growth as a load driver. Industrial demand has been the most variable historically, and it is the most challenging to forecast due to sensitivity to factors such as global commodity markets and economic conditions in the U.S. and Asia. Excluding LNG, the industrial sub-sectors include the following: 1. Forestry (pulp and paper, and wood products): Historically, this has been the largest industrial sector in terms of electricity sales, accounting for about 60% on average of total industrial sales. With external experts, BC Hydro prepares a market analysis and a production outlook for each of BC Hydro s pulp and paper and wood products customers. This includes production forecasts for the key commodities that the facilities produce such as pulp, various paper grades, and various wood products. A market analysis of Asian and U.S. demand and the status of the mountain pine beetle effects on wood supply are also reflected in the forecast. Sales to the forestry sector before DSM are expected to shrink by about 2.4%, 1.2%, and 0.6% over the next five, 10, and 20 years, respectively. This reflects lower mechanical pulp and related paper production forecast, attrition in some sawmills due to the wood supply situation, and the continuing trend to digital media substitution away from print media. 2. Oil and Gas: Currently, oil and gas sales are less than 10% of total industrial sales, but this is expected to increase. BC Hydro prepares natural gas production forecasts for the key B.C. production basins based on a variety of expert forecasts. BC Hydro also uses the B.C. Oil and Gas Commission s production and drilling information to monitor natural gas historical production and possible future trends. Deferred drilling and natural gas processing due to current low natural gas prices have reduced expected growth in sales in the near term. Preferential drilling for higher value oil and liquids, and potential growth in B.C. s supply of LNG to Asian markets are the key drivers of future load growth. The province is seen to have substantial gas development potential, particularly in the Montney (Dawson Creek to Chetwynd) 5-7

72 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project region. Sales to the oil and gas sector before DSM are expected to grow by about 19.0%, 14.3%, and 7.5% over the next five, 10, and 20 years, respectively. 3. Mining: The mining forecast is developed on an account-by-account basis using external expert advice and development plans obtained from current and prospective customers. BC Hydro also considers price forecasts for the key sector products (copper, gold, molybdenum, and coal) and the current status of environmental permitting. The forecast considers the likelihood that new mines will be completed and that existing mines will proceed with expansion plans. The 2012 mining sector forecast is lower relative to recent vintages of forecasts, due to lower price expectations for metals and coal, recent environmental decisions, and generally tighter capital markets. The outlook for mine completions in BC Hydro s forecast have been reduced and expected start dates for several new mines have been deferred. Despite a lower forecast compared to previous years, mining is expected to be one of the strongest load growth areas. This is due to announced expansions at existing mines, along with new projects that have already begun construction. Sales to the mining sector before DSM are expected to grow by about 11.8%, 7.1%, and 2.8% over the next five, 10, and 20 years, respectively. The breakdown of BC Hydro s mid-energy load forecast by sector and for the total BC Hydro integrated system is set out in Table Table 5.3 Sector Breakdown of Mid-Energy Load Forecast Before DSM (Without Losses) Energy Load (GWh/year) F2017 F2022 F2026 F2031 Average Annual Growth Rate F F Residential 19,800 21,900 23,600 25, % 1.9% Commercial 17,800 20,100 21,300 23, % 2.1% Industrial (without LNG) 19,000 21,200 20,800 21, % 1.4% Total domestic sales including 57,600 64,500 67,200 71, % 1.8% sales to other utilities a (No LNG) NOTE: a FortisBC Inc. and City of New Westminster Peak Load Forecast Components and Drivers BC Hydro creates a 20-year peak load forecast. BC Hydro s peak demand typically occurs on a cold day in December or January, driven by electric heating demand. The primary drivers of the distribution component include housing starts and economic drivers such as retail sales, employment, and GDP. The transmission component of the peak load forecast is built up on an account-by-account basis at the same time that the industrial transmission customer forecast is created for the energy forecast described previously. Additional considerations in generating the peak forecast include planned facility expansions, and industry trends and growth in demand for B.C. exports of commodities. The peak demand forecast generally follows the trends in the energy forecast. In the near term, the growth in distribution peak loads in the 2012 Load Forecast is slower relative to recent projections, due to a lower residential customer accounts projection 5-8

73 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project and somewhat lower expectations of economic growth. The growth in the transmission peak demand forecast is slower, due to mining deferrals and reduced demand for pulp and paper customers Existing and Committed Supply-Side Resources The other major input to the energy and capacity LRBs is the existing and committed supply-side resources that serve the BC Hydro integrated system: Existing supply-side resources include BC Hydro s Heritage hydroelectric and thermal (natural gas-fired) generating resources, as well as independent power producer (IPP) facilities delivering electricity to BC Hydro. Committed supply-side resources are: o Resources for which material regulatory approvals have been secured (BCUC, either secured or through exemption, and environmental assessment related), if required, and for which the BC Hydro Board of Directors has authorized implementation. Examples are Mica Units 5 and 6. o Resources that BC Hydro is currently pursuing, e.g., resources for which the BC Hydro Board of Directors implementation approval has been secured, but for which BC Hydro has not yet authorized individual contracts, called electricity purchase agreements (EPAs). An example is BC Hydro s Standing Offer Program. The existing and committed supply-side resources are grouped into three categories: BC Hydro heritage hydroelectric resources, BC Hydro heritage thermal resources, and EPAs with IPPs and other third-party suppliers. The following sections provide further information on the supply resource-related assumptions. The energy capability and dependable capacity of the resources are summarized in Tables 5.4 and 5.5. Heritage Hydroelectric Resources BC Hydro s most significant existing supply-side resource is its heritage hydroelectric system. BC Hydro s 30 existing hydroelectric facilities are located throughout the Peace, Columbia, and Coastal regions of B.C. BC Hydro's heritage assets are identified in Schedule 1 of the Clean Energy Act. Resource Smart is a BC Hydro program that promotes the identification, study, and implementation of projects that provide cost-effective energy and capacity gains at existing BC Hydro facilities. Committed Resource Smart projects such as Mica Units 5 and 6, and the Ruskin Dam and Powerhouse Upgrade Project are included in the heritage hydroelectric energy capability and dependable capacity values set out in Tables 5.4 and 5.5. The Electricity Self-Sufficiency Regulation provides that the water conditions prescribed for purposes of the Heritage hydroelectric capability are average water conditions. Water conditions refers to how much water BC Hydro has in its reservoirs, and average water conditions refers to the mean output of the BC Hydro Heritage hydroelectric resources over the 60-year recorded period of stream flows between October 1940 and September The energy LRBs in this EIS are based on firm energy capability for the heritage hydroelectric resources, this capability is defined under average water conditions; for all non-heritage hydroelectric resources, like run-of-river hydro, BC Hydro uses critical water conditions (the most adverse sequence of stream flows occurring within the same 60-year period). 5-9

74 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Heritage Thermal Resources BC Hydro s Burrard Thermal (Burrard) and Prince Rupert Generating Stations are the only two BC Hydro-owned thermal generating stations that serve the integrated system. Burrard is a natural gas-fired generating facility located in the Lower Mainland of B.C. For purposes of the LRBs: Pursuant to Subsections 3(5), 6(2)(d) and 13 of the Clean Energy Act, Burrard s firm energy contribution is zero GWh/year Pursuant to Section 2 of the Burrard Thermal Electricity Regulation (B.C. Reg. 319/2010), Burrard s dependable capacity of 900 MW will be phased out as Mica Units 5 and 6, the Interior to Lower Mainland Transmission Reinforcement Project, and the third transformer at the Meridian Substation are introduced into service Existing and Committed IPP Supply BC Hydro is forecast to have the rights to approximately 14,200 GWh/year and 1,400 MW of energy and capacity in F2022 through about 120 currently active EPAs with IPPs, after taking into account forecast attrition (attrition relates to the possibility that some of the IPP projects for which EPAs have been awarded will not proceed). IPP attrition is discussed in Section below. BC Hydro used Effective Load Carrying Capability (ELCC) to represent the capacity contribution from intermittent clean or renewable IPP resources such as wind and run-of-river resources in Table 5.5 below, and the capacity LRBs in Tables 5.7 and 5.9. The ELCC method for evaluating wind and run-of-river capability uses a probabilistic approach that is sensitive to wind and run-of-river availability, rather than relying on a deterministic value for available dependable capacity. The ELCC contribution to the system is largely drawn from BC Hydro s large and reliable hydroelectric system. The ELCC method may overstate the capacity contribution of these intermittent clean or renewable resources. The incremental ELCC contributions of intermittent clean or renewable resources will decrease as more of these intermittent resources come into service. Summary A summary of the energy and dependable capacity of existing and committed supply-side resources is set out in Table 5.4 and Table 5.5 respectively. 33 Table 5.4 Energy Capability in F2022 Gigawatt Hours (GWh) Existing and Committed Supply F2022 Heritage hydroelectric (a) 48,500 Heritage thermal (Prince Rupert) (b) 200 Existing and committed IPP supply (c) 14,200 Total supply (d) = a + b + c 62,

75 1 Table 5.5 Dependable Capacity in F2022 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Megawatts (MW) F2022 Heritage hydroelectric (a) 11,400 Heritage thermal (Prince Rupert) (b) 50 Existing and committed IPP supply (c) 1,200 Reserves a Supply requiring reserves (d) = a + b + c 12,700 14% of supply requiring reserves (e) = d * ,800 Supply not requiring reserves Alcan 2007 EPA (f) 150 Total supply (g) = d e + f 11,100 NOTE: a System generating capacity beyond that required to meet peak demand, ensuring sufficient generation is available if some generating units are not available; necessary to meet reliability criteria for planning and operation Load-Resource Balances The purpose of the LRBs is to define the future need for resources by comparing the annual mid-load forecast with the annual capability of BC Hydro s existing and committed supply-side resources. This is done with respect to two views of the system the energy balance and the capacity balance. There are two steps to analyzing the LRBs: First, in Section , the LRBs are depicted without future DSM or Revelstoke Unit 6. Bracketed numbers indicate a surplus, while unbracketed numbers indicate a gap. Thus, there is a need for energy in F2017 (Table 5.6) and a need for dependable capacity in F2016 (Table 5.7). Second, in Section BC Hydro s current DSM target is described, and the LRBs are presented with the DSM target and Revelstoke Unit 6 in Tables 5.8 and Load-Resource Balances Without Demand-Side Management Target and Revelstoke Unit 6 16 Table 5.6 Energy Deficit/Surplus (GWh) (No LNG) Year LRB without DSM F2012 (1,100) F2013 (4,000) F2014 (2,000) F2015 (2,400) F2016 (800) F F2018 2,300 F2019 4,300 F2020 5,

76 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Year LRB without DSM F2021 6,400 F2022 7,200 F2023 8,200 F2024 9,100 F2025 9,900 F ,400 F ,000 F ,100 F ,000 F ,000 F ,000 1 Table 5.7 Capacity Deficit/Surplus (MW) (No LNG) Year LRB without DSM F2012 (800) F2013 (850) F2014 (550) F2015 (250) F F F F2019 1,150 F2020 1,300 F2021 1,500 F2022 1,650 F2023 1,850 F2024 2,000 F2025 2,200 F2026 2,350 F2027 2,500 F2028 2,700 F2029 2,950 F2030 3,200 F2031 3, Load-Resource Balances with Demand-Side Management Target and Revelstoke Unit 6 Demand-Side Management Target DSM is a major element in BC Hydro s long-term resource plan to fill the load-resource gap. Section 1 of the Clean Energy Act defines DSM (referred to as demand-side measures in the Clean Energy Act) to mean: a rate, measure, action or program undertaken (a) to conserve energy or promote energy efficiency; (b) to reduce the energy 5-12

77 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project demand a public utility must serve; or (c) to shift the use of energy to periods of lower demand but does not include (d) a rate, measure, action or program the main purpose of which is to encourage a switch from the use of one kind of energy to another such that the switch would increase greenhouse gas emissions in British Columbia, or (e) any rate, measure, action or program prescribed. Demand-Side Management Tools The DSM target consists of expected savings from the following three main tools: Codes and standards are public policy instruments enacted by governments such as building codes, energy efficiency regulations, tax measures, and local government zoning and building permitting processes to influence energy efficiency. The DSM target relies on both Federal and Provincial Government implementation of a suite of changes to existing codes and standards. Rate structures are aimed at conserving energy, promoting energy efficiency, or reducing the energy demand that BC Hydro must serve, such as inclining block (stepped) rate structures. BC Hydro has conservation rates in place (or with planned implementation) for over 90% of its domestic load. Over the past five years, BC Hydro implemented four conservation rate structures for residential, commercial, and industrial customers. Estimates of energy savings from rate structures is uncertain, particularly in a low electricity rate jurisdiction such as BC Hydro s service area. Programs are designed to address remaining barriers to energy efficiency and conservation after codes and standards, and rate structures, and thereby capture additional conservation potential. Programs include load displacement projects, which reduce the energy demand that BC Hydro must serve as a result of existing customers self-supplying through conservation or through customer self-generation. While BC Hydro has extensive experience working with customer groups to encourage energy conservation and efficiency, the fact that DSM programs are targeting more aggressive levels of savings and that they depend on voluntary participation makes forecasting DSM savings uncertain. Two key drivers of DSM program savings are 1) participation rate of customers for that program, and 2) energy savings per participant. In addition to these tools, there are six supporting initiatives public awareness and education, community engagement, technology innovation, codes and standards support, information technology, and indirect and portfolio enabling that provide a critical foundation for awareness, engagement, and other conditions to support the success of BC Hydro s DSM initiatives. DSM Target BC Hydro s current DSM target is 7,800 GWh/year of energy savings, with associated capacity savings of 1,400 MW, in F2021. Subsection 2(b) of the Clean Energy Act provides that it is a British Columbia s energy objective to take demand-side measures and to conserve energy, including the objective of [BC Hydro] reducing its expected increase in demand for electricity by the year 2020 by at least 66%. Based on the December 2012 mid Load Forecast, BC Hydro s current DSM target of 7,800 GWh/year exceeds the Clean Energy Act s target of at least 66% ; the current DSM target would reduce BC Hydro s forecasted demand for energy by 78% in F2021. In addition, the DSM options examined by BC Hydro that deliver both energy and capacity DSM Options 1, 3, 4 and 5 either meet the subsection 2(b) 66 per cent objective (Option 1) or exceed it (Options 3, 4 and 5). Refer to section (DSM Options 1 and 4) and section (DSM Options 4 and 5). 5-13

78 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project The DSM target is aggressive and comprehensive, as it includes a broad range of codes and standards, rate structures, and programs that provide BC Hydro customers in virtually all market segments an opportunity to participate. BC Hydro is continually reviewing the DSM target to determine if it is achievable and cost-effective. There is regulatory risk with respect to implementing the DSM target. Implementing the current BC Hydro DSM target requires a filing with the BCUC pursuant to Subsection 44.2(1)(a) of the Utilities Commission Act for a determination that the expenditures associated with the BC Hydro DSM target are in the public interest. Please refer to the discussion of DSM delivery risk in Section Revelstoke Unit 6 Revelstoke Unit 6 is a capacity Resource Smart project consisting of installing a sixth unit into the existing powerhouse at Revelstoke Generating Station. Revelstoke Unit 6 would provide 488 MW of dependable capacity but limited energy gains (about 30 GWh/year). For purposes of this EIS, BC Hydro includes Revelstoke Unit 6 in its LRBs; therefore, Revelstoke Unit 6 is not an alternative to the Project. Implementing Revelstoke 6 requires an application for an EAC pursuant to BCEAA and amendment of the Columbia River Water Use Plan. Results The energy LRB in Table 5.8 shows that, after the DSM target and Revelstoke Unit 6, there is a need for energy beginning in F Table 5.8 Energy Deficit/Surplus (GWh) with DSM Target and Revelstoke Unit 6 (No LNG) Year LRB without DSM and Rev 6 DSM Revelstoke Unit 6 LRB with DSM and Rev 6 F2012 (1,100) (2,100) F2013 (4,000) 1,200 0 (5,200) F2014 (2,000) 2,000 0 (4,000) F2015 (2,400) 3,000 0 (5,500) F2016 (800) 3,900 0 (4,700) F ,800 0 (4,700) F2018 2,300 5,700 0 (3,400) F2019 4,300 6,500 0 (2,200) F2020 5,400 7,200 0 (1,900) F2021 6,400 7,800 0 (1,400) F2022 7,200 8,200 0 (1,000) F2023 8,200 8,400 0 (200) F2024 9,100 8, F2025 9,900 9, F ,400 9, F ,000 9, ,200 F ,100 10, ,800 F ,000 10, ,400 F ,000 10, ,100 F ,000 11, ,800 The capacity LRB shown in Table 5.9 identifies a need for new dependable capacity supply in F

79 1 2 Table 5.9 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Capacity Deficit/Surplus (MW) with DSM Target and Revelstoke Unit 6 (No LNG) Year LRB without DSM and Rev 6 DSM Revelstoke Unit 6 (after Reserves) LRB with DSM and Rev 6 F2012 (800) (950) F2013 (850) (1,000) F2014 (550) (900) F2015 (250) (700) F (250) F (200) F (100) F2019 1,150 1, (400) F2020 1,300 1, (350) F2021 1,500 1, (250) F2022 1,650 1, (250) F2023 1,850 1, (100) F2024 2,000 1, F2025 2,200 1, F2026 2,350 1, F2027 2,500 1, F2028 2,700 1, F2029 2,950 1, F2030 3,200 2, F2031 3,400 2, Load/Resource Balance Uncertainty There are a number of uncertainties that result in risks that would have significant consequences in terms of BC Hydro being able to reliably meet its service obligation. Load Forecast Uncertainty BC Hydro s Load Forecast is sensitive to a number of variables, including economic conditions: Factors that can lead to lower load than forecast include: o An increase in the value of the Canadian dollar, which would slow commodity exports from B.C. o Reduction in growth in China and elsewhere, leading to a slowing of commodity demand and lower prices Factors that could lead to higher than forecast electrical sales include: o Strengthening world demand for commodities and strengthening business confidence, leading to increased investment in B.C. and thus increased growth and electrification. There is unprecedented load growth potential in the north of B.C., driven by mining and shale natural gas (e.g., there is up to 500 MW of mining load in the north of B.C.). 5-15

80 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project o Electrification, which is the process of switching specific end uses in the residential, commercial, transportation, and industrial sectors from utilization of fossil-based fuels to using clean or renewable electricity. BC Hydro analyzed potential electrification load such as electric plug-in vehicles and fuel choice in residential space and water heating applications, but has only included a small portion of potential electrification load in the 2012 Load Forecast. For example, the 2012 Load Forecast includes about 150 GWh/year of electric vehicle load by F2022. BC Hydro addresses load forecast uncertainty by developing high and low forecast bands. The intention of this analysis is the creation of high and low forecast bands with approximately 10% and 90% exceedance probabilities, respectively. As stated above, for planning purposes, BC Hydro uses its mid-load forecast. The high and low forecast bands are used to provide an indication of the magnitude of load uncertainty. Figure 5.1 and Figure 5.2 at the end of this section depict the 2012 mid-energy and capacity load forecasts, respectively, and the high and low uncertainty band forecasts before DSM. The uncertainty bands generated as part of the Load Forecast do include the effects of variable economic drivers such as GDP (as provided from third-party economic forecasts), but the mid-load forecast inherently assumes smoothed projections of future growth. In long-term resource planning proceedings, the BCUC agreed with BC Hydro that it is not credible to forecast the precise timing of economic boom and bust cycles. While BC Hydro has incorporated reasonably foreseeable short-term conditions in creating its forecasts, the purpose of the mid-load forecast is to predict average long-term trends in load growth, which will invariably include periods of higher and lower economic growth than the average. LNG Load British Columbia s Natural Gas Strategy and Liquefied Natural Gas Strategy (B.C. Ministry of Energy, Mines and Natural Gas 2012a, 2012b) details the B.C. Government s commitment to LNG exports and outlines the priorities that are to guide development of this new industry. To date, several LNG proponents have approached BC Hydro and/or the B.C. Government with respect to LNG projects for the B.C. north coast. For the purposes of this EIS, potential non-compression LNG demand could be between about 800 GWh/year to about 6,600 GWh/year of additional energy demand, corresponding to about 100 MW to 800 MW of additional peak demand. The energy LRB shown in Table 5.10 identifies that the upper range of this LNG load would advance the need for new energy resources from F2024 to F

81 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Table 5.10 Energy Deficit/Surplus (GWh) with DSM Target, Revelstoke Unit 6 and LNG Year LRB with DSM and Rev 6 and no LNG LRB with DSM, Rev 6 and Low LNG LRB with DSM, Rev 6 and High LNG F2012 (2,100) (2,100) (2,100) F2013 (5,200) (5,200) (5,200) F2014 (4,000) (4,000) (4,000) F2015 (5,500) (5,500) (5,500) F2016 (4,700) (4,700) (4,700) F2017 (4,700) (4,700) (4,700) F2018 (3,400) (3,400) (3,400) F2019 (2,200) (1,400) 300 F2020 (1,900) (1,000) 4,700 F2021 (1,400) (600) 5,200 F2022 (1,000) (100) 5,600 F2023 (200) 600 6,400 F ,000 6,800 F ,600 7,300 F ,600 7,300 F2027 1,200 2,000 7,700 F2028 1,800 2,700 8,400 F2029 2,400 3,300 9,000 F2030 3,100 4,000 9,700 F2031 3,800 4,600 10,400 The capacity LRB shown in Table 5.11 identifies that the upper range of the LNG load would advance the need for new capacity resources from F2025 to F

82 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Table 5.11 Capacity Deficit/Surplus (MW) with DSM Target, Revelstoke Unit 6 and LNG Year LRB with DSM and Rev 6 and No LNG LRB with DSM, Rev 6 and Low LNG LRB with DSM, Rev 6 and High LNG F2012 (950) (900) (900) F2013 (1,000) (1,000) (1,000) F2014 (900) (900) (900) F2015 (700) (700) (700) F2016 (250) (200) (200) F2017 (200) (200) (200) F2018 (100) (100) (100) F2019 (400) (300) (100) F2020 (350) (200) 500 F2021 (250) (200) 500 F2022 (250) (200) 500 F2023 (100) F F F ,000 F ,100 F ,200 F ,400 F ,600 F ,000 1,700 DSM Reliance and Delivery Risk BC Hydro is relying on the DSM target to meet a large percentage of both the energy and capacity gaps: The DSM target amounts to about 107% of the energy LRB gap in F2021, meaning the current DSM target creates an energy surplus The 1,400 MW of capacity savings in F2021 associated with the DSM target is being relied on to contribute a large portion of the capacity needs. The DSM target represents about 85% of the capacity LRB gap in F2021. At this level, the DSM target peak demand savings are more than the dependable capacity the Project would provide, or the three largest Resource Smart projects combined Mica Units 5 and 6, and Revelstoke Unit 6 (after reflecting the associated reserve requirements that would be required for supply-side resources). Precise forecasting of DSM savings for long-term planning purposes is challenging for several reasons, including: Limited BC Hydro experience with respect to targeting and achieving savings at and above the current DSM target level Model uncertainty, in particular, linking customer response to DSM actions, and forecasting the timing and efficacy of regulatory (codes and standards) changes The BC Hydro DSM target is aggressive and entails delivery risks that is, the risk that the current DSM target will not deliver the projected energy and particularly capacity 5-18

83 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project savings within the specified time frame. Ensuring an adequate capacity supply is the primary concern for BC Hydro, since capacity is required at specific times to meet peak load requirements and to maintain system security and reliability. Capacity resources also support intermittent clean or renewable generation resources that primarily supply energy so that generation is available when the loads require it. On the capacity side, a shortfall caused by missed DSM targets could undermine BC Hydro s fundamental obligation to serve its customers: The Utilities Commission Act service obligation means that BC Hydro must make sure its customers demand is met at the peak load every day The risk that DSM will not deliver the anticipated 1,400 MW of dependable capacity savings by F2021 is greater than the risk that DSM does not deliver the anticipated 7,800 GWh of energy savings by F2021. There are two sources of uncertainties regarding DSM-related capacity savings: o The underlying uncertainty around the energy savings themselves o The capacity factors used to translate energy savings into the associated level of capacity savings. These factors have additional uncertainty, due to the lack of precise knowledge about how energy savings from multiple sources would reduce peak demand. The consequence of DSM not delivering the anticipated 1,400 MW of dependable capacity savings by F2021 is greater as compared to failure to deliver the anticipated energy. Generally, external markets can be counted on for supply of energy across the year (albeit with costs), but during winter peaks there are issues with: o The illiquid (thinly traded) nature of the market for capacity o Insufficient transmission capacity o The U.S. market not having surplus to sell This is one of the reasons why BC Hydro develops contingency resource plans that can provide dependable capacity to meet its customers requirements. There are delivery risks associated with each major strategic element of the DSM target: Codes and standards are subject to Federal and/or B.C. Government approval and implementation, and may be deferred in implementation, may not apply to all equipment and buildings governments have planned, may have varying levels of minimum efficiency standards, or may depend on compliance by consumers, retailers, builders, etc. Conservation rate structures are subject to BCUC approval, and customer response to price signals is uncertain in a relatively low electricity rate jurisdiction such as BC Hydro s service area Programs rely on voluntary customer participation and the rate of savings per participant is uncertain BC Hydro developed the following ranges around the current DSM target (DSM Option 2), referred to as DSM Option 1 and DSM Option 3: In Option 1, the DSM program component is reduced to achieve about 75% of the BC Hydro DSM target. All other tactics are similar to those employed in the 5-19

84 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project BC Hydro DSM target. Option 1 is expected to deliver about 7,500 GWh/year of energy savings and 1,200 MW of dependable capacity savings by F2021. DSM Option 3 targets more electricity savings than the current BC Hydro DSM target by expanding program efforts while keeping the level of activity and savings for codes and standards, and conservation rate structures, consistent with the DSM target. Program activities are expanded with increased incentives, advertising, or technical support to address customer barriers as means of potentially increasing customer participation. As a result, program costs increase to deliver the higher volume of projects and resulting applications. DSM Option 3 is expected to deliver 9,200 GWh/year of energy and 1,400 MW of capacity in F2021. BC Hydro notes that DSM Option 3 on its own is not an alternative to the Project because, on its own, Option 3 defers the energy LRB gap by five years and does not defer the capacity LRB gap. IPP Delivery Uncertainty IPP Attrition and Price Risk and EPA Renewals IPP projects are subject to attrition, with EPAs being terminated for various reasons such as unexpected cost increases, financing obstacles, and permitting difficulties. For the most recent broadly-based BC Hydro power acquisition process, the Clean Power Call, a 30% attrition factor was assumed. The attrition rate for the F2006 Call is about 55% (excluding two coal-fired projects). There is also risk that IPP bid prices are not all in prices. IPPs periodically request EPA amendments after power acquisition processes have been completed, including uplifts to EPA prices and delays in the commercial operation date. Both the attrition rate and the request for EPA amendments show that IPPs have been hampered by unanticipated development cost increases and project delays. EPAs with IPPs and other third parties have varying durations, ranging from 15 to 40 years. BC Hydro assumes for purposes of the LRBs presented in this EIS that, with the exception of EPAs with bioenergy generation facilities, a portion of the EPAs with IPPs (about 75% of clean or renewable IPPs) will be renewed upon expiry, and that those IPP facilities will continue to provide the same amount of electricity to BC Hydro. BC Hydro assumes that about 50% of bioenergy EPAs will be renewed. In BC Hydro s view, it is not prudent to plan on the renewal of all existing and committed EPAs with biomass generation facilities, due to fuel pricing and supply risk. In the last 10 years of the planning horizon, bioenergy EPAs totalling approximately 600 GWh/year and 60 MW of firm energy and dependable capacity are set to expire. Overall, there is no assurance that 1) IPP projects will continue operations past the expiry of the EPAs, 2) that IPPs will contract with BC Hydro if they do continue to operate, or 3) that IPPs will contract at a price comparable to their current real dollar prices. All of these factors represent significant supply and price risk to BC Hydro. As noted above in Section , the ELCC method may overstate the capacity contribution of intermittent clean or renewable resources. Contingency Planning Contingency planning is done as a reliability management tool to manage the risk (consequences) of not being able to meet load. The contingency plan seeks to prepare to meet greater demand than forecast, and seeks reduce the lead time for contingency resources to be in service, if the need arises. Contingency planning is part of good utility 5-20

85 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project practice; it is also a component of long-term resource planning that is recognized as important in the BCUC s Resource Planning Guidelines. In developing its contingency plan, BC Hydro uses both capacity and energy shortfall risks summarized above. BC Hydro considers load forecast uncertainty (including LNG), DSM delivery risk and IPP delivery risk: Capacity requirements are the primary concern for BC Hydro, since capacity is required to meet peak load requirements and to maintain system security and reliability. After implementation of Revelstoke Unit 6, the capacity resources available to BC Hydro are limited to natural gas-fired generation Simple Cycle Gas Turbines (SCGTs) and/or pumped storage. The DSM target in particular creates significant uncertainty regarding the volumes of capacity that will ultimately be delivered. As described above, BC Hydro is relying on the current DSM target to deliver 1,400 MW of peak reduction (capacity savings) by F2021. BC Hydro considers additional uncertainty with respect to the reliance on ELCC for intermittent clean or renewable resources and the potential for increased IPP attrition. Uncertainty analysis indicates that the shortfalls shown in Table 5.12 below are adequate for planning purposes; however, using ELCC for intermittent clean or renewable resources and IPP attrition are risks that BC Hydro will need to continue to monitor. Refer to Table 5.12 for a description of the shortfall risks addressed by BC Hydro s Contingency Resource Plan, and to Figure 5.3 for a graphic depiction of the Contingency Resource Plan LRB. 23 Table 5.12 BC Hydro Contingency Resource Plan Shortfall Risks Risk General Load Forecast Uncertainty a DSM Delivery Risk Rationale Capacity Reduction for Contingency Planning Purposes (MW) Energy Shortfall Risk (GWh/year) F2022 F2031 F2022 F2031 Peak load and energy requirements can increase as a result of either sustained growth or low temperatures at winter peak 1,100 1,450 8,200 9,800 The BC Hydro DSM target has a significant range of delivery risk where the variability is driven by implementation of codes and standards, customer response to programs and rates ,700 3,500 NOTE: a LNG load could add approximately 6,600 GWh/year and 800 MW to the amounts shown As discussed in Section below, if BC Hydro were to choose natural gas-fired generation such as SCGTs in lieu of the Project, it would deprive itself of being able to rely on SCGTs as a contingency resource if, for example, DSM does not deliver the anticipated capacity savings. 5-21

86 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Project Range of In-Service Dates Given the uncertainty described in this section and to provide a basis for Project alternatives evaluation, BC Hydro evaluated a range of Project in-service dates from F2022 to F2024. However, given the uncertainties around the amount and timing of potential LNG load and DSM and IPP delivery, BC Hydro considers it prudent to proceed with the Project for its earliest in-service date of F Conclusion Based on the LRBs in Table 5.8 and Table 5.9, there are energy and capacity gaps within the 20-year planning period that must be filled with supply-side options. As described in Section 5.4, targeting more DSM is not a viable alternative to the Project. Section 5.5 contains the available supply-side resources analysis, including the trade-offs between different supply-side resources to address the energy and capacity deficits set out in Table 5.8 and Table 5.9, which forms the basis of the need for the Project. 5.3 Purpose of the Project The EIS Guidelines confirm that the EIS will present the purpose of the Project, and goes on to state that the purpose of the Project will be established from the perspective of the Proponent, and will provide context for consideration of alternatives to the Project in Sections 5.4 and 5.5. The EIS Guidelines also require that the EIS describe the objectives the Project is designed to achieve. The purpose of the Project is to: Cost-effectively meet BC Hydro s forecasted need for energy and capacity identified in Section Refer to Section Align with the relevant objectives of Section 2 of the Clean Energy Act and relevant B.C. Government policy statements, which in turn were used to develop Project-specific objectives, including the objective to maximize the development of the hydroelectric potential of the Site C Flood Reserve. Refer to Section Meeting Identified Need The Project would provide about 5,100 GWh/year of average energy and up to 1,100 MW of dependable capacity. As demonstrated in Table 5.8 and Table 5.9, even with the additional actions of implementing the current BC Hydro DSM target and Revelstoke Unit 6, BC Hydro will have a projected energy shortfall beyond F2023, and a projected capacity shortfall beyond F2024. Table 5.13 and Table 5.14 indicate that, by constructing the Project at its earliest in-service date of F2022, BC Hydro will have sufficient energy and capacity to meet its mid-load forecast energy and peak demand without LNG throughout the 20-year planning horizon. 5-22

87 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project 1 2 Table 5.13 Energy Surplus/Deficit (GWh) with DSM Target, Revelstoke Unit 6 and the Project (No LNG) Year LRB with DSM, Rev 6 & Site C Clean Energy Project F2012 (2,100) F2013 (5,200) F2014 (4,000) F2015 (5,500) F2016 (4,700) F2017 (4,700) F2018 (3,400) F2019 (2,200) F2020 (1,900) F2021 (1,400) F2022 (1,400) F2023 (4,600) F2024 (4,900) F2025 (4,400) F2026 (4,300) F2027 (3,900) F2028 (3,300) F2029 (2,700) F2030 (2,000) F2031 (1,300) 3 4 Table 5.14 Capacity Surplus/Deficit (MW) with DSM Target, Revelstoke Unit 6 and the Project (No LNG) Year LRB with DSM, Rev 6 & Site C Clean Energy Project F2012 (950) F2013 (1,000) F2014 (900) F2015 (700) F2016 (250) F2017 (200) F2018 (100) F2019 (400) F2020 (350) F2021 (250) F2022 (250) F2023 (1,050) F2024 (950) F2025 (850) F2026 (750) F2027 (650) 5-23

88 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Year LRB with DSM, Rev 6 & Site C Clean Energy Project F2028 (500) F2029 (300) F2030 (150) F Aligning with the Clean Energy Act and B.C. Government Policy Section 2 of the Clean Energy Act sets out B.C. Government objectives, referred to as British Columbia s energy objectives, that BC Hydro must respond to and that the BCUC must consider and be guided by in various applications. The alignment of the Project with the relevant Clean Energy Act energy objectives is described in Table Table 5.15 Project Alignment with Clean Energy Act Objectives Clean Energy Act Objective At least 93% generation from clean or renewable resources To ensure that BC Hydro s rates remain among the most competitive of rates charged by public utilities in North America To reduce greenhouse gas (GHG) emissions To encourage economic development and the creation and retention of jobs To maximize the value of B.C. s generation and transmission assets How the Project Supports the Objective The Project is a clean or renewable resource as defined by Section 1 of the Clean Energy Act. a The Project provides clean or renewable energy and dependable capacity, and also has the ability to shape, firm, and help integrate intermittent clean or renewable resources such as wind and run-of-river. Refer to Section in Volume 1 Section 7 Project Benefits. The Project is a cost-effective resource for energy and capacity compared to alternative supply options; refer to Section 5.5 As a hydroelectric resource, the Project emits virtually no GHG emissions when compared to natural gas-fired electricity resources, and on a per GWh basis, emits a similar amount of GHGs as other clean or renewable resources such as wind. Refer to Section in Volume 1 Section 7 Project Benefits and to Volume 2 Section 15 Greenhouse Gases. The Project is a job-intensive capital project that will create employment in B.C. during the construction period. Refer to Section 7.3 in Volume 1 Section 7 Project Benefits. The Project provides additional benefits (e.g., shaping and firming benefits) to optimize the value of B.C. s generation and transmission assets. In addition, as the third project on one river system, the Project would generate 35% of the energy produced at the W.A.C. Bennett Dam, with 5% of the reservoir area. Refer to Section in Volume 1 Section 7 Project Benefits. NOTE: a Clean or renewable resources are defined in Section 1 of the Clean Energy Act as follows: clean or renewable resource means biomass, biogas, geothermal heat, hydro, solar, ocean, wind or any other prescribed resource. To date, biogenic waste, waste heat and waste hydrogen have been added to this definition pursuant to the B.C. Clean or Renewable Resource Regulation, B.C. Reg. 291/2010. In addition to Section 2 of the Clean Energy Act, the 2007 Energy Plan sets the policy framework in which BC Hydro develops resources. The 2007 Energy Plan stresses the development of clean or renewable resources. While a number of 2007 Energy Plan 5-24

89 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Policy Actions have been overtaken by Section 2 of the Clean Energy Act, there are 2007 Energy Plan Policy Actions relevant to the review of natural gas-fired generation and other potential alternatives to the Project, as set out in Table Table 5.16 Relevant 2007 Energy Plan Policy Actions Policy Action 18 All new electricity generation projects will have zero net GHG emissions 20 Require zero GHG emissions from any coal thermal electricity facilities Section in Environmental Impact Statement The B.C. Environmental Management Act (S.B.C., 2003, c.53) is described in further detail in Section All new natural gas-fired generation analyzed in the alternatives to Project analysis factors in the zero net GHG emissions requirement. See above in respect of Policy Action No. 18; the current status of coal-fired generation with carbon capture and storage is examined in Section No nuclear power Nuclear technology is not an alternative to the Project; refer to Section BC Hydro developed the Project objectives listed in Table 3.1 in Volume 1 Section 3 Project Overview, from the Clean Energy Act and the 2007 Energy Plan. BC Hydro s objective to ensure a long-term source of energy and capacity and to optimize existing assets on the Peace River system is supported by the B.C. Government s reservation of Crown land in the Peace River watershed for the purposes of hydroelectric development through an Order-in-Council in 1957 (further described in Section 6.2 in Volume 1 Section 6 Alternative Means of Carrying Out the Project). This Order-in-Council was subsequently amended and the Site C Flood Reserve described in Section 6.2 of this EIS defines the bounds within which the Project can be developed. As a result, to fulfill the Project objectives, the specific purpose of the Project design is to cost-effectively maximize the development of the hydroelectric potential of the Site C Flood Reserve to meet the need and maximize the benefits to British Columbia. 5.4 Identification of Potential Alternatives to the Project and Screened Resources The EIS Guidelines call for the EIS to describe the functionally different ways to meet the need for the Project, that is, the technically and economically feasible alternatives to the Project. The EIS is to identify the alternatives to the Project that were considered. The EIS is to describe the criteria used to compare the Project to other alternatives, with consideration of the major financial, technical, environmental, and economic development attributes, per the Agency Need/Alternatives Operational Policy Statement. This analysis must be done to a level of detail that is sufficient to compare the Project to the alternatives. BC Hydro s analysis of the potential alternatives to the Project is contained in two parts: This section provides an overview of the identification and review process for potential alternatives to the Project, and concludes with the resources that were screened out on the basis that they are not viable. This first category of potential alternatives is referred to as the Screened Resources. The Screened Resources consist of: o Supply-side resources that are not permitted by or are inconsistent with B.C. Government legal requirements, namely: Burrard, Large hydroelectric projects 5-25

90 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project o o o prohibited by the Clean Energy Act, nuclear, and external market purchases/imports including the Canadian Entitlement (Section ) Supply-side resources that are not technically or economically feasible alternatives to the Project. These resources are: Coal-fired generation with carbon capture and storage, wave, tidal and solar (Section ). Increased levels of DSM beyond the current BC Hydro DSM target (i.e., DSM Options 4 and 5) described in Section DSM options designed to deliver capacity savings during BC Hydro s peak load periods (Section ) Section 5.5 describes the second category of potential alternatives the available resources and their attributes. The available resources are supply-side resources that, when used in various combinations, can meet the need identified in Section 5.2. The available resources encompass: o Clean or renewable IPPs, including wind, run-of-river hydro, biomass, geothermal, and pumped storage o BC Hydro Resource Smart potential o Clean or renewable IPPs and/or Resource Smart combined with some natural gas-fired generation. Natural gas-fired generation is constrained by the Subsection 2(c) Clean Energy Act target to generate at least 93% of the electricity in British Columbia from clean or renewable resources. This target and its effect on natural gas-fired generation are addressed in Section Alternatives Identification Resource Options Report The information for potential alternatives to the Project derives in large part from the 2010 Resource Options Report, which is a database of various resource options considered for meeting BC Hydro s future energy and capacity needs. In line with long-term resource planning best practices and the BCUC s Resource Planning Guidelines, BC Hydro included and assessed a wide variety of DSM, generation supply-side resource, and transmission options in its 2010 Resource Options Report. BC Hydro developed resource option attributes and costs reflecting information from BC Hydro project experience, consultant studies, and First Nations and public stakeholder input, including from members of the IPP community. A number of studies were conducted by BC Hydro and its consultants, including: Powertech Labs Inc., Coal with Carbon Capture & Sequestration for Long-Term Transmission Inquiry (September 15, 2009) Garrad Hassan Canada Inc., Updated Capital and O&M Cost Assumptions for Wind Power Development in British Columbia (November 26, 2010) Kerr Wood Leidal Associates Ltd., Run-of-River Hydroelectric Resource Assessment for British Columbia 2010 Update (March 2011) Industrial Forest Service Ltd., Wood-Based Biomass Energy Potential of British Columbia (January 2011) 5-26

91 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Knight Piésold Ltd., Evaluation of Pumped Storage Hydroelectric Potential (November 30, 2010) Knight Piésold Ltd., Evaluation of Pumped Storage Hydroelectric Potential in the North Coast Region of British Columbia (March 15, 2012) Hatch, Pumped Storage at Mica Generating Station: Preliminary Cost Estimate (December 2010) BC Hydro also relied on other third-party reports. These are referenced in the discussions of specific resources in Sections 5.4 and 5.5. The 2010 Resource Options Report-related engagement process consisted of working with people and organizations with technical expertise to gather and review information on DSM and supply-side options in B.C. Focused workshops and meetings were held on specific energy sources, including: 1. DSM: BC Hydro engaged with its Electricity Conservation and Efficiency Committee 2. Run-of-river hydro: A series of workshop meetings were held in September A draft of the Kerr Wood Leidal resource assessment report was posted on BC Hydro s website for comment prior to finalization. 3. Wind resources (onshore and offshore): A working group was established in September 2010 to review drafts of the Garrad Hassan report on onshore/offshore wind cost assumptions, results of onshore wind potential, methodology, and assumptions for determining offshore wind potential. An individual meeting with IPPs was held in October Biomass Biogas, Municipal Solid Waste and Wood-Based: A series of workshop meetings were held between August 2010 and November A biomass working group, including representatives from the B.C. Ministry of Energy, Mines and Natural Gas, the B.C. Ministry of Forests, Lands and Natural Resource Operations, and consultants Industrial Forest Services Ltd., M.D.T. Ltd. and Murray Hall Consulting Ltd., participated in the studies to determine long-term availability potential and cost. A draft copy of the Forest Service report was circulated for comment in November Geothermal: A series of workshop meetings were held in September It was agreed that data compiled by GeothermEX for the Western Renewable Energy Zone initiative would be the basis for conventional geothermal potential. It was recognized that this represents a conservative estimate of the potential, as it does not include resources from enhanced geothermal or co-produced fluids that are likely to be found in B.C. 6. Natural Gas-Fired Generation: Representatives from IPPs, consumer organizations, and consultants met in September 2010 and decided there was no need to establish a working group. 7. Pumped Storage: Two consultants Knight Piésold and Hatch participated with representatives from IPPs, individual developers, and consulting firms in a working group that met between July and October Among other things, this group reviewed the Knight Piésold study methodology and preliminary results, and shared information on potential sites, technical work that had been done to date, etc. 5-27

92 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project BC Hydro also received submissions from workshop participants, which informed the Resource Options Report, including Ocean Renewable Energy Group s August 14, 2009 submission entitled Resource Options Workshop Wave and Tidal. BC Hydro met with the B.C. Ministry of Environment and environmental organizations (Nature Trust of Canada, Ducks Unlimited, BC Sustainable Energy Association, David Suzuki Foundation, West Coast Environmental Law Association, Westcoast Wilderness Committee, Watershed Watch Salmon Society, Sierra Club, and Pembina Institute) to review the methodology for the environmental attributes. BC Hydro reported out on the draft 2010 Resource Options Report results on December 8, BC Hydro circulated a draft of the 2010 Resource Options Report and established a written comment period of between December 8 and 31, Resource Technologies The result is the 2010 Resource Options Report, which looks out 20 years for DSM and supply-side options. Table 5.17 shows the B.C.-based resources that are identified in the Resource Options Report and discussed in Sections and Table 5.17 Resource Technologies Identified Technology Screened/Available Resource Section Reference Demand Side Management Options DSM Options 4 and 5 Screened Resource Section DSM capacity-only initiatives Screened Resource Section Clean or Renewable Resources Wave and tidal Screened Resource Section Solar Screened Resource Section Wind (on-shore and off-shore) Available Resource Section and Section Run-of-river hydro Available Resource Section Geothermal Available Resource Section Biomass Available Resource Section , Section , and Section Large hydroelectric Screened Resource Section (other than the Project) Pumped storage Available Resource Section (dependable capacity only) BC Hydro Resource Smart Available Resource Section Fossil Fuel Resources Coal-fired generation with carbon capture and storage Natural gas-fired generation SCGTs (dependable capacity) CCGTs (firm energy) 2010 Resource Options Report Attributes Screened Resource Section Available Resource within the 93% Clean Energy Act clean or renewable target Section A set of technical, financial, environmental, and economic development attributes were developed in the 2010 Resource Options Report for each technology to compare and evaluate the resource options and for IRP portfolio analysis. Section describes these attributes. 5-28

93 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Limitations The 2010 Resource Options Report database of resources contains sufficient information on physical, financial, environmental, and economic development characteristics to allow for both economic and environmental analysis at a planning level. However, because the 2010 Resource Options Report values present a high level planning assessment of resource type costs, the values: Do not reflect site-specific information, permitting constraints, and other development risks. For example, the UECs estimated for the geothermal resource options do not reflect the exploration risks associated with drilling and proving site-specific resource potential. May not predict accurately future prices set through BC Hydro s power acquisition processes. Historically, the resource options with the lowest unadjusted Unit Energy Cost (UEC) values are not always bid into BC Hydro s power acquisition processes. A case in point is the geothermal resource option, which appears to be low cost, based on an unadjusted UEC value of $88/MWh ($F2013) and upward, but has never been bid into a BC Hydro power acquisition process by IPPs. Refer to Section Wind Cost Update The wind UECs in the 2010 Resource Options Report were based on wind generation modelling studies completed by GEC-KEMA (formally known as DNV-GEC) in May 2009 and September 2009, and cost assumptions provided by Garrad Hassan Canada Inc. in November These studies were conducted and completed as changes in wind turbine efficiencies and apparent changes in wind turbine pricing were taking place. The 2010 Resource Options Report wind UECs have been revised to reflect observed changes in turbine efficiencies and wind turbine prices that have occurred over the past three years: Wind turbine efficiencies: BC Hydro commissioned DNV-KEMA in May 2012 to provide a wind turbine power curve for International Electrotechnical Commission (IEC) Class III wind sites (corresponding to low average wind speeds) and to update the power curves for IEC Class I and II wind sites (corresponding to high and medium average wind speeds, respectively). The three wind power curves were developed by blending wind turbine power curves for a number of recent and current turbine models for each of the three IEC classes. The new power curves were then applied to the modelled wind speeds from the original 2010 Resource Options Report Wind Data Study to create new hourly generation profiles for each wind project. In this analysis, no changes were assumed for turbine hub heights, installed wind capacity of the individual wind projects, or wind farm losses. With the application of the revised power curves, the annual net energy production increased on average by 13% for IEC Class I wind projects, 6% for IEC Class II wind projects, and 18% for IEC Class III wind projects. Wind turbine prices: Over the past decade, wind turbine prices have undergone considerable changes. Turbine prices steadily increased from 2002 to Turbine prices peaked in the first half of 2009, but have dropped since then by approximately 20% to 30%. The trends in turbine prices have been subject to a number of reports (Bolinger and Wiser 2011; National Renewable Energy Laboratory 2012; U.S. 5-29

94 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Department of Energy 2012). The increase in turbine prices has been attributed to increased material and labour costs, upscaling of turbine size, decline in the U.S. dollar relative to the euro, increased costs in turbine warranty provisions, and a general increase in turbine manufacturer profitability, due in part to strong demand growth, and turbine and component supply shortages. The decline in wind turbine prices since 2009 has coincided with the downturn in the global economic situation. The reduced turbine demand has increased competition among manufacturers, and shifted the turbine market from a seller s market to a buyer s market. The current wind turbine prices are forecasted to persist through 2015, but it is uncertain if the low sale margins can be maintained by the manufacturers in the long term. Improved efficiencies in the manufacturing process, continued technical advancements, and potential competition from Chinese turbine manufacturers may help keep turbine prices low in the future. At the same time, resurgence in wind turbine demand, resulting in supply chain pressures similar to those observed between 2004 and 2009, could counter the cost reductions and increase wind turbine prices. In light of these uncertainties, BC Hydro decreased the wind turbine price by 15% from the original assumption used in the 2010 Resource Options Report. Refer to Figure 5.4 at the end of this section, which shows the updated onshore wind supply curve, which takes into account the new turbine efficiencies and lower turbine costs in comparison to the onshore wind supply curve based on the 2010 Resource Options Report. The costs are based on a cost of capital of 8%; refer to Section for a discussion of cost of capital. The updated (lower) wind UECs are used in the available resources analysis in Section Screened Resources Potential alternatives were screened to determine if they are viable. There are four categories of Screened Resources determined to be not viable, with the specific reasons set out in this part in respect of each resource Category 1: Barred Resources The Agency Need/Alternatives Policy Statement provides that alternatives to the project should be established in relation to the project need and purpose and from the perspective of the proponent (CEA Agency 2007). Accordingly, those resources that are legislatively barred (Burrard, the large hydroelectric projects prohibited by the Clean Energy Act, and external markets) or policy barred (nuclear) are not available to BC Hydro and thus are not alternatives to the Project. Burrard Burrard is not an alternative to the Project, as it is an existing resource that is already being relied on to the extent permitted under Sections 3(5), 6(2)(d) and 12 of the Clean Energy Act, which provides that the Burrard firm energy contribution is 0 GWh/year, and the Burrard Thermal Electricity Regulation, which requires that Burrard s dependable capacity of 900 MW be phased out as Mica Units 5 and 6, the Interior to Lower Mainland Transmission Reinforcement Project, and the third transformer at the Meridian Substation are introduced into service by about F2016, well before the Project s earliest 5-30

95 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project in-service date. After this, BC Hydro will only be able to operate Burrard in case of emergency or for voltage support. Other Large Hydro Barred by Clean Energy Act Sections 10 and 11, and Schedule 2, of the Clean Energy Act prohibit the development of the following large hydroelectric projects: Murphy Creek, Border, High Site E, Low Site E, Elaho, McGregor Lower Canyon, Homathko River, Liard River, Iskut River, Cutoff Mountain, and McGregor Diversion. Cutoff Mountain on the Skeena River and McGregor Diversion are also legislatively barred by respectively 1) the B.C. Fish Protection Act (S.B.C., 1997, c.21), which designates the Skeena River as a protected river and prohibits the construction of bank-to-bank dams on the Skeena River, and 2) the B.C. Water Protection Act (R.S.B.C., 1996, c.484), which prohibits the construction of large-scale projects such as McGregor Diversion capable of transferring a peak instantaneous flow of 10 or more cubic metres of water per second between major watersheds. McGregor Diversion would divert most of the McGregor River flows across the divide between the Pacific and Arctic watersheds into the Peace River basin. Aside from pumped storage, which is examined in Section , BC Hydro is not aware of any other B.C.-based potential large hydroelectric projects that could be an alternative to the Project. The alternative means of delivering the Project are discussed in Volume 1 Section 6 Alternative Means of Carrying Out the Project. Nuclear Policy Action No. 23 of the 2007 Energy Plan provides that nuclear power is not part of the Province of B.C. s future and that the B.C. government rejects nuclear power as a strategy to meet British Columbia s future energy needs. While the Federal Government has siting authority over nuclear electricity-generating facilities (Society of Ontario Hydro Professional and Administrative Employees v. Ontario Hydro S.C.R. 327 (S.C.C.)), the B.C. Government can prevent BC Hydro from purchasing electricity from nuclear electricity-generating facilities through its ability to issue directions to BC Hydro and the BCUC. Therefore, nuclear power is not an alternative to the Project. External Market/Imports Pursuant to Section 6 of the Clean Energy Act, BC Hydro is required to achieve electricity self-sufficiency by the year 2016 (i.e., F2017) by holding the rights to an amount of electricity that meets its electricity supply obligations, taking into account DSM and electricity solely from electricity generating facilities within the Province. As a result of the self-sufficiency legal requirement, the following external market/import energy and capacity resources are not alternatives to the Project because they do not result solely from electricity generating facilities within the Province : The spot market and imports from the U.S., Alberta, or other markets external to B.C. under long-term contract The Canadian Entitlement, which is the Canadian portion of the additional electricity produced in the Columbia River in the western U.S. as a result of provisions of the Columbia River Treaty of 1961, because the Canadian Entitlement is produced from electricity generating facilities in the U.S. and is delivered to the U.S.-B.C. border 5-31

96 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Category 2: Supply-Side Resources Not Technically or Economically Feasible Alternatives Coal-Fired Generation with Carbon Capture and Storage Policy Action No. 20 of the 2007 Energy Plan stipulates that coal-fired generation in B.C. must meet a zero GHG emission standard through a combination of clean coal fired generation technology, carbon sequestration and offset for any residual GHG emission. While clean coal technology in the form of Integrated Gasification Combined Cycle is now becoming available, technology that allows plant-generated carbon dioxide (CO 2 ) to be captured and stored through sequestration is still evolving and is not presently viable on a commercial scale. BC Hydro concludes that coal-fired generation with carbon capture and storage is not a technically feasible alternative to the Project. According to the Electric Power Research Institute (Electric Power Research Institute 2007), coal-fired generation plants with 90% CO 2 emission capture and storage could not be commercially available in B.C. until about 2028; this was also the conclusion of Powertech Lab Inc. (Powertech Labs Inc. 2009). There is uncertainty with respect to the cost of carbon capture and storage, and with respect to what impact carbon capture and storage will have on a large coal-fired generating station s efficiency. Although there are some geological sites in B.C. that may prove suitable for CO 2 storage, there is limited information available to assess the suitability for geological storage at this time. There are also a number of legal/regulatory and public acceptance issues that likely need to be addressed before carbon capture and storage technology can be considered on a commercial scale in B.C. For example, there is currently no liability regime in place to govern responsibility for CO 2 leakage once stored. Wave Wave energy is generated by winds blowing over the surface of the ocean. Currently, there are five generic approaches to capturing the wave energy resource, all of which are at the early stages of commercial development, with potential application in B.C. There are no wave energy projects in B.C. waters, although two demonstration projects received support from B.C. and Federal Government innovative clean energy funding agencies. BC Hydro relied on information in the Geographic Information System map of the B.C. Integrated Land Management Bureau tenure database, and the incoming wave power from the Canadian Hydraulic Centre report (Canada Hydraulic Centre 2006) to develop the total theoretical wave energy potential. The costs associated with these wave energy projects have been estimated based on the cost projections from the U.K.-based Carbon Trust report (Carbon Trust 2006). A summary of the technical and financial results for wave resource is contained in Table

97 1 Table 5.18 Summary of Wave Potential Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Transmission Region Number of Potential Sites Installed Capacity (MW) Total Energy (GWh/year) Firm Energy (GWh/year) UEC at POI ($F2013/MWh) North Coast Vancouver Island ,088 2, Total 16 1,078 2,506 2, BC Hydro concludes that wave energy is not an economically feasible alternative to Project. In comparison, the Project UEC excluding sunk costs is $94/MWh at the point of interconnection (POI) with the BC Hydro integrated system ($F2013; refer to Volume 1 Appendix F Project Benefits Supporting Documentation, Part 1 Project Cost Estimate for details as to how the Project UEC is derived), and the Available Resource UECs are also well below the wave UEC range of $479/MWh to $844/MWh. Tidal Tidal energy refers to the energy available in the flow of water driven by the rotation of the earth in the gravitational fields of the sun and the moon. Tidal energy is variable from one hour to the next, but can be accurately predicted several years into the future. Tidal energy can be captured in two different ways tidal barrages and tidal current systems. Tidal barrage is not considered a realistic prospect in B.C. due to its need for dam construction and its negative estuary ecosystem impact. This assessment focuses on tidal current systems. There are no commercial tidal current projects in B.C., although there are two demonstration projects underway. Owing to the early state of commercial development, there is little real-world experience with the costs associated with tidal power on a commercial scale. BC Hydro relied on the Carbon Trust report described above in relation to wave resources to assess the costs of tidal development. A summary of the technical and financial results for tidal resource is contained in Table Table 5.19 Summary of Tidal Potential Transmission Region Number of Potential Sites Installed Capacity (MW) Total Energy (GWh/year) Firm Energy (GWh/year) UEC at POI ($F2013/MWh) Vancouver Island ,426 1, Total ,426 1, BC Hydro concludes that tidal is not an economically feasible alternative to Project. The Project UEC excluding sunk costs is $94/MWh at POI, and the Available Resource UECs are also well below the tidal UEC range of $275/MWh to $605/MWh. Solar Solar power is generated from sunlight and can be achieved directly using photovoltaic cells (crystalline silicon or thin film) or indirectly by using concentrating solar power technologies. Both technologies are commercially proven. Globally, the costs have achieved dramatic decline and are projected to continue to decline, but are not expected to become cost-competitive in Canadian jurisdictions over the next 10 years in the absence of price support. There are no known commercial solar power installations in 5-33

98 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project B.C. However, there are several distributed generation installations on the customer side of the meter. The solar resource option assessment focuses on utility-scale photovoltaic systems given the ability to modularly increase the size of the solar power installation size over time and thereby managing capital investment risk. Concentrating solar power technologies are not included due to the large upfront capital investment as utility-scale concentrating solar powerplants typically require a large-scale implementation. The solar resource assessment examined commercial installations on the utility side of the meter with commercial scale solar installations sized at 5 MW. A summary of the technical and financial results for the solar resource is contained in Table Table 5.20 Summary of Solar Potential Transmission Region Number of Potential Sites Installed Capacity (MW) Total Energy (GWh/year) Firm Energy (GWh/year) UEC at POI ($F2013/MWh) Peace River North Coast Central Interior Kelly/Nicola Mica Revelstoke Vancouver Island Lower Mainland Selkirk East Kootenay Total BC Hydro concludes that commercial solar is not an economically feasible alternative to Project, although solar generation will continue to be used on the customer side of the meter. In comparison, the Project UEC excluding sunk costs is $94/MWh at POI, and the Available Resource UECs are also well below the solar UEC range of $382/MWh to $879/MWh Category 3: DSM Options Section describes the BC Hydro DSM target, and Section outlines BC Hydro s reliance on the current DSM target to fill the energy and capacity resource gaps and the delivery risk associated with the DSM target. BC Hydro has developed a number of DSM options. BC Hydro s traditional DSM initiatives (the DSM target, and DSM Options 1 and 3) are expected to deliver both energy and capacity savings. The following section discusses the two additional, more aggressive DSM options that could deliver both energy and capacity, known as DSM Option 4 and DSM Option 5. BC Hydro also examined DSM options specifically designed to deliver capacity savings during BC Hydro s peak load periods on the electrical system through management and control of customers electricity demand; refer to part

99 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project DSM Options 4 and 5 BC Hydro concludes that DSM Options 4 and 5 are not viable alternatives to the Project because: DSM Options 4 and 5 present government and customer acceptance issues arising from BC Hydro s reliance on an aggressive and untested combination of rate structures, and codes and standards DSM Options 4 and 5 entail significant delivery risk, especially with respect to capacity savings, and could jeopardize BC Hydro s ability to serve its customers DSM Option 4 targets about 9,500 GWh/year of energy savings and 1,500 MW of dependable capacity savings by F2021, and DSM Option 5 targets 9,600 GWh/year of energy savings and 1,600 MW of dependable capacity savings by F2021. Acceptance DSM Option 4 is founded on new or more aggressive conservation rate structures, and significant government intervention and regulation in the form of codes and standards, to generate additional savings. For example, all BC Hydro customers would be exposed to a much larger degree to marginal cost price signals, and rate structures may also need to be tied to a house or building s rated energy performance. Each industrial customer would need to meet a government mandated certified plant minimum efficiency level to take advantage of BC Hydro s Heritage hydroelectric lower priced electricity; otherwise, electricity would be supplied at marginal (market-based) rates. These tactics go well beyond the current DSM target, and would be new and untested. It is uncertain whether they would be accepted by government, customers, and the BCUC. DSM Option 4 also represents a bridge to DSM Option 5 by including activities and pilot initiatives that would facilitate the market and social transformations targeted by Option 5. As noted under DSM Option 5, these additional activities and initiatives would be new and untested, and it is uncertain to what extent they would succeed in generating additional electricity savings. DSM Option 5 is the most aggressive DSM option that BC Hydro considered within the range of DSM resource options. DSM Option 5 aims to create a future scenario where buildings are net-zero consumers of electricity, with some buildings being net contributors of electricity back to the grid. Energy efficiency and conservation activities would be pervasive throughout society and ingrained in a business decision-making culture. This shift would be reflected through widespread district energy systems and micro-distributed generation, smaller and more efficient housing and building footprints, community densification, distributed workforce and hotelling (shared workspace), best practices in construction and renovation, efficient technology choices and behaviour, and an integrated community perspective (land use, zoning, multi-use areas). A carbon neutral public sector would contribute to the culture shift. For the industrial sector, a market transformation to certified plants would occur, supported with expanded regulation. Option 5 includes a fundamental shift in BC Hydro s approach to saving electricity, one that places much greater emphasis on government regulation and rate structures to change market parameters and societal norms and patterns that influence electricity consumption and conservation. As a new and untested approach to saving electricity, Option 5 is subject to considerable uncertainty regarding government, customer, and 5-35

100 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project BCUC acceptance and, ultimately, its effectiveness at generating additional cost-effective electricity savings. Delivery Risk Delivery risk increases as the amount of reliance on DSM increases in a portfolio of DSM and supply-side resources. It is useful to contemplate delivery risk in terms of energy and capacity separately. A shortfall in energy could lead to the acquiring of more costly supply-side resources, such as IPP clean or renewable resources, in a compressed time frame, or could lead to an energy shortfall that could not be met through purchasing from the B.C. market, which could result in relying on imports to a greater extent than contemplated by the legal self-sufficiency requirements. While these are serious shortcomings, delivery risk is more of a critical problem on the capacity side, where a shortfall in electricity at key times would undermine BC Hydro s fundamental obligation to serve its customers demand. An unexpected departure from the mid-load forecast is of concern, particularly with respect to capacity planning. BC Hydro is relying on the current DSM target to deliver 1,400 MW of dependable capacity by F2021. The corresponding figures for DSM Options 4 and 5 are 1,500 MW and 1,600 MW, respectively, by F2021. There is significant uncertainty with respect to DSM capacity savings across all options, including the DSM target (refer to Section 5.2.3); moving to higher levels of DSM increases uncertainty around capacity savings. BC Hydro has limited contingency resource options available on a relatively short timeline if DSM does not deliver the anticipated capacity savings. Natural gas-fired SCGTs (peaking units) of about 100 MW in size would be the principal potential B.C.-based capacity contingency resource. It is anticipated that SCGTs sited outside the Lower Mainland would take about five years for approval and construction. SCGTs above 50 MW trigger BCEAA and the requirement that the B.C. Minister of Energy, Mines and Natural Gas, and the B.C. Ministry of the Environment, authorize an EAC prior to construction. Constructing and operating SCGTs also requires Air Emissions Permits under the B.C. Environmental Management Act. There are social licensing issues associated with natural gas-fired generation, which are discussed in Section Category 4: DSM Capacity Initiatives While DSM Options 4 and 5 discussed in Section have associated capacity savings, additional capacity savings may be possible through DSM capacity activities (also referred to as peak reduction or peak shaving). Capacity-focused DSM savings were grouped into two broad categories: Industrial load curtailment: This DSM option targets large customers who agree to curtail load on short notice to provide BC Hydro with capacity relief during peak periods. BC Hydro has implemented a load curtailment program targeted at shorter term (one to three years) capacity needs in recent years, and customers have delivered as requested. However, it is not clear how easily these can be translated into long-term agreements that can reliably reduce peak demand over the long-term when needed. Capacity programs: This DSM option contains programs that leverage equipment and load management systems to enable peak load reductions to occur 5-36

101 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project automatically or with intervention. Programs may involve payment for customer equipment and a financial payment for participation in the program. Examples of capacity programs include load control of water heaters, heating, lighting, and air conditioning. Thus capacity-focused programs are a collection of several activities; both demand response and load control, spread across different customer classes. The participation rates and savings per participant are key aspects of the uncertainty of capacity savings. An attempt to assess the range of outcomes with respect to industrial load curtailment and DSM capacity programs for a selected year is shown in Table Table 5.21 Savings From Capacity DSM and Uncertainty (MW in F2021) Industrial Load Curtailment Capacity-Focused Programs Low (P10 cut-off) Mid (mean or expected) High (P90 cut-off) There are a number of uncertainties regarding DSM capacity initiatives that are not well understood. Since BC Hydro is just starting to develop long-term DSM capacity savings options, implementation success is an important issue. In particular, precise program initiation dates and customer participation rates are unknown; BC Hydro would want to test both of these drivers through pilot initiatives. Once these approaches are established, operational experience will still be required to understand how participation and savings per participant translate into peak shaving. Similarly, experience will be needed to see how savings for each initiative translates into peak reduction for the entire system whether these peaks are coincident with peak load and whether peak shaving leads to other system peaks. BC Hydro concludes that DSM capacity options are not viable alternatives to the Project, given the number of significant uncertainties underlying such DSM initiatives described above. 5.5 Available Resources This section describes and compares the available resources using financial, technical, environmental, and economic development decision attributes. As set out in Section , the available resources are: Clean or renewable energy resources from third parties: wind both on-shore and off-shore, run-of-river hydro, geothermal, and biomass BC Hydro Resource Smart energy and capacity resources A clean or renewable capacity resource: pumped storage Natural gas-fired generation and cogeneration, including energy resource CCGTs and capacity resource SCGTs, within the 93% Clean Energy Act clean or renewable target described in Section The comparison consists of 1) an overview of the attributes of each individual available resource, provided in Section 5.5.2, and 2) portfolio analysis, the results of which are set out in Section Portfolios are combinations of different mixes of available resources to meet the Project s 5,100 GWh/year of firm energy and 1,100 MW of dependable 5-37

102 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project capacity. Thus these portfolios constitute the economically and technically feasible alternatives to the Project. The remainder of this section is organized as follows: Section describes the financial, technical, environmental, and economic development decision attributes Section provides descriptions of the available resources, including the UECs and Unit Capacity Costs (UCCs) as applicable, and a summary of the key uncertainties and risks of each available resource. Section sets out the Clean Energy Act s 93% clean or renewable target, and the resulting permissible natural gas-fired generation in both GWh and MW for selected years. The result is that, on its own, natural gas-fired generation is not an alternative to the Project because there is not enough space, given the 93% clean or renewable target for natural gas-fired generation, to provide 5,100 GWh/year of firm energy and 1,100 MW of dependable capacity; rather, natural gas-fired generation must be combined with clean or renewable resources. This is done in the portfolio analysis in Section Section sets out the modelling and portfolio process Section presents the expected costs and risk performance of the different portfolios with and without the Project across different future scenarios Section summarizes the available resources assessment Measurement Criteria: Attributes Attributes are the measurement criteria by which impacts of resource alternatives are measured. There are several reasons why BC Hydro considered a broad set of attributes for purposes of the EIS: The Agency Need/Alternatives Policy Statement (CEA Agency 2007) states that the major environmental, economic and technical costs and benefits should be identified and described The EIS Guidelines provide that BC Hydro will describe the major financial, technical, environmental, and economic development attributes of the supply-side alternatives to the Project The Clean Energy Act stipulates that BC Hydro must carry out resource development consistent with good utility practice; this includes understanding the broader implications of BC Hydro s planning actions As part of the IRP and Project-related First Nations and public engagement processes, BC Hydro found that First Nations and the public are interested in a broad set of effects beyond financial impacts As described in Section 5.3, the B.C. Government explicitly laid out a number of objectives in the Clean Energy Act. These objectives include a mix of financial and non-financial considerations, including a focus on clean or renewable electricity and GHG emissions. Refer to Table

103 1 Table 5.22 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Clean Energy Act and Other Objectives and Attributes Decision Objective and Attribute Minimize Financial Impacts: Cost Cost risk Minimize Environmental Footprint, Including: Land footprint Water footprint Criteria air contaminants GHG emissions Maximize Economic Development Reason for Inclusion Good utility practice; First Nations, public and stakeholder interests; congruent with Clean Energy Act objectives Good utility practice; First Nations, public and stakeholder interests; congruent with Clean Energy Act objectives First Nations, public and stakeholder interests; congruent with Clean Energy Act objectives These attributes are considered at a provincial level, as data do not exist at a regional or local level for all projects (in many cases, generation resources are represented as a typical project or block of projects). In addition, the resources selected through portfolio modelling are not necessarily the ones that would be selected through an actual acquisition process Financial Attributes Financial attributes describe the cost of resource options. The Clean Energy Act and good utility practice underscore the importance of tracking costs when comparing resource options. The financial implications of the supply-side resource options or strategies to fill the load-resource gap are tracked at a portfolio level as set out in Section 5.5.4, which provides the portfolio results, both for the cost of acquiring new resources and for how these resources interact with the existing system and the external electricity market. Financial attributes considered include: UEC: reflects the real levelized cost (as described in Volume 1 Appendix F Project Benefits Supporting Documentation, Part 1 Project Cost Estimate) of a unit of energy from a resource option or portfolio (typically in $F2013/MWh). The values serve as an initial ranking of energy resources in scheduling resources to fill a load/resource gap. UCC: reflects the real levelized cost of a unit of capacity from a resource option (typically in $F2013/kW-year). UCCs are calculated by taking the levelized annual cost of a capacity resource divided by the resource s dependable capacity. Some key assumptions or methods of determination used to develop the financial attributes include: Point of Interconnection (POI): Unless otherwise stated, resource options costs are presented as UECs and UCCs at POI. The costs at POI represent the estimated overall cost of both non-firm and firm energy, and are based on the sum of three component costs: costs within plant gate, road costs (linking plant gate area to existing road infrastructure), and transmission interconnection costs. The costs at POI do not reflect the additional costs of delivering resources to the Lower Mainland (BC Hydro s major load centre) and of firming and integrating intermittent clean or renewable resources. While these are important cost considerations, they are 5-39

104 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project factored in at the portfolio analysis stage described in Section GHG offset-related and fuel costs are included in the UECs/UCCs for natural gas-fired generation. Escalation: The UECs and UCCs are presented in constant dollars as of January 1, 2013 ($F2013). A 2% inflation factor is used in instances where it was necessary to inflate dollar values to $F2013. Weighted average cost of capital: An 8% real cost of capital rate is used in determining UECs and UCCs for available resources. Pursuant to Policy Action #13 of the 2002 Energy Plan, IPPs are to develop all resources other than DSM, Resource Smart and the Project, and IPPs have a higher cost of capital than BC Hydro. BC Hydro s weighted average cost of capital is 5.5%; a rounded 6% cost of capital is used for the Project UECs. Refer to Section for further detail. All of the available resources have more cost uncertainty than the Project because they are feasibility- or conceptual-level estimates only. The cost estimates for available resources are generally a Class 4 (feasibility, fairly wide accuracy range, typically used for alternative evaluation) or a Class 5 (concept screening, wide accuracy range) degree of accuracy. In addition, the available resource cost estimates do not reflect site-specific information; on-the-ground assessments tend to increase cost estimates. In contrast, the Project cost estimate of $7.9 billion has a Class 3 (budget authorization or control) degree of accuracy, as defined by the Association for the Advancement of Cost Engineering (AACE 2012). Refer to Volume 1 Appendix F Project Benefits Supporting Documentation, Part 1 Project Cost Estimate for additional detail. A Class 3 degree of accuracy is consistent with the BCUC s requirements for project cost estimates set out in the BCUC 2010 Certificate of Public Convenience and Necessity Application Guidelines. The Project cost estimate of $7.9 billion (nominal dollars) contains cost allowances for mitigation, regulatory review, First Nation consultation, and public engagement. Implementation of the available resources would also entail mitigation, regulatory review, First Nation consultation, and public engagement costs (referred to as soft costs ), but it is not possible to precisely quantify such soft costs, as it is difficult to predict the outcome of consultation/engagement or to identify the costs of such processes or the costs of mitigation requirements that may be imposed following these processes, not least because different First Nations and stakeholders may have conflicting goals and requirements. Accordingly, while the available resource costs set out in Section do not include such costs, BC Hydro has put a cost adder of 5% on available resource portfolios to reflect the fact that implementing any of the available resource options would trigger soft costs. Refer to Section for greater detail Technical Attributes Technical attributes describe the energy and capacity that each available resource provides and are used to assemble portfolios that meet BC Hydro s energy and capacity reliability planning criteria. The technical attributes considered for resource options are: Dependable generating capacity (DGC), which is used for non-intermittent resources, is the amount of MW that a plant can reliably produce when required, assuming all units are in service ELCC, which is used for intermittent or variable generation resources, is the maximum peak load (MW) that a generating unit or a system of units can reliably 5-40

105 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project supply, such that the loss of load expectation will be no greater than one day in 10 years. Refer to Section for a description of ELCC shortcomings. Installed (nameplate) capacity (MW) Firm energy load-carrying capability (FELCC) is the maximum amount of annual energy that a hydroelectric resource can produce under critical water conditions and is measured in GWh/year Average annual energy (GWh/year) Hourly/daily/monthly variability A summary of the generation reliability assumptions and methods of development is presented in Table Table 5.23 Generation Reliability Assumptions and Methods Potential Generation Resources Run-of-river Biomass DGC and ELCC Assumptions and Methods of Determination (MW) ELCC: Weighted average of approximately 60% of the forecasted average MW of potential in the December/January period DGC: 100% of installed capacity for wood-based biomass; 97% of installed capacity for municipal solid waste; and 95% of installed capacity for biogas FELCC Assumptions and Methods of Determination (GWh/year) Region-specific factors applied to the average annual energy; monthly variability 100% of average annual energy Wind onshore ELCC: 24% of installed capacity 100% of average annual energy; hourly and daily variability Wind offshore ELCC: 24% of installed capacity 100% of average annual energy; hourly and daily variability Geothermal DGC: 100% of installed capacity 100% of average annual energy Natural gas-fired generation & cogeneration DGC: Varies from 88% to 100% of installed capacity Based on 18% capacity factor for SCGTs and 90% for CCGTs Project DGC: 1,100 MW 4,700 GWh/year (average energy is 5,100 GWh/year) Pumped storage DGC: 100% of installed capacity N/A (consumes energy) NOTE: a Capacity factor of an electricity generating facility is the ratio of the actual output of the electricity generating facility over a period of time and its potential output if it had operated at full installed capacity over the entire period; natural gas-fired generation is relied upon to run a minimum of 18% of the time for its energy contribution BC Hydro uses reliability planning criteria for planning purposes to evaluate when generation resources are required to maintain an adequate supply of electricity resources to reliably meet customer demand. BC Hydro considers both the peak load (generation capacity reliability planning criterion) and annual energy demand (generation energy reliability criterion) on its electrical system. With respect to energy, from a BC Hydro planning perspective: Heritage hydroelectricity facilities, including the Project, are relied on for their average energy contribution, as shown in Table 5.23, as a result of the Electricity 5-41

106 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Self-Sufficiency Regulation, which mandates that BC Hydro use the average water capability of its heritage hydroelectric resources Available resources developed by IPPs or other third parties are relied on for their firm energy contribution. The Electricity Self-Sufficiency Regulation is silent on IPP energy output and, accordingly, BC Hydro uses its energy reliability criterion. Non-firm energy from IPPs does not contribute to BC Hydro s energy reliability criterion. As described below in Section 5.5.2, run-of-river and wind resources provide very little dependable capacity. For example, run-of-river and wind resources made up virtually all of the 25 EPAs awarded pursuant to BC Hydro s most recent power acquisition process, the Clean Power Call. While these resources are to provide over 3,000 GWh/year of firm energy, they only provide 9 MW of dependable capacity Environmental Attributes Environmental attributes provide high level information on the footprint of the available resources. BC Hydro retained Kerr Wood Leidal Associates Ltd., Hemmera Envirochem Inc. and HB Lanarc to develop the environmental attributes. The environmental attributes were selected based upon the following criteria: Appropriate for provincial-scale portfolio comparisons Science-based and defendable Measurable in a quantity -based approach that facilitates comparison between portfolios of available resources Representative of relevant biophysical resources Based on existing data or easily acquired data Easy to understand for long-term planning and stakeholder engagement purposes The environmental attributes are grouped into four environmental categories: land, atmosphere, freshwater, and marine, and are further broken down into indicators, as described in Table

107 1 Table 5.24 Environmental Attributes Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Environmental Category Land Indicator Net primary productivity (gc/m 2 /year) a Remoteness linear disturbance density (km/km 2 ) High priority species count (percentile) Unit of Measure hectares (ha) per class Classifications Low (0 to < 69) Medium (69 to < 369) High (> 369) ha per class Wilderness (< 0.2) Remote (0.2 to < 0.66) Rural (0.66 to 2.2) Urban (> 2.2) ha per class 0 to < to < to < to 80 > 80 Atmosphere GHG emissions tonnes/gwh Carbon dioxide equivalent (CO 2e) Air contaminant emissions tonnes/gwh Sulphur dioxide Oxides of nitrogen (NO x) Carbon monoxide Volatile organic compounds Fine particulates (PM): PM 2.5 (reported when data are available) Fine particulates: PM 10 (reported when data are available) Fine particulates: PM total Mercury Freshwater b Reservoir aquatic area ha Site C Clean Energy Project only (while pumped storage and resource smart may create reservoir aquatic areas, these have only been described qualitatively in Section 5.5.2, as the calculations were not done for the 2010 Resource Options Report) Affected stream length kilometres (km) Run-of-river and the Site C Clean Energy Project (pumped storage and Resource Smart if applicable/available) Priority fish species (number of priority fish c species per watershed) ha per class No priority species (0) Low species diversity (1 to 12) Moderate species diversity (13 to 23) High species diversity (24 to 38) 5-43

108 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Environmental Category Marine d Indicator Valued ecological features (number of valued ecological features) Key commercial bottom fishing areas Unit of Classifications Measure ha per class None (0) Low (1 to 2) Medium (3 to 5) High (> 5) ha per class No bottom fisheries 1 bottom fishery 2 to 3 bottom fisheries > 3 bottom fisheries NOTES: a gc/m 2 /year = grams of carbon per square metre per year; this indicator is a proxy for how much annual vegetation growth occurs in an area per year b The 2010 Resource Options Report developed a fourth freshwater attribute to address the riparian footprint. This attribute was subsequently dropped due to lack of data for potential run-of-river sites and pumped storage, which would have made the comparisons ineffectual. c Priority fish are those that have been identified for conservation in the province of B.C. through the B.C. Conservation Framework, and then filtered to ensure native species and provincial range data d The 2010 Resource Options Report developed a third marine attribute of bathymetry, which is a descriptor of water depth. This attribute was subsequently not reported, given that it added negligible value compared with the other two marine attributes. Refer to Section for a description of the environmental attributes of individual Viable Alternatives Economic Development Attributes Economic development attributes describe the contributions that the available resources make to the provincial economy. The economic development attributes selected are categorized into three groups: provincial GDP, employment, and Provincial Government revenue, and are further broken down into sub-categories described in Table The British Columbia Input-Output Model was used to determine the economic development attributes, using a methodology and definitions similar to that in Volume 3 Appendix A Economic Assessment Supporting Documentation, Part 2 Project Economic Impact: BC Stats. 12 Table 5.25 Economic Development Attributes Economic Development Category Sub-Category Unit of Measure Classifications Provincial GDP Construction/Operation Dollars ($) and $/year Direct Indirect Induced Employment Construction/Operation Jobs Direct Indirect Induced Provincial Government revenue Construction/Operation $ and $/year Direct Indirect Induced Description of Available Resources This section presents an overview of the available resources. The available resource potential is screened only to remove sites from consideration if they were located in an 5-44

109 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project area where there would be legal or regulatory prohibitions; therefore, this results in a large volume of potential energy and dependable capacity with a wide range of costs, which may or may not be developed in the future. At a high level, this section is organized according to energy-rich available resources, followed by capacity-rich available resources. Technical and financial results are presented for each resource option where UECs and UCCs are shown at the POI. The summarized attributes of portfolios are examined in the portfolio analysis in Section Resource option data are reported by BC Hydro transmission region where the interconnection to the BC Hydro integrated system occurs. For comparison purposes, the UEC of the Project excluding sunk costs is about $94/MWh at POI ($F2013). See Volume 1 Appendix F Project Benefits Supporting Documentation, Part 1 Project Cost Estimate with respect to the calculation of the Project s UEC Run-of-River Hydroelectricity A run-of-river hydroelectric generation facility diverts a portion of natural stream flows and uses the natural drop in elevation of a river to generate electricity. Run-of-river projects divert some of a river s flow for power generation and leave the remaining flow in the original stream. A weir (i.e., a structure smaller than a dam used for storage hydro) is required to divert flows into the pipelines (referred to as penstocks) that lead to the power generation facility turbines. A run-of-river project either has no storage at all, or a limited amount of storage, in which case the storage reservoir is referred to as pondage. Some of the run-of-river generation facilities proposed and/or canvassed in the 2010 Resource Options Report rival traditional large hydroelectric facilities in scale and installed capacity. The expected life of run-of-river projects is about 50 years, with the maximum water licence term being 40 years. To date, BC Hydro run-of-river EPAs have typically had terms of between 30 to 40 years. Environmental Attribute Overview: Hydroelectricity is a clean or renewable resource as defined by Section 1 of the Clean Energy Act. Run-of-river projects have a number of environmental impacts, the most important of which is the impact to fish and aquatic ecosystems. Diverting river water can reduce river flows, affecting water velocity and depth, and potentially affecting habitat quality for fish and aquatic organisms. New access roads and transmission lines can cause habitat fragmentation for many species, introduce invasive species, and increase human activities such as illegal hunting. There may also be recreational impacts. Technical and Financial Attribute Overview: Run-of-river electricity is an intermittent source of energy with low amounts of dependable capacity because such facilities have little or no storage, and hence output is subject to seasonal river flows and cannot be co-ordinated to match customer demand. Run-of-river hydroelectric facilities generate more energy during times when seasonal river flows are high, such as the spring freshet, which coincides with reduced demand and low electricity prices in external markets. Generation drops during low flow periods. Figure 5.5 shows the power output of a typical run-of-river project in BC Hydro s Lower Mainland/South Coast region. Typically, the output from run-of-river projects is not predictable outside the spring freshet and cannot be regulated to match demand. Refer to Section in Volume 1 Section 7 Project Benefits for a discussion of how integrating variable available resources such as run-of-river and wind generation into the BC Hydro system requires 5-45

110 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project backup dispatchable capacity such as large hydroelectricity (the Project) or natural gas-fired generation. The 2010 Resource Options Report for run-of-river resources was undertaken in collaboration with Kerr Wood Leidal. The study used a Geographical Information System tool to assess the energy, capacity, and cost of selected potential run-of-river generating sites. A summary of the technical and financial results for run-of-river is contained in Table Table 5.26 Summary of Run-of-River Potential Transmission Region Number of Potential Sites Installed Capacity (MW) ELCC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) Peace River North Coast 315 2, ,527 6, Central Interior ,100 1, Kelly/Nicola ,429 2, Mica ,675 2, Revelstoke ,796 2, Vancouver Island 395 2, ,778 8, Lower Mainland 187 1, ,829 5, Selkirk ,886 1, East Kootenay ,593 2, Total 1,591 11,130 1,018 41,866 33, NOTE: The table presents results for run-of-river resources under $600/MWh Historically, some of the run-of-river resource options with the lowest unadjusted UEC values have not always bid into BC Hydro s power acquisition processes. BC Hydro examined the results of its two most recent broadly-based power acquisition processes, the 2009 Clean Power Call and the F2006 Call. The Clean Power Call is considered to be the best comparator derived from BC Hydro s power acquisition processes, given that it reflects the most recent BC Hydro power acquisition process pricing, and a large volume and broad array of clean, renewable technologies, including both hydro-based and wind-based projects. The Clean Power Call was open to any form of clean or renewable energy (excluding wood-based biomass, which was subject to a separate call for power), with 25 EPAs awarded in the spring/summer of 2010 for a total of 3,266 GWh/year of firm energy. Run-of-river projects made up about 50% of EPAs awarded pursuant to the 2009 Clean Power Call (by firm energy) and dominated the F2006 Call, the second most recent BC Hydro broadly based power acquisition process: The Clean Power Call weighted average levelized price is $109/MWh at plant gate ($F2013) The F2006 Call was undertaken over six years ago, resulting in a weighted average levelized adjusted plant gate price for large projects of about $86/MWh ($F2013) Onshore Wind Wind power refers to the conversion of energy from moving air into electricity. Modern utility-scale wind turbines are horizontal axis machines with three rotor blades. The blades convert the linear motion of the wind into rotational energy that is then used to drive a generator. Onshore wind is considered a mature technology; see, for example, 5-46

111 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Energy + Environmental Economics report (Energy + Environmental Economics 2012). The expected life of wind projects is about 20 to 25 years, although a recent British study concluded that the economic life of onshore wind turbines is between 10 and 15 years (Renewable Energy Foundation 2012). A shorter wind resource economic life would raise the per unit cost of energy produced (MWh). To date, BC Hydro wind EPAs have typically had terms of between 20 to 25 years. Environmental Attribute Overview: Wind is a clean or renewable resource, as defined by Section 1 of the Clean Energy Act. Wind resources do not use combustion to generate electricity and hence do not produce air emissions. Concerns have been raised over the noise produced by the rotor blades (in recent years, engineers have made design changes to reduce the noise from wind turbines), visual impacts (because wind energy resources are generally sited in exposed places, wind turbines are often visible), and deaths of birds and bats that fly into the rotors. Footprint impacts can also include new access roads and transmission lines. Technical and Financial Attribute Overview: Wind generation resources can have highly variable output over a time frame of minutes, hours, and days. Figures 5.6 and 5.7 show a sample wind resource generation profile over a sample eight-day period in June 2011 and January 2012, respectively. Due to this variability and the difficulty of accurately forecasting wind energy output, wind resources that are acquired by BC Hydro will result in new operating requirements and procedures. While BC Hydro has a large, flexible hydroelectric-based generation system that can manage this variability, the total system flexibility is limited. As a result, there are costs associated with managing wind variability that need to be recognized. Adding wind resources will require the carrying of appropriate additional reserves to compensate for sudden fluctuations in wind power in three different planning horizons: 1) regulation (minute to minute), 2) load following (minutes to hours), and (3) unit commitments/scheduling (hours to days). BC Hydro estimates that the wind integration cost is about $10/MWh generated. This total wind integration cost estimate is slightly higher than that used by Manitoba Hydro, but is comparable to the total wind integration cost estimates proposed by Hydro Quebec, the U.S. Pacific Northwest electric utility PacifiCorp, and the Bonneville Power Administration. The $10/MWh wind integration cost is not reflected in the UEC values set out in Table 5.27 below, but is included in the portfolio analysis in Section For the 2010 Resource Options Report, BC Hydro engaged DNV Global Energy Concepts Inc. to complete the Wind Data Study and Wind Data Study Update to obtain detailed information on the wind resource potential in B.C., and engaged Garrad Hassan to update the onshore wind costs. As noted above in Section , the 2010 Resource Options Report wind UECs have been revised (lowered) to take into account the changes in turbine efficiencies and wind turbine prices that have occurred over the past three years. A summary of the technical and financial results for onshore wind is contained in Table 5.27 using the revised wind costs. For comparison purposes, the average levelized plant gate cost of the approximately 50% of EPAs awarded for wind projects (by firm energy) through the Clean Power Call is $108/MWh ($F2013). 5-47

112 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project 1 Table 5.27 Summary of Onshore Wind Potential Transmission Region Number of Potential Sites Installed Capacity (MW) ELCC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI a ($F2013/MWh) Peace River North Coast Central Interior Kelly/Nicola Revelstoke Vancouver Island Lower Mainland Selkirk East Kootenay Total ,425 3, , NOTE: a The UECs shown do not include a wind integration cost adder of about $10/MWh Offshore Wind In addition to onshore wind potential, BC Hydro examined the potential of offshore wind turbines located in ocean substrate depths of up to 40 m. Onshore and offshore wind assessments are undertaken separately because of the differences in methodologies used to assess the resource potential, as well as differences in the financial cost assumptions. Technical and Financial Attribute Overview: The analysis is based on averaged wind speeds at 80 m hub height from the Canadian Wind Atlas, and gridded bathymetric data provided by the Canadian Hydrological Services. Modelled wind speeds from the Canadian Wind Atlas were compared to long-term wind speed estimates based on actual offshore observations. Garrad Hassan provided representative costs for offshore wind projects as a function of water depth. A summary of the technical and financial results for offshore wind are contained in Table Table 5.28 Summary of Offshore Wind Potential Transmission Region Number of Potential Sites Installed Capacity (MW) ELCC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) North Coast 36 12,873 3,090 41,991 41, Vancouver Island 7 2, ,270 8, Total 43 15,339 3,681 50,261 50, Wood-Based Biomass Wood-based biomass electricity is generated from the combustion or gasification of organic materials as fuels. In developing the potential of wood-based biomass, the following categories of fuels were considered: Standing timber (including wood killed by mountain pine beetles) 5-48

113 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Roadside wood waste (wood already harvested, but left in the forest or on the roadside; some is wood killed by mountain pine beetles) Sawmill wood waste To date, BC Hydro bioenergy EPAs have typically had terms of between 10 to 15 years. Environmental Attribute Overview: Biomass is a clean or renewable resource, as defined by Section 1 of the Clean Energy Act. Combustion of biomass produces local air contaminants such as particulate matter and oxides of nitrogen. The amount of carbon dioxide released when biomass is burned is nearly the same as the amount required to replenish the plants grown to produce the biomass. Thus, in a sustainable fuel cycle, there would be no net emissions of carbon dioxide, although some fossil-fuel inputs may be required for planting, harvesting, transporting, and processing biomass. Footprint impacts can also include new access roads and transmission lines. The environmental attributes used in the portfolio analysis only include the footprint for the facility site the footprint for fuel harvesting is not included. Technical and Financial Attribute Overview: BC Hydro engaged consultants from Industrial Forest Services Ltd., together with industry experts, to conduct a modelling study to estimate the long-term energy potential, costs, and possible locations for wood-based biomass projects. Overall, the study found that the amount of standing timber available for fuel was forecast to decline significantly over the next 15 years, but then stabilize after that. In addition, the study identified the availability of significant volumes of roadside and sawmill wood waste, but indicated that there was uncertainty regarding the actual potential that could be realized. Generally, when a secure fuel supply contract is in place, the installed capacity of wood-based biomass projects is considered dependable, and the annual energy production is considered firm. Biomass is generally not dispatchable. A summary of the technical and financial results for wood-based biomass is presented in Table BC Hydro has undertaken two wood-based biomass power acquisition processes, resulting in the following pricing: Bioenergy Phase I Call Request for Proposals (RFP) (2008/2009) with a levelized plant gate firm energy price of $111/MWh ($F2013). The Bioenergy Phase I Call RFP resulted in four EPAs for a total of 579 GWh/year of firm energy. Bioenergy Phase II Call RFP (2010/2011) with a levelized plant gate firm energy price of $123/MWh ($F2013). The Bioenergy Phase II Call RFP resulted in a total of 754 GWh/year of firm energy. 5-49

114 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project 1 Table 5.29 Summary of Wood-Based Biomass Potential Transmission Region Standing Timber Number of Potential Sites* Installed Capacity (MW) DGC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) Peace River North Coast ,602 1, Kelly/Nicola Vancouver Island ,850 2, Lower Mainland ,850 2, Selkirk East Kootenay Subtotal 11 1,060 1,060 8,447 8, Roadside Debris & Wood Waste Peace River North Coast Central Interior Kelly/Nicola Vancouver Island Lower Mainland Selkirk East Kootenay Subtotal ,499 3, Total 21 1,499 1,499 11,946 11, NOTE: For wood-based biomass, this reflects the number of fibre delivery locations considered in the study. The capacity figures shown reflect the total potential power generation (using multiple plants) based on the estimated fuel supply. In general, there is one fibre delivery location assumed for each forestry sub-region unless the potential is small. Wood-based biomass is considered further in the portfolio analysis. The only exception is the standing timber portion of wood-based biomass, which has been excluded due to cost and other uncertainty Biomass Municipal Solid Waste Municipal solid waste biomass refers to the conversion of municipal solid waste into a usable form of energy, such as electricity. Conventional combustion and gasification are the most commonly used municipal solid waste technologies. The municipal solid waste resource option potential is estimated based on fuel source availability, where an attempt was made to incorporate the zero waste philosophy that endeavours to minimize the amount of waste going to landfills by employing waste avoidance and diversion strategies. A summary of the technical and financial results for municipal solid waste is contained in Table

115 1 Table 5.30 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Summary of Municipal Solid Waste Biomass Potential Transmission Region Number of Potential Sites Installed Capacity (MW) DGC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) Vancouver Island Lower Mainland Selkirk Total Biomass Biogas or Landfill Gas Landfill gas is created when organic waste in a municipal solid waste landfill decomposes under anaerobic conditions. Landfill gas can be captured, converted, and used as an energy source to help prevent methane from migrating into the atmosphere and contributing to global climate change. Technologies for producing electricity from landfill gas include internal combustion engines, gas turbines, and micro turbines. In developing the landfill gas resource potential, BC Hydro reviewed a report by Golder (Golder 2008). A summary of the technical and financial results for biogas is presented in Table Table 5.31 Summary of Biogas Potential Transmission Region Number of Potential Sites Installed Capacity (MW) DGC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) Central Interior Kelly/Nicola Vancouver Island Lower Mainland Selkirk Total Biogas is not included in the portfolio analysis in Section because there has been only one biogas project with a small volume of energy bid into a 2003 BC Hydro power acquisition process, resulting in two EPAs Geothermal Geothermal energy systems draw on natural heat from within the earth s crust to drive conventional power generation technologies. The primary source of geothermal energy is radioactive decay occurring deep within the earth, supplemented by residual heat from the earth s formation and heat generated by earth s gravitational forces pulling dense materials into the earth s core. Geothermal electricity can be produced based on conventional or unconventional resources. Conventional resources are in the form of high or medium temperature steam or hot water associated with geological structures that bring heat relatively close to the earth s surface. Only conventional hydrothermal resources using flash or binary technologies are considered within BC Hydro s resource option assessment. There may be potentially significant unconventional resources that could increase the potential 5-51

116 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project geothermal resource base of B.C., including hot dry rock or low temperature hydrothermal resources in the sedimentary basin. Environmental Attribute Overview: Geothermal is a clean or renewable resource, as defined by Section 1 of the Clean Energy Act. Geothermal resources can have an effect on groundwater flow. Footprint impacts can include new access roads and transmission lines. Technical and Financial Attribute Overview: BC Hydro reviewed a number of external studies to develop its assessment of geothermal potential. A summary of the technical and financial results for the geothermal resource option is contained in Table The geothermal cost estimates are based on generic capital and operating/maintenance costs using U.S. industry experience, with an adjustment for climate and topography in B.C. These values do not account for a relatively higher exploration risk that is expected for B.C. greenfield geothermal resources. Development of greenfield geothermal resources is associated with a relatively higher rate of drilling program failure in the exploration stage, which can add to the development costs and the UEC of a given project, especially for smaller projects. Due to this expected higher exploration risk and the higher costs associated with failed exploration wells of B.C. resources relative to the generic U.S. industry average, the estimates shown are likely to be low. 19 Table 5.32 Summary of Geothermal Potential Transmission Region Number of Potential Sites Installed Capacity (MW) DGC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) Peace River North Coast ,111 2, Kelly/Nicola Revelstoke Vancouver Island Lower Mainland ,505 2, Selkirk Total ,992 5, NOTE: The summary table excludes two sites that are technically inaccessible (e.g., within a protected area or within an area that exceeds technical criteria established for road or transmission access) B.C. s geothermal resource is estimated to total more than 700 MW of potentially cost-effective clean or renewable power. However, BC Hydro has not included the geothermal resource option in the portfolio analysis in Section for the following reasons: As described above in Section , historically, resource options with the lowest unadjusted UECs values have not always bid into BC Hydro s power acquisition processes. Despite its relatively low cost (an unadjusted UEC of $88/MWh in $F2013), geothermal resource developers have never bid into BC Hydro s power acquisition processes. From the 2010 Resource Options Report, BC Hydro understands that there are some challenges with geothermal development in B.C. related to the risk/reward of making a significant upfront capital investment at the early exploration and initial production drilling stages. 5-52

117 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project There are no commercial geothermal electricity projects in B.C. at this time. Since 2002, the B.C. Ministry of Energy, Mines and Natural Gas has released geothermal permits to developers at 12 locations in the province, but these have not resulted in any significant investments in exploration. The only significant private sector investment in exploration was led by Sierra Geothermal (now Ram Power) in 2004 at South Meager Creek; however, the multi-million dollar drilling program failed to yield geothermal wells useful for geothermal power production Natural Gas-Fired Generation and Cogeneration Natural gas-fired units generate electricity using the heat released by the combustion of natural gas: CCGTs are an energy and capacity resource. CCGTs use the combination of combustion and steam turbines to generate electricity. Exhaust gases from a combustion turbine flow to a heat recovery steam generator that produces steam to power a steam turbine, resulting in higher efficiencies than those achievable by operating the combustion or steam turbines individually. CCGTs have a relatively high efficiency in converting fuel to electricity in comparison to other thermal generation. Conversion efficiencies are typically about 55% to 60% for CCGTs. SCGTs are a capacity resource. SCGTs are stand-alone generating plants that use combustion gases to propel a turbine similar to a jet engine connected to an electrical generator. SCGTs are less efficient than CCGTs in converting fuel to electricity. Conversion efficiencies are typically about 35% to 40% for SCGTs. Cogeneration is the simultaneous production of electrical and thermal energy from a single fuel. Cogeneration involves thermal power generation and a steam/thermal host to use the excess heat produced from the generating process. Steam/thermal hosts may include industries and institutions that need heat such as pulp mills, greenhouses, or hospitals. The efficiency of cogeneration plants is typically about 80% or less, depending on the nature of the steam host. Large hydroelectric resources such as the Project, with hydroelectric conversion efficiencies of up to 95%, are more efficient at power generation than thermal resources such as natural gas. Natural gas-fired generation raises unique legal and policy issues in B.C. Clean Energy Act Considerations Section 2 of the Clean Energy Act sets out two of British Columbia s energy objectives which are relevant to the role of natural gas-fired generation: The first, described in Part 1, is found in Subsection 2(c) and provides: to generate at least 93% of the electricity in British Columbia from clean or renewable resources. The definition of clean or renewable resources in Section 1 of the Clean Energy Act does not include natural gas-fired generation. The second, described in Part 2, is contained in Subsection 2(g) of the Clean Energy Act, setting out the B.C. Government s legislated GHG emission reduction targets 5-53

118 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Part 1: Clean Energy Act Clean or Renewable Target BC Hydro currently has five natural gas-fired generating facilities in its system: 1) Burrard [However, as described above, no energy is assumed from Burrard for planning purposes as a result of Subsection 3(5) and 6(2)(b) of the Clean Energy Act. Burrard cannot be relied on for dependable capacity after Mica Unit 6 goes into service in about 2016 as a result of the Burrard Thermal Electricity Regulation.], 2) Fort Nelson Generating Station, 3) Prince Rupert Generating Station, 4) Island Generation Plant (IPP), and 5) McMahon Cogeneration Plant (IPP). These facilities contribute 3,520 GWh/year of firm energy to the system, and account for more than 5% of the space currently available for natural gas-fired generation under the 93% clean or renewable target. Thus, little space is left for developing new natural gas-fired generation. Table 5.33 sets out the maximum GWh of new natural gas-fired generation that could be built in F2022, assuming the 2012 Load Forecast after DSM without LNG load. Table 5.33 also shows the number of MW of new natural gas-fired generation that could be built by F2022 (the Project s earliest in-service date). 17 Table 5.33 Determination of Permissible Natural Gas-Fired Generation Year Space available for natural gas-fired generation (7% of total generation energy requirements used as a proxy for generation) Energy contribution from existing natural gas-fired generation (GWh) Permissible volume of new natural gas-fired generation that could be built (GWh) Associated MW of new natural gas-fired generation (CCGT) (90% capacity factor) Associated MW of new natural gas-fired generation (SCGT) (18% capacity factor) F2022 4,356 GWh 3,520 GWh 836 GWh 106 MW 530 MW Therefore, neither CCGTs nor SCGTs are an alternative to the Project on their own; they must be combined with clean or renewable resources to compare against the Project s 5,100 GWh/year of average energy and 1,100 MW of dependable capacity. Refer to the portfolio analysis in Section BC Hydro is relying on the remaining GWh of natural gas-fired headroom to facilitate future SCGT capacity needs under contingency circumstances (refer to Section 5.2.3). Part 2: GHG Offset Requirement Subsection 2(g) of the Clean Energy Act sets out the B.C. Government s legislated GHG emission reduction targets. In addition, Policy Action No. 18 of the 2007 Energy Plan provides that all new natural gas-fired generation must have zero net GHG emissions. This requirement is legislated pursuant to Part 6.1 of the B.C. Environmental Management Act. While, to date, regulations to bring Part 6.1 of the Environmental Management Act have not been enacted, it is likely that as part of the BCEAA process, which would be triggered by a proposal to construct a CCGT or SCGT with a nameplate capacity of 50 MW or greater, a 100% offset requirement would be imposed through EAC conditions. BC Hydro has factored in GHG offset costs into the UEC values. Environmental Attributes Overview: Natural gas-fired generation can have land use impacts for the facility itself and extension to the transmission grid. The environmental attributes only include the footprint of the facility itself the footprint for fuel extraction is not included. 5-54

119 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project The products of natural gas combustion include the following air contaminants: NO x, sulphur dioxide (SO 2 ), carbon monoxide, and PM. These are known as primary emissions. In addition, NO x is a precursor to ground-level ozone and can lead to its formation in the ambient air. Along with SO 2, NOx is also a precursor of secondary particulate matter. There are known health and environmental effects associated with all of the aforementioned contaminants. Natural gas-fired generation also emits carbon dioxide, methane, and nitrous oxide, which are GHGs. The GHG emissions of a SCGT facility with a nameplate capacity of 500 MW (18% capacity factor) are about 376,000 tonnes of CO 2 e/year. (The SCGT GHG emission factor is about 477 tonnes of CO 2 e per GWh). Metro Vancouver, the regulator in the Lower Mainland, has taken the position that it will not approve any new natural gas-fired generation in the Lower Mainland. Accordingly, for EIS alternative comparison purposes, BC Hydro assumed that a CCGT or SCGT will not be located in the Lower Mainland. The following provides a high level overview of the major permitting requirements for natural gas-fired generation outside the Lower Mainland. CCGT: Siting a 100 MW CCGT triggers the following material regulatory approvals: An EAC under BCEAA from the B.C. Minister of Energy, Mines and Natural Gas, and the B.C. Minister of Environment, as the replacement CCGT will exceed the B.C. Reviewable Projects Regulation threshold of a new powerplant with a nameplate (rated) capacity of 50 MW or greater Air emission permit from the B.C. Ministry of Environment under EMA. CCGTs emit NO x, coarse and fine PM, sulphur dioxide, and ammonia (the latter as part of the select catalytic converter process to reduce NO x emissions), all of which can impact human health, as well as livestock and agricultural crops. The impact would depend in part on ambient (background) air quality. The public would be involved pursuant to the Public Notification Regulation (B.C. Reg. 202/94). Assuming permitting could be secured and no legal challenges to the issuance of permits, the 2010 Resource Options Report indicates that lead times for new CCGTs would be about five years. SCGT: BC Hydro s 2010 Resource Options Report indicates similar lead times for SCGTs as CCGTs. With one exception, SCGTs would trigger similar regulatory approvals for siting CCGTs, including the requirement for an air emission permit from the B.C. Ministry of Environment. As the associated MW of SCGTs is over 200 MW under the Clean Energy Act clean or renewable target (see Table 5.33), in the context of this alternative analysis, SCGTs would also trigger CEAA, because the alternative SCGT is a fossil fuel-fired electrical generating station with a production capacity of 200 MW or more (Regulations Designating Physical Activities SOR/ , schedule, Section 2): It may be easier to site SCGTs, given that they do not run as often as CCGTs and therefore do not emit as many air contaminants However, the newly released performance standard for coal-fired generation of 420 tonnes of CO 2 e per GWh contained in the Federal Government s Carbon Dioxide Emissions from Coal-Fired Generation of Electricity Regulations (SOR/ ) may challenge new SCGTs. The 420 tonnes of CO 2 e per GWh performance standard is the GHG emission intensity level of a CCGT. 5-55

120 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Technical and Financial Attribute Overview: Natural gas-fired generation is dispatchable, that is, natural gas-fired generation can adjust power output on demand. The time periods in which dispatchable natural gas-fired generation can be turned on or off may vary, but can be considered in time frames of minutes or hours. This may be contrasted with intermittent clean or renewable resources such as run-of-river and wind, which cannot be controlled by operators. Natural gas-fired generation provides firm energy and dependable capacity. In contrast to the Project and other clean or renewable resources such as run-of-river, a material portion of the costs of natural gas-fired generation is incurred during operations, due mainly to the cost of fuel. For example, the Project construction and development costs are about 85% of the overall costs, with operating, sustaining capital, and fuel costs (mainly water rentals) comprising the other 15%. For SCGTs, construction and development costs are about 20% of the overall costs, with operating and fuel costs comprising the remaining 80% of the overall costs. Refer to Section in Volume 1 Section 7 Project Benefits for additional detail. As a result, natural gas-fired generation has greater variable cost uncertainty when compared to clean or renewable resources. The two material variable cost risks are: Fuel price risk: This is the risk that the price of natural gas used to generate electricity will exhibit variability over the course of the 25-year to 30-year expected life of a natural gas-fired generating station. Among the fuels most commonly used to generate electricity, natural gas is the most volatile in price. The most significant recent development to affect natural gas prices has been the emergence of shale gas; long-term natural gas prices have dropped due to advancements in gas extraction technologies and the increase in shale reserves. Because there is future natural gas price uncertainty, BC Hydro does not rely on a single natural gas price forecast. Rather, BC Hydro uses a scenario-based approach employing a range of future natural gas prices developed by Ventyx. The mid Ventyx forecast for natural gas at the Sumas, B.C., hub price is between about $3 per gigajoule (GJ) to $7/GJ ($F2013) over the next 30 years and is used in the portfolio analysis in Section Regulatory risk: GHG costs. The requirement that all new B.C.-based natural gas-fired generation have zero net GHG emissions is discussed above. The financial risks associated with GHG regulatory actions the market price for GHG offsets turns on the flexibility of compliance mechanisms. For example, is there flexibility to offset GHG emissions outside the Province of British Columbia? While the B.C. Greenhouse Gas Reduction (Cap and Trade) Act (S.B.C. 2008, c.32) contemplates such flexibility through eventual linkage of a B.C.-based cap-and-trade system (the B.C. cap-and-trade system would come into force by issue of a government regulation, which is currently in the consultation stage) to other systems, to date there is no western regional or continent-wide GHG cap-and-trade system. A GHG market confined to B.C. is likely to be more costly than a larger market. BC Hydro adopted a scenario approach to the impact of GHG offset price variability based on Ventyx s GHG price forecast. The GHG price forecasts provide a wide range of possible future GHG offset prices that capture a range of economic and policy scenarios. The low GHG price is the carbon tax at $30/metric tonne of CO 2 e, and is used in the portfolio analysis in Section The high GHG price is about $173/metric tonne of CO 2 e ($F2013, levelized between 2022 and 2046) and is 5-56

121 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project reflected in the upper financial attribute values for CCGTs (UEC, Table 5.34) and SCGTs (UCC, Table 5.35). Combined Cycle Gas Turbines and Cogeneration BC Hydro undertook an in-house update of the cost and performance characteristics of gas-fired generation units potentially located in the Kelly Lake/Nicola area in the interior of B.C. BC Hydro also undertook an in-house update for potential cogeneration units in the Lower Mainland. A summary of the technical and financial results for these natural gas-fired generation resource options is contained in Table Table 5.34 Summary of CCGT and Small Cogeneration Gas-Fired Generation Potential Resource Option Number of Potential Sites Installed Capacity (MW) DGC (MW) Total Energy (GWh/year) Firm Energy (GWh/year) Unit Energy Cost at POI ($F2013/MWh) 50 MW CCGT in Kelly/Nicola MW CCGT in Kelly/Nicola ,450 1, Small cogeneration in Lower Mainland ,600 1, NOTES: Representative project used to characterize the resource option. Energy is based on a 90% capacity factor and UECs include associated fuel and GHG costs. Natural gas-fired generation options are based on natural gas price estimates for the period using the Ventyx spring 2012 medium levelized forecast of $5.37/GJ ($F2013), which is the most likely forecast Simple Cycle Gas Turbines BC Hydro undertook an in-house update of the cost and performance characteristics of a representative 100 MW SCGT unit in Kelly/Nicola. The UCC range is shown in Table Table 5.35 Summary of SCGT Potential Transmission Region Number of Potential Sites Installed Capacity (MW) DGC (MW) Unit Capacity Costs at POI ($2013/kW-year) 100 MW SCGT in Kelly/Nicola NOTES: UCCs for SCGTs are based on an 18% capacity factor and include associated fuel and GHG costs Natural gas-fired generation options are based on natural gas price estimates for the period using the Ventyx 2012 spring medium levelized gas price forecast of $5.37/GJ ($F2013) Resource Smart BC Hydro s Resource Smart program identifies potential efficiency gains at existing BC Hydro hydroelectric facilities. Resource Smart projects result in 1) increased turbine efficiencies, and/or 2) increased nameplate capacity of turbines. Resource Smart opportunities are limited to BC Hydro s 30 existing hydroelectric facilities. In recent years, BC Hydro has implemented or is implementing a number of 5-57

122 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project such opportunities. Examples already included in BC Hydro s resource stack as committed resources (discussed above in Section ) are: The addition of an approximately 500 MW fifth unit at Revelstoke Generating Station in the B.C. Interior (Revelstoke Unit 5, in-service in F2011) Two additional approximately 500 MW units at Mica Generation Station (increasing capacity by approximately 1,000 MW) in the B.C. Interior (Mica Units 5 and 6, expected to be in-service in F2015 and F2016, respectively) G.M. Shrum Units 6 to 8, providing capacity Increase of about 90 MW (in-service in F2012) on the Peace River Replacing the runners at Ruskin Generating Station in the Lower Mainland, with about a 9 MW dependable capacity increase and 28 GWh/year of additional energy The largest remaining Resource Smart project identified in terms of additional dependable capacity is Revelstoke Unit 6. Revelstoke Unit 6 is not an alternative to the Project, as it is a resource that is already included in the LRBs for purposes of this EIS; refer to Section above. Environmental Attribute Overview: Resource Smart projects generally occur within the existing hydroelectric facility footprint. Resource Smart projects may change hydroelectric facility operations (i.e., reservoir fluctuations and/or downstream flows). Technical and Financial Attribute Overview: Table 5.36 is a list of potential additional Resource Smart projects. 21 Table 5.36 Summary of Resource Smart Potential Resource Smart Option G.M. Shrum Units 1 5 capacity increase (Peace River) Cheakamus generator upgrade (Whistler area, Lower Mainland) Strathcona additional unit (Campbell River, Vancouver Island) Ladore additional unit (Campbell River, Vancouver Island) Ash River additional unit (Ash River, Vancouver Island) Puntledge additional unit (Puntledge River, Vancouver Island) Duncan Dam new generation (Duncan River/Columbia River area) Lajoie additional unit (Bridge River/Fraser River area) Replace runners at Seven Mile Generating Station (Pend-d Oreille River, Interior) Energy (GWh) UEC at POI ($/MWh, $F2013) Capacity (MW) UCC at POI ($/kw-year, $F2013) 0 N/A (about 44 MW per unit) N/A Resource Smart projects contained in the above table would typically be implemented at the time of other necessary safety and reliability-related upgrades at the named 5-58

123 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project BC Hydro hydroelectric facilities. Resource Smart projects typically require BCUC approval prior to implementation; two recent examples are the Ruskin Dam and Powerhouse Upgrade Project and the John Hart Generating Station Replacement Project (BCUC decision pending). BC Hydro is not currently anticipating undertaking the G.M. Shrum Units 1 5 Capacity Increase project because over the next 10 years, BC Hydro will be upgrading most of the 10 G.M. Shrum Generating Station units through other projects, making the undertaking of the GM Shrum Units 1 5 Capacity Increase project difficult during that time frame. BC Hydro notes that the G.M. Shrum Units 1 5 Capacity Increase project is not an alternative on its own to the Project, as it only defers the need for capacity by two years Pumped Storage Pumped storage hydro units are capacity resource options and use electricity from the grid, typically during light load hours, to pump water from a lower elevation reservoir to an upper elevation reservoir. The water is then released during heavy load hours to generate electricity. Reversible turbine/generator assemblies or separate pumps and turbines are used in pumped storage facilities. Pumped storage units are a net consumer of electricity due to inherent inefficiencies in the pumping-generating cycle, which result in recovery of about only 70% of the energy used. Environmental Attribute Overview: The construction of greenfield pumped storage facilities usually creates reservoirs, thus leading to land loss and impacting vegetation and wildlife. It may be possible to use natural bodies of water for reservoirs or using pre-existing dams, thus minimizing this impact. BC Hydro looked at both potential greenfield pumped storage facilities in the Lower Mainland and on Vancouver Island, and at the possibility of pumped storage at BC Hydro s existing Mica Generating Station in the Interior. Operationally, pumped storage can lead to rapid and frequent changes in water reservoir levels, which can impact fish and fish habitat through reduction in the wetted littoral zone (close to shore to about a maximum of 10 m or so in depth, where a large part of biological production occurs), changes to water velocity/directions and temperature, and increased erosion. Pumped storage facilities can create changes in land use through an extension to the transmission line grid. There are no commercial pumped storage facilities in B.C., and only one pumped storage facility operating in Canada, which was permitted in the 1950s. Siting a pumped storage facility in B.C. triggers a number of regulatory/government agency approvals, including: A Course of Action Decision under CEAA, because in the context of this EIS, pumped storage is a hydroelectric generating station with a production capacity of 200 MW or more (Regulations Designating Physical Activities SOR/ , schedule, Section 2) An EAC under BCEAA, because pumped storage facilities will exceed the B.C. Reviewable Projects Regulation threshold of a new powerplant with a nameplate (rated) capacity of 50 MW or greater Technical and Financial Attribute Overview: The ability to store water and release it during times of system need makes pumped storage a useful capacity resource. Pumped storage hydro units can respond quickly to variations in system demand and 5-59

124 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project can provide ancillary services such as voltage regulation. As described above, pumped storage consumes energy due to the inefficiencies in the pumping-generation cycle. BC Hydro engaged Knight Piésold Ltd. to identify greenfield pumped storage potential in the Lower Mainland and Vancouver Island regions, and engaged Hatch Ltd. to assess the cost of installing a pump-turbine or a pump at Mica Generating Station. A summary of the technical and financial results for the pumped storage resource option is contained in Table As pumped storage is considered a capacity option, only the unit capacity cost is shown. 9 Table 5.37 Summary of Pumped Storage Potential Transmission Region Number of Potential Sites Installed Capacity (MW) DGC (MW) Unit Capacity Costs at POI ($F2013/kW-year) Kelly/Nicola 4 4,000 4, Mica Vancouver Island 84 79,000 79, Lower Mainland , , Total , , NOTE: UCCs for pumped storage include fuel costs using an 18% capacity factor and 30% energy loss factor Summary of Available Resources The UEC results are summarized in Table The UEC for the Project are included for comparison purposes. 13 Table 5.38 UECs of Available Energy Resource Supply Options 14 Energy Resource Total FELCC Energy (GWh/year) Total DGC or ELCC Capacity (MW) Unit Energy Costs at POI ($F2013/MWh) Biomass wood based 11,946 1, Biomass biogas Biomass municipal solid waste Wind onshore 46,165 38,885 3, Wind offshore 50,261 3, Geothermal 5, Run-of-river 33,619 35,880 1,018 1, Site C Clean Energy Project 4,700 1, CCGT and cogeneration 7, The UCCs of the supply-side capacity resource options are summarized in Table Revision 1- July 19, 2013

125 1 Table 5.39 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project UCCs of Available Capacity Resource Supply Options Resource Type Capacity Options Dependable Capacity (MW) Unit Capacity Costs at POI ($F2013/kW-year) SCGT Various Locations Pumped Storage Various Locations 1, Resource Smart Various Locations About Portfolio Modelling Framework In addition to assessing available resources as reflected in Section 5.5.2, BC Hydro analyzed the available resources through portfolio analysis to determine whether the Project is the preferred option to serve the need identified in Section 5.2: Section provides details regarding the portfolio-related models, modelling constraints, and input parameters Section discusses the portfolio results. The portfolio results indicate that the Project is a cost-effective resource option compared to the available resources Introduction to Portfolio Analysis Portfolio analysis is a process of developing and evaluating resource portfolios, each consisting of a sequence of supply-side and demand-side resources to meet the energy and capacity needs of BC Hydro s customers. In its 2006 IEP/LTAP Decision, the BCUC stated that a portfolio analysis is consistent with the Commission s Guidelines, and is a best practice for IEP or IRP analysis (BCUC 2006). In general, portfolios were created in this analysis for the planning period from F2015 to F2041. Each portfolio contains BC Hydro s current DSM target. The portfolio analysis for the Project examined how the Project compares to combinations of available resources. This analysis was conducted by comparing portfolios including the Project against portfolios of resources that excluded the Project but combining available resources that provide approximately the same amount of energy and capacity. In general, these alternatives are composed of multiple available resource projects, as most alternatives to the Project are not capable of delivering comparable amounts of energy and dependable capacity on their own. BC Hydro compares portfolios based on portfolio technical, financial, environmental, and economic development attributes. Figure 5.8 shows a schematic of the overall process for developing portfolios and analyzing the results. The following sections provide a more detailed discussion of the components of the process Portfolio Analysis Process and Models BC Hydro s portfolio analysis uses a suite of models: Hydrological system simulation model (HYSIM) System Optimizer Multi-Attributes Portfolio Analysis 5-61

126 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project HYSIM is a BC Hydro-developed model. It is a system production cost model, which runs through 60 years of water records in modelling the large hydro system. HYSIM provides insight on how water variability may impact portfolio performance. It develops the monthly generation profile for the large hydro system that is an input to System Optimizer. For additional details on HYSIM, please see Section 11.4 in Volume 2 Section 11 Environmental Background. Resource portfolios were developed using System Optimizer, a product of Ventyx that has been adopted by several utilities in North America. System Optimizer is a deterministic linear optimization model that selects an optimal resource expansion sequence (referred to as a portfolio) of generation and transmission additions for a given set of input assumptions. System Optimizer minimizes the present value of net costs, including the incremental fixed capital and operating costs for new resources and total system production costs (inclusive of trade revenues), to meet a given load based on BC Hydro s planning criteria. System Optimizer does not capture either resource delivery risk, or the value of ancillary benefits (such as the ability to integrate intermittent resources and firming capability), which could be significant for resources such as the Project. The benefits of the Project are described in Volume 1 Section 7 Project Benefits. Multi-Attributes Portfolio Analysis is a BC Hydro-developed model. It takes the portfolio output from System Optimizer and tracks the various attributes (e.g., environmental and economic development attributes as described in Section 5.5.1) for the portfolios Modelling Constraints The portfolios created satisfy good utility practice (e.g., they meet reliability criteria). Two Clean Energy Act objectives are treated as constraints: 1) achieve self-sufficiency, and 2) meet the 93% clean or renewable energy target described in respect of natural gas-fired generation in Section In addition, the 2007 Energy Plan requirement that natural gas-fired generation GHG emissions be completely offset is treated as a modelling constraint. As discussed in Section , the Clean Energy Act objective of BC Hydro to reduce the increase in demand for electricity by the year 2020 by at least 66% is reflected in the DSM Target. As a result, all portfolios considered have at least 66% of forecast demand met by DSM based on the December 2012 mid Load Forecast Financial Parameters Costs are expressed on a present value basis to capture the impact of the timing of costs and trade revenues over the planning horizon. The portfolio analysis results are expressed in $F2013 dollars. The present values of the portfolios reflect the costs (or levelized costs, where appropriate) for the planning period F2015 to F2041. It is expected that extending the planning period beyond F2041 would increase the additional value of a portfolio with Project relative to one without the Project, reflecting the Project s long expected life. The key financial parameters in the portfolio analysis are described below. Inflation Rate Where nominal and real dollar conversion was necessary, a rate of 2% was assumed as the average inflation rate outlook. This inflationary assumption is consistent with the B.C. Consumer Price Index, which is provided in the Province of B.C Budget and Fiscal Plan. Aside from the annual inflationary assumption, the portfolio analysis assumes no other incremental cost escalation or inflationary allowance for capital costs Revision 1 July 19, 2013

127 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Discount Rate BC Hydro used a 6% real discount rate in the portfolio cost assessments. Cost of Capital Policy Action #13 of the Provincial Government s 2002 Energy Plan (page 30) provides that the private sector (i.e., IPPs) will develop new electricity generation, with BC Hydro restricted to improvements at existing plants (such as Resource Smart projects) and the Project. The BCUC in its 2006 IEP/LTAP Decision, page 205, found: the [BCUC] panel agrees with BC Hydro [and the customer intervenors] that project evaluation methodology must consider the actual costs, benefits, risks and other characteristics of individual projects that may be relevant to cost-effectiveness, and should not seek to artificially compensate for real differences in projects costs, including possible differences in the cost of capital between BC Hydro and other developers. With respect to the cost of capital, BC Hydro projects will clearly have an advantage as a result of access to the Province s high credit rating. [Emphasis added]. BC Hydro is an agent of Her Majesty the Queen in the right of the Province of British Columbia. BC Hydro s borrowing is guaranteed by the Province; BC Hydro can also borrow directly from the Province. BC Hydro s weighted average cost of capital (the overall costs of combined debt and equity capital used to finance an acquisition) is 5.5% (real), which is rounded upwards to 6% (real) for purposes of this EIS and the portfolio alternatives evaluation. It is widely acknowledged that the private sector, including IPPs, has higher borrowing costs than governments such as the B.C. Government. Consistent with the BCUC s 2006 IEP/LTAP Decision, BC Hydro used a higher weighted average cost of capital for the available resource portfolios, as these would be developed by IPPs. Based on its experience with negotiating with IPPs and other third-party developers, BC Hydro used a weighted average cost of capital of 8% (real) for IPPs for purposes of this EIS. In a study for the Western Electric Coordinating Council, Energy + Environmental Economics used an after tax weighted average capital cost for IPPs of 8.25% (Energy + Environmental Economics 2012). U.S./Canadian Exchange Rate Assumptions about the U.S. to Canadian dollar are required for the conversion of market price forecasts. The conversion rate assumption is $0.97 U.S/Cdn. GHG Offset Cost BC Hydro has explicitly considered the cost to offset GHG emissions from natural gas-fired generation because this will become financial liabilities for BC Hydro customers as a result of the requirement to completely offset such GHG emissions. BC Hydro conservatively used the lowest GHG offset cost of $30/t of CO 2 e, based on the B.C. carbon tax for the portfolio analysis. Refer to Section for a discussion of higher GHG offset price scenarios. 5-63

128 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Soft Cost Adder As described above in Section , the Project cost estimate includes costs for mitigation measures, regulatory review, First Nation consultation, and public engagement. The UECs and UCCs for available resources set out in Section do not include such costs. Implementation of the available resources would entail mitigation, regulatory review, First Nation consultation, and public engagement costs (called soft costs). For example: Replacing the Project s dependable capacity contribution of 1,100 MW requires either 1) a large replacement pumped storage facility, which would trigger both CEAA and BCEAA, and would have environmental effects described in Section , or 2) a combination of SCGTs and pumped storage. A replacement SCGT would trigger BCEAA, CEAA, and air emission permitting requirements (refer to Section ). Replacing the Project s average energy contribution of 5,100 GWh/year would entail acquiring clean or renewable intermittent resources such as wind resources. All wind projects awarded EPAs triggered BCEAA because they have a nameplate capacity of 50 MW or greater; refer to Table 5.40 below. The table of mitigation-related commitments appended to EAC E06-03 issued in respect of Dokie Wind Project is several pages in length. 20 Table 5.40 BC Hydro EPA Wind Projects and BCEAA Trigger Project Nameplate Capacity (MW) Bear Mountain 102 Dokie Wind 144 Quality Wind 142 Cape Scott 99 Tumbler Ridge 45 Wildmare 77 Meikle 117 Bull Moose BC Hydro has put a cost adder of 5% on available resource portfolios to reflect the fact that implementing the available resource options would entail soft cost expenditures. BC Hydro chose 5% on the basis of its experience; for example, the environmental assessment, First Nation, and stakeholder engagement costs of a sample of recent representative BC Hydro capital projects ranged from 0.02% to about 10%. Sunk Costs A key concept in understanding the portfolio analysis is the concept of incremental costs. The incremental cost approach focuses on examining how costs change based on potential alternatives. Sunk costs, which are costs that have been incurred prior to the current analysis, are not relevant for purposes of the incremental cost analysis. Accordingly, the Project-related sunk costs (about $5/MWh) have been removed for purposes of the portfolio analysis. 5-64

129 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Load, Market and Transmission Parameters Load/Resource Balance Assumptions Portfolios were created and evaluated across the base LRB gap (Mid-level 2012 Load Forecast, existing and committed resources, the current BC Hydro DSM target, Revelstoke Unit 6; refer to Section ). Market Energy Price Assumptions Using costs to compare portfolios requires estimating the costs and trade revenues of each portfolio operating over the planning time frame. These operating costs and revenues are affected by market price assumptions, including the market prices of natural gas, GHG, and electricity. BC Hydro used the Ventyx Spring 2012 market price forecast in the portfolio analysis. This Ventyx forecast assumes slower economic growth and is the basis for BC Hydro s most likely market price forecast. The forecast of Mid-Columbia spot market electricity price is the hourly price for buying and selling surplus electricity at a trading hub near the Washington/Oregon border. In the portfolio analysis in Section BC Hydro uses a forecast of Mid-Columbia spot market electricity prices ranging from about $25/MWh to $50/MWh (with a further adjustment for the costs of wheeling and losses to the B.C. border) over the next 30 years. Transmission Assumptions The analysis of the long-term transmission requirements is based on BC Hydro s Integrated System Planning Criteria. These criteria define BC Hydro s guidelines for planning a reliable transmission network that is adequate for dispatching designated generation resources to serve the forecasted demand. For system performance under normal and emergency conditions, BC Hydro s planning criteria conform to the BCUC-approved North American Electric Reliability Corporation (NERC) Reliability Standards for transmission planning. In accordance with the criteria, the System Optimizer identifies where and when incremental transmission capacity will be required for a particular portfolio. System Optimizer first selects a set of applicable wire or non-wire transmission options for removing congestion from an existing transmission path by adding incremental transfer capacity to the constrained path. The result is reviewed and, if needed, the reinforcement requirements are adjusted. The present values of the portfolios reflect these adjustments Characterization of Portfolio Attributes Once the System Optimizer creates portfolios for each scenario, the Multi-Attributes Portfolio Analysis process is used to determine the financial, technical, environmental, and economic development characteristics of each portfolio. Please see Section for a more detailed description of the attributes. The portfolio attributes are summarized at a level appropriate for comparing the Project against other portfolios using consequence tables. A consequence table is a collection of the above information arranged in a matrix format so that the Available Resource options considered are displayed as column headers, the relevant decision objectives are displayed as row labels, and for each row, the specific units of measurement are provided. While some judgment is required to reduce the full analysis down to a 5-65

130 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project condensed level, this view allows a reader to easily see the relative impacts of Available Resource options across alternatives and decision objectives Uncertainties and Risks Not Captured by Portfolio Modelling Key uncertainties and risks include the following: Current DSM Target The portfolio modelling assumes that the current DSM target will deliver the expected energy and dependable capacity savings Expected Life The Project is expected to have a life of more than 100 years. In contrast, EPAs with IPPs for available resources have varying durations that are shorter, ranging from 15 to 40 years (refer to Section for each available resource that has been the subject of prior BC Hydro power acquisition processes such as run-of-river, wind and bioenergy). As described in Section 5.2.3, at the end of EPA terms, there is significant supply and price risk to BC Hydro because there is no assurance that 1) IPP available resource-related projects will continue operations past the expiry of EPAs, 2) that IPPs will contract with BC Hydro if they do continue to operate, or 3) that IPPs will contract at a price comparable to their current real-dollar prices. IPP Attrition Risk The portfolio modelling does not reflect the relatively high IPP attrition rate that BC Hydro has observed through its power acquisition processes. If BC Hydro were to pursue some combination of available resources instead of the Project, it would likely have to award EPAs representing more energy than the lost Project contribution of 5,100 GWh/year of average energy. Regulatory Risk The portfolio model does not account for available resource development and regulatory risk. If BC Hydro were to pursue available resources, the EPAs with IPPs must be filed with the BCUC for acceptance pursuant to Section 71 of the Utilities Commission Act. BC Hydro qualitatively described available resource development and regulatory risks above in Section 5.5.2; see, for example, SCGTs (air emission permitting) and pumped storage (only one such facility permitted to date in Canada) Portfolio Evaluation Results This section compares the technical, financial, environmental, and economic development attributes of portfolios with and without the Project. Volume 1 Appendix D Part 4 Portfolio Attributes provides additional detail on the full suite of attributes described in Section High-level environmental footprints and economic development attributes are used for comparison of resource options across provincial-scale portfolios, and act as proxies for more detailed environmental, social, and heritage effects of potential projects. Since detailed site-specific information is unknown for the majority of the potential sites in the database, detailed environmental, social, and heritage attributes are not possible, or intended to be used, for individual site-specific resource option evaluations and comparisons Portfolio Development To compare the Project to available resources, BC Hydro built a number of portfolios including the Project and excluding the Project. Three categories of portfolios were established, using different assumptions regarding available resources: Site C Portfolios that include the Project, with the remaining energy and capacity gap being filled using clean or renewable generation resources Revision 1 July 19,

131 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Clean Generation Portfolios that exclude the Project and fill the energy and capacity gap using clean or renewable generation resources. As referenced in Section 5.5.2, available clean or renewable resources for portfolio purposes are wind, run-of-river, and biomass to provide energy and capacity, with pumped storage providing backup capacity but representing an energy consumer. Revision 1 July 19, a

132 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Clean + Thermal Generation Portfolios that exclude the Project and fill the energy gap using clean or renewable generation resources as in the Clean Generation Portfolio, while backup capacity is provided by thermal generation (in the form of SCGTs) up to the 93% clean or renewable target, as well as pumped storage. It should be noted that the partial replacement of the dependable capacity provided by the Project with SCGTs would use up all of the 7% non-clean headroom. As a result, BC Hydro s ability to use natural gas-fired generation for contingency resource planning purposes is foregone. This value is not fully represented in the portfolio analysis undertaken. A number of assumptions are consistent through all portfolios, including: LRB is based on 2012 Load Forecast with no LNG load Electricity and gas market scenario based on Ventyx s spring 2012 price forecast The current BC Hydro DSM target is used in every portfolio The cost of most alternatives is based on 2010 Resource Options Report data using an 8% weighted average cost of capital (refer to Section ) Wind costs are based on the 2012 wind cost update (see Section ) Refer to Figure 5.9 for a representation of the portfolios considered. Once the portfolios were constructed, BC Hydro compared the technical, financial, environmental, and economic development attributes between these portfolios Technical Attributes The portfolios used to compare alternatives to the Project are constructed to have similar overall technical attributes (i.e., each portfolio is built to fill the energy and capacity gaps identified in Section 5.2.2). However, there are some differences between these portfolios that are important to highlight. Energy: BC Hydro s portfolio building exercise identified wind as the primary energy technology to provide energy in both the Clean Generation portfolios and the Clean + Thermal Generation portfolios. The balance of energy requirements are mostly provided by biomass resources in the Clean Generation portfolio, while both biomass and SCGTs provide energy in the Clean + Thermal Generation portfolio. Run-of-river resources provide only a minor amount of energy. This result is not aligned with the results of previous BC Hydro power acquisition processes in these calls, run-of-river was the primary resource bid in. This is generally due to the lower wind costs resulting from the wind cost update discussed in Section If wind costs are left at the levels in the Resource Options Report, run-of-river hydro and/or biomass would provide higher proportions of energy for the portfolio. The Clean Generation portfolio requires more energy resources in total due to the requirement to offset energy losses from pumped storage. That is, an additional 700 GWh/year of energy generation resources are required in the Clean Generation portfolio, due to the net energy consumption from the pumped storage capacity resource. 5-67

133 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Figure 5.10 shows the comparison of the energy provided by the Project to a 5,100 GWh/year block of energy resources that are similar to those selected in the Clean Generation and Clean + Thermal Generation portfolios. Capacity: In both the Clean Generation and Clean + Thermal Generation portfolios, capacity is partially provided by the DGC of biomass and the ELCC of wind resources. The balance of the capacity requirements are provided by DGC from pumped storage in the Clean Generation portfolio, while SCGTs and pumped storage provide DGC in the Clean + Thermal Generation Portfolio. ELCC has a greater level of uncertainty than the DGC of a dependable capacity resource such as the Project, which is set as part of the project design. A portfolio that relies significantly on the contribution of intermittent clean or renewable generation to ELCC has the potential to overstate the available capacity due to an expected capacity contribution versus having dependable capacity that is known to be available when the system requires it. Both the Clean Generation and Clean + Thermal Generation portfolios rely significantly on intermittent resources for the energy contribution. There may be additional firming and/or shaping capability required from the BC Hydro system that is not included in the portfolio analysis. Figure 5.11 shows the comparison of the dependable capacity provided by the Project to an 1,100 MW block of energy resources that are similar to those selected in the Clean Generation and Clean + Thermal Generation portfolios Financial Attributes The analysis evaluated the cost-effectiveness of the Project by comparing the present value of the costs between portfolios with and without the Project. This represents the financial benefits over the 30-year analysis period. This present value calculation was performed for a range of in-service dates for the Project to evaluate whether the Project was cost-effective both at F2022 and at F2024. Table 5.41 shows the results of this present value analysis. Note that the present value analysis is based on a no LNG load scenario and on the current DSM target. The present value analysis does not take DSM or other resource delivery risk into account. 31 Table 5.41 Portfolio Present Value Comparison Portfolio Comparison Site C portfolio compared to Clean Generation portfolio Site C portfolio compared to Clean + Thermal Generation portfolio Project In-Service Date Portfolio Present Value Differential ($ million) F F F2022 (150) F NOTES: Positive values indicate that the Site C portfolio has lower costs than the alternative portfolio Present value calculated at 6% discount rate All values in F2013 dollars, rounded to nearest $10 million This present value analysis shows that the Project is cost-effective at its earliest in-service date, saving about $450 million in present value, compared to a Clean 5-68 Revision 1- July 19, 2013

134 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Generation portfolio. The Project is more expensive than a Clean + Thermal Generation portfolio at a F2022 in-service date; however, the Project becomes more cost-effective than a Clean + Thermal Generation portfolio with a F2024 in-service date. A change to BC Hydro s load-resource balances that accelerated the capacity and/or energy gap would create a similar change to the Project present value benefits. In addition to the present value analysis, BC Hydro evaluated the adjusted UEC of the Project against the adjusted UEC of a comparable block of 5,100 GWh/year of energy and 1,100 MW of capacity. This adjusted UEC represents the present value of the amount BC Hydro s customers pay per unit energy delivered, and is a proxy for the financial benefits over project life. Table 5.42 provides the difference in portfolio UEC between portfolios with and without the Project in F$ Table 5.42 Adjusted Unit Energy Cost Comparison Clean Generation Clean + Thermal Generation Project Adjusted UEC ($/MWh, $F2013) NOTE: UEC values include transmission-related costs to the Lower Mainland, wind integration costs, soft costs, and costs of capacity backup, and exclude sunk costs Environmental Attributes Portfolios with and without the Project were compared based on their environmental attributes. More details of the measures can be found in Section Table 5.43 shows the differences in the environmental attributes between the Project and a 5,100 GWh/1,100 MW block of power from the Clean Generation and Clean + Thermal Generation portfolios. Note that the environmental attributes for the Project are unique within the range of resource options under analysis, given the advanced level of project definition for the Project and accompanying accuracy in the project footprint. The portfolios without the Project are populated with forecast generic typical projects with estimated footprints. The portfolio values include the impacts of associated transmission requirements to the POI. 25 Table 5.43 Environmental Attribute Comparison Environmental Attribute Clean Generation Clean + Thermal Generation Project Land footprint (ha) 2,230 2,430 5,660 Affected stream length (km) Reservoir created (ha) 0 0 9,300 Operational GHG Emissions (t/year, 000s) Local Air Emissions (t/year, 000s) NOx Carbon Monoxide NOTE: All values are rounded Revision 1- July 19,

135 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Land and freshwater footprint: The environmental attributes for the Project are unique compared to the alternatives shown as a result of the advanced level of project definition for the Project, which allows a higher level of accuracy in determining the Project footprint. The portfolios without the Project are populated with forecast typical projects with estimated footprints. As a result, the differences in environmental attributes between portfolios shown in this section compare a defined attribute for the Project to a representative estimate for IPPs. The actual difference in attributes between portfolios cannot be known with certainty. Both the Clean and the Clean + Thermal Generation portfolios identified wind resources as the primary alternative source of energy. Based on these portfolio compositions, the comparison of environmental attributes shows that the Project could have a larger land footprint than portfolios without the project. However, the difference between the portfolios is less than the full 5,660 ha Project land footprint, as a portfolio without the Project must employ different supply-side resources to meet energy and capacity needs, which also have environmental footprints. As with the land footprint, based on the wind-heavy portfolio composition of the Clean and the Clean + Thermal Generation portfolios, the Project could have a larger freshwater footprint than the portfolios that do not include the Project. The land and freshwater footprint of the Project reservoir represents a conversion of habitat from terrestrial and river environments to a reservoir environment, and not a loss of productive environment. This may not be the case with other portfolios of alternative resources. As a result, portfolios with the Project include the creation of a 9,330 ha reservoir, while portfolios without the Project do not. It should be noted, however, that pumped storage, an alternative capacity-rich option and net energy consumer, is assumed to occur on existing water bodies with no reservoir footprints for this modelling analysis. Since, to date, no pumped storage project has ever been permitted in B.C., this is a conservative assumption. The differences in land and freshwater footprint are highly dependent on the mix of energy resources. The portfolios of available resources generally include a majority of wind energy. If these portfolios had a higher proportion of run-of-river resources (as was the result of BC Hydro s recent calls for power), it is likely that the portfolios of alternatives would have a comparable or larger footprint than the Project. This is because wind and biomass resources generally have smaller footprints per unit energy delivered than either the Project or run-of-river hydro. It is also important to note that the land footprints in Table 5.43 only include the footprint of the primary generation site. For hydroelectric projects such as the Project and run-of-river resources, this footprint therefore includes the structures to capture the fuel (i.e., the water) for generation purposes. For other available resource options such as natural gas-fired generation and biomass, the fuel collection footprint is not included in the land footprint. GHG Emissions: The portfolio analysis compared the operating phase GHG emissions due to fuel combustion between the portfolios. The operating phase GHGs are sufficient for planning-level analysis. A full assessment of the life-cycle GHGs of the Project may be found in Volume 2 Section 15 Greenhouse Gases. The portfolio including the Project has lower operational GHG emissions than both portfolios not including the Project. The Clean Generation portfolio selects a municipal 5-70

136 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project solid waste resource option, which includes GHG emissions from fuel combustion. The Clean + Thermal Generation portfolio has the highest level of GHG emissions, due to the combustion of natural gas. Local Air Emissions: The portfolio including the Project has lower local air emissions than both portfolios not including the Project. The Clean Generation portfolio selects both wood-based biomass and municipal solid waste resource options, which create local air emissions from fuel combustion. The Clean + Thermal Generation portfolio includes biomass resources as well as natural gas-fired generation and, as a result, has the highest level of local air emissions. Marine Attributes: Due to the location and characteristics of the Project, there are no significant differences in the marine attributes between portfolios with and without the Project. Location of Portfolio Footprint: The locations of the environmental attributes used in the analysis of alternatives were compared between portfolios. The Project is located solely in the Northeast Development Region (NEDR), while the available resources are located in a range of locations across the province. However, the portfolio analysis identified wind as the primary source of energy to the system, and more than 90% of wind resources identified were located in the NEDR. As a result, more than 50% of the land footprint in both the Clean and the Clean + Thermal Generation portfolios would be located in the NEDR, with the balance in the Lower Mainland and on Vancouver Island Economic Development Attributes Portfolios with and without the Project were compared based on their economic development attributes, including jobs and GDP. Table 5.44 shows the differences in the economic development attributes between the Project and a 5,100 GWh/1,100 MW block of power from the Clean Generation and the Clean + Thermal Generation portfolios. The portfolio values include the impacts of associated transmission requirements to the POI. 28 Table 5.44 Economic Development Attribute Comparison Economic Development Attribute Clean Generation Clean + Thermal Generation Project Construction jobs (total jobs) 33,200 28,500 44,200 Construction GDP ($ million) 2,600 2,200 3,500 Operations jobs (jobs per year) 1,175 1, NOTE: All values rounded The portfolio with the Project generally increased measures of economic development during construction as compared to portfolios without the Project. Jobs and GDP related to construction are higher for the portfolio including the Project, due to the high job intensity of the construction period. Jobs and GDP during operations are lower for the portfolio including the Project, as a result of the low operating costs for the Project. These estimates are high level for use in comparing the resource options at a portfolio level, and as with the environmental attributes, the exact difference between the economic development attributes is uncertain. 5-71

137 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project Summary and Rationale for Project Selection There is a need for new energy and capacity resources within the next 10 to 15 years of BC Hydro s planning horizon in order to meet forecast customer demand, as demonstrated in Section New energy and capacity resources may be required at the Project s earliest in-service date in scenarios where BC Hydro is required to meet LNG facility non-compression load, if BC Hydro s current DSM target does not deliver anticipated energy and/or capacity volumes, or if higher than mid-load forecasts are experienced. BC Hydro has an obligation to meet this customer demand, and has evaluated a range of different options to do so. The Project is the most cost-effective manner in which BC Hydro can meet this need, as shown by the portfolio analysis in Section The Project would also provide the additional benefits of economic development and employment, and would generate electricity with comparatively low GHG emissions per unit energy. Portfolios including the Project generally have a lower present value of costs to ratepayers, as compared to portfolios including only clean or renewable resources, and portfolios including both clean and thermal resources The environmental footprint analysis shows that the Project may have a larger land and freshwater footprint than portfolios of alternative resource options; however, this is dependent on the mix of resources that would replace the Project The Project would have a lower amount of greenhouse gas emissions and local air emissions than portfolios of alternative resource options, which would involve the combustion of fuel at municipal solid waste and/or natural gas facilities The economic development attributes of the portfolio analysis show that portfolios including the Project provide higher amounts of provincial GDP and employment during construction Based on this portfolio analysis, BC Hydro believes that the Project provides the best combination of financial, technical, environmental, and economic development attributes and is therefore a preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. 5-72

138 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project References Literature Cited AACE International International Recommended Practice No. 10S-90, Cost Engineering Terminology. December 3, B.C. Energy Plan Energy for Our Future: A Plan for B.C.Bolinger, M. and R. Wiser Understanding Trends in Wind Turbine Prices Over the Past Decade. Lawrence Berkeley National Laboratory. October British Columbia Utilities Commission (BCUC) IEP/LTAP Decision. Pages 89 and 90.British Columbia Utilities Commission (BCUC) Long-Term Acquisition Plan Decision. BCUC Order G British Columbia Utilities Commission (BCUC) Certificate of Public Convenience and Necessity Application Guidelines. BCUC Order G March 19, Burrard Thermal Electricity Regulation B.C. Reg. 319/2010. Canada Hydraulic Centre Inventory of Canada s Marine Renewable Energy Resources. April Canadian Environmental Assessment Agency (CEA Agency) Operational Policy Statement, Addressing Cumulative Environmental Effects under the Canadian Environmental Assessment Act. Published by the Minister of Public Works. Carbon Trust Future Marine Energy, Results of the Marine Energy Challenge: Cost competitiveness and growth of Wave and tidal stream energy. January Electric Power Research Institute EPRI Journal. Pathways to Sustainable Power in Carbon-Constrained Future, Fall 2007, Pages Golder Associates (Golder) Inventory of Greenhouse Gas Generation from Landfills in British Columbia. National Renewable Energy Laboratory IEA Wind Task 26: The Past and Future Cost of Wind Energy. Technical Report NREL/TP-6A May Energy + Environmental Economics Cost and Performance Review of Generation Technologies. Report for the Western Electricity Coordinating Council. October Page 47. Powertech Labs Inc Coal with Carbon Capture & Sequestration for Long-Term Transmission Inquiry. September Page 5. Renewable Energy Foundation The Performance of Wind Farms in the United Kingdom and Denmark. December U.S. Department of Energy Wind Technology Market Report. Prepared by R. Wiser and M. Bolinger. August Internet Sites BC Hydro 2010, 2010 Resource Options Report. Available at: energy_in_bc/irp/document_centre/reports/final_ror.html. Accessed: February 10,

139 Site C Clean Energy Project Environmental Impact Statement Volume 1: Introduction, Project Planning, and Description Section 5: Need for, Purpose of, and Alternatives to the Project B.C. Ministry of Energy, Mines and Natural Gas. 2012a. British Columbia s Natural Gas Strategy: Fuelling B.C. s Economy for the Next Decade and Beyond. Available at: Accessed: February 3, B.C. Ministry of Energy, Mines and Natural Gas. 2012b. Liquefied Natural Gas: A Strategy for B.C. s Newest Industry. Available at: Accessed: February 3,

140 RESPONSE TO WORKING GROUP AND PUBLIC COMMENTS ON THE SITE C CLEAN ENERGY PROJECT ENVIRONMENTAL IMPACT STATEMENT Technical Memo ALTERNATIVES TO THE PROJECT MAY 8, 2013

141 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Subject: Alternatives to the Project Purpose The purpose of this technical memo is to provide an overview of how BC Hydro reviews potential electricity resources to meet customer demand, and to address questions raised during the comment period on the EIS regarding BC Hydro s analysis of alternatives that has identified the Project as the preferred option to meet the need for firm energy and dependable capacity in BC Hydro's service area. Overview Consistent with Section 4.2 of the EIS-G 1 and good utility practice (as reflected in the BCUC s Resource Planning Guidelines among other things), BC Hydro identified and undertook a multi-layered review of electricity resources which could be alternatives to the Project: EIS, Section BC Hydro used the 2010 Resource Options Report (ROR) as the starting point for identification of resources. BC Hydro updated the 2010 ROR with respect to forecasted wind prices and made other adjustments to facilitate comparisons described in the EIS and in further detail below. EIS, Section As mandated by Section 4.2 of the EIS-G, BC Hydro screened resources to determine if the resources are economically and technically feasible. BC Hydro clearly identified and set out its conclusions with regard to these screened resources. EIS, Section 5.5 BC Hydro developed criteria to identify the major environmental, economic and technical costs and benefits of available resources, which are resources that are viable and which in various combinations could be alternatives to the Project: o o In Section BC Hydro set out the attributes it used to measure the relative consideration of the environmental, economic and technical costs and benefits of the available resources and the Project In Section 5.5.2, BC Hydro applied the four types of attributes (financial, technical, environmental and economic development) to individual available resources through: the Unit Energy Cost (UEC) or the Unit Capacity Cost (UCC); describing whether a resource was intermittent or dispatchable, and whether a resource provides dependable capacity; and presenting an overview of the environmental effects and benefits of different available resources. BC Hydro also highlighted where Provincial legislation such as the Clean Energy Act set out limits to or otherwise impacted individual available resources. o In Sections and 5.5.4, and consistent with the BCUC s Resource Planning Guidelines, BC Hydro developed three plausible resource portfolios which could meet the identified need (1) Site C portfolio; (2) Clean Generation Portfolio; and (3) Clean +Thermal Generation Portfolio, with natural gas as a component within the Clean Energy Act s 93% clean or renewable target. These three portfolios were compared using the four types of attributes. As a result of this analysis, BC Hydro reached the conclusion that the Project provides the best combination of financial, technical, environmental, and economic development attributes and is therefore a preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. 1 The EIS Guidelines are quoted in italics throughout this Technical Memo. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 2

142 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Identifying Alternatives The EIS-G in Section 4.2 provides that BC Hydro must identify the alternatives to the Project that were considered; this was done in Section 5.4 and summarized in Table 5.17 of the EIS. The information on the alternatives as shown in the EIS is based upon, but in certain aspects supersedes, the 2010 ROR. The 2010 ROR is a database of resource option attributes and costs reflecting: (1) input from stakeholders with technical expertise, including information from members of the independent power producer (IPP) community, as well as First Nations and public stakeholders; (2) consultant studies; and (3) BC Hydro s own project experience. Please see Appendix 1 to this Technical Memo for a list of the resource technologies considered in the EIS. There are five main changes from the values presented in the 2010 ROR to the values presented in the EIS: 1. BC Hydro updated the wind energy volumes and UECs based on observed changes in turbine efficiencies and wind turbine prices that have occurred over the past three years as described in Section BC Hydro updated the UECs and UCCs of all resources to constant dollars as of January 1, 2013 ($F2013) using a 2% inflation factor where necessary as described in Section BC Hydro used an 8% real cost of capital for determining the UECs and UCCs for IPP resource options and a 6% real cost of capital for determining the UECs and UCCs for BC Hydro resource options as described in Section For natural gas resource options, UECs and UCCs include associated fuel and greenhouse gas (GHG) costs 5. For pumped storage resource options, UCCs include associated costs for 30% energy losses with an 18% capacity factor BC Hydro describes the limitations of the 2010 ROR on page 5-29 of the EIS. The 2010 ROR contains sufficient information on physical, financial, environmental and economic development characteristics for analysis at a planning level; however, the values: Do not reflect site-specific information, permitting constraints and other development risks May not accurately predict future prices or projects set through BC Hydro s power acquisition processes. Historically, the resource options with the lowest unadjusted UEC values are not always bid into BC Hydro s power acquisition processes. Screened Resources The EIS-G in Section 4.2 provides that alternatives must be technically and economically feasible. In Section of the EIS, BC Hydro described the process of screening resources on the basis that they are not viable; all other resources were deemed available for creating portfolios. The screened resources fall into three categories: Supply-side (generation) resources that are legally barred. Section of the EIS-G provides that the purpose of the Project will be established from the perspective of the Proponent, and will provide context for the consideration of alternatives to the Project. A potential resource that is legally barred is not available to BC Hydro and thus not an alternative to the Project. Refer to Section of the EIS, where four groups of supply side options were screened Burrard Thermal Generating Station, large hydroelectric projects prohibited by the Clean Energy Act, TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 3

143 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT nuclear, and external market resources prohibited by the self-sufficiency provisions of the Clean Energy Act. Supply-side resources that are not economically or technically feasible. Refer to Section of the EIS, where coal-fired generation with carbon capture and storage, wave, tidal and solar resources were screened. Demand Side Management (DSM) options that are not economically or technically feasible refer to Section of the EIS for the screening analysis regarding two broad DSM categories, and within these two categories, additional DSM options. Please also see the Technical Memo on Demand-Side Management for further discussion on these DSM options. In addition, supply-side generation resources that appeared to be economically or technically feasible based on the 2010 ROR results were screened for use in the portfolio analysis. BC Hydro used the results of its acquisition processes to date as the basis for this step. This resulted in the screening of two additional resources: geothermal and biogas/landfill gas. For example, while geothermal is a mature technology, there are significant risks in developing green-field geothermal sites and no projects have ever been bid into BC Hydro acquisition processes. However, the attributes of both geothermal and biogas/landfill gas are reviewed in Section of the EIS. Resources Available for Portfolio Analysis As shown in EIS Table 5.38 on page 5-60 there is over 140,000 GWh of available clean or renewable resources were identified that could be used as alternatives to the Project s 5,100 GWh of energy supply. For additional clean or renewable resource options to impact the EIS, the additional resources would need to be identified in volumes comparable to the Project and at costs that are below the most cost-effective shown in this table and selected in the portfolios as shown in Section of the EIS. Appendix 5 shows supply curves for the resources available for portfolio analysis. Resource Option Attributes Section 4.2 of the EIS-G requires BC Hydro to [d]evelop criteria to identify the major environmental, economic and technical costs and benefits of the alternatives. In Section of the EIS BC Hydro describes the financial, technical, environmental and economic development attributes that were used to compare the resource alternatives. The comparison of alternatives consists of 1) an overview of the attributes of each individual resource option, provided in Section 5.5.2, and 2) portfolio analysis, the results of which are set out in Section The purpose of the resource option attributes is not to essentially undertake a formal environmental assessment of the alternatives to the Project; this is both untenable and outside the scope of the environmental assessment, and indeed has never been required in past harmonized environmental assessment/joint Review Panel processes for hydroelectric projects: The scope of the assessment of the alternatives to the Project described in Section 5 meets both Section 4.2 of the EIS-G and the Canadian Environmental Assessment Agency s Operational Policy Statement for alternatives analysis Attributes were developed for resource options as a way of characterizing and comparing, at a high level, different portfolios. These high-level attributes are used for comparison of resource options across provincial-scale portfolios, and act as proxies for more detailed economic, technical, environmental, social, and heritage effects of potential projects. Since detailed site-specific information is unknown for the majority of the potential sites in the 2010 ROR database, these TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 4

144 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT attributes are not appropriate, or intended to be used, for individual site-specific evaluations and comparisons of the impacts of potential resource options. The attributes for the Project are unique compared to the alternatives as a result of the advanced level of project definition for the Project, which allows a higher level of accuracy in determining the Project costs and footprint. The portfolios without the Project are populated with forecast typical projects with estimated costs and footprints. As a result, the differences in attributes between portfolios compare a defined attribute for the Project to a representative estimate for IPPs. Financial and Technical Attributes BC Hydro showed the UECs of generation resources in two ways: UEC at Point of Interconnection to the BC Hydro integrated system (POI), as described in Section , shown in Section and summarized in Table 5.38 of the EIS. These are calculated based on the total energy provided by the resource options. UEC adjusted to the Lower Mainland ( Adjusted UEC ), as summarized in the comparable block analysis in Section and Table These are calculated based on the firm energy provided by the resource options. These adjustments reflect delivery costs to the lower mainland, wind integration costs (where applicable), capacity costs, soft costs, and adjustments to reflect the time of delivery of the energy (the freshet firm energy adjustment and the time of delivery price adjustment). The Adjusted UEC is the appropriate measure to use when comparing resource options as it adjusts the generation resources to be a common firm energy product delivered to BC Hydro s major load centre, the Lower Mainland. To make these comparisons more obvious, Table 5.38 of the EIS has been modified in Table 1 below to include Adjusted UECs upon which Table 5.42 of the EIS was created. Different resources have different technical attributes. For example, intermittent clean or renewable resources like wind and run-of-river are not always available and cannot be economically dispatched, that is, cannot be used to take advantage of market conditions (shut down when market electricity prices are low, ramped up when electricity markets prices are high). In contrast, dispatchable resources such as the Project and natural gas-fired generation are reliable and can be economically dispatched. BC Hydro analyzed the available resource option technical attributes in two steps: In Section and in Table 1 below, BC Hydro used the following to begin the technical attributes analysis: FELCC (which stands for Firm Energy Load Carrying Capability); ELCC (which stands for Effective Load Carrying Capability, which as explained in Sections and of the EIS is applied to intermittent resources that provide little if any dependable capacity); and DGC (which stands for Dependable Generating Capacity which, as described in Section of the EIS, is used for non-intermittent resources such as the Project and natural gas-fired generation). These measures do not capture the ability to economically dispatch, which provides value to BC Hydro s ratepayers and is a point of differentiation between intermittent resources and resources with dispatchable capacity. The portfolio analysis captures most of the economic dispatch value; refer also to the Hydro-Electric Storage and Dispatchable Capacity Technical Memo. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 5

145 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Table 1 Energy Resource Selected Financial and Technical Attributes of Available Energy Resource Supply Options Total FELCC Energy Total DGC or ELCC Capacity UEC at POI (GWh/year) (MW) ($F2013/MWh) Capacity Cost Adder based on Pumped Storage 2 Adjusted UEC ($F2013/MWh) Capacity Cost Adder based on Pumped Storage and SCGTs 3 Biomass Wood Based 11,946 1, Biomass Biogas Biomass Municipal Solid Waste Wind Onshore 46,165 3, Wind Offshore 50,261 3, Geothermal 5, Run-of-River 33,619 1, Site C Clean Energy Project 4,700 1, Combined cycle gas turbine (CCGT) and Cogeneration 7, Notes: 1. Adjusted UEC values include transmission-related costs to the Lower Mainland, wind integration costs, a freshet firm energy cost adjustment, time of delivery costs, soft costs (refer to EIS, page 5-64) and capacity adjustments to provide the same relative contribution of dependable capacity as the Project. 2. The UEC for the Project does not include sunk costs. 3. The variation in UEC values shown in Table 1 is largely determined by the quality of the underlying resource, the distance to POI, and the transmission costs of delivering the electricity to the Lower Mainland. 4. Appendix 2 provides detail on the calculation of the Project UEC. The life-cycle costs of the capacity provided by resource options are provided as Unit Capacity Costs (UCCs). As stated in Section of the EIS: The UCC reflects the real levelized cost of a unit of capacity from a resource option (typically in $F2013/kW-year). UCCs are calculated by taking the levelized annual cost of a capacity resource divided by the resource s dependable capacity. POI-level UCCs for resource options are provided in Section of the EIS and reproduced from table 5.37 in Table 2 below. Table 2 UCCs of Available Capacity Resource Supply Options Resource Type Dependable Capacity (MW) Unit Capacity Costs at POI ($F2013/kW-year) Simple Cycle Gas Turbine (SCGT) Pumped Storage 1, Capacity Credit Valued at $232/kW-year (based on pumped storage only). Capacity Credit Valued at $154/kW-year (based on pumped storage and SCGTs). TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 6

146 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Resource Smart About Environmental Attributes Section of the EIS explains that BC Hydro retained a number of consultants to provide a high level indication of the environmental attributes of the resource options. The environmental attributes were tabulated for four key categories: land, atmosphere, freshwater and marine, and are further broken down into indicators as described in table 5.24 of the EIS. Please refer to Section of the EIS for a description of the environmental attributes of the available alternative resource options. In some cases, measures were further classified to allow more detailed comparisons. As the rightmost column in Table 5.24 of the EIS displays, these classes subdivide each measure into 3 5 subcategories in order to facilitate some of the comparisons shown in Section The assessment of the potential effects of the Project is provided in Volumes 2, 3, and 4 of the EIS. Economic Development Attributes As described in Section of the EIS, BC Hydro uses economic development attributes to describe the contributions of resource options to the provincial economy. The British Columbia Input-Output model was used to determine the economic development attributes. There are three categories of attributes as follows: 1. Provincial Gross Domestic Product (GDP) 2. Employment; and 3. Provincial government revenue. These categories are further broken down into sub-categories in table 5.25 of the EIS. Creating Portfolios As described in Section 5.5. of the EIS, the comparison of alternatives is largely done through portfolio modelling and further analysis on the underlying resources. Portfolios are created by the linear optimization model (System Optimizer) that selects the optimal combinations of available resource options under different assumptions and constraints that will meet the energy and capacity needs of BC Hydro s customers as defined in Section 5.2. Portfolio modeling runs economic dispatches of the potential portfolio in a way that looking at resource UEC comparisons cannot. The portfolio modeling provides: Timing of resources, including modelling their operation; Capital expenditures based on the timing of resource additions; Expected operating costs from the manner in which the resources will be operated; Electricity market trade benefits depending on the flexibility of the portfolio; and Permits the calculation and comparison of a portfolio present value (PVs) to allow 30 year planning timeframe cost comparisons. BC Hydro built three categories of portfolios as follows: - Site C Portfolios: include the Project; - Clean Generation Portfolios: exclude the Project and use clean or renewable alternatives; and TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 7

147 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT - Clean + Thermal Generation Portfolios: exclude the Project and use a combination of clean or renewable resources with capacity provided by thermal generation (in the form of SCGTs) up to the 93% Clean Energy Act clean or renewable target, and pumped storage. System Optimizer was used to select the resource mix to make up the portfolios. BC Hydro created sets of portfolios for Project in-service dates of F2022 and F2024. For additional information on the System Optimizer model and the portfolio construction, please refer to Appendix 4. To facilitate a useful comparison to the Project the resource options selected in the portfolio analysis were used to create a comparable block of energy and capacity to the Project s 5,100 GWh/year of energy and 1,100 MW of dependable capacity for the three portfolio categories. These blocks were used to calculate the values for 1) the Adjusted UEC comparison shown in table 5.42 of the EIS; 2) the environmental attribute comparison in table 5.43 of the EIS; and 3) the economic development attribute comparison in table 5.44 of the EIS. Compared to the 30-year portfolio PV calculation, the adjusted UEC value is a proxy for a comparison of the costs of the Project and alternatives over their project lives and demonstrates the long-term value of the Project. This analysis excludes the consideration of resource timing and of some operational considerations. To account for the energy losses associated with pumped storage and still supply 5,100 GWh of clean energy, the clean generation portfolio and clean + thermal generation portfolio were made up of approximately 5,800 GWh and 5,400 GWh of resources, respectively. Tables are included in Appendix 3 to this memo that show the resources selected for the comparable blocks and the construction of the UEC. Portfolio Evaluation and Decision Process To identify the preferred portfolio, BC Hydro undertook an analysis of the quantitative financial, technical, environmental and economic development attributes of the three categories of portolios. The attributes are described in Section of the EIS which includes the details of the indicators, units of measures, and classifications provided in Table 5.24 and Table For each portfolio, attribute values were calculated for each measure by summing up the attribute values of the selected resource options. For the environmental attributes BC Hydro brought forward footprint-level indicators to facilitate portfolio comparisons as a further level of detail did not provide any additional useful information. For convenience, portfolio attributes and results described in Section are reproduced in Table 3. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 8

148 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Table 3 Portfolio Analysis Consequence Table Attribute Units Clean Generation Clean + Thermal Generation Financial Attributes (EIS Section ) PV Differential $F2013 million F2022 F2024 F2022 F (150) 180 Site C Portfolio Adjusted UEC $F2013/MWh Environmental Attributes (EIS Section ) Land footprint Hectares 2,230 2,430 5,660 Affected stream length Kilometres Reservoir created Hectares 0 0 9,300 GHG emissions Local Air Emissions Tonnes/year, thousands Tonnes/year, thousands Economic Development Attributes (EIS Section ) N/A NOx CO NOx CO NOx CO Construction jobs Total Jobs 33,200 28,500 44,200 Construction GDP Operations jobs $F2013, million Jobs per Year 2,600 2,200 3,500 1,175 1, Notes: 1. Portfolios are created to have similar technical attributes i.e., the amounts of energy and dependable capacity are roughly similar 2. All values are rounded, with the exception of the adjusted UEC costs In both cases, compared to both the Clean portfolio and the Clean + Thermal portfolio, the Site C portfolio had sufficiently superior characteristics that no quantitative weighting of attributes was conducted. Compared to the Clean portfolio, the Site C portfolio had the following results: - Superior financial attributes, with a lower PV and portfolio UEC than alternatives - Mixed economic development attributes, with a larger number of construction jobs created and higher construction GDP but lower operations jobs - Mixed environment attributes, with a larger land and stream footprint but slightly lower GHG and local air emissions (CO, NOx). The Site C portfolio was preferred under financial and most economic development attributes, as well as based on a comparison of GHG and local air emissions. The land and stream footprint was higher with the Site C portfolio, although the majority of the Site C portfolio footprint represents a conversion of habitat from terrestrial and river environments to a reservoir environment rather than a facility footprint. As the Site C portfolio was preferred in nearly all attributes there was no requirement to undertake a quantitative weighting exercise. The superior financial, economic development and air emission attributes would have to be effectively ignored compared to the land and stream footprint for the Clean portfolio to be preferred. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 9

149 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Compared to the Clean + Thermal portfolio, the Site C portfolio had the following results: - Mixed financial attributes, with a Site C PV either higher or lower than the Clean + Thermal portfolio depending on the Project in-service date, and the Site C portfolio having a lower UEC than the Clean + Thermal portfolio - Mixed economic development attributes, with a larger number of construction jobs created and higher construction GDP but lower operations jobs - Mixed environment attributes, with a larger land and stream footprint but lower GHG and local air emissions. Similar to the Clean portfolio, the Project footprint represents a conversion of habitat from terrestrial and river environments to a reservoir environment rather than a facility footprint. Given the Province s legislated GHG emission targets, and given the financial and technical benefits of including the Project, the Project was determined to be a preferred resource option compared to the Clean + Thermal portfolio. Based on the consideration of alternatives and the portfolio analysis of the Clean and Clean+Thermal portfolios, BC Hydro believes that the Project provides the best combination of financial, technical, environmental, and economic development attributes and is therefore a preferred option to meet the need for energy and capacity within BC Hydro s planning horizon. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 10

150 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Appendix 1 Resource Technologies Technology Screened/Available Resource EIS Section Reference DSM Options DSM Option 1 Available Resource Section DSM Option 3 Available Resource Section DSM Options 4 and 5 Screened Resource Section DSM capacity-only initiatives Screened Resource Section Clean or Renewable Resources Wave Screened Resource Section Tidalal Screened Resource Section Solar Screened Resource Section Wind (on-shore and off-shore) Available Resource Section and Section Run-of-river hydro Available Resource Section Geothermal Available Resource Section Biomass Available Resource Section , Section , and Section Large hydroelectric (other than the Project) Screened Resource Section External Markets Screened Resource Section Nuclear Screened Resource Section Pumped storage (dependable capacity only) Available Resource Section BC Hydro Resource Smart Available Resource Section Fossil Fuel Resources Coal-fired generation with carbon capture and storage Screened Resource Section Burrard Thermal Generating Station Screened Resource Section Natural gas-fired generation SCGTs (dependable capacity) CCGTs (firm energy) Available Resource within the 93% Clean Energy Act clean or renewable target Section TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 11

151 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Appendix 2 Unit Energy Costs and Calculation of Project UEC There have been a number of references to the Project UEC in the EIS and this Technical Memo: The UEC at POI in $F2011 is $95/MWh as provided in Volume 1 Appendix F Part 1 (Project Cost Estimate) on page 5. After removing the sunk costs of the Project, described on page 5-64 of the EIS, and adjusting to $F2013 the value becomes $94/MWh. The Adjusted UEC is $110/MWh as provided in Section (Financial Attributes) Table 5.42 on page As noted in footnote (2) to Table 3 in Volume 1 Appendix F Part 1, the difference between the $110/MWh UEC and the $95/MWh UEC is the inclusion of adjustments to reflect delivery costs to the lower mainland, escalation to F$2013 and the exclusion of sunk costs. All UEC figures provided for the Project in the EIS are consistent and based on the same project cost estimate as provided in Volume Appendix F Part 1 (Project Cost Estimate). Please see the table below for details on the development of Project UEC values. POI-level UEC LM-level UEC Note: Unit Energy Cost Calculation at 6% Discount Rate UEC at POI including sunk costs (F2011 dollars) $/MWh Less sunk costs -5 Escalation to F2013 dollars +4 UEC at POI excluding sunk costs (F2013 dollars) 94 Adjustments to reflect delivery costs to the lower mainland +16 UEC adjusted to Lower Mainland, excluding sunk costs (F2013 dollars) 110 All analysis in the EIS has been performed at a 6.0% discount rate. At the time of preparation of the EIS BC Hydro s planning discount rate was 5.5%. Using a 5.5% discount rate, the UEC at POI including sunk costs (F2011 dollars) was $87/MWh. 95 a TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 12

152 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Appendix 3 Comparable Block Resource Composition Clean Generation Block Details and UEC Calculation Project Name Dependable Capacity (MW) Annual Firm Energy (GWh) Energy Costs Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013 million) Wind_PC MSW2_LM Wind_PC Wind_PC Wind_PC Wind_PC Wind_PC ROR_T1R1_60-80_LM Wind_PC10-1, Wind_PC WBBio_VI Wind_VI Wind_VI Wind_PC Pumped Storage Variable Cost (see notes) n/a (736) Capacity Costs Sub-total 114 5, Dependable Unit Capacity Capacity Cost (MW) ($F2013/kW-year) Annual Firm Energy (GWh) Total Cost ($F2013 million) Pumped Storage Fixed Cost (see notes) 1,000 n/a Clean Generation Block Sub-total 1,000 n/a Dependable Adjusted Unit Capacity Energy Cost (MW) ($F2013/MWh) Annual Firm Energy (GWh) Total Cost ($F2013 million) Total 1,114 5, Notes: 1. Project names refer to project identifiers from the 2010 Resource Options Report 2. UECs include a regional transmission cost adder of $6/MWh, a soft cost adder of 5%, a freshet firm energy cost adjustment, a time of delivery cost adjustment, and the cost of delivery to the Lower Mainland. 3. Pumped Storage variable costs include variable OMA and water rentals. The cost of energy losses is included in the total cost of the clean resources that would be used to serve those losses. The yearly variable cost of the pumped storage was calculated using a capacity factor of about 20% for the peak usage. BC Hydro used a slightly higher capacity factor than the 18% used in the portfolio analysis to make the comparable blocks exactly 5,100 GWh per year. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 13

153 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Clean + Thermal Generation Portfolio Details and UEC Calculation Project Name Dependable Capacity (MW) Annual Firm/Effective Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013M) Energy Costs Wind_PC MSW2_LM Wind_PC Wind_PC Wind_PC Wind_PC Wind_PC ROR_T1R1_60-80_LM Wind_PC10-1, Wind_VI Pumped Storage Variable Cost (see notes) n/a (369) 13 5 SCGT Variable Cost (see notes) n/a Capacity Costs Sub-total 33 5, Dependable Capacity (MW) Annual Firm Energy (GWh) Unit Capacity Cost ($F2013/kW-year) Total Cost ($F2013 million) Pumped Storage Fixed Cost 500 n/a SCGT Fixed Cost 588 n/a Clean + Thermal Generation Comparable Block Sub-total 1,088 n/a Dependable Capacity (MW) Annual Firm Energy (GWh) Adjusted Unit Energy Cost ($F2013/MWh) Total Cost ($F2013 million) Total 1,121 5, Notes: 1. Project names refer to project identifiers from the 2010 Resource Options Report 2. UECs includes a regional transmission cost adder of $6/MWh, a soft cost adder of 5%, a freshet firm energy cost adjustment, a time of delivery cost adjustment, and the cost of delivery to the lower mainland. 3. Pumped Storage variable cost include variable OMA and water rentals. The cost of energy losses is included in the total cost of the clean resources that would be used to serve those losses. The yearly variable cost of the pumped storage was calculated using a capacity factor of about 20% for the peak usage. BC Hydro used a slightly higher capacity factor than the 18% used in the portfolio analysis to make the comparable blocks exactly 5,100 GWh per year. 4. SCGT variable cost includes variable OMA, fuel cost and GHG cost TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 14

154 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Appendix 4 System Optimizer and Portfolio Construction BC Hydro built a number of portfolios to compare the Project to available resources. As described in section of the EIS, the System Optimizer model was used in creating the portfolios. System Optimizer (SO) is a linear optimization model that selects the optimal combinations of available resource options and timing under different assumptions and constraints that will meet the energy and capacity needs of BC Hydro s customers as defined in Section 5.2. In constructing the portfolios, SO takes a planning perspective ensuring that the portfolio meets reliability constraints, as well as an operating perspective evaluating the operating performance of the portfolio. The planning perspective requires that the firm energy and dependable capacity of the selected resource portfolio be sufficient to meet system energy and capacity demands respectively, including an allowance for a capacity reserve margin. The operation of the portfolio is simulated taking into account average energy output of the resources and includes sales of portfolio surpluses into export markets. The model assesses the interaction of future generation and transmission resource options with the existing system and evaluates the manner in which the portfolio can be operated to maximize market revenue while meeting domestic load. It also takes into account system constraints such as minimum generation requirements and transmission constraints both within B.C. and on interties with US and Alberta. The annual cost of operating the portfolio is a combination of market revenue, transmission costs, and the fixed and variable costs of generation and transmission resources. Fixed costs include capital charges and fixed operating and maintenance costs while variable costs include cost of renewable IPP energy, fuel costs, GHG offset costs, and transmission wheeling costs. The model seeks to minimize the present value of these costs over the planning time period in selecting an optimal resource portfolio. BC Hydro created a total eight of portfolios in comparing the Project to available resources: (A) A portfolio with the Project in-service in F2022, with other available clean resources being used to meet any residual needs; (B) A portfolio where only other available clean resources are used to meet energy and capacity needs; (C) A portfolio with the Project in-service in F2022, with other available clean and thermal resources (in the form of SCGTs and up to the 93% clean or renewable target) being used to meet any residual needs; (D) A portfolio where only other available clean and thermal resources (in the form of SCGTs and up to the 93% clean or renewable target) are used to meet energy and capacity needs. Four more portfolios were created in a similar manner assuming an in-service date of F2024 for the Project; please refer to the figure below showing the eight portfolio runs. The present value of the portfolio cost in $F2013 is also shown in the following table. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 15

155 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio Analysis Runs Base Assumptions: 2012 Load Forecast without LNG F2022 In-Service Date F2024 In-Service Date Clean Generation Portfolios Clean & Thermal Generation Portfolios Clean Generation Portfolios Clean & Thermal Generation Portfolios With Site C (A-F2022) Without Site C (B-F2022) With Site C (C-F2022) Without Site C (D-F2022) With Site C (A-F2024) Without Site C (B-F2024) With Site C (C-F2024) Without Site C (D-F2024) Portfolio Analysis PV Results Portfolio Name Portfolio Description Portfolio PV ($F2013M) Portfolio PV Difference to Equivalent Portfolio with Site C A-F2022 Site C in F Other clean resources 8,898 9,361 8,898 = 463 B-F2022 Other Clean Resources 9,361 C-F2022 Site C in F Other clean and thermal resources 8,621 D-F2022 Other clean and thermal resources 8,469 A-F2024 Site C in F Other clean resources 8,533 B-F2024 Other Clean Resources 9,192 C-F2024 Site C in F Other clean and thermal 8,254 resources D-F2024 Other clean and thermal resources 8,436 8,469 8,621 = ,192 8,533 = 659 8,436 8,254 = 182 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 16

156 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT The details of the portfolios are presented below with three tables shown for each portfolio. The first table shows the energy resources selected. The Resource Name, Type, In-service date as determined by the System Optimizer model, Installed capacity, Average annual energy, and the Unit Energy Cost (UEC) are shown. The UEC shown is the cost of the resource at the point of interconnection and does not include integration costs, transmission costs, capacity costs, freshet firm energy costs, time of delivery costs, and costs associated with disposal of non-firm energy. These costs are reflected in the Present Value (PV) of the portfolios shown above. The second table shows the capacity resources selected. The capacity costs shown reflect only the fixed costs of the resource. The cost of operating these resources to meet peak demand is reflected in the portfolio PV, as is the cost of acquiring additional energy resources to meet the energy losses in the case of Pumped Storage facilities. The third table shows the transmission upgrades that are required on the bulk transmission system to accommodate the generation resources. The cost of these upgrades is reflected in the portfolio PV. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 17

157 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio A - F2022: Site C + Other clean resources Resource Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) UEC ($/MWh) Site C Large Hydro Wind_PC19 Wind Wind_PC21 Wind MSW2_LM Municipal Solid Waste Wind_PC10 Wind Wind_PC28 Wind ROR_T1R1_60-80_LM Run of River Wind_PC13 Wind Wind_PC16 Wind Wind_PC14 Wind Wind_PC09 Wind Wind_PC15 Wind Wind_PC41 Wind ROR_T1R1_80-90_VI Run of River Wind_VI12 Wind Wind_VI14 Wind WBBio_VI Biomass WBBio_PG Biomass WBBio_EK Biomass Wind_VI08 Wind Wind_VI13 Wind TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 18

158 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio A (F2022) In Service Resource Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW PS_LM Pumped Storage Transmission Required for Portfolio A F022 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank Series compensation upgrade at Kennedy from 50% to 65% on GMS to Williston 500 kv lines 5L1, 5L2, 5L3 and 5L7 with thermal upgrades to 3000A rating. 60 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 19

159 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio B - F2022: Other clean resources only Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) UEC ($/MWh) Wind_PC19 Wind Wind_PC21 Wind Wind_PC28 Wind Wind_PC16 Wind MSW2_LM Municipal Solid Waste Wind_PC10 Wind WBBio_VI Biomass Wind_PC13 Wind Wind_PC14 Wind ROR_T1R1_60-80_LM Run of River Wind_PC11 Wind Wind_PC15 Wind Wind_PC20 Wind Wind_PC09 Wind Wind_PC41 Wind ROR_T1R1_80-90_VI Run of River Wind_PC18 Wind Wind_PC42 Wind Wind_VI12 Wind Wind_VI14 Wind Wind_PC26 Wind Wind_PC48 Wind Wind_PC06 Wind WBBio_KM Biomass WBBio_WK Biomass WBBio_EK Biomass Wind_VI13 Wind Wind_VI15 Wind ROR_T1R1_90-110_VI Run of River ROR_T1R1_80-90_LM Run of River Wind_PC27 Wind ROR_T1R1_70-80_KN Run of River ROR_T1R1_90-100_LM Run of River TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 20

160 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio B (F2022) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW PS_LM Pumped Storage MW PS_LM Pumped Storage Transmission Required for Portfolio B F2022 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor Series compensation upgrade at Kennedy from 50% to 65% on GMS to Williston 500 kv lines 5L1, 5L2, 5L3 and 5L7 with thermal upgrades to 3000A rating. 60 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 21

161 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio C - (F022: Site C + Other clean and thermal resources Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) UEC ($/MWh) Site C Largo Hydro Wind_PC28 Wind ROR_T1R1_60-80_LM Run of River Wind_PC21 Wind MSW2_LM Municipal Solid Waste Wind_PC13 Wind Wind_PC16 Wind Wind_PC19 Wind WBBio_VI Biomass WBBio_KM Biomass WBBio_WK Biomass WBBio_PG Biomass Wind_SI15 Wind WBBio_EK Biomass Wind_VI08 Wind Wind_VI12 Wind TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 22

162 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio C (F2022) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine Transmission Required for Portfolio C F2022 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank Series compensation upgrade at Kennedy from 50% to 65% on GMS to Williston 500 kv lines 5L1, 5L2, 5L3 and 5L7 with thermal upgrades to 3000A rating New 500 kv, 50% series compensated transmission circuit 5L46 between Kelly Lake and Cheekye 657 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 23

163 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio D - F2022: Other clean and thermal resources only Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) UEC ($/MWh) WBBio_VI Biomass MSW2_LM Municipal Solid Waste Wind_PC13 Wind Wind_PC28 Wind Wind_PC19 Wind ROR_T1R1_60-80_LM Run of River Wind_PC14 Wind Wind_PC21 Wind Wind_PC16 Wind Wind_PC41 Wind Wind_PC10 Wind Wind_PC42 Wind Wind_PC09 Wind Wind_PC11 Wind Wind_PC15 Wind Wind_PC20 Wind ROR_T1R1_80-90_VI Run of River ROR_T1R1_80-90_LM Run of River Wind_PC18 Wind Wind_PC26 Wind ROR_T1R1_70-80_KN Run of River Wind_PC48 Wind Wind_VI14 Wind ROR_T1R1_90-110_VI Run of River TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 24

164 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio D (F2022) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine Transmission Required for Portfolio D F2022 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor. 65 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 25

165 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio A - F2024: Site C + Other clean resources Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Energy Cost ($/MWh) Site C Large Hydro Wind_PC19 Wind Wind_PC21 Wind MSW2_LM Municipal Solid Waste Wind_PC10 Wind Wind_PC28 Wind ROR_T1R1_60-80_LM Run of River Wind_PC13 Wind Wind_PC16 Wind Wind_PC14 Wind Wind_PC09 Wind Wind_PC15 Wind WBBio_VI Biomass Wind_PC11 Wind Wind_PC41 Wind Wind_VI12 Wind Wind_VI13 Wind WBBio_WK Biomass WBBio_EK Biomass Wind_VI08 Wind Wind_VI15 Wind TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 26

166 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio A (F2024) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW PS_LM Pumped Storage Transmission Required for Portfolio A F2024 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank Series compensation upgrade at Kennedy from 50% to 65% on GMS to Williston 500 kv lines 5L1, 5L2, 5L3 and 5L7 with thermal upgrades to 3000A rating. 60 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 27

167 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Name Portfolio B - F2024: Other clean resources only In Service Type Date Installed Capacity (MW) Average Annual Energy (GWh) UEC ($/MWh) Wind_PC19 Wind Wind_PC21 Wind Wind_PC28 Wind Wind_PC16 Wind MSW2_LM Municipal Solid Waste Wind_PC10 Wind WBBio_VI Biomass Wind_PC13 Wind Wind_PC14 Wind ROR_T1R1_60-80_LM Run of River Wind_PC11 Wind Wind_PC15 Wind Wind_PC20 Wind Wind_PC09 Wind ROR_T1R1_80-90_VI Run of River Wind_PC18 Wind Wind_PC41 Wind Wind_PC42 Wind Wind_VI12 Wind Wind_VI14 Wind Wind_PC26 Wind Wind_PC48 Wind Wind_PC06 Wind Wind_PC27 Wind WBBio_WK Biomass WBBio_EK Biomass Wind_VI08 Wind Wind_VI13 Wind ROR_T1R1_90-110_VI Run of River ROR_T1R1_80-90_LM Run of River ROR_T1R1_70-100_NC Run of River ROR_T1R1_70-80_KN Run of River Wind_VI15 Wind ROR_T1R1_90-100_LM Run of River TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 28

168 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio B (F2024) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW PS_LM Pumped Storage MW PS_LM Pumped Storage Transmission Required for Portfolio B F2024 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor Series compensation upgrade at McLeese from 50% to 65% on Williston to Kelly 500 kv lines 5L11, 5L12 and 5L13 with thermal upgrades to 3000A rating. 57 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 29

169 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio C - F2024: Site C + Other clean and thermal resources Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Energy Cost ($/MWh) Site C Large Hydro Wind_PC28 Wind ROR_T1R1_60-80_LM Run of River Wind_PC21 Wind Wind_VI12 Wind MSW2_LM Municipal Solid Waste Wind_PC13 Wind Wind_PC19 Wind Wind_PC41 Wind WBBio_VI Biomass Wind_PC15 Wind WBBio_WK Biomass Wind_PC10 Wind WBBio_PG Biomass WBBio_KM Biomass WBBio_EK Biomass TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 30

170 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio C (F2024) In Service Name Type Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine Transmission Required for Portfolio C F2024 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank Series compensation upgrade at Kennedy from 50% to 65% on GMS to Williston 500 kv lines 5L1, 5L2, 5L3 and 5L7 with thermal upgrades to 3000A rating New 500 kv, 50% series compensated transmission circuit 5L46 between Kelly Lake and Cheekye 657 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 31

171 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Portfolio D - F2024: Other clean and thermal resources only Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Energy Cost ($/MWh) WBBio_VI Biomass MSW2_LM Municipal Solid Waste Wind_PC13 Wind Wind_PC28 Wind Wind_PC19 Wind ROR_T1R1_60-80_LM Run of River Wind_PC14 Wind Wind_PC16 Wind Wind_PC15 Wind Wind_PC21 Wind Wind_PC10 Wind Wind_PC09 Wind Wind_PC11 Wind Wind_PC41 Wind Wind_PC42 Wind Wind_PC20 Wind ROR_T1R1_80-90_VI Run of River ROR_T1R1_80-90_LM Run of River Wind_PC18 Wind ROR_T1R1_70-80_KN Run of River Wind_PC26 Wind Wind_PC48 Wind Wind_VI14 Wind ROR_T1R1_90-100_LM Run of River TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 32

172 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Capacity Resources Required for Portfolio D (F2024) Name Type In Service Date Installed Capacity (MW) Average Annual Energy (GWh) Unit Cost of Capacity ($/kwyear) Revelstoke Unit 6 Resource Smart MW SCGT KN Single Cycle Gas Turbine MW SCGT KN Single Cycle Gas Turbine MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine MW PS_LM Pumped Storage MW SCGT KN Simple cycle Gas Turbine MW SCGT KN Simple cycle Gas Turbine Transmission Required for Portfolio D F2024 Year Name Capital Cost ($M) % series compensation of the 500 kv lines 5L91 and 5L kv and 230 kv shunt compensation: At Meridian 230 kv add two 110 MVAr capacitor banks At Nicola 500 kv add one 250 MVAr capacitor bank kv Shunt compensation: At Williston add one 300 MVAr SVC and two 250 MVAr switchable capacitor banks. At Kelly Lake add one 250 MVAr shunt capacitor. 65 TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 33

173 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Appendix 5 Adjusted UEC Supply Curves for Available Resources Used in Portfolio Analysis The following figures show supply curves for individual available resources as well as a consolidated supply curve for all available resources used in the portfolio analysis. All figures include the following curves: - Adj UEC (PS): Adjusted UEC for the energy resources, including a capacity cost adder priced based on pumped storage - Adj UEC (PS+SCGT): Adjusted UEC for the energy resources, including a capacity cost adder priced based on a blend of pumped storage and simple-cycle gas turbines The consolidated supply curve also includes the Adjusted UEC of the Project as the curve Site C for comparison purposes. TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 34

174 Figure 1 Consolidated Adjusted UEC Supply Curve for Available Resources Used in Portfolio Analysis $1,500 $1,300 Adjusted Unit Energy Cost ($/MWh) $1,100 $900 $700 $500 Adj UEC (PS) Adj UEC (PS+SCGT) Site C $300 $ ,000 40,000 60,000 80, , , , ,000 Average Annual Energy (GWh)

175 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Figure 2 Adjusted UEC Supply Curve for Onshore Wind $500 $450 $400 Adjusted Unit Energy Cost ($/MWh) $350 $300 $250 Adj UEC (PS) Adj UEC (PS+SCGT) $200 $150 $ ,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 Average Annual Energy (GWh) TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 2

176 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Figure 3 Adjusted UEC Supply Curve for Offshore Wind $900 $800 $700 Adjusted Unit Energy Cost ($/MWh) $600 $500 $400 Adj UEC (PS) Adj UEC (PS+SCGT) $300 $ ,000 20,000 30,000 40,000 50,000 60,000 Average Annual Energy (GWh) TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 3

177 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Figure 4 Adjusted UEC Supply Curve for Run of River $1,500 $1,300 Adjusted Unit Energy Cost ($/MWh) $1,100 $900 $700 $500 Adj UEC (PS) Adj UEC (PS+SCGT) $300 $ ,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 Average Annual Energy (GWh) TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 4

178 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Figure 5 Adjusted UEC Supply Curve for MSW $400 $350 Adjusted Unit Energy Cost ($/MWh) $300 $250 $200 Adj UEC (PS) Adj UEC (PS+SCGT) $150 $ Average Annual Energy (GWh) TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 5

179 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Figure 6 Adjusted UEC Supply Curve for Biomass Woodwaste $1,100 $900 Adjusted Unit Energy Cost ($/MWh) $700 $500 Adj UEC (PS) Adj UEC (PS+SCGT) $300 $ ,000 4,000 6,000 8,000 10,000 12,000 Average Annual Energy (GWh) TECHNICAL MEMO ALTERNATIVES TO THE PROJECT Page 6

180 Related Comments / Information Requests: This technical memo provides information related to the following Information Requests: form_ gov_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_

181 RESPONSE TO WORKING GROUP AND PUBLIC COMMENTS ON THE SITE C CLEAN ENERGY PROJECT ENVIRONMENTAL IMPACT STATEMENT Technical Memo PROJECT NEED MAY 8, 2013

182 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Subject: Project Need Purpose The purpose of this Technical Memo is to respond to a number of comments provided regarding the need for the Project with respect to: (1) Load Forecast methodology and assumptions; (2) the methodology for the construction of load-resource balances (LRBs); and (3) whether the Project is proposed to meet potential demand from Liquefied Natural Gas (LNG) facilities. Overview of Project Need BC Hydro must plan in advance to meet its customers residential, business (commercial) and industrial requirements and to ensure that the electricity resources required are available when required. To ensure it has enough resources to meet future demand, BC Hydro establishes a forecast of how much electricity customers are expected to need each year and then compares that requirement to how much electricity BC Hydro can supply in that given year. The relationship between projected customer demand and BC Hydro s electricity supply is called the LRB. BC Hydro uses the LRB to determine whether there is a gap between the needs of its customers and its electricity supply. Chapter 5 of the EIS presents two sets of LRBs one for energy, and one for dependable capacity; refer to page 5-11 of the EIS. Based on the LRB analysis provided in the in EIS, 1 new resources are required to meet the energy and dependable capacity needs of BC Hydro customers within the next 10 to 15 years, even when taking into account BC Hydro s aggressive demand side management (DSM) targets and Revelstoke Unit 6, and excluding load from LNG facilities. Basis of Need Section 5.2 of the EIS contains the need for the Project analysis. The need for the Project is "to address future customer demand for firm energy and dependable capacity in BC Hydro's service area. The need for the Project is established based on demand from BC Hydro's residential, commercial and industrial customers. The need for the project is established through LRBs, which calculate the gap between BC Hydro customer demand and available supply. There are three main inputs to the determination of need: 1) Forecasting load, in this case the 2012 Load Forecast dated December 2012, the most recent BC Hydro load forecast (addressed in Section of the EIS) 2) Estimating the energy and capacity available from existing and committed supply side resources (addressed in Section of the EIS); 3) Determining the level of future DSM savings that are achievable and cost-effective (addressed in Section of the EIS) 1 See Table 5.8 and Table 5.9. TECHNICAL MEMO PROJECT NEED Page 2

183 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT BC Hydro s Obligation to Serve As described in Section 2 of the EIS, BC Hydro s mandate is to generate, manufacture, conserve, supply and acquire electricity to meet the needs of its customers. This mandate is set out in section 12 of the Hydro and Power Authority Act (R.S.B.C. 1996, c.212). BC Hydro serves 95% of B.C. s population, delivering electricity to approximately 1.9 million customers. BC Hydro has an obligation to serve its customers in accordance with standards established by the British Columbia Utilities Commission (BCUC) pursuant to a number of sections in the B.C. Utilities Commission Act (R.S.B.C., 1996, c.473), including sections 25, 28, 29, and 30. BC Hydro serves its customers pursuant to tariffs (rates) submitted to and approved by the BCUC pursuant to sections of the Utilities Commission Act. As stated in Section 5.2, this service obligation drives BC Hydro s long-term resource planning process including the evaluation of need for the Project. Load Forecast Methodology and Assumptions BC Hydro s 2012 Load Forecast assumptions and results are set out in Section of the EIS. page 5-5 of the EIA provides that: BC Hydro is basing its analysis of the need for the Project on the 2012 mid-level load forecast. Use of the mid-level load forecast has been endorsed by the BCUC in prior proceedings and is consistent with other public utilities. The 2012 Load Forecast was prepared in accordance with the BCUC s Resource Planning Guidelines (provided as Volume 1 Appendix D Part 2), and was developed using the same methodological approach approved by the BCUC in past long-term resource plan proceedings The 2012 Load Forecast was issued in December It is based on end-use and econometric models that use historical billed sales data combined with third party economic indicators, including gross domestic product forecasts from the B.C. Ministry of Finance, external economic consultants and customer-by-customer information in the industrial customer forecast: o o o The 2012 Load Forecast methodology used by BC Hydro for industrial customers is largely a bottom-up approach which carefully considers individual industrial customer information The residential and commercial sectors are largely a top-down approaches that consider provincial housing starts, economic indicators and projected saturation and end-use information for individual home appliances to extrapolate from current consumption levels The peak load forecast is a detailed substation-by-substation accounting of expected future incremental loads, and expected transmission customer activities including possible curtailments and expansions The 2012 Load Forecast reflects the impact of savings from BC Hydro s past DSM initiatives such as energy conservation achieved through F2012. Future projected DSM savings from F2013 onward are accounted for separately in Section of the EIS as part of development of the overall energy and capacity LRBs. BC Hydro s treatment of DSM is guided by the BCUC s Resource Planning Guidelines, which specifically provide that future DSM should not be reflected in the utility s gross demand forecasts. BC Hydro also notes that the impacts of possible future electricity rate increases are reflected in the 2012 Load Forecast. TECHNICAL MEMO PROJECT NEED Page 3

184 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT For the purposes of clarification regarding BC Hydro s load forecasting methodology, a copy of the 2012 Load Forecast dated December 2012 is attached to this memo. Existing and Committed Supply Side Resources After the 2012 Load Forecast, the second step to determine if there is a gap between load and resources is to estimate the energy and capacity available from existing and committed supply side resources such as BC Hydro s existing Heritage hydroelectric assets and independent power producer projects. This second step is the subject of Section of the EIS. The result of the first and second steps is the energy and capacity LRBs set out in Tables 5.6 and 5.7 of the EIS. Based on the LRBs in the EIS there is a need for new energy resources in F2017 and a need for new capacity resources in F2016. Appendix 1 provides the annual composition of the existing and committed supply side resources used in EIS analysis of need. Determining the Level of DSM The third step in developing the energy and capacity LRBs is for BC Hydro to determine the level of future DSM savings it believes are achievable and cost-effective. DSM is BC Hydro s preferred resource and it is the first resource looked at to address the gaps depicted in Tables 5.6 and 5.7. The DSM target is 7,800 gigawatt hours per year (GWh/year) of energy savings and 1,400 megawatts (MW) of capacity savings by F2021, and is described in Section of the EIS. BC Hydro s reasons for choosing the DSM target, which is aggressive, are found in Sections and of the EIS, which outlines DSM delivery risks. Additional detail concerning BC Hydro s current DSM target is found in the Technical Memo on DSM. Revelstoke Unit 6 In addition to the DSM target, Revelstoke Unit 6, which is a potential capacity resource, is factored in as it is a project BC Hydro is likely to undertake in advance of the Project; refer to page 5-14 of the EIS. If undertaken, Revelstoke Unit 6 would deliver about 488 MW of dependable capacity but very little energy (about 26 GWh/year of average energy). EIS Need for the Project The results are set out in Tables 5.8 and 5.9, which form the basis of determining the need for the Project. There is a need for additional energy resources in F2024 and a need for additional capacity resources in F2025. Based on the 2012 Load Forecast and after taking into account projected future DSM-related energy savings (i.e., net of DSM), BC Hydro forecasts annual energy system demand growth of about 0.8% per year. The EIS analysis then proceeds to review potential alternatives in Sections 5.4 and 5.5 to address the energy and capacity gaps shown in Tables 5.8 and 5.9. Refer to the Technical Memos on DSM and Alternatives for additional detail. TECHNICAL MEMO PROJECT NEED Page 4

185 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Relevance of LNG Demand BC Hydro s load forecast does not include potential electricity demands from the proposed LNG projects because the requirements of the facilities have not yet been confirmed by proponents. As set out in Section 5.2 of the EIS, the Project is needed whether or not new LNG projects proceed. Section 5.2 of the EIS contains the need for the Project analysis. Section of the EIS sets out the assumptions underpinning BC Hydro's energy and capacity LRBs, and states with respect to potential LNG demand (referred to as load in the EIS): "The 2012 mid-load forecast presented in this section does not include potential LNG load, which is discussed in Section 5.2.3" (EIS, page 5-5). Section , and in particular Tables 5.8 and 5.9, of the EIS set out BC Hydro's energy and capacity LRBs. Section 5.3 ( Purpose of the Project ) confirms that one of the purposes of the Project is to cost-effectively meet BC Hydro s forecasted need for energy and capacity identified in Section As described in this memo and the EIS itself, the need for the Project analysis in Section does not include potential LNG demand. Good utility practice and the BCUC s Resource Planning Guidelines provide that LRB uncertainties should be acknowledged. Accordingly, BC Hydro has included an analysis of the main sources of LRB uncertainty in Section of the EIS. The potential for LNG demand is one such uncertainty, and this is why in Section 5.2.3, Tables 5.10 and 5.11 BC Hydro set out the range of effect LNG demand may have on the need for new energy and capacity resources. BC Hydro notes that while it is not factored into the analysis of need in the EIS, LNG load would be incorporated into future Load Forecasts and LRBs if LNG proponents elect to take service from BC Hydro with respect to their non-compression loads. Note that the potential LNG demand discussed in the LRB uncertainty analysis in Section relates to potential LNG non-compression load. Compression load is the power demand associated with compressing the natural gas into liquid form and represents the majority of LNG facility requirements. BC Hydro is not expecting to serve this component of LNG load. Non-compression load refer to the rest of LNG facility power demand, and is primarily made up of power required for LNG facility loading equipment, lighting and office requirements. TECHNICAL MEMO PROJECT NEED Page 5

186 Appendix 1 Existing and Committed Supply Side Resources Energy Gigawatt Hours (GWh) F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 Heritage (a) Hydroelectric 46,300 48,800 47,800 48,200 48,300 48,200 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 48,500 Heritage (b) Thermal (Prince Rupert) Existing and (c) Committed IPPs 11,600 12,200 12,800 14,200 13,900 14,300 14,400 14,100 14,500 14,500 14,200 14,000 14,100 13,900 13,900 13,900 13,800 13,800 13,800 13,800 Total Supply (d) = a + b + c 57,900 61,100 60,700 62,600 62,400 62,800 63,100 62,800 63,200 63,200 62,900 62,700 62,700 62,600 62,600 62,600 62,500 62,500 62,500 62,500 Capacity Megawatts (MW) F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 Heritage (a) Hydroelectric 10,500 10,500 10,500 10,950 11,350 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 11,400 Heritage (b) Thermal Existing and (c) Committed IPPs 950 1,100 1,100 1,250 1,250 1,300 1,250 1,250 1,250 1,200 1,200 1,200 1,200 1,150 1,150 1,150 1,150 1,150 1,150 1,150 Reserves Supply (d) = requiring a + b reserves + c 12,350 12,500 12,550 12,650 12,650 12,700 12,750 12,700 12,700 12,650 12,700 12,650 12,650 12,650 12,650 12,650 12,650 12,600 12,600 12,600 14% of (e) = Supply (d) requiring reserves *0.14 1,750 1,750 1,750 1,750 1,750 1,800 1,800 1,800 1,800 1,750 1,800 1,750 1,750 1,750 1,750 1,750 1,750 1,750 1,750 1, MW (f) market reliance Supply not requiring reserves Alcan 2007 (g) EPA Total supply (h) = d e + f + g 11,450 11,550 11,550 11,450 11,050 11,100 11,100 11,050 11,100 11,050 11,050 11,050 11,050 11,000 11,000 11,000 11,000 11,000 11,000 11,000

187 Related Comments / Information Requests: This technical memo provides information related to the following Information Requests: form_ gov_ gov_ gov_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_0213_001 pub_ pub_0248_001 pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ ab_ pub_ pub_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ Response to Wilderness Committee Standard Responses

188 RESPONSE TO WORKING GROUP AND PUBLIC COMMENTS ON THE SITE C CLEAN ENERGY PROJECT ENVIRONMENTAL IMPACT STATEMENT Technical Memo Attachment 1 PROJECT NEED MAY 8, 2013

189 ELECTRIC LOAD FORECAST F13-F33 Electric Load Forecast Fiscal 2013 to Fiscal 2033 Load and Market Forecasting Energy Planning and Economic Development BC Hydro 2012 Forecast December 2012 PAGE 1

190 ELECTRIC LOAD FORECAST F13-F33 Tables of Contents Executive Summary Introduction Regulatory Background and Current Initiatives Forecast Drivers, Data Sources and Assumptions Forecast Drivers Data Sources Growth Assumptions Comparison of 2011 and 2012 Forecasts Integrated System Gross Energy Requirements before DSM with Rate Impact Total Integrated Peak Demand before DSM with Rate Impacts Sensitivity Analysis Residential Forecast Sector Description Forecast Summary Residential Forecast Comparison Key Issues Forecast Methodology Risks and Uncertainties Commercial Forecast Sector Description Forecast Summary Commercial Forecast Comparison Key Issues Forecast Methodology Risk and Uncertainties Industrial Forecast Sector Description Forecast Summary Industrial Forecast Comparison Key Issues and Sector Outlook Forestry Mining Oil and Gas Other Industrials Non-Integrated Areas and Other Utilities Forecast Non Integrated Area Summary Other Utilities & Firm Export Peak Demand Forecast Peak Description Peak Demand Forecast Peak Forecast Comparison Integrated System Peak Risks and Uncertainties Appendix 1 Forecast Processes and Methodologies A1.1. Statistically Adjusted Forecast Methodology A1.2. Industrial Forecast Methodology PAGE 2

191 ELECTRIC LOAD FORECAST F13-F33 A1.3. Peak Demand Forecast Methodology Appendix 2 - Monte Carlo Methods Appendix Oil and Gas (transmission serviced) Appendix Shale Gas Producer Forecast (Montney) Appendix 3.3 LNG Load Outlook Appendix 4 - Electric Vehicles (EVs) Appendix 5 - Codes and Standards Overlap with DSM Appendix 6 - Forecast Tables PAGE 3

192 ELECTRIC LOAD FORECAST F13-F33 Tables Table E1 Comparison of Integrated System Energy before DSM with Rate Impacts Table E2 Comparison of Integrated System Peak Demand before DSM with Rate Impacts Table E3. Reference Energy and Peak Forecast before DSM and With Rate Impacts Table 3.1. Key Forecast Drivers Table 3.2. Data Sources for the 2012 Load Forecast Table 3.3. Growth Assumptions (Annual rate of growth) Table 4.1 Comparison of Integrated Gross System Requirements Before DSM With Rate Impacts (Including Impacts of EVs and Overlap for Codes and Standards) (GWh) Table 4.2. Comparison of Integrated Gross System Requirements Before DSM With Rate Impacts (Including Impacts of EVs and Overlap for Codes and Standards) (MW) Figure 7.1 Comparison of Commercial Sales Forecast before DSM with Rate Impacts. 31 Table 7.1 Commercial Sales before DSM with Rate Impacts Table 8.1 Consolidated Industrial Forecast by Sector before DSM and Rate Impacts Table 8.2 Industrial Forecast by Voltage Service before DSM and Rate Impacts Table 9.1 NIA Total Sales before DSM with Rate Impacts (GWh) Table 9.2 Non Integrated Area Peak Requirements before DSM with Rate Impacts (MW) Table 10.1 Comparison of BC Hydro s Distribution Peak Demand Forecasts before DSM with Rate Impacts Table 10.2 Comparison of BC Hydro s Transmission Peak Demand Forecast before DSM with Rate Impacts Table 10.3 Comparison of Total Integrated Peak Demand Forecast before DSM with Rate Impacts Peak Demand Forecast Methodology Table A1.1 Industrial Distribution Forecast before DSM and Rates Table A2.1. Elasticity Parameter for Monte Carlo Model Table A2.2. Triangular distribution for random variable in Monte Carlo Model Table A3.1 Montney Gas Production and Sales Forecasts Before DSM and Rate Impacts Table A3.2 Major Driver Characteristics and Production Assumptions Table A4.1 Residential and Commercial EV Load (GWh) and (MW) Table A5.1 Residential Energy Forecast (before DSM and rate impacts) with Overlap for Codes and Standards Table A5.2 Commercial Energy Forecast (before DSM and rate impacts) with Overlap for Codes and Standards Table A5.3 Distribution Peak Forecast with Overlap for Codes and Standards PAGE 4

193 ELECTRIC LOAD FORECAST F13-F33 Table A6.1 Regional Coincident Distribution Peaks Before DSM with Rate Impacts (MW) Table A6.2 Regional Coincident Transmission Peaks Before DSM with Rate Impacts (MW) Table A6.3 Domestic System and Regional Peak Forecast Before DSM with Rate Impacts (MW) Table A Reference Load Forecast before DSM with Rate Impacts PAGE 5

194 ELECTRIC LOAD FORECAST F13-F33 Figures Figure 5.1 High and Low Bands for Integrated System Energy Requirements before DSM with Rate Impacts Figure 5.2 High and Low Bands for Integrated System Peak Demand before DSM with Rate Impacts Figure 6.1 Comparison of Residential Sales before DSM and with Rate Impacts Figure 6.2 Comparison of Forecasts of Number of Residential Accounts Figure 8.1 Comparison of Industrial Sales Forecast before DSM and Rate Impacts Figure 10.1 Comparison of BC Hydro s Distribution Peak Demand Forecast before DSM with Rate Impacts Figure 10.2 Comparison of Transmission Peak Demand Forecast before DSM with Rate Impacts Figure 10.3 Comparison of BC Hydro s Integrated System Peak Demand Forecast before DSM with Rate Impacts Figure A1.1 Statistically Adjusted End Use (SAE) Model Figure A1.2 Peak Demand Forecast Roll-up Figure A3.1: Oil and Gas Sector Figure A3.1. Map of Montney and Horn River Basins Figure A3.2 Montney Shale Gas Production Forecast Figure A3.3 Well Production Curve (with other industry projections) PAGE 6

195 ELECTRIC LOAD FORECAST F13-F33 Executive Summary Background and Context BC Hydro is the third largest utility in Canada and serves 95 percent of British Columbia s population. BC Hydro s total energy requirements, including losses and sales to other utilities and non-integrated areas (NIAs), were 57,083 GWh in F Excluding the NIAs, the total integrated system energy requirements were 56,800 GWh 2. The total integrated system peak demand in F2012 before weather adjustments and including losses and peak demand supplied by BC Hydro to other utilities was reported to be 10,338 MW excluding any load curtailments and outages. Load forecasting is central to BC Hydro s long-term planning, medium-term investment, and short-term operational and forecasting activities. BC Hydro s Electric Load Forecast is published annually for the purpose of providing decision-making information regarding where, when and how much electricity is expected to be required on the BC Hydro system. The forecast is based on several end-use and econometric models that use historical billed sales data up to March 31 of the relevant year, combined with a variety of economic forecasts and inputs from internal, government and third party sources. BC Hydro s load forecasting activities are focused on the preparation of a number of termspecific and location-specific forecasts of energy sales and peak demand requirements in order to provide decision-making information for users. A variety of related products including monthly variance reports, inputs for revenue forecasts and load shape analyses, are produced to supplement the forecasts presented in this report. Forecast Methodology BC Hydro produces 21-year forecasts (remainder of current year plus a 20 year projection) for both energy and peak demand. These forecasts are compiled separately but undergo a number of checks to ensure consistency. The load forecasts are prepared before and after incremental Demand Side Management (DSM). The load forecast presented in the Executive Summary and the remainder of the document is before incremental DSM. This is done to keep continuity with previous Annual Load Forecast documents and is consistent with the British Columbia Utilities Commission s (BCUC) Resource Planning Guidelines. Load Forecasts with incremental DSM are presented in other documents such as BC Hydro s Integrated Resource Plan (IRP) or Revenue Requirements Applications. BC Hydro incorporates relatively certain loads and demand trends into its load forecast. BC Hydro s makes use of its Residential and Commercial End Use surveys to calibrate its end use models to historical trends in various end uses and space heating trends. Similarly, BC Hydro includes verifiable information regarding specific customer loads in its load forecast in order to reflect possible reductions due to customer attrition. BC Hydro is closely monitoring technological trends such as the future effects of electrification loads for possible inclusion into its base (Reference, which is the mid) load forecast. In terms of incremental electrification loads, demands from future electrical vehicle (EV) loads are included in the Reference load forecast. EV load estimates are lower as compared to the 2011 Load Forecast for the forecast period; EV load is estimated to be about 1,000 gigawatts per annum (GWh/year) towards the end of the 20 years. Other potential electrification loads are monitored for inclusion into the forecast. The impacts of possible future electricity rate increases (i.e. rate impacts) are also 1 BC Hydro s fiscal year end is March 31; thus, F2012 covers April 1, 2011 to March 31, The NIAs include the Purchase Areas, Zone II and Fort Nelson. A number of small communities located in the northern and southern areas of B.C. that are not connected to BC Hydro s electrical grid make up the Purchase Areas and Zone II. PAGE 7

196 ELECTRIC LOAD FORECAST F13-F33 reflected in BC Hydro s load forecasts. Load forecasts presented in this document are designated as being with rate impacts unless otherwise noted. The energy forecast is produced for each of the three major customer classes: residential, commercial and industrial. Sales to the three customer classes are combined with sales to other utilities to develop total BC Hydro firm sales. These sales estimates are adjusted for system line losses resulting in total gross energy requirements. To determine gross energy requirements for only the integrated system, sales and losses to all NIAs are excluded. Residential The residential sector forecast is the product of accounts and use per account. The account forecast is driven by projections of regional housing starts. This sector is most responsive to variations in temperature relative to the other sectors. The residential use per account forecast (before Rates Impacts, electric vehicles and adjustments for codes and standards) are developed with Statistically Adjusted End-Use (SAE) models. These models combine traditional regression-based forecasting with detailed end-use data to produce forecasts. The key drivers of these end-use models are regional economic variables (i.e., disposable income and population, etc.) and noneconomic variables such as weather and average stock efficiency of the various end uses of electricity. Commercial The total commercial sales forecast includes commercial general distribution loads, other commercial distribution loads such as irrigation and street lighting, and commercial transmission-connected loads such as pipelines and institutions such as universities. In terms of forecasting complexity, larger commercial accounts are forecast using similar methods for large industrial accounts. These methods are forward-looking information that includes expected sector trends, whereas the forecasts for the smaller sales categories such as street lighting rely upon historical sales trends. The commercial general distribution sales forecasts (before including Rates Impacts, electric vehicles and adjustments for codes and standards) are developed with SAE models. The key drivers of these end-use models are regional economic variables (i.e., commercial output (Gross Domestic Product (GDP)), employment, retail sales, and noneconomic variables such as weather and average stock efficiency of the various end uses of electricity. Industrial The industrial sector is made up of distribution and transmission-connected customers. The industrial distribution forecast is developed for specific sub-sectors; where sub-sector analysis has not undertaken, GDP growth projections are used to develop the forecast. The forecasts for larger transmission-connected industrial customers are primarily done on an individual customer account basis and sector basis, utilizing specific customer and sector expertise from inside and outside of BC Hydro (e.g., third party consultant studies). BC Hydro applies a risk assessment to specific accounts within each sector to quantify their individual contribution to a total system forecast. These assessments are based on industry and customer-specific risk factors such as commodity prices, and First Nations/environmental issues. Forestry is made up of wood, pulp and paper and chemicals, where wood and pulp and paper are most of the sales. Mill specific information on production, intensity and on-site generation as well global outlooks for forestry products such as Kraft pulp, papers and packaging are used to develop the forestry forecast. PAGE 8

197 ELECTRIC LOAD FORECAST F13-F33 For the mining sector, the forecast is developed using industrial sector reports from consultants, government mining reports, production forecasts and energy intensity factors. BC Hydro applies risk adjustments to mining project loads, which are intended to factor development risks. Some of the considerations that inform these weights include the financial viability of projects; the status of environmental approvals and whether or not the potential mine proponent has formally applied to BC Hydro for electrical service. For the oil and gas sector, BC Hydro employs two approaches to develop load forecasts, specifically the top-down and the bottom-up methodology. For the top-down approach, BC Hydro uses internal and third party predictions of oil and gas production and energy intensities to create annual load forecasts. The bottom-up method involves the development of forecasts of customer-specific loads, which are then risk adjusted and summed to produce composite loads. The risk adjustment factors are informed by discussions with BC Hydro s key account managers, potential new customers, and government/industry experts. Future LNG Load To date, several Liquefied Natural Gas (LNG) proponents have approached BC Hydro and/or the B.C. Government with respect to LNG projects for the B.C. north coast. Over the past couple of years, BC Hydro and government have been working with LNG proponents on options for meeting all or some of the energy needs of LNG plants with power from the BC Hydro system. The two key options available to LNG developers that involve BC Hydro providing electrical service include: a) Provide power for entire plants with electricity. There is currently a single LNG plant in the world that uses electricity to power liquefaction compressors for making LNG. b) Provide power under a hybrid approach. Natural gas would power liquefaction compressors about 85 per cent of a plant s energy needs and BC Hydro would supply the rest of the plant s needs. The potential new demands of non-compression loads are material and could be between 800 GWh/year to 6,600 GWh/year of additional energy demand, corresponding to about 100 megawatts (MW) to 800 MW of additional peak demand. Given the materiality and binary nature of these outcomes, consideration of these loads in context of the load forecast and its impact of the supply and demand load resource balance will be addressed in BC Hydro s long term plans (e.g., IRPs). Hence the 2012 Reference (mid) load forecast as presented in this document does not include potential LNG loads apart from very small allocations associated with on-site construction (for example, at its highest LNG on-site construction load is forecast to be 86 GWh in F2015). New gas processing and chilling demands from LNG facilities would significantly increase the requirements for electricity above BC Hydro s mid load forecast as presented below. A range of LNG loads are considered as scenarios, and are addressed separately in BC Hydro s planning process. Peak Demand A peak demand forecast is produced for each of BC Hydro s distribution substations and for individual transmission customer accounts. Distribution substation forecasts are prepared for 15 distribution planning areas using energy forecasts and other drivers such as smaller distribution loads or spot loads. These substation forecasts are further aggregated on a coincident basis to develop a total system coincident distribution peak forecast. Relevant production and account information from the transmission energy forecast informs the peak forecasts for each of BC Hydro s large transmission customers. PAGE 9

198 ELECTRIC LOAD FORECAST F13-F33 The transmission peak forecasts for each account are aggregated on a coincident basis to develop a total system coincident transmission peak forecast. The total system peak forecast includes the system coincident distribution, transmission, peak demand transfers from BC Hydro to other utilities and system transmission losses. Comparative Load Forecasts The 2012 Load Forecast was prepared in the fall of 2012 as part of BC Hydro s annual forecasting cycle. The forecast methodology is similar to that used for the 2008 Load Forecast, which was reviewed by BCUC in the 2008 Long Term Acquisition Plan (LTAP) proceeding. The major changes in methodology since the 2008 Load Forecast include: 1. A portion of the industrial distribution sector is now forecast on a sub-sector basis (i.e., mining, oil and gas, wood) versus the previous use of a regression analysis for the entire sector. This change has enhanced the Load Forecast by improving upon the regional and total system load projections by incorporating load drivers such as the pine beetle infestation and specific industrial customer expansions; 2. EV load is now included in the 2012 (Reference) Load Forecast. The EV load estimates are moderate over the first 10 years of the forecast with 14 GWh projected for F2017. By F2032, the EV load rises to 1,270 GWh; and 3. The potential for DSM double counting issue was raised in the 2008 LTAP proceeding. 3 Adjustments to the load forecast for DSM double counting were first made in the 2009 Load Forecast, and have been continued up to the current (2012) Load Forecasts. Appendix 5 shows the annual adjustments for the overlap in codes and standards. As shown in the tables below at the total system level, the 2012 Load Forecast is below the 2011 Load Forecast for all years of the forecast for both energy and peak demand. 3 Refer to 2008 LTAP Decision, Directive 6, page 180. BC Hydro s load forecasting models assume the U.S. Energy Information Administration s (EIA) level of end-use efficiencies. These EIA efficiency levels form the basis of the double counting which results in a lower forecast. In addition, DSM savings due to codes and standards are subtracted in the Load Forecast. PAGE 10

199 ELECTRIC LOAD FORECAST F13-F33 Table E1 Comparison of Integrated System Energy before DSM with Rate Impacts Fiscal Year 2012 Forecast (GWh) 2011 Forecast (GWh) 2012 Forecast minus 2011 Forecast (GWh) Change over 2011 Forecast (percent) F ,153 59,260 (2,107) -3.6% F ,238 67,457 (4,219) -6.3% F ,721 74,171 (2,450) -3.3% F ,475 77,766 (2,291) -2.9% F ,486 83,309 (3,823) -4.6% Table E2 Comparison of Integrated System Peak Demand before DSM with Rate Impacts Fiscal Year 2012 Forecast (MW) 2011 Forecast (MW) 2012 Forecast minus 2011 Forecast (MW) Change over 2011 Forecast (percent) F ,719 11,026 (308) -2.8% F ,681 12,389 (708) -5.7% F ,950 13,382 (432) -3.2% F ,817 14,232 (415) -2.9% F ,701 15,174 (474) -3.1% The residential forecast is below last year s forecast for all years of the forecast due to lower housing starts and account growth projections, and lower loads anticipated from EVs. The residential sector approximately makes up about 8% of the difference in the forecast after 5 years into the forecast, 16% 11 years into the forecast and 27% 20 years into the forecast. The commercial forecast is below last year s forecast within the first five years of the forecast, above last year s forecast in the middle period and below last year forecast in the later years. The lower difference early on comes from the commercial distribution sales; sales are below last year forecast primarily due to a lower anticipated economic forecast in drivers such as employment, retail sales and commercial GDP. In the middle period of the forecast, increased sales to larger commercial transmission customers offset the decline in commercial distribution sales. Sales to large transmission connected pipelines are higher in this year s forecast as well as sales to larger ports and terminals. Towards the end of the forecast, commercial transmission sales are relatively stable and overall commercial sales are below last year s forecast due to lower commercial distribution sales. The commercial sector makes up about 9% of the difference 5 years into the forecast, 1.5% 11 years into the forecast and1 8% 20 years into the forecast. Industrial sales are projected to be lower than last year s forecast for all years of the forecast. Industrial distribution sales, which makes up 20% of all industrial sales, are lower for all years of the forecast because of: i) lower GDP growth forecast and ii) lower sales from the forestry sector and mining sector. On a sub sector basis, industrial transmission PAGE 11

200 ELECTRIC LOAD FORECAST F13-F33 sales have changed as follows: 1. Mining sales are lower due to deferred start-ups and reduced probabilities for new mines driven by lower commodity price expectations and global uncertainty; 2. Sales to forestry are lower as a result of lower load expectations for several Kraft pulp mills and continued trends in digital substitution away from print media; 3. Other transmission sales are lower because of brief delays for expansions for some bulk terminals; and 4. Oil and gas over the short-term as natural gas prices are anticipated to be lower in the short term resulting from deferrals in drilling plans and activities. Overall total industrial sales make up about 63% of the difference in the overall forecast 5 years into the forecast, 72% 11 years into the forecast and 45% 20 years into the forecast Annual Sector and Peak Demand Forecasts Residential Forecast Load in the residential sector, while subject to short-term variability due to weather events, tends to exhibit more predictable growth compared to the other sectors. The residential sector is forecast on a regional basis with the key forecast features including the following: Electricity Use BC Hydro s residential sector currently consumes about 35 percent of BC Hydro s total annual firm billed sales. This electricity is used to provide a range of services (end uses) including space heating, water heating, refrigeration, and miscellaneous plug-in load which includes computer equipment and home entertainment systems. Drivers The drivers of the residential forecast are number of accounts and the average annual use per account. Growth in the total number of accounts is driven largely by growth in housing starts. The use per account forecast is developed on a regional basis from the SAE models. The drivers of the model include economic variables such as disposable income, weather and average stock efficiency of residential end uses of electricity. Trends The residential sales forecast is below the 2011 Load Forecast for all years of the forecast primarily from lower predicted housing starts growth and therefore accounts growth is expected to be slower relative to the previous forecast. The energy impact of EVs over the long term is considerably lower than the 2011 forecast reflecting revised drivers of the EV load model. The 21-year compound growth rate 4, before DSM and with Rate Impacts, is projected to be 1.8 percent per annum. Refer to Chapter 6 for a detailed description of the residential forecast. Commercial Forecast BC Hydro s commercial sector encompasses a wide variety of commercial and publiclyprovided services, including irrigation, street lighting and BC Hydro s own use. The most diverse commercial segment consists of customers who operate a range of facilities such as office buildings, retail stores and institutions (i.e., hospitals and schools) provided at distribution voltages. It also includes transportation facilities in the form of pipelines and bulk transportation terminals which receive electricity at transmission voltages. The key features of the commercial forecast include the following: 4 Unless otherwise noted, all growth rates are calculated as annual compound growth rates. PAGE 12

201 ELECTRIC LOAD FORECAST F13-F33 Electricity Use BC Hydro s commercial sector currently consumes 30 percent of BC Hydro s total annual firm billed sales. On the distribution system, electricity is used to provide a range of services such as lighting, ventilation, heating, cooling, refrigeration and hot water. These needs vary considerably between different types of buildings and types of loads. Drivers Consumption in commercial distribution sales is closely tied with economic activity in the province. Key drivers for the commercial distribution sales include retail sales, employment and commercial output. Other drivers of the end use forecasting model for this sector include weather and commercial end use stock average efficiency forecasts. For the commercial transmission sector, individual customer load projections are developed. Historical load trends are a good indicator of future trends for accounts with relatively stable loads. Trends Electricity consumption in the commercial sector can vary considerably from year to year, reflecting the level of activity in B.C. s service sector. Total commercial forecast is below the 2011 Forecast in the initial period of the forecast; this primarily reflects lower commercial distribution sales driven by slower growing economic drivers. Towards the middle the forecast, the 2012 Forecast is above 2011 Forecast as stronger sales to large pipelines are expected. Total commercial sales towards the end of the forecast are projected to be below last year s forecast due to lower EV load expectations and a lower long term economic growth projection. Over a 21-year period, the 2012 Load Forecast growth rate, before DSM and with Rate Impacts, is 2.0 percent per annum. Refer to Chapter 7 for a detailed description of the commercial forecast. Industrial Forecast BC Hydro s industrial sector is concentrated in a limited number of industries, the most important of which are pulp and paper, wood products, chemicals, metal mining, coal mining and oil and gas sector loads. The remaining industrial load is made up of a large number of small and medium sized manufacturing establishments. Key features of the industrial forecast include the following: Electricity Use BC Hydro s industrial sector currently consumes 32 percent of BC Hydro s total annual firm billed sales. This electricity is used in a variety of applications including fans, pumps, compression, conveyance, processes such as cutting, grinding, stamping and welding and electrolysis. At distribution voltages, wood products manufacturing is the major component of industrial sales. Drivers Industrial electricity consumption is tied closely with economic conditions in the province, and the broader export markets, product commodity prices, and world and domestic events that impact product demand. The key drivers of the forecasts are production, intensity levels, third party industry reports and changes in customer plant operations as identified by BC Hydro s Key Account Managers. Probability assessments are undertaken for existing accounts and new accounts to determine specific customer load projections. Trends Electricity consumption in the industrial sector is quite volatile, driven substantially by external economic conditions that affect commodity markets. The current forecast is lower for all years of the forecast. This reflects several factors such as deferrals and lower probabilities for mining loads, less sales expected for Kraft pulp mills, lower wood sector sales due to slower recovery of US housing starts and reduced gas producer loads in the short term as drilling activity has been pushed back. The 21-year growth rate in the current forecast, before DSM and with Rate Impacts is 1.3 percent per annum. Refer to Chapter 8 for a detailed description of the industrial forecast. PAGE 13

202 ELECTRIC LOAD FORECAST F13-F33 Peak Demand Peak demand is composed of the demand for electricity at the distribution level, transmission level plus inter-utility transfers and transmission losses on the integrated system. Key features of the peak forecast include the following: Electricity Use Peak demand is forecast as the maximum expected one-hour demand during the year. For BC Hydro s load, this event occurs in the winter with the peak driven particularly by space heating load. As with the 2011 Load Forecast, BC Hydro s peak forecast is based on normalized weather conditions, which is the rolling average of the coldest daily average temperature over the most recent 30 years. Drivers Key drivers of electricity peak include the level of economic activity, number of accounts, employment and the other discrete developments such as new shopping malls, waste treatment plants or industrial facilities that drive substation peak demand. Trends BC Hydro s total system peak forecast has grown moderately over the past couple of years. Slower economic growth has tempered increases in distribution and transmission peak demand. The current total system peak forecast is below the 2011 Forecast for all years of the forecast. This is due to lower housing starts and residential account growth projection, slower growth in economic variables such as employment, retails sales and GDP, and lower peak demand from larger industrial customers. The 21-year growth rate in the current forecast, before DSM and with Rate Impacts is 1.8 percent per annum. Refer to Chapter 10 for a detailed description of the peak demand forecast Similar to the 2011 Load Forecast, the energy and peak demand requirements for unconventional gas producers within the Horn River Basin are not included in the 2012 Reference load projections for Fort Nelson. BC Hydro has constructed scenarios that examine various Horn River shale gas play load requirements and alternatives on how to supply these loads. These scenarios are examined in BC Hydro s IRP. Reference Energy and Peak Forecasts Table E3 provides a summary of forecast sector sales, total energy requirements and total peak demand requirements for selected years before DSM and with Rate Impacts. The forecasts include the impact of EVs and an adjustment for overlap in codes and standards. Table E3. Reference Energy and Peak Forecast before DSM and With Rate Impacts Fiscal Year BC Hydro Residential (GWh) BC Hydro Commercial (GWh) BC Hydro Industrial (GWh) Total Firm Sales* (GWh) Total Integrated System Energy Requirements (GWh) Peak Demand** (MW) F ,035 15,617 16,352 51,284 56,800 10,319 F ,211 16,387 16,468 52,220 57,152 10,719 F ,761 17,815 19,016 57,898 63,238 11,681 F ,291 20,323 21,207 65,667 71,721 12,950 F ,409 21,865 20,836 69,038 75,475 13,817 F ,471 23,700 21,273 73,408 80,316 14,915 5 years: F % 2.7% 3.1% 2.5% 2.2% 2.5% PAGE 14

203 ELECTRIC LOAD FORECAST F13-F33 11 years: F % 2.4% 2.4% 2.3% 2.1% 2.1% 21 years: F % 2.0% 1.3% 1.7% 1.7% 1.8% * Total firm sales includes sales to all residential, commercial and industrial customers and sales to all other utilities including Seattle City Light, City of New Westminster and FortisBC and Hyder. ** Peak Demand for F2012 is weather normalized as shown in the table. PAGE 15

204 ELECTRIC LOAD FORECAST F13-F33 1 Introduction BC Hydro's Load Forecast is typically published annually. The Load Forecast consists of a 21-year forecast (remainder of the current year plus a 20-year projection) for future energy and peak demand requirements. These forecasts focus on the annual Reference Load Forecast or the most likely electricity demand projections that are used for planning future energy and peak supply requirements. The Load Forecast is used to provide decision-making support for several aspects of BC Hydro s business including: the Integrated Resource Plan, revenue requirements, rate design, system planning and operations and the Service Plan. Ranges in the load forecasts, referred to as uncertainty bands, are developed using simulation methods. These bands represent the expected ranges around the annual Reference load forecasts at certainty levels of statistical confidence. These forecasts are produced because there is uncertainty in the variables that predict future loads and in the predictive powers of the forecasting models. The Reference energy forecast consists of a sales forecast for three main customer sectors (residential, commercial and industrial) plus the other utilities supplied by BC Hydro. The Reference Total Gross energy requirements forecast consists of the sector sales forecast, other utility sales forecast plus total line losses. The sales forecast is developed by analyzing and modeling the relationships between energy sales and the predictors of future sales, which are referred as forecast drivers. Drivers consist of both economic variables and non-economic variables. Economic variables include GDP, housing starts, retail sales, employment and electricity prices (rates). Non-economic variables include weather and average stock efficiency of various residential and commercial end uses of electricity. The Rate Impacts are reflected in the Reference forecasts; these impacts consist of the effect on load due to potential electricity rate changes under flat rate structures or a single tier rate design 5. Savings or reductions in the load due to changes in rate structures are considered to be part of BC Hydro s 20-year DSM Plan. These savings are not included in the load forecasts contained in this document but are contained in other applications such as BC Hydro s Revenue Requirements Application. The total Reference peak forecast consists of peak demands for BC Hydro s coincident distribution substations, large transmission-connected customers and other utilities, along with total transmission losses. The distribution peak demand forecast is developed by analyzing and modelling the relationship between aggregate substation peak demands and economic variables. Distribution peak forecasts are prepared under average cold weather conditions or a design temperature. The transmission peak demand is based on estimating the future demands of larger customers which are driven by future market conditions and company-specific production plans. BC Hydro continuously attempts to improve the accuracy of its forecasting process by monitoring trends in forecasting approaches and tracking developments that may affect the load forecasts. Forecasts are continually monitored and compared to sales, and are adjusted for variances. Additionally, the load forecasts are adjusted if new information on forecast drivers becomes available during the year they are developed. 5 The electricity price elasticity of demand used to develop the rate impacts is assumed to be for all rate classes. Additional rate-induced savings resulting from stepped rates (conservation rates) are counted separately as DSM savings. PAGE 16

205 ELECTRIC LOAD FORECAST F13-F33 For continuity between the 2011 Load Forecast and the 2012 Forecast, load estimates of EVs are shown in Appendix 4, and adjustment for double counting in codes and standards is shown in Appendix 5. These load categories are necessarily included in the Reference load forecast. Comparisons between the 2011 and the 2012 Forecasts for the Residential and Commercial section are with rate impacts. The Industrial section is compared before rate impacts so as to highlight the key differences between the two vintages of forecasts. The 2012 large industrial transmission loads do not include any LNG loads. These loads are considered in separate load scenarios in BC Hydro s planning process. PAGE 17

206 ELECTRIC LOAD FORECAST F13-F33 2 Regulatory Background and Current Initiatives The British Columbia Utilities Commission (BCUC), various intervenors and other stakeholders have reviewed BC Hydro s Electric Load Forecasts in past years by way of the following regulatory review processes: 2003 Vancouver Island Generation Project Certificate of Public Convenience and Necessity (CPCN) Application F2005 and F2006 Revenue Requirements Application (RRA) 2004 Vancouver Island Call for Tenders Electricity Purchase Agreement (EPA) F2006 Call for Tenders F2007 and F2008 RRA 2006 Integrated Electricity Plan (IEP) and Long Term Acquisition Plan (LTAP) 2008 LTAP F2009 and F2010 RRA 2009 Waneta Transaction F2011 RRA F2012-F2014 RRA (Order G-77-12A June 20, 2012) Dawson Creek/Chetwynd Area Transmission (DCAT) Project. (Decision October 10, 2012) During F2012, there were no major directives that impact the development of the 2012 Forecast from the most recent Decisions and Orders noted above. In its decision on the 2008 LTAP, the BCUC issued two directives related to the 2008 Load Forecast. BC Hydro s 2010 Annual Load Forecast document addresses these two directives in detail. At this time, BC Hydro believes that there is no additional work required to fulfill Directive 7. As for Directive 6 which centers issues related to DSM/Load integration BC Hydro has continued its work in this area and made adjustments to its current load forecast to account for potential overlap between the Load Forecast and the DSM Plan estimates for codes and standards. Please see Appendix 5 for further details on the adjustments. PAGE 18

207 ELECTRIC LOAD FORECAST F13-F33 3 Forecast Drivers, Data Sources and Assumptions 3.1 Forecast Drivers Table 3.1 provides a summary of the load forecast components and key data drivers. Table 3.1. Key Forecast Drivers Forecast Component Data 1. Residential Forecast Historical number of accounts and use per account Housing starts and personal income Heating Degree Day (HDD) and Cooling Degree Day (CDD) Appliance saturation rates from Residential End Use Survey and efficiency data from the EIA 2. Commercial Billing data (Distribution) Forecast Commercial GDP Output Employment and Retail Sales HDD and CDD End use saturation rates from Commercial End Use Survey and efficiency data from the EIA 3. Industrial Distribution Forecast 4. Large Commercial and Industrial Transmission Forecast 5. Non-Integrated Area (NIA) Forecast Billing data GDP Production Forecast Billing data GDP Forecasts from consultants Information from various reports and Key Account Managers Billing data Historical number of accounts Local conditions in the short-term Population forecasts 6. Peak Forecast Distribution energy forecast and housing starts Weather data and load research data on load shape 3.2 Data Sources Information on the sources and uses of the data is shown in Table 3.2. Table 3.2. Data Sources for the 2012 Load Forecast Variable Application Forecast Period GDP Industrial distribution energy forecast Commercial GDP Output Housing Starts Employment, Retail Sales Commercial distribution energy forecast Residential accounts forecast Commercial distribution sales Source BC Ministry of Finance - First Quarter Report, Sept 13, 2012 Stokes Economic Consulting, Aug 2012 Stokes Economic Consulting, Aug 2012 Stokes Economic Consulting, Aug 2012 Stokes Economic Consulting, Aug 2012 PAGE 19

208 ELECTRIC LOAD FORECAST F13-F Growth Assumptions The growth assumptions for key drivers used in the Reference load forecast are shown in Table 3.3 below. Table 3.3. Growth Assumptions (Annual rate of growth) Fiscal Year Residential Accounts (%) Calendar Year Employment (%) Real GDP* (%) Retail Sales (%) Actual F Forecast F F F F F F F F F F F F F F F F F F F F F * Real GDP is total provincial GDP PAGE 20

209 ELECTRIC LOAD FORECAST F13-F33 4 Comparison of 2011 and 2012 Forecasts 4.1 Integrated System Gross Energy Requirements before DSM with Rate Impact Table 4.1 compares this year s total integrated gross requirements Reference forecast with the 2011 Forecast. Both the 2011 and 2012 Forecasts are before DSM, with rate impacts, and includes the impact of electric vehicles (EVs) and adjustments for Load Forecast / DSM overlap in codes and standards. Table 4.1 Comparison of Integrated Gross System Requirements Before DSM With Rate Impacts (Including Impacts of EVs and Overlap for Codes and Standards) (GWh) Fiscal Year 2012 Forecast 2011 Forecast 2012 Forecast minus 2011 Forecast Change over 2011 Forecast (%) Actual F ,982 57, F ,735 58, F ,381 57, F ,190 55, F ,047 55, F ,800 56,803* % Forecast F ,152 59,260-2, % F ,714 61,743-3, % F ,378 63,895-3, % F ,855 65,796-3, % F ,238 67,457-4, % F ,769 69,055-3, % F ,545 70,432-2, % F ,111 71,659-2, % F ,207 72,476-2, % F ,811 73,419-2, % F ,721 74,171-2, % F ,707 75,164-2, % F ,428 75,860-2, % F ,812 75,544-1, % F ,512 76,573-2, % F ,475 77,766-2, % F ,386 78,911-2, % F ,420 80,315-2, % F ,433 82,075-3, % F ,486 83,309-3, % F ,316 Note. * = forecast PAGE 21

210 4.2 Total Integrated Peak Demand before DSM with Rate Impacts ELECTRIC LOAD FORECAST F13-F33 Table 4.2 compares this year s total integrated peak requirements forecast with the 2011 Forecast. Both the 2011 and 2012 Forecasts are before DSM, with rate impacts, and include the impact of electric vehicles (EVs) and adjustments for Load Forecast DSM overlap in codes and standards. An explanation of the changes in the forecast is contained in Chapter 10 on the Peak Forecast. Table 4.2. Comparison of Integrated Gross System Requirements Before DSM With Rate Impacts (Including Impacts of EVs and Overlap for Codes and Standards) (MW) Fiscal Year 2012 Forecast 2011 Forecast 2012 Forecast minus 2011 Forecast Change over 2010 Forecast (%) Actual F ,371* 10,371* - - F2008 9,861* 9,861* - - F ,297* 10,297* - - F ,112* 10,112* - - F ,203* 10,203* - - F ,319* (10,303)** 10, (-348) -3.1% (-3.3%) Forecast F ,719 11,026 (308) -2.8% F ,011 11,505 (494) -4.3% F ,222 11,832 (610) -5.2% F ,451 12,140 (689) -5.7% F ,681 12,389 (708) -5.7% F ,971 12,558 (587) -4.7% F ,230 12,737 (507) -4.0% F ,443 12,923 (481) -3.7% F ,613 13,053 (440) -3.4% F ,743 13,197 (454) -3.4% F ,950 13,382 (432) -3.2% F ,125 13,579 (453) -3.3% F ,288 13,775 (487) -3.5% F ,438 13,891 (453) -3.3% F ,609 14,021 (412) -2.9% F ,817 14,232 (415) -2.9% F ,036 14,436 (400) -2.8% F ,258 14,673 (416) -2.8% F ,482 14,945 (463) -3.1% F ,701 15,174 (474) -3.1% F ,915 - Note. * = actuals **= Weather normalized peak in brackets and forecast variance for F2012 is computed on a weather normalized basis. PAGE 22

211 ELECTRIC LOAD FORECAST F13-F33 5 Sensitivity Analysis 5.1 Background Future electricity consumption is fundamentally uncertain and dependent on many variables such as economic activity, weather, electricity rates and DSM. The future impact of these variables on load is characterized by significant uncertainty. Moreover, load is affected by extraordinary events such as strikes, trade disputes, pine beetle infestations and volatility in commodity markets. Additionally, world events such as recent economic crises, wars and revolutions impact electricity demand. BC Hydro tries to quantify the uncertainty in future load as much as possible by developing accurate, reliable and stable models that specify the relationship between load and its key drivers, and by using reliable and credible sources for forecasts of the key drivers of load. BC Hydro uses a Monte Carlo model to estimate the potential distribution of future loads, and to represent this against the Reference load forecast (see Appendix 2 for details on the Monte Carlo model). This model produces high and low uncertainty bands for each customer category around the Reference forecast by examining the impact on load from the uncertainty in a set of key drivers. For the industrial sector high and low uncertainty bands are generated by a discrete Low and High forecast of the four main industrial sectors (Forestry, Mining, Oil and Gas, and other). Uncertainty for electricity rates and response to electricity rate changes (price elasticity) are also considered in the overall high and low industrial uncertainty bands. For the residential and small commercial sectors, high and low uncertainty bands are generated from the Monte Carlo model using the following major causal factors: economic growth rate (measured by GDP), the electricity rates charged by BC Hydro to its customers, the sales response to electricity rate changes (price elasticity) and weather (reflected by heating degree-days). Probability distributions are assigned to each of these major causal factors, and a further distribution is assigned to a residual uncertainty variable which is also included in the Monte Carlo model. As with the 2011 Forecast, BC Hydro added to the Monte Carlo model a probability distribution for electric vehicles (EVs) and DSM/ load forecast integration on overlap of codes and standards. The Monte Carlo model uses simulation methods to quantify and combine the probability distributions, reflecting the relationships between all factors and electricity consumption with a correlation factor between the Residential, Commercial and Industrial loads. A probability distribution for the overall load forecast (i.e. total Gross Requirements) is thus obtained which shows the likelihood of various total load levels resulting from the simultaneous combined effect of all factors. The intention of this analysis is the creation of high and low forecast bands with approximately 10% and 90% exceedance probabilities, respectively. For planning purposes, BC Hydro uses its mid-load forecast. The high and low forecast bands are used to provide an indication of the magnitude of load uncertainty. The high and low load forecasts before DSM with rate impacts (excluding LNG Load) are shown in Figures 5.1 and 5.2. The high and low total peak forecasts contained in these tables are based on applying a load factor to Monte Carlo simulation outcomes of the total energy requirements. PAGE 23

212 ELECTRIC LOAD FORECAST F13-F33 Figure 5.1 High and Low Bands for Integrated System Energy Requirements before DSM with Rate Impacts 95,000 90,000 85,000 80,000 75,000 GWh 70,000 65,000 60,000 Upper 55,000 Mid Lower 50,000 Figure 5.2 High and Low Bands for Integrated System Peak Demand before DSM with Rate Impacts 17,000 16,000 15,000 14,000 13,000 12,000 11,000 10,000 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 F2032 F2033 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 F2032 F2033 Fiscal Year MW Upper Mid Lower Fiscal Year PAGE 24

213 ELECTRIC LOAD FORECAST F13-F33 6. Residential Forecast 6.1. Sector Description The residential sector currently comprises about 35% of BC Hydro s total annual sales. This electricity is used to provide a range of services for customers (referred to as enduses ). Examples of residential end-uses of electricity are space heating, water heating, refrigeration, and miscellaneous plug-in loads which include computer equipment and home entertainment systems. Since space and water heating loads are dependent on the outside temperature, residential sales can be strongly affected by the weather. Of the 1.67 million residential accounts served by BC Hydro at the end of F2012, 58% are located in the Lower Mainland, 21% are on Vancouver Island, 13% are in the South Interior, and 8% are in the Northern Region. With regard to residential sales, 53% occur in the Lower Mainland, 26% on Vancouver Island, 13% in the South Interior and 8% in the Northern Region. 6.2 Forecast Summary Of the three major customer classes, apart from short-term weather impacts, the residential sector is the most stable in terms of demand variability. Sales to the residential sector are driven by two main factors accounts and use per account. Growth in the number of residential accounts has been 1.6 percent per annum over the last 10 years. The annual growth rate in the number of accounts is expected to remain at 1.4 percent over the next 21 years. Growth in accounts is expected be strong the near and middle terms of the forecast period due to the significant investment expected to take place in the province. Historical use per account reflects several factors such as the recent lingering recession, efficiency-related modifications to building standards, and changes in appliance efficiency and BC Hydro s DSM efforts. The forecast in use per account is expected to grow (before rate impacts and adjustments) on an average annual basis of 0.2 percent over the 20-year forecast period. The residential load forecast is shown in Table 6.1, including a breakdown by the four main regions. The average annual growth in residential sales over the entire forecast period is expected to be about 400 GWh per annum, including rate impacts and the adjustments for electric vehicles and the Load Forecast/DSM overlap for codes and standards. 6.3 Residential Forecast Comparison Residential sales in the 2012 Forecast are projected to be lower than the 2011 Forecast over the entire forecast period (see Figure 6.1). Before DSM with rate impacts the decrease in the residential sales forecast is 440 GWh (-2.4%) in F2013, 327 GWh (-1.7%) in F2017, 399 GWh (-1.8%) in F2023 and 1,043 GWh (-3.8%) in F2032. The key variables that account for the lower residential sales are the residential accounts forecast and electrical vehicle loads projections. The ending number of accounts for F2012 was 1,671,358 which is 7,584 accounts (or 0.5%) below the level assumed in the 2011 Forecast. The lower starting point for the number of accounts and projections for housing starts are the main reasons why the total residential accounts forecast has been reduced. In the 2011 Forecast, the 5, 11, and 21-year growth rates for number of accounts were 1.6%, 1.7%, and 1.5% respectively. In the 2012 Forecast, the growth rates for number of accounts are 1.4%, 1.5% and 1.4%, respectively. PAGE 25

214 ELECTRIC LOAD FORECAST F13-F33 Figure 6.2 below illustrates the residential accounts forecast for the 2012 Forecast compared to the 2011 Forecast. Figure 6.1 Comparison of Residential Sales before DSM and with Rate Impacts 28,000 Annual Billed Sales (GWh) 26,000 24,000 22,000 20,000 18, Forecast 2011 Forecast 16,000 Figure 6.2 Comparison of Forecasts of Number of Residential Accounts 2,300,000 2,200,000 2,100,000 2,000,000 1,900,000 1,800,000 1,700,000 1,600,000 1,500,000 F2008 F2010 F2012 F2014 F2016 F2018 F2020 F2022 F2024 F2026 F2028 F2030 F2032 F2008 F2010 F2012 F2014 F2016 F2018 F2020 F2022 F2024 F2026 F2028 F2030 F2032 Fiscal Year Number of Accounts 2012 Forecast 2011 Forecast Fiscal Year 6.4. Key Issues Over the longer term, the slow growth trend in usage per residential account is not expected to change significantly because of the offsetting effects of the following factors: Increased electric space heating market share is expected to be offset by smaller housing units. Due to limited availability of land for residential development, the trend PAGE 26

215 ELECTRIC LOAD FORECAST F13-F33 in metropolitan centres is expected to be towards denser housing. Since row houses and apartments are more likely to be built with electric heat compared to single family homes, the market share for electrically-heated housing is expected to increase. Although new row houses and apartments tend to be larger than existing similar dwellings, they generally have a smaller floor area than detached single family homes, and therefore have lower space heating load requirements. The increase in market share of electric space heating is also offset to some extent by the improvements in building standards. Manufacturers throughout Canada and the U.S. are expected to continue to improve the energy efficiency of major electrical appliances. As older models wear out and are replaced by newer ones, electricity consumption for major appliances such as refrigerators, freezers, ovens and ranges is forecast to decrease. However, the new models of these appliances tend to be larger and include more features than models currently in use. Therefore, some of the reduction in electricity use resulting from improvements in electricity efficiency will be offset by increases in appliance size and extra features. The projected decrease in the number of people per household tends to reduce electricity use per account. However, this reduction is expected to be offset by changes to lifestyle and technological improvements, which are expected to cause an increase in demand for electronic, entertainment and telecommunication devices in the home. A trend towards home offices is also expected to produce a long-term increase in residential electricity consumption. In the long term, the expected overall impact of these various trends is that the factors working to increase use rates will be offset by the factors working to decrease use rates. 6.5 Forecast Methodology The forecast for residential sales is calculated as the product of the forecast number of accounts times the forecast use per account. To develop the overall residential sales forecast, BC Hydro s total service area was divided into four customer service regions Lower Mainland, Vancouver Island, South Interior and Northern Region. For each region, a third party housing stock forecast was prepared based on the housing starts forecast in the region. The 2012 residential load forecast was prepared using the Statistically Adjusted End-Use (SAE) model. Refer to Appendix 1.1 for further details on the residential sales methodology and drivers of the SAE model. 6.6 Risks and Uncertainties Uncertainty in the residential sales forecast is due to uncertainty in three factors: forecast of number of accounts, forecast of use per account, and weather. (a) Number of Accounts: In the short term, an error in the forecast for account growth would not result in a significant error in the forecast for total number of accounts. This is because account growth is on average 1.4% per year, so in the first year, an error of 1% in the forecast for account growth would result in an error of about 0.014% to the forecast for total number of accounts. However, in the long term, there is increased risk due to the cumulative effect of errors in the forecast for account growth. (b) Use per Account: Most of the risk in the residential forecast resides in the forecast of use per account for the following reasons: i. Unlike the forecast of account growth, an error of 1% in the forecast for use per account in any year would contribute to a direct error of 1% to the forecast for residential sales for that year. PAGE 27

216 ELECTRIC LOAD FORECAST F13-F33 ii. The forecast for use per account is the net result of many counteracting factors. Some of the forces working to increase use rate are: increases in home sizes; natural gas prices increasing faster than electricity prices; increases in electric space heating share; increases in real disposable income; and increases in saturation levels for appliances Some of the forces working to decrease use rate are: increases in heating system efficiencies; electricity prices increasing faster than natural gas prices; new dwellings being built with higher insulation standards; heat omissions from additional appliances reducing electric heating load; increased use of programmable thermostats; and decreases in household sizes Although these positive and negative forces were recognized when the forecast for use rate was developed, there is uncertainty inherent in all of these factors. (c) Weather: In the short term, weather is highly variable. Therefore, in any one year, there is a risk that weather may have a significant impact on residential sales. For example, the El Nino event of F1998 is estimated to have reduced residential sales by about 4%. Since average weather is expected to be close to the rolling 10-year normal values used in the 2012 Forecast, weather is not viewed as being a high risk to the long-term forecast for residential sales. PAGE 28

217 ELECTRIC LOAD FORECAST F13-F33 Table 6.1 Residential Sales before DSM and with Rate Impacts Fiscal Year Lower Mainland Vancouver Island Residential Sales (GWh) South Interior Northern Region Total Residential Actual F2007 8,879 4,426 1,975 1,574 16,853 F2008 9,122 4,631 2,057 1,652 17,462 F2009 9,255 4,730 2,153 1,675 17,813 F2010 9,241 4,553 2,179 1,677 17,650 F2011 9,404 4,676 2,296 1,522 17,898 F2012 9,494 4,750 2,276 1,514 18,034 Forecast F2013 9,594 4,686 2,348 1,583 18,211 F2014 9,846 4,747 2,407 1,663 18,663 F ,099 4,828 2,454 1,727 19,109 F ,274 4,884 2,483 1,776 19,416 F ,481 4,951 2,512 1,817 19,761 F ,731 5,028 2,547 1,857 20,163 F ,001 5,106 2,583 1,888 20,578 F ,302 5,198 2,624 1,918 21,041 F ,575 5,273 2,657 1,950 21,455 F ,852 5,355 2,694 1,983 21,885 F ,114 5,432 2,728 2,017 22,291 F ,401 5,520 2,768 2,052 22,742 F ,658 5,591 2,800 2,084 23,133 F ,935 5,671 2,835 2,113 23,554 F ,206 5,750 2,865 2,138 23,959 F ,504 5,841 2,900 2,164 24,409 F ,767 5,918 2,929 2,186 24,800 F ,048 6,004 2,964 2,211 25,226 F ,329 6,088 3,000 2,235 25,653 F ,626 6,180 3,041 2,261 26,107 F ,873 6,247 3,070 2,281 26,471 Growth Rates 5 years: F2007 to F % 1.4% 2.9% -0.8% 1.4% 5 years: F2012 to F % 0.8% 2.0% 3.7% 1.8% 11 years: F2012 to F % 1.2% 1.7% 2.6% 1.9% 21 years: F2012 to F % 1.3% 1.4% 2.0% 1.8% * Historical growth rates are not weather normalized. Forecast is prepared based on normal weather. PAGE 29

218 ELECTRIC LOAD FORECAST F13-F33 7 Commercial Forecast 7.1 Sector Description The commercial sector currently comprises about 31 per cent of BC Hydro s total domestic sales. The commercial sector consists of distribution voltage sales (below 60 kv) and transmission voltage sales (above 60 kv). Also included within the commercial sector are street lighting, irrigation and BC Hydro Own Use, which is electricity for BC Hydro s buildings and facilities. Within the commercial distribution subsector (94% of commercial sales), there are currently two major demand levels: (i) General Under 35 kw, which includes small offices, small retail stores, restaurants, and motels, and (ii) General Over 35 kw, which includes large offices, large retail stores, universities, hospitals and hotels. The commercial transmission subsector (6% of commercial sales) includes universities, major ports and oil and gas pipelines. 7.2 Forecast Summary Table 7.1 provides a summary of the historical and forecast sales before DSM and with rate impacts 6. Electricity consumption in the commercial sector can vary considerably from year to year reflecting the level of activity in the service sector of B.C. s economy. During F2011, reported billed sales increased by 265 GWh or 1.7 percent, while during F2012 the reported billed sales decreased by 279 GWh or 1.8 percent. The annual average growth rate for commercial sales forecast over the next 5, 11 and 21 years (before DSM with rate impacts) is forecast to be 2.7 per cent, 2.4 per cent and 2.0 per cent, respectively. Commercial distribution, which is the largest portion of total commercial sales, is expected to grow on average by about 300 GWh per annum. Commercial transmission sales are expected to increase in the near term and moderate over the long term; overall commercial transmission sales are expected to grow on average about 80 GWh per annum. 7.3 Commercial Forecast Comparison Figure 7.1 shows the 2012 Forecast of total commercial sales before DSM with rate impacts. Compared to the 2011 Forecast, the current total commercial sales forecast is lower by 73 GWh (-0.4%) in F2013, 381 GWh (-2.1%) in F2017, 29 GWh (-0.1%) in F2023 and 695 GWh (-2.9%) in F2032. The overall commercial distribution load has been revised downwards which is primarily due to lower projections of economic drivers. Slower economic growth projections for the U.S. and global economies impact tourism and retail spending in BC. Sales to the larger commercial customers such as ports and pipelines are projected to grow significantly over the first five years of the forecast; after these expansions are completed, sales are then expected to remain relatively flat. The forecast for oil and gas loads (i.e., pipelines) are further discussed in Appendix Commercial general distribution sales as shown in Table 7.1 include the impact of EV and double counting adjustments for codes and standards. PAGE 30

219 ELECTRIC LOAD FORECAST F13-F33 Figure 7.1 Comparison of Commercial Sales Forecast before DSM with Rate Impacts 25,000 Annual Billed Sales (GWh) 23,000 21,000 19,000 17,000 15, Forecast 2011 Forecast 13,000 F2007 F2009 F2011 F2013 F2015 F2017 F2019 F2021 Fiscal Year F2023 F2025 F2027 F2029 F2031 F Key Issues This section discusses the commercial sales growth projections for each of BC Hydro s four main service regions. Given that the health of the economy and business activity are key drivers of growth in commercial distribution sales, the comments below centre on the economic outlook for each region. Lower Mainland Approximately 66 percent of the sales in the commercial sector are in the Lower Mainland. Commercial sales growth in this region over the next 5, 11 and 21 years is expected to be 2.7 per cent 2.5 percent and 2.2 percent. After two relatively flat years, commercial economic output showed a strong increase of 3 per cent in Commercial GDP output is expected to increase by 2 to 3 per cent per year until it slows down to below 2 per cent in the last 8 years of forecast. As new job seekers are attracted to the Lower Mainland, employment in the service sector is expected to grow to serve the expanding population. Retail, health, education, accommodation and food, and other personal services sectors are likely to see increasing activity. Vancouver Island Vancouver Island makes up 17 percent of BC Hydro s total commercial sales. Commercial sales growth in this region is expected to be 0.1 per cent, 0.3 per cent and 0.5 per cent, over the next 5, 11 and 21 years of the forecast, respectively. During 2011, employment, commercial GDP output and retail sales in Vancouver Island experienced modest or negative growth. Moderate growth in employment is expected, averaging about 0.7% throughout the forecast period. The growth in employment is mainly concentrated in the provincial capital region and in the health, post-secondary education PAGE 31

220 ELECTRIC LOAD FORECAST F13-F33 and government services sector. High paying jobs in these areas are expected to boost disposable income and retail sales. South Interior About 10 percent of BC Hydro s total commercial sales are in the South Interior. Commercial sales growth in this region is expected to be 2.1 per cent, 3.5 per cent and 2.3 per cent, over the next five, 11 and 21 years, respectively. Commercial GDP output grew by 1% in 2011 and is expected to grow by an average of over 2% in the first 10 years of forecast, slowing down to below 2% later in the forecast horizon. The growth is mainly supported by future mining and utility projects, especially in the near term. Similarly, employment is expected to grow at an average of about 1.5% in the near term and 0.5% thereafter. Retail sales will track employment growth but will generally outpace employment, since most new jobs are in high-paying industries such as mining, utilities, health care, government services and education. Northern Region The Northern Region makes up 8 percent of the BC Hydro s total commercial sales. Commercial sales growth in this region is expected to be 7.4 per cent, 4.3 per cent and 2.3 per cent, over the next five, 11 and 21 years, respectively. Industrial investment is the main driver of economic growth in the Northern Region. Economic conditions in the region s industrial base influence migration decisions to the region and drive employment growth, thus influencing income and services sector output growth. Employment, output and population growth are expected to be strong in the first 5 or 6 years of forecast, supported by major projects in natural gas, transportation (pipelines) and mining. Thereafter, employment and population growth slowdown and commercial GDP output stabilizes near the end of the forecast period. Retail sales will follow a similar trend, but will outpace employment because of the creation of higher-paying jobs. 7.5 Forecast Methodology The main determinant of the commercial electricity sales forecast is the level of future economic activity in the province and sub provincial or regional level. The stronger the economy, the more services are needed and the greater the electricity consumption of the commercial sector. Economic drivers such as retail sales, employment, and commercial GDP output are good indicators of future electricity consumption in the commercial sector. These economic variables are combined in the BC Hydro s SAE models that are used to develop the commercial distribution sales forecast for each of BC Hydro s four major service regions. The methodology for the commercial distribution sales forecast is described in Appendix 1.1. Commercial transmission customer forecasts are developed on individual account basis, which is similar to the approach used for developing individual forecasts for industrial customers. 7.6 Risk and Uncertainties Commercial sales models are dependent on the outcome of the regional economic drivers. The regional economic forecasts are provided by Stokes Economic Consulting. In the SAE model, heating degree days and cooling degree days are used to calculate the heating and cooling variables. Total commercial sales are not as sensitive to weather as compared to residential sales. The increase in the large commercial sales in the Forecast is attributed to larger commercial projects including pipelines and storage facilities; there is PAGE 32

221 ELECTRIC LOAD FORECAST F13-F33 some uncertainty regarding the completion of large individual projects and their need for electrical service. Factors Leading to Lower than Forecast Commercial Sales: A change in the economic conditions as commercial sales tends to follow the major indicators of the economy; The pine beetle infestation will cause forestry employment to decline in the long term; this may impact local commercial activity and growth Improved equipment efficiency across the end uses; and The aging provincial population will suppress future employment growth. Factors Leading to Higher than Forecast Commercial Sales: A robust economic recovery and increased tourism activity that would create additional demands for commercial services; Low interest rates encourage consumer spending; and Substantially warmer summers (increasing air conditioning loads) or colder winters (increasing heating loads) relative to historical patterns. PAGE 33

222 ELECTRIC LOAD FORECAST F13-F33 Table 7.1 Commercial Sales before DSM with Rate Impacts Fiscal Year Irrigation, Street Lights and BC Hydro Own Use Commercial Sales (GWh) Commercial General Distribution Commercial Transmission Total Commercial Sales 1 Actual F , ,105 F , ,439 F , ,577 F ,235 1,025 15,631 F ,475 1,062 15,896 F , ,617 Forecast F ,909 1,112 16,387 F ,106 1,278 16,752 F ,208 1,493 17,071 F ,436 1,577 17,384 F ,736 1,707 17,815 F ,103 2,382 18,859 F ,417 2,423 19,216 F ,718 2,454 19,551 F ,954 2,468 19,804 F ,197 2,483 20,064 F ,436 2,500 20,323 F ,722 2,549 20,660 F ,993 2,564 20,948 F ,280 2,587 21,260 F ,542 2,598 21,536 F ,856 2,611 21,865 F ,176 2,625 22,202 F ,535 2,639 22,577 F ,909 2,653 22,968 F ,298 2,667 23,374 F ,616 2,673 23,700 Growth Rates 5 years*: -1.9% 0.4% 6.1% 0.7% F2007 to F years: 1.5% 2.0% 11.6% 2.7% F2012 to F years: 1.0% 1.8% 8.8% 2.4% F2012 to F years: F2012 to F % 1.8% 4.9% 2.0% * Historical growth rates are not weather normalized. Forecast is prepared based on normal weather. 1. Total commercial sales are the sum of Irrigation, Street Lights and BC Hydro Own Use plus Commercial Distribution and Commercial Transmission. PAGE 34

223 ELECTRIC LOAD FORECAST F13-F33 8 Industrial Forecast 8.1 Sector Description The industrial sector currently comprises about 32 percent of BC Hydro s total annual sales. It is organized into four main sub-sectors: forestry, mining, oil and gas and other. Industrial customers are involved in extracting, processing and manufacturing resource based commodities which are largely destined for exports. The industrial sector is also organized by voltage service (transmission vs. distribution). Approximately 80% of the total industrial sales are served at transmission voltages (above 60 kv) with the remaining 20% served at distribution voltages (below 60 kv). New LNG facilities, which are categorized as industrial sector load, potentially represent the biggest additional loads on BC Hydro s system. BC Hydro continues to monitor the development of several potential LNG projects, which are treated as separate scenarios in BC Hydro s long-term planning processes. More information on potential new LNG demands can be found in Appendix Forecast Summary Total industrial sales forecast before DSM and rate impacts are shown in Table 8.1 and Table 8.2. Table 8.1 shows a consolidated projection of industrial sales broken down by industry sub-sectors. Table 8.2 shows total industrial sales broken down between transmission and distribution voltage customers. Over the past five years, total industrial sales declined by about 16 percent. This was primarily due to a decline in forestry sales due to structural changes and permanent closures of pulp and paper mills. Total industrial sales in F2013 are expected to increase by 151 GWh or 0.9 percent relative to F2012, with growth in most of the sub-sectors. The five, 11 and 21-year year growth projection of total industrial sales, before DSM and rate impacts is 3.3 percent, 2.5 percent and 1.3 percent, respectively. Looking forward, BC s industrial customers are expected to have a strong global position due to the quality of the resource base, the demand for B.C. s natural resources and advanced infrastructure to supply industrial products to market. 8.3 Industrial Forecast Comparison Figure 8.1 compares the 2012 Forecast to the 2011 Forecast (before DSM and rate impacts). PAGE 35

224 ELECTRIC LOAD FORECAST F13-F33 Figure 8.1 Comparison of Industrial Sales Forecast before DSM and Rate Impacts 25,000 20,000 Annual Billed Sales (GWh) 15,000 10,000 5,000 - F2008 F2009 F2010 F2011 F2012 F2013 F2014 F2015 F2016 F2017 F2018 F2019 F2020 F2021 F2022 F2023 F2024 F2025 F2026 F2027 F2028 F2029 F2030 F2031 F2032 F2033 Fiscal Year 2012 Forecast 2011 Forecast 8.4 Key Issues and Sector Outlook The following sections describe the outlook, drivers and risk factors for the major industrial sub-sectors. Unless otherwise stated, the comparison between the 2011 Forecast and the 2012 Forecast is based on sales by transmission class customers only Forestry The forestry sector accounts for about 60 percent of industrial sales. Forestry is categorized into three sub-sectors: pulp and paper, wood products and chemicals. Although generalizations can be made across the forestry sector (for instance, the impact of the pine beetle infestation and the recent recession), each sub-sector has different sales history, drivers and market characteristics. Forestry sales have changed significantly over the past number of years. It is expected that the demand for forestry sector goods will continue to recover from the recession. During the past four years, forestry sales declined by about 20 percent, largely due to the pulp and paper and wood product sub-sectors which both experienced shutdowns. In F2013, forestry sales are forecast to decrease by three percent relative to F2012. For the five years ending in F2017, projected sales steadily decline. The decline is attributable to further restructuring measures in the pulp and paper sub-sector and increasing constraints in the wood products sub-sector due to the continuing impact of the pine beetle Infestation. During the F2017-F2022 period, forestry sales remain relatively unchanged with moderate growth in pulp and paper sales being offset by anticipated declines in wood products sales. For the latter 10 years of the forecast period, forestry sales are relatively unchanged from sales in F2023. For details, please see the Overview section below. Pulp and paper sales are forecast to be relatively flat. However, wood products sales remain unchanged as the pine beetle infestation continues to hamper production levels. PAGE 36

225 ELECTRIC LOAD FORECAST F13-F33 Compared with the 2011 Forecast, the 2012 Forecast is approximately 1,300 GWh lower at the end of the forecast period. This is primarily due to the pulp and paper sub-sector where production expectations for certain product grades have been reduced relative to the 2011 Forecast Pulp and Paper Overview Transmission pulp and paper sales represent 61 percent of forestry sector sales and 37 percent of industrial sales. Pulp and paper sales are concentrated in 19 mills located primarily in the south-western and north-eastern parts of B.C. These mills produce and export a wide variety of products including newsprint, coated and uncoated groundwood paper, unbleached kraft (UBK) pulp, bleached chemical pulp, thermo-mechanical pulp (TMP) and marked bleached thermo-mechanical pulp (CTMP). Softwood is predominantly used by mills in the Prince George, Quesnel, South Interior and Vancouver Island regions. Hardwood is used by northern mills located in the Chetwynd area. Vancouver Island uses softwood to produce TMP and CTMP. The main drivers for this sub-sector are pulp and paper market prices, the U.S. economy and increasingly, the global economy. Pulp and Paper Outlook Over the past five years, transmission pulp and paper sales declined by about 30 percent largely due to pulp and paper mill and line closures. The factors contributing this large decrease include: aging equipment, declining fibre availability (due to pine beetle infestation), rising prices of recycled feedstock (due to Chinese demand), strong competition from mills in South America, displacement of newspaper by digital media and increased targeting of electronic media by advertisers. In F2013, sales are forecast to decline over the prior year as global economic condition and pulp and paper demand soften. For the first 10 years of the 2012 Forecast, pulp and paper sales are projected to decline by approximately 1,000 GWh or 17 percent. Further mill and line closures are expected to occur as the industry continues to restructure in order to become more competitive. In the latter half of the forecast period, sales are projected to remain flat. During this period, further mill and line closures are expected but there will also be mill and line expansions into areas that better leverage the operational and fibre environment in which B.C. pulp and paper mills operate. Compared to the 2011 Forecast, the 2012 Forecast for pulp and paper is lower by roughly 600 GWh in the first 10 years and lower by over 1,300 GWh in F2032. These reductions are primary the result of lowered production expectations for certain product grades. Pulp and Paper Drivers and Risk Drivers: North American paper demand for advertising; Growing demand for paper products and market pulp by China and other developing economies because of increased needs for packaging materials and tighter markets for fibre (positive factors for B.C.); Global demand for B.C. s attractive wood fibre which adds strength to recycled papers and a growing number of other applications and products; Growing demand for B.C. s environmentally-friendly pulp and paper (i.e. produced with renewable fuel); PAGE 37

226 ELECTRIC LOAD FORECAST F13-F33 Ability of B.C. mills to transition away from kraft pulp and newsprint to higher value products; Incentive programs for increased electricity self-generation at kraft mills; and B.C. having one of the lowest industrial electricity costs in the world. Risk Factors: Economic swings in the U.S.; Fibre shortage due to pine beetle infestation. This will reduce fibre supply for B.C. pulp mills which use residual chips from lumber and whole log chipping; Competition for fibre supply from bio-fuel and pellet operations; Ongoing decline in the North American newsprint market, where both shipments and advertising expenditures have been progressively declining over the last 10 years; Displacement of B.C. softwood with hardwood pulp by low-cost competitive mills which continue to be built in the Southern Hemisphere; Risk of major equipment failure as some assets near end-of-life, with some mills being forced to close due to a lack of cash flow to fix or replace such capital-intensive assets; Long-term Chinese demand for pulp and paper; and Long-term global demand for tissue Wood Products Overview Wood products represent about 23 percent of forestry sector sales. BC Hydro provides electricity to more than 100 wood products mills located in every major region of B.C., particularly the North Coast, Central Interior and Southern Interior which contain 75 percent of the mills. These facilities produce dimensional and structural lumber, oriented strand board (OSB), medium density fiberboard, plywood, fuel pellets and other specialty products. The primary drivers for wood products demand are housing starts and repair and remodeling. B.C. s share of the U.S. lumber market is greater than all other non-u.s. producers combined. Furthermore, B.C. could soon displace Russia as the dominant lumber supplier to the Chinese market. The B.C. Interior has some of the lowest cost producers of lumber in the world. However, sawmill and plywood plant production will be constrained by saw-log availability due to the mountain pipe beetle (MPB) devastation in the forests of B.C. Although the Ministry of Forests is undertaking measures to address the impact, it is anticipated that forest management practices will be imposed (i.e., limiting the annual allowable cut) such that lumber production will be dramatically reduced. A sustainable level of logging and annual allowable cut is expected to be reached around Thereafter, wood products sales are expected to remain flat for the duration of the forecast period. Wood Products Outlook The recessions had a devastating effect on the wood products sub-sector. Over the last five years, sales fell by 21 percent due primarily to depressed U.S. housing starts. In F2013, wood products sales are forecast to increase modestly due to growth in U.S. housing starts and lumber exports to China. In the near term, sales are expected to increase moderately due to growing demand from China, a recovery in U.S. housing starts and construction activity in post-tsunami Japan. For the five year period starting in F2017, B.C. wood products sales are expected to PAGE 38

227 ELECTRIC LOAD FORECAST F13-F33 progressively decline. As demand for B.C. wood products will exceed the industry s ability to supply due to constraints caused by the Mountain Pine Beetle. For beetle-killed trees, the amount of useable lumber diminishes over time due to deterioration. Over the last 10 years of the forecast period, wood product sales are projected to remain flat, although below historical levels, and below market demand. BC Hydro expects B.C. forest management practices to successfully achieve a sustainable annual cut level which in turn will stabilize lumber production. Compared to the 2011 Forecast, the 2012 Forecast for wood products is lower in the short to medium term (demand weakness and a more constraining effect of the MPB impact on useable log availability) and slightly higher in the long term due to assumptions with respect to the severity of the pine beetle infestation on the wood products sub-sector. Wood Products Drivers and Risk Drivers: U.S. housing starts (currently are less than one half/the level required to match U.S. population growth); Repair and remodeling demand in the U.S., Chinese demand for roof trusses and framing for houses and small apartments; Japanese housing starts (demand for hemlock and SPF); and Demand from other areas in the world such as Korea, India, Taiwan, Hong Kong, Singapore and the Middle East. Risk Factors: The effect of the U.S. economy on the recovery of U.S. housing starts; A softwood lumber trade issues with the U.S.; Harvest life of trees killed by the Mountain Pine Beetle; Medium to long run severity of pine beetle infestation; Higher harvesting costs for B.C. coastal sawmills (caused by steep terrain, outdated equipment and relatively high labour costs); Ability of industry in B.C. Interior to transition towards processing higher volumes of beetle-killed timber; and Ability of B.C.-based OSB producers to continue to improve products for markets Chemicals Overview Chemicals represent about 16 percent of forestry sector sales. Sales are primarily to customers who produce bleaching agents for the pulp and paper industry, for customers who produce cleaning agents for the oil and gas industry and for water purification. Chemical sales are strongly correlated to the health of the pulp and paper industry, particularly the global industry given that much of the product is destined for export. Since chemical companies use electrolysis to producer their bleaching agents, electricity forms a large part of their operating costs. Chemicals Outlook Over the past four years, sales in this sector have remained relatively flat with modest dips that arose due to closures of pulp and paper mills and lines in B.C. In F2011, sales were particularly low due to an extended downtime at a large customer facility experiencing a PAGE 39

228 ELECTRIC LOAD FORECAST F13-F33 complete plant makeover. In F2013, sales are forecast to decrease slightly from the previous year as plant operational improvements were recently made at a couple of facilities thereby decreasing electricity requirements per unit of output. In the near term, chemical sales are expected to slowly increase as some facilities are expanded to meet growing demand for bleaching and cleaning agents, some of which is driven by exports. In the medium and long term, sales are projected to only modestly grow due to weak demand in the B.C. pulp and paper sector, but otherwise stimulated by growing demand for cleaning agents (for the oil and gas industry) and water purification agents (for municipalities). Much of this demand growth in the latter half of the forecast period will be export-based. Chemical Drivers and Risk Drivers: Pulp and paper demand; Global economy; and Oil and gas activity. Risk Factors: Electricity rate increases; Closure of B.C. pulp mills; and Capability of some chemical customers to transition into producing the type of bleaching agents that can be exported outside of B.C Forestry Methodology The 2012 Forecast for the forestry sector was developed by initially assessing last year s forecast. BC Hydro determined that updated information was required for several areas including: (i) a forecast of lumber exports to China (ii) the expected impact of the pine beetle infestation; and (iii) customer mill production. To obtain the necessary information, BC Hydro retained consultants with relevant forestry expertise. The consulting team produced mill production forecasts for all B.C. mills and for various product lines, using several inputs, including long term GDP forecast for countries that purchase B.C. forestry products. BC Hydro incorporated these production forecasts into its load forecasting model to create a sector forecast. The forestry forecast also considered issues such as customers with onsite generation, electricity purchase agreements, historical consumption and electricity consumption intensities, as well as input from BC Hydro s Key Account Managers. BC Hydro developed the forestry sector forecast by multiplying facility production forecasts by the electricity intensity forecast Mining The mining sector accounts for about 17 percent of total industrial sales. It is categorized into two sub-sectors: metal and coal mines. Metal mining makes up for 78% of the current mining sector load. For mining customers, electricity is mostly used for ore extraction, crushing and processing. In the short run, mining sales are not highly sensitive to economic drivers and mineral price movements since existing mines tend to produce continuously through commodity price cycles. In the medium to long term, mining expansions (or attritions), start-ups (or closures) and new project advancements (or deferrals) are sensitive to economic conditions and mineral prices. PAGE 40

229 ELECTRIC LOAD FORECAST F13-F33 The Asia-Pacific region is important for the health of mining in B.C. because more than two-thirds of mining exports are shipped to Japan, China and South Korea. The future outlook for mining is also shaped by mineral exploration, which in turn is influenced by provincial policy. Exploration expenditures in BC increased to record highs following the recession of to meet the surging demand for metal from Chinese and Indian markets. The mining sector invested an estimated $680 million in exploration in 2012, a 47% increase over the previous year s $462 million which was a record year for exploration in British Columbia. Nonetheless, due to a recent slowdown in growth in China s economy, recession in the EU and Japan and prolonged recovery process in other developed countries such as the US, the rate of acquisition and foreign investment in the mining sector has cooled off in 2012, after intense activity between 2009 and Part of the explanation is that mining companies are starting to feel the pressure of higher costs and tighter budgets represented a challenging year for the mining sector. On the positive side, New Afton mine was brought into production last summer; Thompson Creek has successfully completed the expansion project at Endako mine replacing the old mill in March In addition, construction is well underway at Mount Milligan mine with expected start-up in mid-2013, while construction work at Red Chris mine has begun. Expansion projects are continuing on schedule at Gibraltar Mine and Highland Valley Copper while Mount Polley has publically announced the extension of mining operations to Nonetheless, access to financing has become an issue for smaller companies, while lower commodity outlooks for molybdenum, copper or coal have affected most of the competitors. Faced with continued depressed prices for molybdenum as well as operational problems, Thompson Creek has decided to temporarily shut down mining operations at Endako in July While the newly commissioned $500 million mill would still operate on stockpiles, the low molybdenum prices may continue to hamper profitability. Additionally, cost outruns at Mt Milligan have forced Thompson Creek to sell rights to future gold production and implement cost saving measures at other mining operations in order to raise necessary financing to complete the project. Teck has also announced in the fall of 2012 that the $1.5-billion of planned spending in 2012 and 2013 is being pushed out to the future. The company is facing permitting delays at the Quintette coal mine project in Northeast BC. Disputes over the employment of foreign workers in coal mining operations in Northeast BC as well as First Nation opposition to a series of projects (most notably New Prosperity) could delay or cancel the development of several new mines. In spite of the recent pressure on the mining sector, the 2012 Mining Forecast load still grows significantly in the next few years of the forecast. Most of the growth is, however, the result of new projects recently energized and expected to wrap up or expansions to existing operations. The 2012 Mining Forecast is lower compared to the 2011 Forecast due to increased uncertainty in the economic outlook and lower commodity price outlooks. Short term surplus and depressed prices continue to be a concern for molybdenum operations, while a slowdown in steelmaking activity has cooled off the metallurgical coal markets after several years of steady increases, driven by construction activity in Asia. The forecast is also lower as a result of a recent decision of the Provincial government to reject Morrison mine environmental permit. While the current environment has negatively affected some metal mine projects, the increased economic uncertainty has maintained the interest in gold operations. Additionally, existing copper-gold mines that are not facing large investment decisions are still fairly well positioned to increase production and push back shutdown dates. PAGE 41

230 ELECTRIC LOAD FORECAST F13-F33 Despite a recent slowdown in growth, China is still expected to fuel long-term activity in the BC mining sector Metal Mines Overview Metal Mines Outlook BC metal mining sector includes copper, gold, silver, molybdenum, lead and zinc operations. In the long term, electricity sales to mines are tied to price expectations for copper, molybdenum and gold. The prices of these commodities are influenced by global demand and supply and the state of the global economies. In the short term on a month to month basis, electricity sales to metal mines are relatively independent of commodity price fluctuations because these mines are predominantly fixed-cost operations which typically need to run continuously. Mining sales are not overly dependent on domestic economic activity but are more correlated to the global economy since the most of BC metal mining production is exported. The top destinations for BC metallic mineral exports include Japan, the United States, China and Korea. Since early 2009, the metal mining sector in B.C. has benefited from strong copper and gold prices. British Columbia is viewed as an attractive environment for global mining investment. Sales to metal mining customers in short term are expected to increase due to start-up or ramp ups of several newly commissioned mines as well as expansions to existing facilities. In the medium to long term, metal mine sales are expected to peak at approximately 5,000 GWh per year around 2020 as new mines come online and several existing mines ramp up production. The long term demand for copper and molybdenum is expected to be driven by high demand from Asia and to some extent recovering Western economies. The forecast decreases to 4,000 GWh per year long term as some of the large operations shut down. Compared to the 2011 Forecast, this year s metal mining sales forecast is significantly lower overall as several new projects have deferred start dates. Probabilities to several new mines have been lowered due to increased uncertainty in the economic and commodity outlook. Metal Mine Drivers and Risk Drivers: Copper, gold and molybdenum prices which in turn are driven by economic activity Industry perception of the resource friendliness of the B.C. government and its present and future tax regime; and Level of supporting infrastructure (ports, roads, power and proximity to communities) and the potential for future development. Risk Factors: Future provincial and federal government actions that increase or decrease clarity of Regulatory policy, conflict resolution measures, and tax efficiencies; Outcome of future Environmental Assessment applications, particularly with regard to First Nations issues; and Aging workforce and the looming wave of retirements over the next years. According to a report released in 2012 by the Mining Industry Human Resources Council in partnership with the BC Mining HR Task Force, British Columbia will employ over 16,700 mining professionals in the next 10 years. However the study PAGE 42

231 ELECTRIC LOAD FORECAST F13-F33 acknowledges that human resources challenges continue to threaten the future competitiveness of the BC mining industry Coal Mines Overview Coal mines comprise about 22% percent of BC Hydro s mining sector sales. The coal is predominantly produced in southeastern B.C. with the larger coal mining customers in this region accounting for roughly 90 percent of total sales. Coal is also produced in the northeastern B.C., which currently has a small production share but is expected to grow significantly. The single mine on Vancouver Island produces thermal coal. Elk Valley Coal Partnership, which owns five mines in southeastern B.C., is the second biggest supplier of metallurgical coal in the world. Metallurgical coal is an export commodity which is sold worldwide to integrated steel mills for steel-making purposes. In the long term, coal mining sales are tied to price expectations for coal, which is largely driven by metallurgical coal demand. Markets for British Columbia coal include Japan, China, South Korea and India, Europe, South America and the US but shipments to Asian countries represent more than 50% of BC coal exports. As a result, the state of the BC economy has little effect on coal sales but provincial regulatory and policy actions can have a significant impact. Most of the coal produced in southeast BC is transported by rail to the Westshore Terminals; coal produced by the northeast BC mines is shipped via Ridley Terminals Inc. s in Prince Rupert while the coal produced on Vancouver Island is exported via Texada Island and Neptune Terminals in Vancouver. The aforementioned terminals were or will be subject to significant upgrades in the coming years to accommodate the higher volume of coal shipments and cargo traffic. The provincial and federal governments recently pledged $750 million "that will improve rail efficiency and add capacity for coal and other export bulk commodities. 7 Coal Mines Outlook The price for metallurgical coal has weakened recently after a strong five-year run spurred by rising demand from Asia, and particularly China. Additionally, global uncertainty has forced several companies to revise capital expenditures in short term. In the 2012 Forecast, short-term coal mining sales are expected to stay relatively flat in the next couple of years and increase past F2014 with the anticipated start-up of new mines. Over the long term, the distribution and transmission coal sales growth is projected to slow due to more moderate expectations of growth in the global economy, rail line and mine constraints in BC. Compared to the 2011 Forecast, the current forecast is lower in short, medium and long term. This is largely the result of decreased expectations for several new coal mine projects as a result of lower global economic outlook and deferred capital expenditure. Nonetheless, the coal forecast is still increasing by more than 30% by F2017 relative to F2012 sales, sustained by global demand for metallurgical coal, particularly from China and India. Coal Mine Drivers and Risk Drivers: 7 PAGE 43

232 ELECTRIC LOAD FORECAST F13-F33 Demand for steel in Japan, South Korea, China, the European Union and India; and Global economic outlook, particularly in Asia and the U.S. Increased coal export capacity Risk Factors: Expanded Australian coal production. Australia accounts for roughly two-thirds of the global metallurgical coal production; First Nation opposition and increasing environmental and local opposition Disputes over the employment of foreign workers in coal mining operations have the potential to delay projects such as Murray River or Gething B.C. mining construction costs; Rail and terminal capacity constraints; and Future policies or regulations that could impact coal exploration or development Mining Methodology To develop the 2012 Forecast for coal mining, BC Hydro relied upon a consulting team with a proven record that annually publishes a BC mining report which includes production forecasts and metrics. In addition to the consultant s report, BC Hydro used several other internal sources (BC Hydro Key Account Managers, Marketing, Powersmart, intelligence from BC Hydro s Interconnection Group), external sources (company reports, industry reports) as well as its own judgement to assign risk probability weightings to new mines and expansion projections. As such, the forecast is developed on an in depth analysis that involves intensity, production and probability assessments or risk factors Oil and Gas Oil and gas loads exist in both the industrial and commercial sectors. The forecast outlook and drivers for the oil and gas sector are fully described in Appendix 3.1. In addition, Appendix 3.2 provides an overview of the unconventional shale gas sub-sector in northeastern B.C Other Industrials In F2012, sales to Industrial Other category, as shown in Table 8.2, makes up 2.1 per cent of total industrial sales Other Industrials Overview A sizable portion of the transmission customers includes cement companies and auto parts manufacturers. Accordingly, sales are relatively sensitive the provincial economy Other Industrials Outlook As shown in Table 8.2, sales in F2013 are expected to rise by 8.7 per cent over the previous year. Cement sales are expected to remain relatively strong driven by a rebound in construction activity in North America and continuing growth in Asia. In long run, sales growth slows down to roughly 0.7 per cent per year as it is expected that the provincial and global economic growth rate slows down. PAGE 44

233 ELECTRIC LOAD FORECAST F13-F33 Compared with the 2011 Forecast, the 2012 Forecast is generally slightly below the 2011 Forecast. This reflects updated information on the expansion plans for several customers as well as a marginally lower long term economic growth. Other Sector Drivers and Risk: Drivers Provincial economic growth. Construction activity, which in turn affects the demand for cement companies. Risk factors: Economic slowdown or sectorial shifts in BC economy Increased environmental regulations may affect competitiveness of large cement producers. PAGE 45

234 ELECTRIC LOAD FORECAST F13-F33 Table 8.1 Consolidated Industrial Forecast by Sector before DSM and Rate Impacts Fiscal Year Industrial Customers Mining Forestry Total Sales Actual Forecast Metal Mines Coal Mines Wood Pulp & Paper Chemical Oil & Gas Other F2007 2, ,850 8,678 1, ,884 19,469 F2008 2, ,674 8,024 1, ,950 18,737 F2009 2, ,228 7,184 1, ,894 17,382 F2010 2, ,039 5,830 1, ,696 15,608 F2011 2, ,189 5,928 1, ,680 15,783 F2012 2, ,216 6,046 1, ,723 16,352 F2013 2, ,287 5,715 1, ,798 16,504 F2014 2, ,384 5,459 1,565 1,091 2,930 17,031 F2015 3, ,446 5,156 1,605 1,499 3,001 17,887 F2016 3, ,467 5,084 1,601 1,750 3,116 18,664 F2017 4, ,357 4,863 1,612 2,358 3,130 19,234 F2018 4, ,330 4,943 1,614 2,877 3,151 20,167 F2019 4, ,268 5,178 1,615 3,263 3,187 21,050 F2020 5, ,206 5,298 1,617 3,521 3,222 21,675 F2021 5, ,206 5,278 1,619 3,679 3,223 21,857 F2022 4, ,203 5,016 1,621 3,764 3,275 21,477 F2023 4, ,186 5,038 1,627 3,897 3,257 21,478 F2024 4, ,165 5,012 1,633 3,934 3,311 21,542 F2025 4, ,165 4,937 1,639 3,967 3,361 21,509 F2026 4, ,165 4,959 1,645 3,994 3,399 21,102 F2027 4, ,165 4,977 1,651 4,020 3,424 21,048 F2028 4, ,165 4,982 1,657 4,045 3,451 21,131 F2029 4, ,165 4,987 1,663 4,070 3,486 21,222 F2030 4, ,165 4,991 1,669 4,129 3,522 21,348 F2031 4, ,165 4,996 1,675 4,152 3,561 21,440 F2032 4, ,165 5,000 1,681 4,173 3,594 21,522 F2033 4, ,165 5,000 1,683 4,183 3,624 21,575 Growth Rates: 5 years: -1.1% 3.7% -4.9% -7.0% 0.2% 8.3% -1.1% -3.4% F2007 to F years: 13.6% 5.5% 1.2% -4.3% 0.1% 19.1% 2.8% 3.3% F2012 to F years: 7.2% 2.5% -0.1% -1.6% 0.2% 13.3% 1.6% 2.5% F2012 to F years: 3.1% 1.3% -0.1% -0.9% 0.2% 7.1% 1.4% 1.3% F2012 to F2033 PAGE 46

235 ELECTRIC LOAD FORECAST F13-F33 Table 8.2 Industrial Forecast by Voltage Service before DSM and Rate Impacts Fiscal Year Transmission Voltage Customers Distribution Mining Forestry Oil & Gas Metal Coal Wood Pulp & Chemical Mines Mines Paper Other All Total Sales Sectors Actual F2007 2, ,195 8,678 1, ,252 19,469 F2008 2, ,162 8,024 1, ,181 18,737 F2009 2, ,001 7,184 1, ,891 17,382 F2010 2, ,830 1, ,613 15,608 F2011 2, ,051 5,928 1, ,704 15,783 F2012 2, ,105 6,046 1, ,819 16,352 Forecast F2013 2, ,170 5,715 1, ,865 16,504 F2014 2, ,202 5,459 1, ,017 16,937 F2015 3, ,215 5,156 1,605 1, ,066 17,768 F2016 3, ,216 5,084 1,601 1, ,166 18,567 F2017 4, ,128 4,863 1,612 1, ,279 19,173 F2018 4, ,117 4,943 1,614 2, ,402 20,141 F2019 4, ,099 5,178 1,615 2, ,476 21,023 F2020 5, ,074 5,298 1,617 2, ,492 21,648 F2021 5, ,074 5,278 1,619 3, ,547 21,857 F2022 4, ,074 5,016 1,621 3, ,613 21,477 F2023 4, ,069 5,038 1,627 3, ,680 21,478 F2024 4, ,055 5,012 1,633 3, ,730 21,542 F2025 4, ,055 4,937 1,639 3, ,783 21,509 F2026 4, ,055 4,959 1,645 3, ,823 21,102 F2027 4, ,055 4,977 1,651 3, ,852 21,048 F2028 4, ,055 4,982 1,657 3, ,882 21,131 F2029 4, ,055 4,987 1,663 3, ,920 21,222 F2030 4, ,055 4,991 1,669 3, ,958 21,348 F2031 4, ,055 4,996 1,675 3, ,999 21,440 F2032 4, ,055 5,000 1,681 3, ,033 21,522 F2033 4, ,055 5,000 1,683 3, ,055 21,575 Growth Rates: 5 years: -1.1% 3.0% -1.5% -7.0% 0.2% 5.3% -4.2% -2.1% -3.4% F2007 to F years: 13.6% 4.9% 0.4% -4.3% 0.1% 22.9% 6.7% 2.3% 3.2% F2012 to F years: 7.2% 2.0% -0.3% -1.6% 0.2% 14.9% 1.7% 1.9% 2.5% F2012 to F years: 3.1% 1.0% -0.2% -0.9% 0.2% 7.9% 1.3% 1.3% 1.3% F2012 to F2033 PAGE 47

236 ELECTRIC LOAD FORECAST F13-F33 9 Non-Integrated Areas and Other Utilities Forecast 9.1. Non Integrated Area Summary Characteristics The Non Integrated Areas (NIA) include the Purchase Areas, Zone II and Fort Nelson. Load estimate for Fort Nelson is not included in the Integrated System Load forecast as it is connected to the Alberta transmission grid instead of the BC Hydro grid. A number of small communities located in the Northern and Southern parts of B.C. that are not connected to BC Hydro s electrical grid make up the Purchase Areas and Zone II. The Purchase Area consists of six locations in the South Interior, namely Lardeau, Crowsnest, Newgate, Kingsgate-Yahk, Kelly Lake, and Keenleyside Dam. To serve customers in the Purchase Area, BC Hydro purchases electricity from a number of neighbouring electric utilities. Zone II consists of ten locations in the Northern Region, namely Masset, Sandspit, Atlin, Dease Lake, Eddontenajon, Telegraph Creek, Anahim Lake, Bella Bella, Bella Coola and Toad River. In F2012, sales to the total NIA represented about 0.5% of total BC Hydro service area sales. In F2012, annual sales in the Purchase Area, Zone II, and Fort Nelson were approximately 13 GWh, 103 GWh, and 167 GWh respectively. Fort Nelson sales accounted for about 60% of all the sales in the NIA. Drivers For the Purchase Area, the forecast is developed by a trend analysis of the total energy and capacity requirements for each location that makes up the Purchase Area. For Zone II and Fort Nelson, forecasts are developed on a customer sector basis. The drivers for residential sales are housing starts and the average annual use per account. A housing starts forecast is provided by external sources. The average annual use per account in Zone II is based on a statistically adjusted end use (SAE) model. For Zone II, the driver for commercial and industrial sales is the population forecast provided by BC Stats. The driver for small commercial and industrial sales within the Fort Nelson area is the employment forecast provided by consultants. For Fort Nelson, the large industrial accounts at the distribution and transmission level represent a significant part of the load. The forecast for each large industrial customer is developed separately. Increased activity in the oil and gas sector in the Horn River basin, north of the city of Fort Nelson, is anticipated to have an impact on sales within the municipality. As such Fort Nelson sales are expected to have the highest growth rates amongst all NIA communities. Trends and New Developments Table 9.1, 9.2 and 9.3 show the sales, total gross requirements and total peak demand forecast for the Purchase Areas, Zone II and Fort Nelson. Sales within Zone II grew at an average annual rate of 0.4% over the last 5 years and they are expected to grow by 2%, 1.2% and 0.7% annually over the next 5, 11 and 21 years. Total sales within Fort Nelson have declined by 15% since F2009 mainly due to reduced sales to the wood products sector. It is expected that sales will recover and grow relatively steadily into the medium term. This growth will be fuelled by future oil and gas activity which is anticipated to increase sales to residential and commercial customers connected to the Fort Nelson distribution system. In addition, some increase in sales to larger conventional oil and gas customers is expected over the forecast period. Consistent with the 2011 Forecast, sales and peak demand requirements for unconventional gas producers within the Horn River basin are not included in the 2012 load projections for Fort Nelson. BC Hydro has constructed scenarios that examine various Horn River shale gas play load requirements and alternatives on how to supply PAGE 48

237 ELECTRIC LOAD FORECAST F13-F33 these loads 8. Risks and Uncertainties The main risks to the NIA forecast are discrete events such as the opening or closing of a large new account and developments in Northeast BC, particularly the rate of gas resource development. This is impacted by natural gas prices and the rate of economic growth. 8 These supply scenarios are in BC Hydro planning process. PAGE 49

238 ELECTRIC LOAD FORECAST F13-F33 Table 9.1 NIA Total Sales before DSM with Rate Impacts (GWh) Fiscal Year Purchase Area Sales Zone II Sales Fort Nelson Sales Total NIA Sales Actual F (estimate) F (estimate) F (estimate) F (estimate) F (estimate) F (estimate) Forecast F F F F F F F F F F F F F F F F F F F F F Growth Rates 5 years: F % 0.4% 1.3% 0.8% to F years: F % 2.0% 10.2% 7.1% to F years: 0.8% 1.2% 5.2% 3.7% F2012 to F years: F2012 to F % 0.7% 2.9% 2.1% Note: the sales in the table above represent part of the total sales for residential, commercial and industrial sales as shown in other sections of this document. PAGE 50

239 ELECTRIC LOAD FORECAST F13-F33 Table 9.2 Non Integrated Area Peak Requirements before DSM with Rate Impacts (MW) Fiscal Year Purchase Area Peak Zone II Peak Fort Nelson Peak Total NIA Peak Actual F F F F F F Forecast F F F F F F F F F F F F F F F F F F F F F Growth Rates 5 years: F % 1.6% 0.8% 1.0% to F years: F % 1.3% 7.5% 4.5% to F years: 0.1% 0.9% 4.2% 2.6% F2012 to F years: F2012 to F % 0.5% 2.5% 1.6% Note: NIA peak requirements, including Fort Nelson, are not included in the peak demand forecast shown in Chapter 10. PAGE 51

240 ELECTRIC LOAD FORECAST F13-F Other Utilities & Firm Export The other utilities served by BC Hydro are: City of New Westminster, FortisBC, Seattle City Light and Hyder. The City of New Westminster is surrounded by BC Hydro s Lower Mainland region. The FortisBC service area is part of southeastern B.C., Seattle City Light is in the state of Washington, and Hyder is in the state of Alaska. Hyder is served at distribution voltage whereas the other three utilities are served at transmission voltage. Pursuant to a BCUC decision dated June 9, 1993, BC Hydro is obligated to provide FortisBC with up to 200 MW of capacity and associated energy under tariff rates. BC Hydro is obligated to serve Seattle City Light in accordance with a treaty between British Columbia and Seattle dated March 30, The treaty expires on January 1, The community of Stewart, B.C. is connected to BC Hydro s grid. Since Hyder, Alaska is only five km away from Stewart, BC Hydro also serves the Alaskan community. In F2012, annual energy sales to City of New Westminster, FortisBC, Seattle City Light, and Hyder were 454 GWh, 514 GWh, 311 GWh, and 1 GWh, respectively Forecast Drivers The forecast for the City of New Westminster is based on trend analysis and information from BC Hydro s distribution planners on new potential larger projects. Previously, BC Hydro s forecast of sales to FortisBC was based on information received annually from that utility. For the 2012 Forecast, projected sales to FortisBC are additionally based on a comparison of the relative cost of purchasing electricity from BC Hydro (including rate projections) under the 3808 Tariff versus the cost of spot market purchases. The results of this analysis was to decrease the forecasted sales to FortisBC by about 500 GWh per year in the near and middle of the forecast period. Long-term sales forecasts were only slightly modified. The forecast for Seattle City Light is prescribed within the treaty, and the sales forecast for Hyder remains at 1 GWh per year Trends and Risks The City of New Westminster is forecast to have modest average annual growth rate of about 1.3 per cent over the entire forecast period. The forecast for sales to FortisBC is lower than last year s forecast given that market prices have recently been lower than BC Hydro s 3808 Tariff. Both Seattle City Light and Hyder are forecast to have no significant growth. The main risk to the forecast for the City of New Westminster is a discrete event such as a large new account. The main risk to the forecast for FortisBC would be a possible change in how that utility plans to meet its supply requirements. Given that the forecast for Seattle City Light is based on a signed treaty, there is minimal sales risk over the entire forecast period. The sales risk for Hyder is also minimal given that its load is so small. PAGE 52

241 ELECTRIC LOAD FORECAST F13-F33 Table 9.3 Sales to Other Utilities & Firm Export before DSM and Rate Impacts (GWh) Fiscal Year Sales to Other Utilities and Firm Export (GWh) City of New Westminster FortisBC Seattle City Light Hyder, Alaska Total Other Utilities & Firm Export Actual F ,712 F ,674 F ,598 F ,504 F ,289 F ,280 Forecast F ,154 F ,301 F ,299 F ,333 F ,311 F ,317 F ,325 F ,336 F ,477 F ,687 F , ,853 F , ,904 F , ,910 F , ,918 F , ,926 F , ,935 F , ,942 F , ,950 F , ,958 F , ,967 F , ,973 Growth Rates 5 years: 1.1% -12.0% 0.1% 1.1% -5.6% F2007 to F years: 1.5% -0.1% -0.1% -1.1% 0.5% F2012 to F years: 1.6% 6.2% 0.0% -0.5% 3.4% F2012 to F years: F2012 to F % 3.4% 0.0% -0.3% 2.1% PAGE 53

242 ELECTRIC LOAD FORECAST F13-F33 10 Peak Demand Forecast 10.1 Peak Description BC Hydro s peak demand is defined as the maximum expected amount of electricity consumed in a single hour under an average cold temperature assumption referred to as the design temperature. BC Hydro is a winter peaking utility, as its demand is more sensitive to colder temperatures than warmer temperatures. The total BC Hydro system typically reaches its annual peak on a cold winter day between 5:00 pm and 6:00 pm. Vancouver Island has a morning and an evening peak as residential space heating is a larger component of the Island load. The Domestic peak includes distribution substation peaks, transmission customer peaks and the peak demand of the City of New Westminster and system transmission losses. The Integrated system peak demand is the domestic peak demand plus the peak demands from the other served utilities including FortisBC and system transmission losses. Distribution substation peaks are the most sensitive to ambient temperature. The distribution peak demand is driven by various factors including residential accounts and growth in distribution energy sales, which in turn is driven by economic forecasts. In addition, larger discrete loads such as shopping malls, waste treatment facilities and other infrastructure projects contribute to the peak at specific distribution substations are also considered. Transmission peak demand is responsive to external market conditions and changes in demands for BC s key industrial commodities such as wood, pulp and paper and mining sectors Peak Demand Forecast The 2012 peak forecast presented in the section and the comparison to the 2011 forecast is with rate impacts and before incremental DSM. The forecasts below include the impact of EVs and other adjustment for overlap in savings from codes and standards. BC Hydro s all-time total domestic system peak was 10,113 MW which occurred on November 29, The daily average temperature for that day recorded at the Vancouver International Airport (YVR) was -5.9 ºC. For F2012, the actual domestic peak demand of 9,929 MW was recorded at 6:00 pm on January 18, The average temperature for the day at YVR was -5.7 ºC. The weather-adjusted domestic peak for the winter of F2012 was estimated at 10,054 MW, this value also includes an adjustment for curtailment of a transmission customer and a substation outage at the time of the peak. For the winter of F2012, the total integrated system peak forecast, including peak requirements from the other utilities served by BC Hydro, was 10,352 MW before weather adjustments but including outages and curtailments and 10,319 MW, after weather adjustments including outages and curtailments. The integrated system peak forecast, before DSM and with rate impacts (excluding LNG related loads) is expected to 11,681 MW in F2017, 12,950 MW in F2023, and 14,915 MW in F2033. These increases represent growth rates of 2.5 per cent over the next five years (F2012 to F2017), 2.1 per cent over the next 11 years (F2012 to F2023), and 1.8 per cent over the next 21 years of the forecast (F2012 to F2033). Between F2011 and F2012, the total system coincident distribution peak increased after weather adjustments, by 66 MW or about 0.9%. The moderate growth in the peak is attributed to a moderate economic growth over this time period which impacted both energy and peak demand. The coincident transmission peak demand grew very moderately by 33 MW or 2.4% over the same time period. PAGE 54

243 ELECTRIC LOAD FORECAST F13-F Peak Forecast Comparison Distribution Peak Comparison Figure 10.1 and Table 10.1 show last year s coincident distribution peak forecast and the current projection for BC Hydro s coincident distribution substation peak forecasts before DSM and with rate impacts. The distribution peak demand forecast is below last year s forecast. A slower growth in residential accounts is projected in this year s forecast relative to last year forecast. In addition, economic drivers of employment, retail sales and GDP are projected to grow slower in this year s forecast relative to last year which resulted in lower growth in the general service contribution to the distribution peak demand. The reduction in energy sales for the distribution wood sector has also contributed to a lower expected growth in distribution peak demand from over the short term. As well, a reduction in peak demand is expected in near term from distribution connected oil and gas loads as natural gas prices have remained low. The distribution forecast is also affected by the reduction in peak demand from electrical vehicles. This decrease is attributed to reduced drivers of EV load; for additional details please Appendix 4. PAGE 55

244 ELECTRIC LOAD FORECAST F13-F33 Table 10.1 Comparison of BC Hydro s Distribution Peak Demand Forecasts before DSM with Rate Impacts Distribution Peak Demand (MW) 2012 Forecast Less 2011 Forecast Fiscal Year 2012 Forecast 2011 Forecast F2011 7,771* 7,771* 0 0.0% F2012 7,837* 7, % F2013 8,027 8, % F2014 8,198 8, % F2015 8,297 8, % F2016 8,407 8, % F2017 8,549 8, % F2018 8,710 8, % F2019 8,868 9, % F2020 9,019 9, % F2021 9,154 9, % F2022 9,285 9, % F2023 9,482 9, % F2024 9,642 9, % F2025 9,802 9, % F2026 9,970 10, % F ,144 10, % F ,332 10, % F ,527 10, % F ,723 10, % F ,920 11, % F ,118 11, % F ,309 * = Weather Normalized Actual % Difference Figure 10.1 Comparison of BC Hydro s Distribution Peak Demand Forecast before DSM with Rate Impacts PAGE 56

245 Transmission Peak ELECTRIC LOAD FORECAST F13-F33 Figure and Table compare the 2012 and 2011 BC Hydro total coincident transmission peak forecast before DSM and with rate impacts, and excluding LNG. The transmission coincident peak forecast is substantially lower in the 2012 Forecast compared to last year. In the short-term, the current transmission peak forecast is below the 2011 Forecast due to a several factors consistent with the transmission energy forecast. This includes reduced forestry related peak demand from revised production and specific mill forecasts, and new in-service date information on peak demand requirements for new mines expected over the five years. Additionally the near-term peak demand from oil and gas sector is lower. Over the medium to long-term, the transmission peak forecast is lower than last year forecast driven by a decrease in the mining sector energy and peak forecast. The uncertainty in global economic conditions, lower commodity outlook and the tightening of financing conditions for many mining companies have resulted in lower probabilities for new projects and pushed out start dates for several mines. While expectations for mining peak loads are considerably lower over the medium to long term, the oil and gas producer load forecasts (energy and peak demands) are somewhat high over this period. For further details, on long term gas producers and oil pipeline loads see Appendix 4. PAGE 57

246 ELECTRIC LOAD FORECAST F13-F33 Table 10.2 Comparison of BC Hydro s Transmission Peak Demand Forecast before DSM with Rate Impacts Fiscal Year 2012 Forecast (NO LNG) Transmission Peak Demand (MW) 2011 Forecast 2011 Forecast Less 2011 Forecast % Difference F2011 1,385 1, % F2012 1,418 1, % F2013 1,469 1, % F2014 1,565 1, % F2015 1,660 2, % F2016 1,761 2, % F2017 1,830 2, % F2018 1,935 2, % F2019 2,016 2, % F2020 2,059 2, % F2021 2,079 2, % F2022 2,067 2, % F2023 2,059 2, % F2024 2,060 2, % F2025 2,048 2, % F2026 2,018 2, % F2027 2,001 2, % F2028 2,006 2, % F2029 2,012 2, % F2030 2,021 2, % F2031 2,029 2, % F2032 2,034 2, % F2033 2,038 Figure 10.2 Comparison of Transmission Peak Demand Forecast before DSM with Rate Impacts PAGE 58

247 Integrated System Peak ELECTRIC LOAD FORECAST F13-F33 Table and Figure compare the total integrated system peak demand forecasts for the 2011 and 2012 Forecasts before DSM and with rate impacts. The integrated peak demand forecast is the sum of the peak forecast for coincident distribution, transmission, and other utilities plus system transmission losses. Table 10.3 Comparison of Total Integrated Peak Demand Forecast before DSM with Rate Impacts Fiscal Year Integrated System Peak Demand (MW) 2012 Forecast 2011 Forecast 2012 Forecast Less 2011 Forecast % Difference F ,335* 10,335* 0 0.0% F ,319* 10, % F ,719 11, % F ,011 11, % F ,222 11, % F ,451 12, % F ,681 12, % F ,971 12, % F ,230 12, % F ,443 12, % F ,613 13, % F ,743 13, % F ,950 13, % F ,125 13, % F ,288 13, % F ,438 13, % F ,609 14, % F ,817 14, % F ,036 14, % F ,258 14, % F ,482 14, % F ,701 15, % F ,915 * = Weather Normalized Actual PAGE 59

248 ELECTRIC LOAD FORECAST F13-F33 Figure 10.3 Comparison of BC Hydro s Integrated System Peak Demand Forecast before DSM with Rate Impacts 16,000 15,000 14,000 13,000 MW 12,000 11,000 10,000 9, Forecast 2011 Forecast F2011 F2013 F2015 F2017 F2019 F2021 F2023 F2025 F2027 F2029 F2031 F2033 Fiscal Year 10.4 Peak Demand Forecast Methodology This section provides an overview of how the distribution, transmission and total system peak demand forecast is developed. The detailed methodology is described in section Appendix A1.3. The methodology description excludes additional peak load impacts of electric vehicles and the DSM overlap between codes and standards. These additional adjustments to the distribution peak forecasts are shown in Appendices 4 and Distribution Peak Methodology At the distribution level, electricity demand is closely linked to the historical trends in distribution substation load growth and the economic outlook for each forecast region. Thus, the regional economic outlook is one of the primary inputs into distribution peak demand forecasts, with such input being provided to BC Hydro by Stokes Consulting Inc. The distribution peak forecast is developed using forecasts from two main sources: (1) outputs from an econometric model referred to as the distribution peak guideline forecast; and (2) load forecast information consistent with BC Hydro s individual distribution substations. The substation forecasts are based on the growth in the guideline forecasts, expected transfers among substations and anticipated new large loads (i.e., discrete projects) that are specific to each substation. The distribution peak guideline forecast is prepared for 15 different planning areas for the first 11 years of the forecast period. The forecast provides a guideline for the total noncoincident (MVA) growth for all of the substations serving distribution customers in that area. The main drivers used in the model are the forecasts of distribution energy and the number of residential customer accounts, which is driven by housing starts. After the distribution peak guideline and substation forecasts are completed for each of the 15 areas, a final distribution peak forecast is prepared. These forecasts are aggregated for the 15 planning areas to develop a total distribution substation peak for each the four major service regions (Lower Mainland, Vancouver Island, South Interior PAGE 60

249 ELECTRIC LOAD FORECAST F13-F33 and Northern Region). Regional power factors and coincidence factors are applied to aggregated forecasts to produce four regional coincident distribution peak forecasts in MW. For the second 10 years of the forecast period, the distribution peak forecast for each region is derived using the growth rate in the distribution energy sales forecast. A total BC Hydro distribution substation peak forecast is prepared as a coincident sum of the four regional distribution peak forecasts. The equations and other details describing the development of the distribution peak forecast are contained in Appendix A Transmission Peak Methodology The transmission peak demand forecast is prepared on a customer-by-customer account basis for the entire forecast period. Individual transmission customer forecasts are developed using market intelligence from BC Hydro s key account managers, historical peak demand trends, reports on industry outlooks, plus production and intensity estimates. These forecasts are aggregated into regional peak forecasts (i.e.; a total transmission peak demand forecast) for each of the four main service regions. Regional coincidence factors and power factors are applied to each of these total regional peak forecasts to establish regional coincident transmission peak forecasts. A total BC Hydro transmission peak demand forecast is prepared as a coincident sum of the four regional transmission peak forecasts. The equations and other details describing the development of the transmission peak forecast are located in Appendix A1.3. PAGE 61

250 ELECTRIC LOAD FORECAST F13-F Integrated System Peak Forecast Methodology A total system peak demand forecast is prepared as the sum of the total coincident distribution peak, total coincident transmission peak, peak demands for other utilities and total system transmission losses. The coincident distribution peak and transmission peak forecasts are informed from the individual substation forecasts. As such, the substation demands at the distribution and transmission level are counted once in developing the total system peak forecast. The system transmission losses are assumed as 7.5 percent of the total system peak demand forecast. The system peak demand forecast is prepared for the BC Hydro s domestic system and the total integrated system. The domestic peak demand is the sum of the total domestic distribution and transmission peaks, the peak demand of the City of New Westminster and system transmission losses. The integrated system peak demand is the domestic peak demand plus the peak demands from the other utilities (i.e., Seattle City Light and FortisBC) and system transmission losses Risks and Uncertainties Uncertainties and risks in the peak demand forecast come from several factors such as the assumptions on the growth of forecast drivers and model parameters to the anticipated normal weather assumption and its impact on the peak demand. Upward Pressure on Peak Demand: The strong housing demand in B.C. as evidenced by residential accounts growth; Stronger regional growth; Continued high commodity prices and market demand for B.C. s exports; and Increased number of discrete distribution-connected spot loads. Downward Pressure on Peak Demand: Slowdown in the housing market with more vacancies and less development than expected; Lower commodity prices and a slowdown in the U.S. or Asian economies; and Pine beetle infestation resulting in additional forestry sector challenges. BC Hydro quantifies the overall uncertainty in the peak demand using the results of the Monte Carlo uncertainty model as described in Chapter 5. PAGE 62

251 11 Glossary ELECTRIC LOAD FORECAST F13-F33 Accrued Sales are an estimate of electricity delivered within a specific month. Most customer meters are not read at every month-end, so the amount of electricity delivered in a month is not known precisely. In accordance with GAAP, monthly accrued sales are used for monthly financial reporting. Backcasting Estimating econometric or other models over a historical time period and comparing the predictions of the models to actual results over the same time period. Billed Sales The amount of electricity billed. Because bills are produced after the electricity has been delivered, monthly billed sales lag monthly delivery of electricity. Binary Variable is a variable whose value is either zero or one. Binary variables are often used as independent variables in regression models in order to account for events that either occur or do not occur. In this latter context, binary variables are often referred to as dummy variables in regression. Calibration Estimating econometric or other models over a historical time period. Coincidence Factor A ratio reflecting the relative magnitude of a region s (or customer s or group of customers ) demand at the time of the system s maximum peak demand to the region s (or customer s or group of customers ) maximum peak demand. Commercial Output Commercial output focuses on the provisions of services in the economy and so includes such things as public administration, insurance agents, bankers, wholesale and retail trade, food services, accommodation provisions etc. Consumer Price Index (CPI) An inflation index calculated by comparing the price of a typical bundle of goods in the year in question to the price of the same goods in a set reference year. Cooling Degree Day (CDD) is a measure of warmness, defined by the number of degrees above 18 degrees Celsius for the average daily temperature. CDDs are drivers of utility air-conditioning electricity loads. Demand-Side Management (DSM) Activities that occur on the demand side of the revenue meter and are influenced by the utility. DSM activities result in a change in electricity sales. Past DSM savings include incremental load displacement and energy efficiency savings. Note that BC Hydro s historical sales include the impact of DSM savings realized up to that year. Design Temperature Rolling average of the coldest daily average temperature over the most recent 30 years Distribution voltage customer A BC Hydro customer who receives electricity via distribution lines that operates at lower voltages (60 kv and less). Domestic System Peak includes the peak requirements for BC Hydro s distribution and transmission customers in its service territory; sales to the City of New Westminster and system transmission and distribution losses. Econometric Modelling The use of statistical techniques, typically regression analysis of time-series and/or cross-sectional data, to detect statistically verifiable relationships, coherent with economic theory, between an explained variable (e.g. electricity consumption) and explanatory variables (e.g. industry output, prices of alternative energy inputs and GDP). Elasticity The proportionate change in a dependent variable (e.g. electricity consumption) divided by the proportionate change in a specified independent variable (e.g. electricity price). A dependent variable is highly elastic with respect to a given independent variable if the calculated elasticity is much greater than one. The dependent variable is inelastic if the elasticity is less than one. PAGE 63

252 ELECTRIC LOAD FORECAST F13-F33 End-use Model A model used to analyze and forecast energy demand, which focuses on the end uses or services provided by energy. Typical end uses are lighting, process heat and motor drive. For a given industry, the model estimates the influence of prices and technological change on the evolution of the secondary energy inputs required to satisfy the industry's end uses over time. Energy The amount of electricity delivered or consumed over a certain time period, measured in multiples of watt-hours. A 100-watt bulb consumes 200 watt-hours in two hours. Energy Efficiency Is the ratio of the energy service delivered from a process or piece of equipment to the energy input. Energy efficiency is a dimensionless number, with a value between 0 and 1 or, when multiplied by 100, is given as a percentage. EV Electric Vehicle GAAP Generally Accepted Accounting Principles Gigawatt-hour (GWh) A measure of electrical energy, equivalent to one million kilowatthours. (See Units of Measure.) Gross Domestic Product (GDP) A measure of the total flow of goods and services produced by the economy over a specified time period, normally a year or quarter. It is obtained by valuing outputs of goods and services at market prices (alternatively at factor cost), and then aggregating the total of all goods and services. Heating Degree Day (HDD) Is a measure of coldness, defined by the number of degrees below 18 degrees Celsius for the average daily temperature. HDDs are drivers of utility space heating electricity loads. Integrated System That portion of the BC Hydro electricity system which is connected as one whole by a high voltage transmission grid. Integrated System Peak includes the peak requirements for BC Hydro s distribution and transmission customers in its service territory; sales to Other Utilities, which includes Seattle City Light, New Westminster, FortisBC and Hyder Alaska (Tongass Power and Light Co. Inc.); and system transmission and distribution losses. Intensity A unitized measure of energy consumption, typically in kilowatt-hours per unit of stock. For example, kwh per account in the residential sector or kwh per unit of production in the industrial sector. Kilowatt-hour (kwh) A measure of electrical energy, equivalent to the energy consumed by a 100-watt bulb in 10 hours. (See Units of Measure) Liquefied Natural Gas (LNG) is natural gas that has been converted temporarily to liquid form for ease of storage or transport. This process involves refrigeration, and requires no chemical transformations. Load The total amount of electrical power demanded by the utility's customers at any given time, typically measured in megawatts. Load Displacement Projects that involve the installation of self-generation facilities at customer sites, with the electricity generated being used on-site by the customer, with a resultant decrease in the purchase of electricity from BC Hydro. Megawatt (MW) A unit used to measure the capacity or potential to generate or consume electricity. One MW equals one million watts. (See Units of Measure.) Megawatt-hour (MWh) A measure of electrical energy, equivalent to 1,000 kwh. (See Units of Measure) Monte Carlo Method A technique for estimating probabilities involving the construction of a model and the simulation of the outcome of an activity a large number of times. PAGE 64

253 ELECTRIC LOAD FORECAST F13-F33 Random sampling techniques are used to generate a range of outcomes. Probabilities are estimated from an analysis of this range of outcomes. Megavolt-Amps (MVA) a unit of apparent power, which is real power in MW, divided by power factor. Natural conservation The increase in energy efficiency that would occur in the absence of any utility-induced demand-side management program, all other things being equal. Non-coincident In general is the magnitude of a region s (or customer s or group of customers ) demand at the time of its peak. Non-Integrated Area (NIA) Non-integrated facilities refer to generating facilities that are not connected to the system, located in remote areas of the province Normalization The correction of actual customer sales and peak demand for factors such as unusually warm or cold weather. Ordinary Least Squares (OLS) is a method of estimating parameters to minimize the sum of squares errors in a regression model. Price Elasticity of Demand The percentage change in quantity demanded, divided by the percentage change in price that caused the change in quantity demanded. Real Price Increases that have been adjusted for changes in prices of all goods. The nominal price of an item may rise by 10 per cent over a year, but inflation (and assumed wages) may have risen by seven per cent over the same time period. Therefore the effective price increase faced by the consumer is close to three per cent. It is necessary to deflate current prices by an appropriate inflation index (the CPI in Canada) to convert money values to constant prices or real terms. Reference Forecast before DSM and Rate Impacts is the energy and peak demand forecast developed under the current methodology. It is developed under the assumption that electricity rates increase at the rate of inflation and normal weather conditions. Region A geographical sub-division of the BC Hydro service area used for Load Forecast purposes. Four regions exist: Lower Mainland, Vancouver Island, South Interior and the Northern Region. Stock A quantity representing a number of energy consuming units. For example, in the residential sector, stock is the number of accounts or housing units; in the commercial sector, stock is represented by the floor area of commercial building space. System Coincident Peak Demand The greatest combined demand of all BC Hydro customers faced by the generation system during a given fiscal year. Transmission Voltage Customer A BC Hydro customer that is supplied its electricity via high-voltage transmission lines (60 kv or above). Units of Measure The large amounts of electricity generated and consumed on a systemwide basis are discussed in multiples of the basic units of watt and watt-hours. Kilowatts and megawatts are used to measure power, and kilowatt-hours, megawatthours, and gigawatt-hours are used to measure energy. The equivalence is: 1 kilowatt (kw) = 1,000 watts 1 megawatt (MW) = 1,000 kilowatts or 1 million watts 1 kilowatt-hour (kwh) = 1,000 watt-hours 1 megawatt-hour (MWh) = 1,000 kilowatt-hours or 1 million watt-hours 1 gigawatt-hour (GWh) = 1,000 megawatt-hours or 1 billion watt-hours PAGE 65

254 ELECTRIC LOAD FORECAST F13-F33 Appendix 1 Forecast Processes and Methodologies There are a number of key components to the demand and sales forecast: the residential forecast; the commercial forecast (distribution and transmission voltage), the industrial forecast (distribution voltage and transmission voltage), and the regional and system peak forecasts. The peak forecast includes the distribution voltage and transmission voltage peak demands. This section covers the methodology used for these forecast components. A1.1. Statistically Adjusted Forecast Methodology Distribution BC Hydro forecasts residential and commercial distribution sales 9 by using the Statistically Adjusted End-Use model (SAE). This model incorporates end-use information, economic data, weather data and market data to construct regional forecasts. The statistically adjusted end-use modeling framework begins by defining energy use (Use m ) in year and month (m) as the sum of energy used by heating equipment (Heat m ), cooling equipment (Cool m ), and other equipment (Other m ). Formally, (A1.1) USE m = Heat m + Cool m + Other m Equation (A1.1) can be shown in a regression form, as shown below in (A1.2): (A1.2) USE m = a + b1 XHeatm + b2 XCoolm + b3 XOther m + ε m Here, XHeat m, XCool m, and XOther m are explanatory variables constructed from end-use information, economic drivers, dwelling data and weather data and ε m is the error term for the regression. The estimated model can then be thought of as a statistically adjusted end-use model, where the estimated coefficients are the adjustment factors or the relative contribution by the major end uses to the total consumption. The equations used to construct these X-variables are simplified end-use models, and the X-variables are the estimated usage levels for each of the major end uses based on the end use models. BC Hydro also includes other variables in equation A1.2. Other variables include binary variables to account for migration of accounts between customer classes. In addition seasonal variables are included. Constructing XHeat. Space heating energy is specified to depend on the following types of variables: Heating degree days (weather), Heating equipment saturation levels (fraction of building stock for the commercial sector), Assumptions about heating equipment operating efficiencies, Average number of days in the billing cycle for each month, 9 The commercial sales are composed of commercial general rate class, transmission and BC Hydro Own Use, Irrigation, Street-lighting. The SAE model is used to forecast the sales for the commercial general rate class. The sales forecast for BC Hydro Own Use, Irrigation, and Street-lighting is done using historical sales data and trend analysis. The SAE models are calibrated over a 10 year rolling period. PAGE 66

255 ELECTRIC LOAD FORECAST F13-F33 Economic variables include employment, retail sales and commercial output. The heating variable is represented as the product of an annual equipment index and a monthly usage multiplier. That is, (A1.3) XHeat = HeatIndex HeatUse m m where, XHeat m is estimated heating energy use in a year (y) and month (m), HeatIndex y is the annual index of heating equipment in the year (y), and HeatUse m is the monthly usage multiplier. The sub equation for HeatIndex m in (A1.3) is: m HeatIndex y = EndUseEnergye, spaceheating BaseYear Sharey Eff ShareBaseYear Eff y BaseYear Where, y means year, e refers to the category of space heating, Share means saturation level of space heating, Eff means efficiency level of space heating based on Energy Information Administration (EIA) data The sub equation for XHeatUse m in (A1.3) is: HeatUse m = Commercial GDPIndex β1 m EmploymentIndex β2 m RetailSalesIndex β3 m Heating Degree Days Index m. Where m refers to month specific values and the β values are the elasticity that apply to the various regional economic indices above (i.e., commercial GDP, employment, and retail sales) and small commercial sales. The residential SAE model some of the economic drivers are different to the commercial sector economic drivers. The residential sector drivers include: disposable income, household sizes and weather as non-economic drivers. The economic indices for each variable are developed based on a 12 month rolling average of the economic variable weighted by its average monthly value in the last historical year. The heating equipment index (HeatIndex) depends on the space heating equipment saturation levels normalized by average operating efficiency levels. As a result, the index will increase over time if there are increases in heating equipment saturation levels, and will decrease over time if there are improvements in equipment and building efficiency levels. Heating system usage levels (HeatUse) are driven on a monthly basis by economic variables and non-economic factors, such as weather (Heating Degree Days). Constructing XCool. The explanatory variable for cooling loads is constructed in a similar manner. The amount of energy used by cooling systems depends on the following types of variables: Cooling degree days (weather), Cooling equipment saturation levels (fraction of building stock for the commercial sector), Assumptions about cooling equipment operating efficiencies, Average number of days in the billing cycle for each month, PAGE 67

256 ELECTRIC LOAD FORECAST F13-F33 Economic variables include employment, retail sales and commercial output. The cooling variable is represented as the product of an equipment-based index and monthly usage multiplier. That is, (A1.4) XCool = CoolIndex CoolUse m m m where, XCool m is estimated cooling energy use in a year and month (m), CoolIndex y is an index of cooling equipment for the year (y), and CoolUse m is the monthly usage multiplier. As with space heating, the cooling equipment index (CoolIndex) depends on the cooling equipment saturation levels normalized by average operating efficiency levels. As a result, the cooling index will increase over time if there are changes in cooling equipment saturation levels, and will decrease over time if there are improvements in equipment efficiencies or the thermal efficiency of buildings. Space cooling system usage levels (CoolUse) are driven on a monthly basis by several factors, including weather (Cooling Degree Days) and similar economic factors used to develop heating usage. Constructing XOther. Monthly estimates of consumption for non-weather sensitive end uses can be derived in a similar fashion. Non-weather sensitive end-uses include lighting, refrigeration, cooking, clothes washing and drying, entertainment and other miscellaneous equipment. Based on end-use concepts, other sales are driven by: Appliance and equipment saturation levels, Appliance efficiency levels, Average number of days in the billing cycle for each month, and Economic variables include employment, retail sales and commercial output. The explanatory variable for other uses is defined as follows: (A1.5) XOther = OtherEqp Index OtherUse m m The first term on the right hand side of this expression (OtherEqpIndex y ) embodies information about appliance saturation and efficiency levels. The second term (OtherUse) captures the impact of changes in economic variables that impact use of other equipment. These economic variables are similar to those used for explaining heating and cooling. m Figure A1.1 below summarized the inputs that are used in the construction of the regression variables (i.e. the predictor variables) for the commercial sector. PAGE 68

257 Figure A1.1 Statistically Adjusted End Use (SAE) Model ELECTRIC LOAD FORECAST F13-F33 Heating Saturation Resistance Heat Pump Heating Efficiency Thermal Efficiency Economic Drivers for Commercial Sector AC Saturation Central AC Room AC AC Efficiency Thermal Efficiency Economic Drivers for Commercial Sector Saturation Levels Water Heating Appliances Lighting Densities Plug Loads Appliance Efficiency Economic Drivers for Commercial Sector Heating Degree Days Cooling Degree Days Billing Days XHeat XCool XOther USE m = a + b 1 XHeat m + b 2 XCool m + b 3 XOther m + ε m The main reason BC Hydro adopted the statistically adjusted end use model for the commercial sector is to enhance transparency. In the 2005 Forecast, the commercial sector load forecast was based on a regression approach using GDP as the main driver. Since the 2006 Forecast, BC Hydro has run the SAE models for the distribution class by the four regions. A1.2. Industrial Forecast Methodology Industrial Distribution As indicated in the industrial section, BC Hydro applies a regression model to estimate the sales for the remaining sectors of the industrial distribution customers. The customers do not include sectors such as wood, mining, and oil and gas but includes customers such as agriculture, chemical, and other types of manufacturing and processing. The methodology used to develop the forecast for oil and gas loads please see Appendix A3.2. For mining and wood, the methodology follows from production and intensity, where the production estimates come from third party consultants. The industrial distribution energy forecast for the remaining segment is developed using regression methods based on the following expression: (A1.6) Where: INDD = (e α + β * T )*GDP INDD is industrial distribution sales PAGE 69

258 ELECTRIC LOAD FORECAST F13-F33 α and β are the regression coefficients from a time series regression of industrial distribution sales over provincial real GDP and a time trend and appropriate binary variables. e is exponential base T is a time trend variable The results of the industrial distribution regression forecast, for the remaining segment, are provided in the table below. Model A1.1 Model A1.1 Estimation OLS Method Constant 2.76 Independent Trend Variable Economy Binary Variable N/A Adjusted R-sq 0.14 Autocorrelation < 1.01 or > 1.34 Range (AR) Durbin-Watson 1.71 Autocorrelation Detected? No The forecast as produced by estimated regression and the forecasts for oil and gas, mining and wood sectors are provided in the table below. Table A1.1 Industrial Distribution Forecast before DSM and Rates Fiscal Year Regression Forecast Remaining Industrial Distribution (GWh) Total Distribution Oil and Gas Mining and Wood (GWh) Total Industrial Distribution Forecast (GWh) F2013 2,411 1,454 3,865 F2014 2,442 1,575 4,017 F2015 2,487 1,579 4,066 F2016 2,538 1,628 4,166 F2017 2,587 1,692 4,279 F2018 2,637 1,765 4,402 F2019 2,673 1,803 4,476 F2020 2,703 1,788 4,492 F2021 2,731 1,816 4,547 F2022 2,783 1,830 4,613 F2023 2,837 1,843 4,680 F2024 2,886 1,844 4,730 PAGE 70

259 ELECTRIC LOAD FORECAST F13-F33 F2025 2,932 1,850 4,783 F2026 2,966 1,857 4,823 F2027 2,988 1,864 4,852 F2028 3,012 1,870 4,882 F2029 3,043 1,876 4,920 F2030 3,076 1,882 4,958 F2031 3,111 1,888 4,999 F2032 3,140 1,893 5,033 F2033 3,167 1,888 5,055 Industrial Transmission Development of the load forecast for the gas loads is described in Appendix A3.2. The following information is supplemental to the process outline in the forestry and mining sections in Chapter 8. The methodology used in forecasting the industrial, transmission-voltage consumption incorporates expertise from many sources. Although the forecast is performed on a sector and customer basis, the methodology within each is basically a three step process: 1) creation of consultant reports, 2) internal verification of the reports and 3) application of the reports to the forecast. The consultant reports, used to develop the forestry and mining are produced by independent industry experts. Most of the reports generated provide a long-term economic outlook for that sector and individual production forecasts within that sector. During the compilation and forecasting process, the following information is compiled and used to produce the individual account forecasts: Historical loads, power factors, load factors, production forecasts, energy intensity factors (such as kwh/ unit of output); Expansion and expected in-service dates; The perceived risk of projects and new loads; and Discussions with BC Hydro s Key Account Managers and other expert contacts. These are compiled to develop a forecast for each transmission account in the areas of forestry, coal and metal mining. For the other large transmission industrial sector, which includes cements companies and auto parts manufacturers, the forecasts are developed on account-by-account basis for the first 11 years of the forecast and then extended by growth rate in GDP and elasticity to GDP in a similar manner to equation (A1.6). PAGE 71

260 Transmission Other Sector ELECTRIC LOAD FORECAST F13-F33 Sales to the Other sector in this section refers to: 1) large industrial Other sales as shown in Table 8.2 and 2) commercial transmission non-oil & Gas customers. The following regression model was used to develop elasticity to GDP estimates for these customers. The elasticity is 0.49 which was used to develop the long term forecast for this sector. (A1.7) Sales = α + β*gdp t Where: Sales is sales for the remaining transmission sector GDP is total provincial real output Model A1.3 Model A1.3 Estimation OLS Method Constant (81.53) Independent X Variable 3.25 (0.54) (X = GDP) Adjusted R-sq 0.75 Durbin-Watson 1.13 Autocorrelation < 1.01 or > 1.34 Range (AR) Autocorrelation Detected? Neither accept or reject. PAGE 72

261 ELECTRIC LOAD FORECAST F13-F33 A1.3. Peak Demand Forecast Methodology Figure A1.2 below shows that the bottom-up peak forecast methodology involves several steps for each of the distribution and transmission peak forecasts. The general description of the development stages in system peak forecast is provided following. Figure A1.2 Peak Demand Forecast Roll-up System Bottom Up Driven Forecasting Process Detailed to meet users and planners needs 4 Regions 15 Distribution Planning Areas 9 Transmission Planning Areas 220 Distribution Substations; 160 Transmission Substations The peak demand forecast is built up in three main stages, each incorporating several steps. First stage is the creation of the substation peak in MVA non-coincident 10, second, the four main service region peak forecasts in MW are determined on a region coincident basis and third, the system peak in MW on a system coincident basis. Stage 1: Substation Peak Demand Forecast The substation peak forecast is built up in several sub steps: 1 (a) first the weather normalized peak loads by substation/area and short-term forecasts are developed; 1 (b) second the substation peak forecast guidelines are developed from an econometric model for each planning area; 1(c) third an 11-year substation forecast for each substation is created; and, 1 (d) finally the substation and guideline peak forecast are averaged together. The appropriate equations and description of the sub steps are provided below. 1 (a) Weather Normalized Substation Peak and Short-term Forecast The equation below is the basis for a linear regression model that estimates the relationship between substation peak demand and temperature: (A1.8) KVA = α + β*min Where: KVA is the metered peak load; and min is the minimum mean temperature for the coldest day during the metered period. α and β are the regression coefficients from a time series regression of peak substation demands on temperatures. 10 Non-coincident is defined in the glossary. PAGE 73

262 ELECTRIC LOAD FORECAST F13-F33 Using the estimated regression coefficients, the weather-normalized peak is then calculated based on the design day temperature for that substation 11 : (A1.9) NKVA = α + β*designmin Where: NKVA is weather-normalized peak; and designmin is the design temperature for the substation. The first step involves estimating a relationship between substation peak demand and temperature and determining weather-normalized substation peak for each substation for the previous winter. This is produced by equation A1.15. The weather normalized substation peak along with historical growth rates of substation peak demands, expected transfers of substation load and expected discrete load additions or closures are used by BC Hydro Distribution planners to prepare a short-term forecast for each substation for the upcoming winter. The first step is completed with an estimate of the weather normalized peak for each substation for the base year or the most recent historical year. 1(b) Distribution Peak Guideline Forecast. In the section sub step, a distribution substation peak guideline forecast is prepared for 15 planning areas for the first 11 years of the forecast period using the following forecasting and (econometric model) equation: (A1.10) SK it = [α 1 SFDHTG + α 2 SFDNON + α 3 MULTHTG + α 4 MULNON + α 5 U35E + α 6 O35E] Where: SK it is the total substation peak for the i th planning area; SFDHTG is the number of single-family electrically heated homes; SFDNON is the number of single-family non-electrically heated homes; MULTHTG is the number of multi-family electrically heated homes; MULTNON is the number of multi-family non-electrically heated homes; U35E is annual energy consumption General under 35 kw; O35E is annual energy consumption General over 35 kw; the coefficients α1, α2, α3, and α4 are kw contribution to the distribution peak per dwelling in area i, for the four dwelling types under normal temperature conditions; and the coefficients, α5 and α6 represent the increase in peak demand due to a one-kwh increase in the General rate class Under 35 and Over 35 kw energy consumption. The forecasting equation for the distribution peak guideline model is provided in equation A1.18. The guideline forecast provides the expected total substation growth from the base year for each planning area. The 11 A regression model using non-linear variables was also used for weather normalization. PAGE 74

263 ELECTRIC LOAD FORECAST F13-F33 drivers of the guideline forecast are based on regional economic information such as housing starts and employment. The guideline forecast is provided to BC Hydro Distribution planners from Market Forecast without adjustments for specific capacity additions or transfers. 1(c) Long-term Substation Forecast In the third sub-step, an eleven-year substation peak forecast is prepared for each substation using the guidelines, trends in substation growth, forecast load transfers between substations and larger substation load additions. During this step, BC Hydro planners may have additional and information or revised information from field engineers on expected increases or decreases on discrete customer loads as well as operational requirements for substations. This new information, along with the impact of the guideline forecast, may result in a change to the initial short-term forecast for each substation forecast from the first step. The long-term forecasts for each substation are summed up to fifteen planning region totals. These are the total long-term substation forecasts for each planning region. 1(d) Average of Long-term Substation Forecast and Guideline Forecast The fourth sub step is the calculation of the blending or averaging of the long-term substation forecast and the guideline forecast for each of the 15 planning areas. Prior to the forecasts being averaged, the long-term substation peak forecast and the guideline are aggregated from 15 planning areas into four regional total substation forecasts. These sets substation forecasts (i.e. the long-term substation forecast and the peak guideline forecast) are then averaged together for each of the four service regions based on the following equation: (A1.11) PK it = Σ it SK itguideline + SK i Substation Forecast Stage 2: Regional Peak Forecast The regional peak is forecast developed using: (A1.12) RPK jt = Σ j [PK it *DCF j *PF j + TP j *TCF j *PF j + OP j *OCF j ] Where: DCF is the regional distribution peak coincidence factor; PF is the regional power factor for distribution and transmission; TP is the transmission peak; this is the aggregate of the transmission account peak forecast in each service region. TCF is the transmission coincident factor; OP is the other utility peak sales; OCF is the other utility coincident factor; and PK is the weighted average distribution substation forecast A transmission peak forecast is prepared for each commercial and industrial transmission account using a bottom-up approach. This involves using the historical peak data, information from Key Account Managers and market information and industry reports. PAGE 75

264 Stage 3: System Coincident Peak Forecast ELECTRIC LOAD FORECAST F13-F33 Finally, system coincident peak is created as the sum of coincidence-adjusted regional peaks and it includes transmission losses: (A1.13) SPK = (1 + TL)*Σ j RPK jt *SCF j Where: TL is the transmission loss factor; and SCF are the system coincidence factors for each of the four regions. PAGE 76

265 ELECTRIC LOAD FORECAST F13-F33 Appendix 2 - Monte Carlo Methods This Appendix describes the Monte Carlo model that is used to assess the uncertainty associated with BC Hydro's Load Forecast. The description includes a discussion of the methodology, assumptions and parameters of the model. Load forecasting involves considerable uncertainty. The demand for electricity depends on a large number of factors which fluctuate widely with time and which are difficult to measure. Some of these factors include population, gross domestic product, weather, technology, energy conservation programs (DSM), alternate energy source options, the business climate experienced by major customers and the changing tastes and customers. The challenge of assessing the uncertainty of the load forecast is to quantify the way in which uncertainty in the major causal factors flows through to impact the resultant load. To quantify load forecast uncertainty, BC Hydro uses a Monte Carlo model and Monte Carlo simulation techniques. The model and simulation analysis proceeds as follows: First, several major input variables or causal factors are identified. These are: economic growth (measured by GDP); price of electricity (electricity rates); weather (measured by heating degree days) and elasticity of load (with respect to GDP and BC Hydro electricity rates). In addition to the major causal factors, uncertainty for residual load impacts, Electrical Vehicles and Load Forecast DSM/Integration overlap with codes and standards are included in the model. Second, probability distributions are assigned to each input variable. A model represented by a mathematical relationship between the input variable and the output variables is determined for each sector and the overall load. Third, a large number of random samples are taken from the input probability distributions. The mathematic model is used, with each sample as input, to calculate a large number of simulations of the output variables. These simulations are used to construct probability distributions for the output variables. The model perturbs the Reference forecast for each sector by calculating the impact factors for each of the causal factors and other uncertainty variables. The impact factors are random variables shown in the equations below. For the 2012 forecast, each of the sectors - Residential, Commercial and Industrial have separate formulas to which their respective Reference forecast is perturbed by separate impact factors. As such the Monte Carlo model has two major components; the energy demand model for the residential and general service sector and the energy demand model for the transmission sector. Previously, the same methodology and essentially the perturbation formula were applied to all the sectors. As for peak demand, the probability distribution for the overall system peak demand is generated using an overall system load factor the energy model. The model is implemented in Microsoft EXCEL augmented with Palisade Corporation software. The energy demand model for the residential, small commercial and industrial sector is the following equation: P G W U (A2.1) E = 0 E I I I I t t t t t t The energy demand model for the transmission sector, which is most of the overall industrial sector, is the following equation: (A2.1a) E = 0 E t t I I P S t t PAGE 77

266 ELECTRIC LOAD FORECAST F13-F33 Here E t is perturbed energy demand, 0 E t is base case or Reference energy demand, and the major impact factors are identified by their superscripts; P for electricity price (rates), G for GDP, W for weather, U for residual load uncertainty. For the transmission sector the S It is a new impact factor developed for the forestry, oil and gas, mining and remaining portions of the transmission load S The equation I t is as follows: S S (A2.1b) I t = 0 E t + ( S 0 E t - E ) S t Where, S stands for forestry, oil and gas, mining and remaining transmission sectors, 0 E S t is the Reference forecast for those sectors and Et is a randomly drawn forecast for those sectors from a triangular distribution. The following describes the impact factors for the major causal factors and other variables in more detail. Impact of GDP Uncertainty: This applies to the residential and general service loads and correlation with the transmission loads. In order to assess the impact of uncertainty in future GDP, the base case GDP is perturbed. The base case GDP is denoted by 0 G t and the perturbed GDP is denoted by G t. The perturbed GDP starts off being equal to the base case GDP in the first year. It then grows at a growth rate equal to the base case GDP growth rate ( 0 g t ) plus a random perturbation growth rate ( g t ). This random perturbation is a normally distributed random variable with zero mean and a standard deviation of 1.70%. That is: (A2.2) g t N(0,1.70%) The perturbed GDP is calculated by: (A2.3.) G t = G t-1 [ g t + g t ]. The impact factor for GDP is then given by the following equation: (A2.4) I G t = exp( α ln(g t / 0 G t )) = ( G t / 0 G t ) α where α 0 is the elasticity of load with respect to GDP. Impact of Price Uncertainty: (BC Hydro electricity rates): This applies to all major sector loads. The calculation of the impact factor for price changes ( I P t ) is treated similarly. A random variable, the perturbed price P t, is calculated starting from the base case price 0 P t. The perturbed price starts out being equal to the base case price in the initial year. It then grows at a rate equal to the base case growth rate plus a random perturbation. In the model, the random perturbation has a triangular distribution with parameters (-2.5%, 0, +2.5%). However, unlike the case of GDP, the impact of price change is assumed to take place on a cumulative basis. Impact of Elasticity Uncertainty: Table A2.1 gives the elasticity parameters and distributions around the elasticity used in the current Monte Carlo model. This elasticity are part of the price and GDP impact factors for the respective sectors. S PAGE 78

267 ELECTRIC LOAD FORECAST F13-F33 Table A2.1. Elasticity Parameter for Monte Carlo Model Price Elasticity Residential Commercial and Industrial General Service Transmission GDP Elasticity Residential Commercial and Industrial General Service. Mean Probability Distribution (a,b,c) Triangular (-0.075, -0.05, ) Triangular (-0.075, -0.05, ) Triangular (-0.075, -0.05, ) Triangular (0.470, 0.670, 0.870) Triangular (0.580, 0.780, 0.980) In Table A2.1, Triang(a,b,c) refers to a probability distribution known as a triangular distribution because its graph is a triangle. This distribution is zero for values of its random variable less than a or greater than c. It has a maximum (most probable) value at b. Impact of Residual Uncertainty in Load: This factor incorporates the effect on load of other factors such as changes in technology, consumer taste, household structure, business type, and inter-regional differences. This applies to the residential and general service load. The residual error factor starts out at 1.00 in the base year and grows at a rate that is, in each year, a random variable with the triangular distribution. The impact factor is defined by the following equations: (A2.5) I U t = I U t-1 ( 1 + g U t) I U 0 = 1 where g U t denotes a random variable with a triangular distribution. Again, software allows the specification of probability distributions in the model. Impact of Weather: Variations in weather are an important source of uncertainty in load. This applies to the residential and to a lesser extend the commercial general service loads. The weather impact is most important for the residential and commercial loads, so weather impact is modeled only for these sectors. In British Columbia, the impact of cold weather on residential heating load is the most important weather effect and is modeled using heating degree days (HDD). HDD is an indicator of how much energy is needed to heat housing up to a comfortable temperature. BC Hydro s summer cooling load is much smaller than the heating load, so the small effect of cooling degree days (CDD) is not modeled. The weather analysis is based on the last 10 years of daily temperature data at Vancouver International Airport. For every day, the number of heating degree days is calculated by the formula: HDD=max(0, Daily Temperature -18). Then, the annual sum of HDD is calculated for each year. A standard probability distribution of the Beta type was found to provide the best fit to this data. The Beta distribution has 4 parameters, and is written Beta(a1,a2,Min,Max). Min and max are the maximum and minimum, while a1 and a2 determine the shape of the distribution. The weather impact factor is calculated by: (A2.7) I W t = exp{ ε W log( HDD t / 2,776) } PAGE 79

268 ELECTRIC LOAD FORECAST F13-F33 where ε W is the elasticity of Residential or Commercial load with respect to HDD. ε W is estimated judgmentally to be for Residential and 0.05 for Commercial. The number 2,782 is the mean value of HDD in the Lower Mainland as calculated from a 10-year rolling historical average. I W t is a random variable as are the other impact factors. However it differs from the other impact factors in that its properties are the same for all years. This is because weather in each year is independent of weather in all other years. Therefore the width of the 80% confidence region for I W t does not increase with time. Impact of EVs and Codes and Standards: The Monte Carlo uncertainty model also considers the uncertainty in EVs and for overlap in codes and standards between Load Forecast and DSM. This work involved developing distributions for each of these new items and including them in the model. For EVs the distribution is log normal where the mean and standard deviation come from the reference and high EV load scenario as contained in Appendix 4. For Load Forecast/DSM Integration, there is a tri-angular distribution around the estimates of the overlap between the DSM plan and pre-dsm forecast in the area of coder and standards. The distribution is +/- 50 % the mean estimates in the overlap in codes and standards. Other Modifications of the Monte Carlo Model The Monte Carlo model has been modified this year for the large transmission sector to include a more detailed analysis of the potential risk bandwidth. Separate long term high and low forecasts for forestry, oil and gas (including commercial such as pipelines), mining and the remaining portion of the transmission sector were developed based on a qualitative appraisal of reasonable high and low load scenarios specific to these sectors. These high and low forecasts, along with the Reference forecasts, are used to determine the end points of a triangular distribution for each of these sectors. The triangular distribution for the random variable table below for F2017, F2022 and F2032. E is provided in the S t Table A2.2. Triangular distribution for random variable in Monte Carlo Model F2017 F2022 F2032 Sector (S) Forestry Oil and Gas Mining Remaining Forestry Oil and Gas Mining Remaining Forestry Oil and Gas Mining Remaining Mean GWh 7,603 2,655 4,812 1,546 7,711 4,568 5,480 1,620 7,735 4,941 4,790 1,727 Probability Distribution of Variable S E t (GWh) Triangular (4,933, 7,603, 11,018) Triangular (1,009, 2,655, 4,990) Triangular (3,017, 4,812, 5,983) Triangular (1,160, 1,546, 1,852) Triangular (5,007, 7,711, 11,389) Triangular (1,432, 4,568, 9,267) Triangular (2,015, 5,480, 8,230) Triangular (1,147, 1,620, 1,940) Triangular (4,881, 7,735, 11,621) Triangular (1,446, 4,941, 10,094) Triangular (1,961, 4,790, 6,965) Triangular (1,042, 1,727, 2,202) PAGE 80

269 ELECTRIC LOAD FORECAST F13-F33 Next a correlation matrix between the transmission subsectors in the table above was developed. This correlation matrix ensures that a high draw of say mining load is correlated with a high draw of load from the other sectors. Finally a correlation matrix was developed between the transmission subsectors and the GDP growth disturbance term which impacts the residential and general service load. This ensures that if a series of high draws for the industrial sub-sector occurs in any single simulation then a high draw of a random GDP disturbance term occurs. This brings together the element of correlation between high transmission load with a higher residential and general service load. PAGE 81

270 ELECTRIC LOAD FORECAST F13-F33 Appendix Oil and Gas (transmission serviced) This appendix documents BC Hydro s commercial and industrial oil and gas forecast, and the reasoning behind the forecast for oil and gas sales. The oil and gas sector is categorized into four sub-sectors: Oil Pipelines Oil Refineries Gas Pipelines Gas Producers. Figure A3.1 illustrates the sub-sector components of the oil and gas load forecast. As shown, significant load growth is expected for the Gas Pipelines and the Gas Producer sub-sectors. GWh Figure A3.1: Oil and Gas Sector 5,000 4,500 4,000 3,500 3,000 2,500 2,000 Oil Pipelines (Commercial) 1,500 Oil Refineries (Industrial) 1,000 Gas Pipelines (Commercial) 500 Gas Producers (Industrial) 0 F2008 F2013 F2018 F2023 F2028 Oil and gas customers take electricity service at both transmission and distribution voltages. A3.1.1 Oil and Gas Overview Currently, the oil and gas sector makes up five percent of BC Hydro s industrial sales. These operations primarily produce, process and ship petroleum and natural gas. Electricity is mainly used to drive compressors for production and pipeline transportation. In the medium to long term, it is expected that the majority of new gas production will be for export to markets in the U.S. and Asia. The main driver to this sector in the medium to long term is the price for natural gas. Sales to this sector have been aggressively trending upward (by 28 percent over the last 5 years), consistent with significant increases in oil and gas production. In F2013, sales are forecast to decrease by 3 percent over the previous year. In the short term (F ), sales are predicted to more than double, primarily due to increased gas producer and pipeline load in the Montney Basin. PAGE 82

271 ELECTRIC LOAD FORECAST F13-F33 In the medium term (F2017-F2022), oil and gas sales increase by about 60 percent, largely due to increased activity in oil and gas producer and pipeline load. For the latter 10 years of the forecast period, sales flatten in line with a levelling-off of gas production. Compared with the 2011 Forecast, the 2012 Forecast is lower in the short term but higher in the medium to long term. This is due to deferred gas production in the short term and increased gas production and Oil & Gas pipeline load in the medium and long term. Details are provided below. Note that gas producer load for the Horn River is treated as a separate scenario in the analysis for BC Hydro planning process. A3.1.2 Oil Pipelines Overview Sales to oil pipelines currently make up 17 percent of BC Hydro s sales to the oil and gas sector. These customers operate pipelines which serve to transport crude oil and petroleum products. Electricity is primarily used in pumping stations and the power sales are correlated to the volume of liquids shipped. Since these customers are providing a service, as opposed to manufacturing a product, they are classified as commercial load. The main advantage enjoyed by B.C. pipeline operators is that the proximity to Asian markets is conducive to export. Oil Pipelines Outlook Over the last four years, sales have generally trended up as new pipeline capacity had been added to meet growing demand for exporting crude. In F2013, sales are forecast to increase materially compared to previous year, as operational constraints that were previously in place have been removed. For the first five years of the 2012 Forecast sales significantly increases as incremental pipeline capacity is expected to increase. From F2018 onward, oil pipelines sales are forecast to only marginally grow. Oil Pipelines Drivers and Risk Drivers: Addressing capacity constraints along the pipeline; Demand for crude from California and Asia; B.C. demand for crude, gasoline and jet fuel, and; Economic conditions. Risk Factors: Environmental and social approvals for pipeline expansions and new pipelines. Construction risks and delays A3.1.3 Oil Refineries Overview Sales to oil refineries make up 30 percent of the oil and gas sector. These customers extract, refine and store crude oil and are thus classified as industrial load. A small number of these customers (primarily located in the Lower Mainland) refine crude oil to produce gasoline and jet fuel. They also refine diesel by removing sulphur and provide liquid fuel storage. Sales in this sub-sector primarily depend on domestic demand from automobiles and air travel. In the future, oil refineries sales are expected to be relatively more dependent on export demand for crude oil and petroleum products. B.C. operators have a competitive PAGE 83

272 ELECTRIC LOAD FORECAST F13-F33 advantage due to proximity to petroleum sources, dependability of shipping and receiving, and access to ports. Oil Refineries Outlook Over the last four years, sales have increased by 44 percent due to increases in oil production and refining activity. In F2013, sales are forecast to increase by 8 percent due to the expected recovery in gasoline, diesel and aircraft fuel sales. Over the entire forecast period, sales are expected to increase by 13 percent. Compared to the 2011 Forecast, oil refineries sales in the current forecast are relatively unchanged. Oil Refineries Drivers and Risk Drivers Demand for gasoline, diesel and jet fuel; Oil and gasoline prices; and Asian demand. Risk Factors Environmental concerns; GHG regulations which might impact refineries; and Local and global economic conditions. A3.1.4 Gas Pipelines Overview Sales to this sub-sector compromises 10 percent of the total oil and gas sector sales. Pipeline companies use electricity for compressing gas for shipping and processing; this is not a manufacturing process, they are categorized as commercial customers. Gas Pipelines Outlook Over the last five years, the load in this sector has been relatively small and highly correlated to North American natural gas prices. Please see Appendix A3.2 for more information on northeastern B.C. gas production and electricity demand expectations. Gas Pipeline Drivers and Risk Drivers: Potential for the conversion of coal-fired generation to less carbon-intensive natural gas-fired generation; Possible conversion of some of the Japanese nuclear fleet to gas-fired generation; Medium to long term expectations for gas and oil prices; Carbon tax and fuel switching for GHG reduction purposes; BC Hydro would tend to service more industry loads at higher carbon prices; and Electrification of NE BC gas production. Risk factors: Social concerns over the footprint of the extraction operations and the shipping and exporting of oil; Rate impacts to BC Hydro customers; and PAGE 84

273 ELECTRIC LOAD FORECAST F13-F33 The speed at which industry customers need electricity supply, and the ability of BC Hydro and the regulatory process to respond to these requests. A3.1.5 Gas Producers Overview Sales to this sub-sector currently make up 45 percent of the oil and gas sales. The gas producers are located in northeastern B.C. and primarily use electricity to power their compressors. These customers are categorized as industrial because they produce and process either conventional gas or shale gas for sale. Although the production of conventional gas in B.C. is expected to progressively decline, shale gas production is forecast to grow substantially. BC Hydro anticipates it will be servicing a large portion of shale gas production (see Appendix 3.2). Gas Producer Outlook Over the past five years, sector sales have risen by over 60 percent. In F2013, sales are forecast to remain relatively unchanged due to weak gas prices in the near term, which will dampen B.C. gas production. In the first five years of the 2012 Forecast, sales are projected to increase nearly six-fold; most of this growth attributable to shale gas development in the Montney Basin (refer to Appendix 3.2). During the F period, sales growth is forecast to slow and flatten out as new drilling is expected to be directed at maintaining infrastructural efficiency. For the latter 10 years of the forecast, sales are expected to increase marginally with new drilling directed at maintaining gas flows at close to capacity to realize efficiencies. Compared to the 2011 Forecast, the current forecast for the Gas Producer sub-sector is lower in the short term but higher in the medium to long term. This is due to currently low natural gas prices in North America and uncertain financial markets have caused gas producers in the Montney gas basin to deferred drilling projects in the short term; however, in the medium to long term, greater than expected production activity is expected. Gas Producer Drivers and Risk See Appendix 3.2 PAGE 85

274 ELECTRIC LOAD FORECAST F13-F33 Appendix Shale Gas Producer Forecast (Montney) Gas Producer Overview As indicated in Appendix A3.1, transmission and distribution customers serviced by BC Hydro for the production of shale gas are included in BC Hydro s industrial customer sector. This appendix documents BC Hydro s estimates of future load requirements for these shale gas producers. Shale gas refers to natural gas enclosed in a fine-grained sedimentary formation with low reservoir porosity and low permeability. Although such basins have been uneconomic in the past, new technological advancements such as horizontal drilling and multi-stage hydraulic fracturing have enhanced commercial production of shale gas. Sales for servicing shale gas production are expected to occur in northeast B.C. BC Hydro s 2010 Load Forecast included expected sales from both the Horn River and Montney shale gas plays; the 2011 and 2012 Forecasts include sales from only the Montney play and treats potential Horn River sales as a separate scenario for analysis in BC Hydro s long-term planning processes. For more detail on this point, refer to Chapter 9. Regarding the Montney, (in the vicinity of Dawson Creek, see Figure A3.1), sales are expected to increase substantially over the next 10 years, from current low levels, primarily due to regional shale gas development. The Montney Basin shales are believed to contain among the largest untapped reserves of unconventional gas in North America. Figure A3.1. Map of Montney and Horn River Basins BC Hydro is closely following a significant number of developments in the Montney area and potential liquid natural gas projects on BC s North Coast. Below are recent public industry announcements which reflect continued global interest in the Montney Basin: In January 9, 2013, TransCanada Corp. announces plans to build a $5-billlion pipeline to transport gas to the North Coast from the North East to PETRONAS planned LNG plant near Prince Rupert. PAGE 86

275 ELECTRIC LOAD FORECAST F13-F33 In December 2012, PETRONAS announces plans to proceed with $9-billion LNG plant after completing a detailed feasibility study. In December 2012, Chevron announces intent to purchase 50 percent ownership of the proposed pipeline and related export terminal in Kitimat. In December 2012, Painted Pony completes a $108-million deal, further expanding its Montney land holdings. The company has one of the largest contiguous northeast BC Montney land blocks. In October 2012, Exxon Mobil offers $3.1-billion for Celtic Exploration Ltd, to acquire its 545,000 net acres of land in the liquids-rich Montney shale in West Central Alberta. Exxon-controlled Imperial Oil Ltd. is in the early stages of assessing the viability of an LNG export facility. In June 2012, PETRONAS makes a $5.9-billion offer to acquire all of Progress Energy Resources Corp. Progress has the largest acreage in the Montney. In February 2012, British Gas (BG) Group announces that it will begin conducting a feasibility study on developing an LNG terminal in Prince Rupert. In February 2012, Encana enters into a C$2.9 billion agreement with Mitsubishi Corporation for a 40 % interest in the Cutbank Ridge Partnership. This includes 409,000 net acres of Encana s undeveloped Montney-formation natural gas lands in its Cutbank Ridge resource play in northeast British Columbia. The major advantages for Montney producers are the thickness and richness of the gas reservoirs and their proximity to markets. Montney formations are among the thickest in North America reaching up to 350 meters; which increases the resource base and simplifies drilling. The Montney is also relatively rich in liquids, for which the sale price is more related to an oil-price proxy than a lower gas price. Given foreseeable oil prices, this is a major incentive to production economics. Montney gas is relatively free of contaminants such as CO 2 and sulphur compounds. In terms of infrastructure (roads, personnel, servicing industry) the Montney region is well developed, relative to the more remote Horn River. Finally, Montney gas production may form a significant basis for LNG exports from the BC west coast, which is the closest potential export point from North America to Asian load centers. These advantages serve as primary drivers for investment and drilling activity in the Montney Basin. Gas Producer Outlook Sales to gas producers are forecast to continue to rise as it is expected that producers will continue with drilling and completions programs. Drilling in F2013 will likely be motivated less by gas prices and more by high liquids prices, existing supply contracts (where gas prices were previously locked in at higher levels) and drilling obligations for the maintenance of land leases. In the short term (to F2017), sales are forecast to substantially increase, driven mainly from expectations of new drilling operations. These projections are based on customer requests for service and from BC Hydro s forecasting model (see next section for further details). In the medium term (F2017-F2022), sales are forecast to continue to rise but at a slower pace. It is expected that gas production will continue to expand and that the number of sites serviced by BC Hydro will increase. By the end of F2022, gas production is expected to reach 4,600 million cubic feet per day (MMcf/d) in the Montney Basin. This current increase relative to the previous forecast is in line with third party projections. The primary reason for the change is that BC Hydro has revised upward its forecast for the PAGE 87

276 ELECTRIC LOAD FORECAST F13-F33 northwestern part of the Montney Basin. This area has experienced a great deal of investor activity as of late and is reportedly very rich in valuable natural gas liquids. For the last 10 years of the forecast, sales peak, then level-off and are not expected to decline until after the forecast horizon. Compared to the 2011 Forecast, as driven by updated gas production expectations, the 2012 Forecast for Montney gas producers is lower in the initial years but becomes higher afterwards. As shown in Table A3.1 below. This can be attributed to a number of factors including: (i) BC Hydro has experienced increased inquires for electricity service, (ii) industry experts have increased their gas production forecasts; and (iii) additional industry capital is being committed towards gas production and export infrastructure. Table A3.1 Montney Gas Production and Sales Forecasts Before DSM and Rate Impacts Integrated Area (Peace Region) Total Gas Production Electrical Load (GWh) (MMCf/day) F2013 1,383 1, F2014 1,648 1, ,068 F2015 2,298 2, ,637 F2016 2,889 2,859 1,095 2,136 F2017 3,362 3,428 1,788 2,323 f2018 3,770 3,792 2,305 2,477 F2019 4,151 4,029 2,682 2,610 F2020 4,436 4,204 2,936 2,681 F2021 4,533 4,345 3,067 2,845 F2022 4,642 4,463 3,179 2,889 F2023 4,749 4,563 3,312 2,922 F2024 4,846 4,646 3,349 2,952 F2025 4,849 4,714 3,382 2,979 F2026 4,854 4,768 3,409 3,005 F2027 4,884 4,808 3,435 3,030 F2028 4,920 4,836 3,461 3,055 F2029 4,954 4,853 3,486 3,079 F2030 4,964 4,858 3,509 3,101 PAGE 88

277 Montney Shale Gas Drivers and Risk Drivers ELECTRIC LOAD FORECAST F13-F33 Natural gas prices in North America a high price stimulates sector demand because it makes it more profitable to produce shale gas; Price of oil a high price elevates load demand. The Montney Basin is one of a limited number of North American gas plays that is rich in natural gas liquids; since liquids prices closely follow oil prices, a high oil price stimulates production in liquids-rich gas plays; Fracturing technology evolving hydraulic fracturing technology produces proportionally greater benefits to the large rich shale gas plays such as the Montney. Risk Factors Greenhouse gas regulation GHG emission reduction targets in B.C. and the U.S.; Regulation of formation fracturing operations a number of provincial, state and federal agencies are reviewing this, which may lead to constrained shale gas production; Other new N. American gas supply which includes methyl hydrates, coal bed methane and other shale gas plays on the continent and associated gas in Alaska; New global gas supplies. Russia, China and Australia have shale gas potential. However, shale gas development in Asia is significantly behind that in N. America; and Montney development and operational costs the Montney is relatively far from the major gas markets. Shale Gas Forecast Methodology BC Hydro employs two approaches to develop the forecast, referred to as the bottom-up and top-down methodologies. The bottom-up forecast is based on customer-specific information and analysis and serves as BC Hydro s official load forecast. The top-down forecast is a macro forecast that is used to guide and confirm the bottom-up forecast. Bottom-up Forecast The 2012 gas producer load forecast is generated using a bottom-up approach; it also includes an iterative exercise with the top-down forecast. The bottom-up forecast originates from a compilation of current and expected customer load requests. In arriving at an expected or most likely net customer service requirement, each customer request is evaluated, shaped and discounted based on information from various sources internal and external to BC Hydro. External factors come from a number of areas such as industry, producer publications and the top-down forecast, as explained below. Top-down Forecast The top-down forecast uses macro information to arrive at the Montney load forecast. In doing so, it serves as a guide to check and improve the accuracy of the bottom-up forecast. PAGE 89

278 ELECTRIC LOAD FORECAST F13-F33 As discussed below, the top-down forecast is derived by creating and then multiplying three data sets, as follows: Top-down Forecast = Production x Intensity x Service Percent Production Table The production table is a forecast of annual natural gas volume over the life of the gas play. The production table is constructed using a forecast of two drivers wells drilled (per year) and a well production profile. These parameters are determined by setting the expected well life, initial production level and well decline rate. The production table results need to be consistent with expectations for total gas recovered, total wells drilled, average well production, planned pipeline capacities, gas price forecasts and full-cycle economic costs for B.C. gas plays and competing plays in North America. To ensure that the results are reasonable, BC Hydro conducts a comparative analysis with those of industry associations, producers, pipeline companies, and government and industry experts. For the Montney Basin, the major drivers for the production table are shown in Table A3.2 below: Table A3.2 Major Driver Characteristics and Production Assumptions Well life 25 years Initial well production level first month 5.25 MMcf/day Well decline rate - month 1 (annualized) 10.3% Well decline rate - month % Well decline rate - month % Assumed to be uniform Drilling pattern throughout the year Total recoverable gas 68 trillion cubic feet Wells drilled 14,000 Average production per well 4.4 billion cubic feet (Bcf) Peak production year for Montney F2031 Montney peak production year volume 5.0 Bcf/day Number of years of drilling 46 Number of years in modelling 70 years Figure A3.2 shows BC Hydro s shale gas production forecast for the Montney Basin (bold line). This is used to produce the Base Case Forecast. Also shown are production forecasts from other third parties. PAGE 90

279 ELECTRIC LOAD FORECAST F13-F33 10,000 9,000 8,000 7,000 Figure A3.2 Montney Shale Gas Production Forecast MMcf / day 6,000 5,000 4,000 3,000 2,000 1,000 BCH Base 0 F'11 F'16 F'21 F'26 F'31 F'36 F'41 F'46 Fiscal Year Figure A3.3 shows the production profile of a typical well in BC Hydro s model and typical well projections from other expert sources. As with Figure A3.2, source of the other well curves is blanked out in the chart legend for the purposes of confidentiality. Figure A3.3 Well Production Curve (with other industry projections) BCH Base Months Multiplying the production table by an intensity level yields the energy needed to produce the gas over the next 60 years. This represents the total energy required to bring gas to the high pressure pipeline grid. A percentage of this is assumed to be serviced by BC Hydro (see below). MMcf/day Intensity Table PAGE 91

280 ELECTRIC LOAD FORECAST F13-F33 The intensity factor is multiplied against gas production estimates to determine the total energy requirement needed to produce the gas. Intensity times production equals total energy needed, as shown in the equation below: Intensity (MW/MMcf/day) x Production (MMcf/day) = Power Requirement (MW) where: MW is megawatts of power consumption and MMcf/day is million cubic feet of gas per day BC Hydro s intensity rate is a compilation of two approaches: (a) determining the energy requirements of the major processes within a typical plant, and (b) conducting an industry survey. BC Hydro s calculation factors for estimating the typical plant requirement are detailed below: Compression MW/MMcf/d + Processing MW/MMcf/d + Additional Compression to 0.01 MW/MMcf/d = Total to MW/MMcf/d As shown above, the total intensity rate range is to MW/MMcf/d. This is comparable to industry information indicating a range of 0.08 to 0.14 MW/MMcf/day, with a number of estimates clustered around a value of The compression intensity of MW/MMcf represents the energy needed to move the gas from the wellhead, through the field gathering system and into a centralized processing facility (where electricity is also used in the processing process, (which includes the removal of gas liquids) and then eventually to the high-pressure, downstream pipeline. This calculation assumes: Well-head pressures of 140 to 240 Psi Mainline pipe pressure of 900 to 1,440 Psi 2 or 3 stages of compression. The processing intensity of MW/MMcf/d is for ancillary electric loads for removing water, acid gases and liquids. In the Montney, gas can be processed at the processing facility since gathering pressures are low and the gas generally is only slightly sour. This estimate assumes: Only a small portion of gas in the Montney is sour (in the regions closest to the Alberta border), per industry sources; and The water content of the gas is low and much of the gas meets pipeline specifications of about four pounds of water per MMcf of gas. The additional compression intensity of to 0.01 MW/MMcf/d is BC Hydro s estimate for additional load that is expected to be required to move gas from the processing facility to the downstream pipeline. As the Montney play develops, additional pipeline compression is expected to be required to move gas downstream. Other assumptions: Hydraulic fracturing operations would not require service from BC Hydro; these operations are of a short duration and generally in remote locations; Water recycling loads would not be material; Downstream pipeline loads would not be served by BC Hydro. PAGE 92

281 Service Percent Table ELECTRIC LOAD FORECAST F13-F33 The service percent is the proportion of total energy to be provided by BC Hydro s electricity service. A number of factors have been considered by BC Hydro in arriving at this figure namely, evolving trends for the areas, engineering calculations and economic analysis, discussion with BC Hydro staff who work directly with the new customers and industry surveys conducted by BC Hydro. For the Montney Basin, the forecast is divided into five areas with the following service percentages: Dawson Creek: 40% ramping up to 85% over the forecast horizon Groundbirch: 30% ramping up to 95% Chetwynd: 40% ramping up to 85% Fox/Fort St. John: 5% ramping up to 70% G.M. Shrum: 15% ramping up to 25%. PAGE 93

282 ELECTRIC LOAD FORECAST F13-F33 Appendix 3.3 LNG Load Outlook Demand for natural gas is growing in Asia and Europe, primarily for electricity generation and heating purposes, as well as in transportation. China and Japan are both pursuing new supply options China to fuel its massive modernization and Japan to diversify its fuel supply. With demand growing quickly, gas prices in Asia are considerably higher than they are in North America. This creates the opportunity for natural gas exports to these markets in the form of LNG. To date, several LNG proponents have approached BC Hydro and/or the B.C. Government with respect to LNG projects for the B.C. north coast. Canadian producers are increasingly looking to take advantage of this price differential, with a number of LNG export projects being proposed. LNG is a very capital intensive undertaking; these operations typically run at very high load factors, with minimal downtime, and little seasonal or intra-day load variations. Over the past couple of years, BC Hydro and government have been closely working with LNG proponents on options for meeting all or some of the energy needs of LNG plants with power from the BC Hydro system. LNG-related electricity demand falls in to two general categories: compression and noncompression. The compression work energy is about 85% of the total plant s energy needs. The remaining (non-compression) energy requirement is from plant pumps, motors, other equipment, heating and lighting. Compression energy is typically supplied with direct-drive natural gas turbines, although this can also be accomplished with electric drives. Nevertheless, LNG non-compression demand is still significant, and could be one of BC Hydro s biggest system loads. Potential non-compression LNG demand could be between about 800 GWh/year to about 6,600 GWh/year of additional energy demand, corresponding to about 100 MW to 800 MW of additional peak demand. A range of potential LNG loads are considered as scenarios in BC Hydro s planning processes. The 2012 Reference Load Forecast presented in this document does not include any specific LNG demand beyond very small allocations associated with on-site construction. PAGE 94

283 ELECTRIC LOAD FORECAST F13-F33 Appendix 4 - Electric Vehicles (EVs) Overview In the past two years automobile manufactures have launched several models of electric vehicles (EVs) in North America while announcing plans for mass production of EVs in the near future. However, the market is still new and uncertainties remain around the timing and extent of large-scale adoption of EVs. The operating cost and environmental advantages of EVs make them attractive alternatives to conventional gasoline vehicles. On the other hand, the generally higher purchase price of EVs and lower gasoline prices may dampen the market share growth of EVs. EVs have a large fuel cost advantage over gasoline vehicles, offering drivers lower ongoing operating costs. The low price of electricity in BC compared to other North American jurisdictions further magnifies the operating cost advantage of EVs. Large-scale adoption of EVs may help lower greenhouse gas emissions and related environmental costs. Some of the key barriers that need to be overcome before EVs gain a significant market share include: higher costs, limited driving range of EVs, and overall consumer acceptance as alternative to gas vehicles. The purchase price of EVs remains significantly higher than the price of comparable gasoline vehicles, in part due to the high cost of batteries. Despite major research and development investments in battery technology by the private sector and governments, battery prices remain high and some battery manufacturers have faced financial difficulties. The limited range of all-electric vehicles is an obstacle for drivers who drive long distances; this may be a challenge for both urban and rural drivers in various parts of the province. Even drivers who seldom travel distances longer than the current range of EVs may forego this option due to range anxiety the perceived threat of being stranded. While plug-in hybrid electric vehicles (PHEVs) offer extended range and therefore reduce range anxiety, their higher costs compared to pure EVs limits their attractiveness to potential buyers. Availability of public charging infrastructure and consumer education are ways to reduce range anxiety. EV Impacts on Energy Demand The load forecast of EVs consists of a reference case and a high case scenario. A forecast of the number of EVs and annual energy consumption of EVs is created. The forecast is produced using a model that takes into account many variables including driving-age population and vehicle growth, gasoline and electricity price forecasts, and efficiencies for both electric and conventional vehicles. The EV reference case forecast includes the following main assumptions: A constant energy efficiency of 30 miles per gallon for gasoline vehicles and 0.20 KWh per km for EVs. Existing government subsidies are taken into account, but no new policies or initiatives are assumed. The supply and demand for EVs is initially constrained because the EV fleet is currently very small and the rate of development depends upon several factors. These factors include: consumers tastes and acceptance of EVs, and time needed for manufacturing capacity to expand in areas of battery production, retrofitting current factories or creating new facilities dedicated to EV manufacturing. PAGE 95

284 ELECTRIC LOAD FORECAST F13-F33 As such, BC Hydro expects the rate of market uptake to be gradual, making the load growth on its system manageable in the near future. The EV adoption rate produced by the model is driven primarily by economics. Competition between the fuel cost advantage of EVs and the lower capital cost of conventional vehicles affects consumer choice. Purchase price of a representative EV is assumed to be about $11,000 higher than a similar gasoline car. The market share of EVs is very small in the early years but increases rapidly in later years due to the relaxation of availability constraints that have been assumed. As shown in Figure A4.1, the market share of EVs as a percentage of all light duty vehicles increases from 5% in 2020 to 20% in 2028, in the reference case. Figure A4.1 Electric Vehicles in BC: Market Share (Percentage of New Vehicle Sales) 50% 40% Reference Case High Case 30% 20% 10% 0% F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 In the High case, EV market share reaches over 50% in the same timeframe, as a series of potential developments are assumed to facilitate the introduction of EVs. In particular, it is assumed that the government will extend the $5,000 EV purchase price subsidy past the current expiry date in Similarly, it s assumed that the additional rebate of $500 towards home charging equipment costs will persist. Also, gasoline prices are assumed to be higher by about 10% throughout the forecast horizon, favouring EVs. Finally, the upper range of EVs is assumed to increase over time based on the assumption of technological improvements and a significant increase in the number of public EV charging stations in BC Hydro s service territory. The annual energy load due to EVs is forecast for both scenarios. In the EV reference case, load from electric vehicles increases from 14 GWh in 2017 to 1,270 GWh in In the High case (scenario), EV load increases from 28 GWh in 2017 to 2,939 GWh in Figure A4.2 illustrates both load scenarios before rate impacts. As seen in Figures A4.1 and A4.2, the High case assumptions significantly increase the adoption rate and energy requirements of EVs compared to the reference case. PAGE 96

285 ELECTRIC LOAD FORECAST F13-F33 Figure A4.2 EV Load Forecast Reference Case High Case 2000 GWh F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 Table A4.1 at the end of this appendix shows the residential EV load, commercial EV load and the total EV load included in the 2012 reference load forecast. EV Impacts on Peak Demand BC Hydro developed an EV peak model to study the impact of EVs on BC Hydro s system peak. The peak EV model was updated in the 2012 Forecast with consistent inputs from the EV energy model. The EV peak model is a simulation model that has several inputs including: (i) number of EVs per year; (ii) daily distance travelled; (iii) EV efficiency in kwh per km; (iv) power of the charging equipment in kw; and (v) a charging time profile. These inputs combine in the simulation model to determine an EV daily peak shape which is used to estimate the EV impact on BC Hydro system coincident peak demand. The model does not account for specific peak shifting behaviour. This means the model produces the impact on the peak demand without any constraints to shift EV load impact away from the system peak hours. It is possible that when EVs become available in large numbers, incentives or policies may be used to mitigate EV contribution to the system peak load. Overall, the impact of EVs on BC Hydro peak in the reference case is approximately 4 MW in F2017 and 459 MW in F2032. Figure A4.3 below and table A4.1 show the EV impact on BC Hydro s total distribution system coincident peak before DSM and rate impacts and before system transmission losses. PAGE 97

286 ELECTRIC LOAD FORECAST F13-F33 Figure A4.3 EV Impact on System Peak Demand 1,200 1,000 Reference Case High Case 800 MW F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 Forecast Risks and Uncertainties The EV forecast is uncertain. The relatively slow penetration of hybrid vehicles in the North American market over the past decade is an indication of challenges facing EVs. Some of the sources of uncertainty are discussed here: Future measures taken by governments to encourage adoption of EVs can accelerate EV adoption. These measures can include new fuel efficiency regulations, continued subsidies to reduce the initial price of EVs, continued investments in charging infrastructure, government fleet purchases, grants to automotive and battery manufacturers, access to HOV lanes and provision of free parking to EVs. A sustained slowdown in the growth of global economy can delay investments in EVs by manufacturers and consumers, postponing the mass adoption of EVs by several years. Changes in gasoline price expectations can have significant impacts on the market share of EVs. EVs become more economical at higher gasoline prices. For example, emergence of new global sources of oil and a slower expected growth in the global economy have somewhat alleviated concerns about long-term oil supply shortages and put downward pressure on the long-term outlook for gasoline prices. This has in turn reduced the expected operating cost advantage of electric vehicles over gasoline vehicles. As the high price of EVs is one of the major hurdles to their widespread adoption, potential technological advances in battery technology can bring down the price and contribute to rapid adoption of EVs. The outcome of various research and development projects is highly uncertain, but any breakthrough can have major consequences. PAGE 98

287 ELECTRIC LOAD FORECAST F13-F33 Similarly, increased competition from alternative technologies can reduce the appeal of EVs. For example, gasoline vehicles continue to improve in efficiency as a result of lighter components, turbochargers, regenerative braking and energy recovery technologies and other technological advances. Clean diesel, natural gas, and hybrid vehicles also compete with EVs for market share Changes in driving habits of drivers and increased use of public transit and other alternative transportation can also impact the market share of EVs. Statistics show a general trend of decreasing vehicle kilometers driven. Drivers who commute shorter distances or regularly take public transit will not benefit as much from the operating cost advantage of EVs and may favour conventional vehicles. In recent years consumers have been keeping their cars longer and delaying new car purchases. If this trend continues, the replacement of existing fleet of predominantly gasoline vehicles is expected to occur at a slower pace. Comparison to 2011 Forecast Figures A4.4 and A4.5 compare the F2011 and F2012 EV reference forecasts. The energy consumption by EVs is 188 GWh (54%) lower by F2022 and almost 1000 GWh (46%) lower by F2032. Factors contributing to a lower forecast include: The new forecast considers the downward trend in distances travelled by BC drivers Conventional vehicles are continuing to show improvements in efficiency New vehicle purchase statistics have declined, reducing expectations of new vehicle sales and expected rate of replacement of the existing fleet of vehicles Technological advances and new sources of oil have led to lower gasoline price forecasts The EV peak model was not updated in The peak impact of EVs beyond the first 10- year period of the load forecast was assumed in 2011 to follow the energy load growth rates that are used to develop the distribution peak forecast over this period. The growth rates in the total of EV energy sales, residential sales and small commercial and industrial sales were used to grow the overall peak demand rather than adding the EV model peak impact to the overall System peak forecast. In 2012, the EV peak model was updated as described earlier in this section. Although the EV energy forecast is lower in 2012 as a result of lower number of EVs and distance travelled, the EV peak values are relatively close between 2011 and This is mainly due to the fact that EV peak values in 2012 are generated by the EV peak model instead of following the overall distribution energy load growth. PAGE 99

288 ELECTRIC LOAD FORECAST F13-F33 Figure A4.4 Changes in Reference EV Energy Forecast F2012 F GWh F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 Figure A4.5 Changes in Reference EV Peak Demand Forecast 1, F2012 F2011 MW F13 F14 F15 F16 F17 F18 F19 F20 F21 F22 F23 F24 F25 F26 F27 F28 F29 F30 F31 F32 PAGE 100

289 Table A4.1 Residential and Commercial EV Load (GWh) and (MW) ELECTRIC LOAD FORECAST F13-F33 A B C=A+B D 2012 Forecast - Residential EV Load 2012 Forecast - Commercial EV Load Total EV Load Reference Case Total EV Peak Load Reference Case Fiscal Year (GWh) (GWh) (GWh) (MW) F F F F F F F F F F F F F F F F F F F F F2033 1, Note: The values in the table above do not include any rate impacts. PAGE 101

290 ELECTRIC LOAD FORECAST F13-F33 Appendix 5 - Codes and Standards Overlap with DSM Codes and standards are minimum end-use efficiency requirements that come into effect in a jurisdiction, and that are enabled by legislation or by regulation of manufacturers. U.S based codes and standards are reflected in the average stock efficiency forecast of residential and commercial end uses of electricity produced by the U.S. Department of Energy s Energy Information Administration (EIA). This EIA efficiency forecast is one of the main drivers of the residential and small commercial end-use models that are used to produce the BC Hydro load forecast before incremental Demand Side Management (DSM) savings. BC Hydro s DSM plan also considers savings that can be achieved from B.C. and Canadian Federal codes and standards that target similar end uses as those represented in the EIA efficiency forecast data. As such, there is a potential for inconsistency in codes and standards baseline assumptions between the before DSM Forecast and the DSM plan. Areas of Overlap between EIA and DSM Plan Codes and Standards The EIA assumes that no new legislation or regulations fostering efficiency improvements beyond those currently embodied in law or government programs will take place over the forecast horizon. As such, the end-use efficiency levels assumed in the EIA forecast only consider the targeted efficiency level from the mostly recently passed legislation or regulations. These efficiency level assumptions are documented by the EIA 12. BC Hydro reviewed the EIA baseline codes and standards efficiency assumptions and compared it to the codes and standards baseline efficiency assumptions as of December Using this information, BC Hydro was able to determine where there were overlaps in assumptions between the before DSM and rate impacts forecast and the savings from codes and standards. The areas are shown as follows: Areas of Overlap between EIA Codes and Standards and BC Hydro DSM Plan 13 Residential Sector Lighting, ceiling fans, dishwashers, standby power, set top boxes, TVs, freezers, refrigerators and external power supply Commercial Sector Lighting, large clothes washers, traffic lights, large refrigerators, air conditioning, packaged terminal air conditioning, dry transformers, and building code. Estimates of Overlap between EIA Codes and Standards and the DSM Savings from Codes and Standards The method used in the 2012 Forecast to estimate the impact of codes and standards double counting was to rely upon on the estimated codes and standard savings included in the BC Hydro DSM plan 14. For lighting codes and standards double counting, a process 12 Appendix A of the EIA Annual Energy Outlook 2009 documents titled Handling of Federal and Selected State Legislation and Regulation in the Annual Energy Outlook. In addition information from EIA 2011 Annual Energy Outlook and website was used to develop estimates of the overlap. 13 Note that in all of the end uses listed, the EIA provides an efficiency forecast for lighting separately. The other end uses listed above are reflected in the other category and the EIA provides an efficiency forecast for other category as a total group. 14 The codes and standards savings forecast included in BC Hydro s DSM plan contained in the F12-F14 Revenue Requirement Application Evidentiary Update was used to inform estimates of the overlap in codes and standards. PAGE 102

291 ELECTRIC LOAD FORECAST F13-F33 of freezing the input efficiency levels to the 2007 lighting efficiency forecast was used. This method for lighting was chosen to provide consistency with previous forecasts that had already identified a double counting issue with lighting codes and standards. BC Hydro applied 50 percent of the DSM savings estimates of the various codes and standards which overlapped with the EIA. The main reasons for discounting half of the DSM estimates were: There is the potential for some error in the double counting impact estimating process because there is uncertainty as to compliance levels for codes and standards. At the time the load forecast was developed BC Hydro was exploring several future DSM options. As such the overlap associated with the double counted enduses might vary pending which DSM option would be used for planning purposes. Table A5.1 and Table A5.2 below show the estimates of the overlap between the residential and commercial sector energy forecasts for the overlap areas. Table A5.3 below shows the BC Hydro s distribution peak forecast with an estimate of the overlap between codes and standards over the long-term. PAGE 103

292 ELECTRIC LOAD FORECAST F13-F33 Table A5.1 Residential Energy Forecast (before DSM and rate impacts) with Overlap for Codes and Standards Fiscal Year A B C=A+B Residential Adjustment Sales 2012 for Overlap Forecast Forecast in with Codes Residential Residential and Sales Code and Standards Standards Overlap (GWh) (GWh) (GWh) 1 F , ,251 F , ,703 F , ,217 F , ,587 F , ,978 F , ,410 F , ,833 F , ,271 F , ,652 F , ,037 F , ,410 F , ,820 F , ,160 F , ,517 F , ,848 F , ,206 F , ,500 F , ,830 F , ,160 F , ,525 F , ,800 Notes: all the values in columns above do not include any adjustments for the impact of EVs and rate impacts. PAGE 104

293 ELECTRIC LOAD FORECAST F13-F33 Table A5.2 Commercial Energy Forecast (before DSM and rate impacts) with Overlap for Codes and Standards Fiscal Year A B C=A+B Commercial Adjustment Distribution 2012 Forecast for Overlap in Sales with Commercial Commercial Codes and Distribution Code and Standards Sales (GWh) Standards Overlap (GWh) (GWh) 1 F , ,941 F , ,138 F , ,294 F , ,573 F , ,913 F , ,311 F , ,637 F , ,927 F , ,148 F , ,371 F , ,604 F , ,881 F , ,140 F , ,412 F , ,654 F , ,941 F , ,231 F , ,561 F , ,906 F , ,269 F , ,560 Notes: all the values in columns above do not include any adjustments for the impact of EVs and rate impacts. PAGE 105

294 ELECTRIC LOAD FORECAST F13-F33 Table A5.3 Distribution Peak Forecast with Overlap for Codes and Standards A B C=A+B 2012 Forecast Distribution Peak (MW) Adjustment for Overlap in Code and Standards (MW) Peak Forecast with Codes and Standards Overlap (MW) 1 Fiscal Year F2013 8, ,045 F2014 8, ,217 F2015 8, ,346 F2016 8, ,484 F2017 8, ,648 F2018 8, ,822 F2019 8, ,983 F2020 9, ,122 F2021 9, ,243 F2022 9, ,354 F2023 9, ,536 F2024 9, ,676 F2025 9, ,812 F2026 9, ,949 F2027 9, ,085 F , ,224 F , ,366 F , ,510 F , ,656 F , ,805 F , ,949 Notes: all the values in columns above do not include any adjustments for the impact of EVs and rate impacts. PAGE 106

295 ELECTRIC LOAD FORECAST F13-F33 Appendix 6 - Forecast Tables Table A6.1 shows the Regional coincident peak (MW) forecast for distribution before DSM with rate impacts Table A6.2 shows the Regional coincident peak (MW) forecast for transmission before DSM with rate impacts Table A6.3 shows the Domestic and Regional peak forecast before DSM with rate impacts Table A6.4 summarizes BC Hydro s 2012 Reference Load Forecast before DSM with rate impacts PAGE 107

296 ELECTRIC LOAD FORECAST F13-F33 Table A6.1 Regional Coincident Distribution Peaks Before DSM with Rate Impacts (MW) Fiscal Year Lower Mainland Coincident Peak (MW) Vancouver Island South Interior Northern Region Actual F2012 4,505 1,801 1, Weather-Normalized Actual F2012 4,554 1,862 1, Forecast (Weather-Normalized) F2013 4,664 1,905 1, F2014 4,777 1,937 1, F2015 4,837 1,948 1, F2016 4,914 1,963 1, F2017 5,008 1,980 1, F2018 5,118 2,001 1, F2019 5,224 2,021 1, F2020 5,333 2,039 1, F2021 5,430 2,057 1, F2022 5,527 2,074 1, F2023 5,661 2,103 1, F2024 5,779 2,129 1, F2025 5,899 2,155 1, F2026 6,025 2,182 1, F2027 6,156 2,210 1, F2028 6,296 2,240 1,264 1,001 F2029 6,441 2,272 1,282 1,010 F2030 6,588 2,303 1,300 1,019 F2031 6,736 2,335 1,317 1,029 F2032 6,884 2,366 1,335 1,038 F2033 7,030 2,396 1,352 1,046 5 years: F2012 to F % 1.2% 1.3% 2.6% 11 years: F2012 to F % 1.1% 1.3% 2.4% 21 years: F2012 to F % 1.2% 1.3% 1.7% Notes: 1. Growth rates based on weather normalized actual peak. 2. Vancouver Island peak values include Gulf Island s peak requirements. PAGE 108

297 ELECTRIC LOAD FORECAST F13-F33 Table A6.2 Regional Coincident Transmission Peaks Before DSM with Rate Impacts (MW) Fiscal Year Lower Mainland Coincident Peak (MW) Vancouver Island South Interior Northern Region Actual F Forecast F F F F F F F ,051 F ,093 F ,112 F ,099 F ,087 F ,086 F ,077 F ,079 F ,115 F ,136 F ,140 F ,147 F ,151 F ,151 F ,149 5 years: F2012 to F % -1.0% 3.5% 7.8% 11 years: F2012 to F % -0.6% 2.2% 5.5% 21 years: F2012 to F % -0.4% -0.5% 3.1% PAGE 109

298 ELECTRIC LOAD FORECAST F13-F33 Table A6.3 Domestic System and Regional Peak Forecast Before DSM with Rate Impacts (MW) Lower Mainland Vancouver Island South Interior Northern Region Domestic System Vancouver Island with Transmission Losses (MW) (MW) (MW) (MW) (MW) (MW) Actual F2012 5,024 2,050 1,463 1,341 10,088 2,050 Weather-Normalized Actual F2012 5,079 2,111 1,474 1,343 10,054 2,206 Forecast (Weather Normalized) F2013 5,314 2,143 1,563 1,356 10,376 2,238 F2014 5,429 2,177 1,594 1,412 10,668 2,275 F2015 5,496 2,186 1,614 1,522 10,879 2,283 F2016 5,577 2,200 1,636 1,629 11,108 2,298 F2017 5,678 2,217 1,649 1,722 11,339 2,316 F2018 5,797 2,236 1,686 1,829 11,628 2,335 F2019 5,908 2,255 1,697 1,940 11,888 2,355 F2020 6,022 2,273 1,710 2,001 12,100 2,374 F2021 6,123 2,291 1,724 2,034 12,270 2,393 F2022 6,222 2,308 1,733 2,034 12,400 2,410 F2023 6,361 2,338 1,752 2,047 12,607 2,441 F2024 6,488 2,363 1,761 2,054 12,783 2,468 F2025 6,612 2,383 1,776 2,053 12,946 2,489 F2026 6,741 2,410 1,754 2,063 13,095 2,517 F2027 6,875 2,438 1,714 2,107 13,266 2,546 F2028 7,018 2,469 1,713 2,138 13,474 2,577 F2029 7,167 2,500 1,731 2,150 13,693 2,610 F2030 7,315 2,532 1,750 2,167 13,915 2,643 F2031 7,467 2,563 1,771 2,180 14,139 2,676 F2032 7,618 2,595 1,791 2,189 14,358 2,708 F2033 7,767 2,625 1,813 2,196 14,572 2,740 Growth Rates: 5 years: F2012 to F % 1.0% 2.3% 5.1% 2.4% 1.0% 11 years: F2012 to F % 0.9% 1.6% 3.9% 2.1% 0.9% 21 years: F2012 to F % 1.0% 1.0% 2.4% 1.8% 1.0% Notes: 1. Regional peaks include distribution losses only, unless otherwise stated in the table. Regional peaks are not system coincident, as such they do not sum to the Domestic System Peak. 2. Lower Mainland includes peak supply requirement to City of New Westminster and Seattle City Light. 3. South Interior peak includes supply requirement to FortisBC. 4. Northern Peak includes supply requirement to Hyder, Alaska but does not include Fort Nelson or other Non-Integrated Areas. 5. The Domestic System peak recorded for the winter F2012 was 9,929 MW, excluding curtailment and outages. 6. Actual, weather normalized and forecast values for all Vancouver Island peaks values include Gulf Island peak demand. PAGE 110

299 ELECTRIC LOAD FORECAST F13-F33 LOAD FORECAST TABLES Table A6.4 PAGE 111

300

301 ELECTRIC LOAD FORECAST F13-F33 Table A Reference Load Forecast before DSM with Rate Impacts Total Hydro 2012 REFERENCE FORECAST - PROBABLE - BEFORE DSM WITH RATE IMPACTS BC Hydro Service Area Sales Integrated System Residential Commercial Industrial Total BCH Nwest Total Firm Total Losses Total Total Peak Fortis BC Domestic Export Firm Gross Gross Sales Sales Requirement Requirement (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (GW.h) (MW) Actual F ,462 15,439 18,737 51,639 1,363 53, ,313 5,722 59,036 58,735 9,861 F ,813 15,577 17,382 50,771 1,291 52, ,370 5,345 57,715 57,381 10,297 F ,650 15,631 15,608 48,889 1,198 50, ,393 5,100 55,494 55,190 10,112 F ,898 15,896 15,783 49, , ,867 4,502 55,368 55,045 10,203 F ,035 15,617 16,352 50, , ,284 5,800 57,083 56,800 10,319 Forecast F ,211 16,387 16,468 51, , ,220 5,260 57,480 57,152 10,719 F ,663 16,752 16,995 52, , ,710 5,403 59,113 58,714 11,011 F ,109 17,071 17,785 53, , ,261 5,537 60,799 60,378 11,222 F ,416 17,384 18,499 55,299 1,016 56, ,627 5,659 62,286 61,855 11,451 F ,761 17,815 19,016 56, , ,898 5,778 63,676 63,238 11,681 F ,163 18,859 19,902 58,924 1,000 59, ,235 5,978 66,213 65,769 11,971 F ,578 19,216 20,755 60,548 1,007 61, ,867 6,126 67,993 67,545 12,230 F ,041 19,551 21,382 61,975 1,016 62, ,303 6,261 69,564 69,111 12,443 F ,455 19,804 21,574 62,833 1,160 63, ,304 6,360 70,664 70,207 12,613 F ,885 20,064 21,213 63,162 1,370 64, ,843 6,429 71,272 70,811 12,743 F ,291 20,323 21,207 63,821 1,535 65, ,667 6,518 72,185 71,721 12,950 F ,742 20,660 21,262 64,664 1,584 66, ,560 6,614 73,174 72,707 13,125 F ,133 20,948 21,223 65,304 1,591 66, ,207 6,690 73,896 73,428 13,288 F ,554 21,260 20,814 65,628 1,599 67, ,538 6,745 74,283 73,812 13,438 F ,959 21,536 20,754 66,249 1,606 67, ,167 6,819 74,985 74,512 13,609 F ,409 21,865 20,836 67,110 1,614 68, ,038 6,914 75,951 75,475 13,817 F ,800 22,202 20,925 67,927 1,622 69, ,860 7,004 76,864 76,386 14,036 F ,226 22,577 21,049 68,853 1,630 70, ,794 7,104 77,898 77,420 14,258 F ,653 22,968 21,140 69,761 1,638 71, ,710 7,204 78,914 78,433 14,482 F ,107 23,374 21,221 70,701 1,646 72, ,660 7,309 79,968 79,486 14,701 F ,471 23,700 21,273 71,443 1,654 73, ,408 7,391 80,799 80,316 14,915 Growth Rates: 5 yrs F % 2.7% 3.1% 2.5% 0.5% 2.5% -0.1% 2.5% -0.1% 2.2% 2.2% 2.5% F yrs F % 2.4% 2.4% 2.2% 4.3% 2.3% 0.0% 2.3% 1.1% 2.2% 2.1% 2.1% F yrs F % 2.0% 1.3% 1.7% 2.6% 1.7% 0.0% 1.7% 1.2% 1.7% 1.7% 1.8% F2033 PAGE 113

302 RESPONSE TO WORKING GROUP AND P UBLIC COMMENTS ON THE S ITE C CLEAN ENERGY P ROJECT ENVIRONMENTAL IMP ACT S TATEMENT Technical Memo DEMAND-SIDE MANAGEMENT MAY 8, 2013

303 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT Subject: Demand-Side Management Purpose A number of comments received during the Comment Period raise the question of whether BC Hydro could pursue additional Demand Side Management (DSM) to delay or avoid the need for the Project. The purpose of this Technical Memo is to summarize the level of DSM that is reflected in the evaluation of need, and the treatment of additional DSM as a potential alternative to the Project. Project Need: BC Hydro s DSM Target Section 5.2 of the EIS describes the analysis of the need for the Project. As described in the Technical Memo on Project Need, the need for the Project is established based on demand from BC Hydro's residential, commercial and industrial customers. Once the load forecast is established, BC Hydro develops energy and capacity load-resource balances (LRBs) to determine if there is a gap between customer demand and expected resources. This results in the energy and capacity LRBs set out in tables 5.6 and 5.7 of the EIS. The topic of how to meet the gap between demand and resources after taking into account the current DSM target is addressed in the Technical Memo on Alternatives. One of the components of the energy and capacity LRBs is the level of future DSM savings that BC Hydro believes are achievable and cost-effective. DSM is BC Hydro s preferred resource and as a result it is the first resource looked at to address the gaps depicted in tables 5.6 and 5.7 of the EIS. BC Hydro DSM Target The current DSM target is 7,800 gigawatt hours per year (GWh/year) of energy savings, which is expected to also deliver 1,400 megawatts (MW) of capacity savings by F2021. A description of BC Hydro s current DSM savings target, together with the reasons for choosing the DSM target, are found in section of the EIS. Subsection 2(b) of the B.C. Clean Energy Act provides that it is a British Columbia s energy objective to take demand-side measures and to conserve energy, including the objective of [BC Hydro] reducing its expected increase in demand for electricity by the year 2020 by at least 66%. BC Hydro s current DSM target of 7,800 GWh/year exceeds the Clean Energy Act s target of at least 66% ; the current DSM target would reduce BC Hydro s forecasted demand for energy by 78% in F2021. The current DSM target is a significant step up from DSM targets BC Hydro pursued prior to The forecast average annual energy growth rate for the BC Hydro system without liquefied natural gas (LNG) is 2.2% between F2012 to F2022 (refer to table 5.1 of the EIS). With the implementation of the DSM target, BC Hydro forecasts annual energy system demand growth of about 0.8% per year (again without LNG). The current DSM target is comprehensive; it includes a broad range of codes and standards, rate structures, and programs that provide BC Hydro customers in virtually all market segments with an opportunity to participate (EIS, p. 5-13). The current DSM target is aggressive. For example, without TECHNICAL MEMO DEMAND-SIDE MANAGEMENT Page 2

304 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT further DSM there is a need for new energy resources in F2017 (table 5.6), but with the implementation of BC Hydro s current DSM target, the need for new energy resources is pushed out by 7 years to F2024 (table 5.8). In other words, with BC Hydro s current DSM target, there will be no need for new energy resources for a 7 year period, and a reduced need for energy new resources after that timeframe. DSM Delivery Risk BC Hydro must balance DSM s relatively low cost and environmental benefits against DSM delivery risk (the risk that forecasted DSM energy and capacity savings do not materialize). BC Hydro believes that the DSM target strikes the appropriate balance between these factors. Information concerning DSM delivery risk is found in section of the EIS. BC Hydro has a legislated service obligation under the B.C. Utilities Commission Act (refer to p. 5-3 of the EIS), and the consequences of DSM not delivering the anticipated capacity savings in particular are significant. While generally external markets can be counted on to supply some amount of energy across the year with associated costs, it may not be possible to secure capacity from the external market during winter peaks for one or more of the following reasons: (1) the illiquid (thinly-traded) nature of the market for capacity (2) insufficient transmission capacity (3) the U.S. market not having a surplus to sell Consistent with good utility practice and prior British Columbia Utilities Commission (BCUC) decisions, BC Hydro develops Contingency Resource Plans because the consequences of not being able to meet customer demand at the peak load could be severe. Refer to table 5.12 and pages 5-20 and 5-21 of the EIS for a description of BC Hydro s Contingency Resource Plans. The BCUC is the regulator that reviews expenditures associated with the current DSM target, and has the authority under section 44.2 of the Utilities Commission Act to approve, reject, approve in part or reject in part these expenditures. Past performance with respect to meeting past DSM targets is not likely to be indicative of the delivery risk associated with the current DSM target because the current DSM target is a significant step up from DSM targets BC Hydro set before Given BC Hydro s reliance on the current DSM target to deliver 1,400 MW of dependable capacity savings in about an eight year timeframe, there is a greater adverse consequence if the response to DSM programs and other initiatives is less than anticipated, as compared to a scenario where the response is greater than anticipated. DSM Options Considered in the EIS The need for the Project is based on among other things BC Hydro s current DSM target; refer to section and tables 5.8 and 5.9 of the EIS. In the EIS there are four alternatives to the current DSM target - DSM Options 1, 3, 4 and 5. The alternatives described in the EIS are generally equivalent to the DSM Options 1, 3, 4 and 5 as described in BC Hydro s 2010 Resource Options Report, and included in BC Hydro s draft Integrated Resource Plan of May Differences are generally due to a TECHNICAL MEMO DEMAND-SIDE MANAGEMENT Page 3

305 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT change from presenting savings with a different base year for calculation of savings. Please note that for the purposes of the EIS the options described in Section of the EIS update and replace the DSM options described in the 2010 Resource Options Report. The alternative DSM options considered in the EIS are as follows: DSM Option 1 is described at pages 5-19 and 5-20 of the EIS. The savings associated with DSM Option 1 are lower than the current DSM target 7,500 GWh/year of energy savings and 1,200 MW of capacity savings by F2021 DSM Option 3 is described at page 5-20 of the EIS, and is expected to deliver 9,200 GWh/year of energy savings and 1,400 MW of dependable capacity savings in F2021. DSM Option 3 is addressed below DSM Options 4 and 5 are described at section of the EIS. DSM Option 4 targets 9,500 GWh/year of energy savings and 1,500 MW of dependable capacity savings by F2021; the corresponding figures for DSM Option 5 are 9,600 GWh/year of energy savings and 1,600 MW of dependable capacity savings by F2021. DSM Options 4 and 5 are described in further detail below Potential DSM Alternatives to the Project: DSM Option 3 The EIS concludes on page 5-20 that DSM Option 3 on its own is not an alternative to the Project because if BC Hydro were to implement DSM Option 3 instead of the current DSM target, the effect would be to: (1) defer the need for energy set out in table 5.8 for five years; and (2) not defer the need for capacity set out in table 5.9. DSM Option 3 must be combined with supply side resources to meet the need for the Project and to be considered an alternative. The supply side resources would be composed of resources similar to the portfolios described in Section of the EIS. Potential DSM Alternatives to the Project The EIS review of potential alternatives to address the energy and capacity gaps shown in tables 5.8 and 5.9 of the EIS after implementation of the current DSM target (and after implementation of Revelstoke Unit 6, a BC Hydro Resource Smart generation project described in the EIS at page 5-14) is found in sections 5.4 and 5.5 of the EIS. BC Hydro does not rely on resources that are not viable in its portfolio analysis. Therefore, the first step in the EIS review of potential alternative resources is to determine if the particular resource is viable or not. BC Hydro identified and analyzed two categories of potential DSM options in sections and of the EIS: The first category consists of DSM Options 4 and 5 which entail levels of DSM beyond the current DSM target, and which like the current DSM target are anticipated to deliver both energy and capacity The second category are DSM options specifically designed to deliver dependable capacity savings during BC Hydro s peak load periods, and are addressed at the end of this memo TECHNICAL MEMO DEMAND-SIDE MANAGEMENT Page 4

306 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT DSM Options 4 and 5 Section of the EIS provides the GWh/year and MW of anticipated savings (which are also set out above in this memo) as well as the uncertainties associated with DSM Options 4 and 5. DSM Option 5 is the most aggressive potential DSM option BC Hydro has identified. The effect of DSM Option 5 would be to essentially reverse load growth over about a 20 year period such that there would be no need for new energy resources until F2031. BC Hydro is of the view that DSM Options 4 and 5 are not viable alternatives to the Project for the reasons set out in section , specifically: DSM Options 4 and 5 present government and customer acceptance issues arising from BC Hydro s reliance on aggressive and untested tactics. Implementing either DSM Option 4 or DSM Option 5 would require the mobilization of the full suite of DSM tools applied in combination with a number of tools employed by governments and other entities. For example, as described at page 5-35 of the EIS, DSM Option 5 would require BC Hydro rate structures with aggressive pricing that with the exception of smaller residential customers, would expose all BC Hydro customers to either efficiency-based rates and/or to marginal cost price signals Provincial and Federal Government codes and standards; significant government intervention and regulation at all levels of society; industry buy-in to facility energy efficiency certification undertaken by government(s) if industry wants access to embedded cost Heritage hydroelectricity, which in turn may require re-opening the Heritage Contract; buildings must be net-zero consumers of electricity; smaller and more efficient housing and building footprints, etc. DSM Options 4 and 5 entail significant delivery risk, especially with respect to capacity savings, and could jeopardize BC Hydro s ability to serve its customers For these reasons, it is not prudent for BC Hydro to rely on either DSM Option 4 or Option 5 to address the energy and capacity gaps shown in tables 5.8 and 5.9 of the EIS. DSM Capacity Initiatives The second category of potential DSM alternatives to the Project are DSM capacity initiatives, which are described in Section In contrast to the current DSM target and DSM Options 3, 4 and 5, the DSM capacity initiatives - industrial customer load curtailment and capacity programs - specifically target capacity savings. On their own, these DSM capacity initiatives are not an alternative to the Project, and would need to be combined with additional supply-side options to meet the identified need. As described on page 5-36 of the EIS, BC Hydro had a load curtailment offer in place from 2007 to 2010 to seek demand reduction options from large industrial customers during the winter (November to February) as an operational resource option in the event of short term capacity constraints. The load curtailment options are associated with operational opportunities in customer s existing industrial processes given operational capacity and market conditions. There are restrictions on how much advance notice is required, how long the periods of curtailment can last, how frequent and how many curtailment requests are acceptable each winter, and how many years the customers are willing to TECHNICAL MEMO DEMAND-SIDE MANAGEMENT Page 5

307 WORKING GROUP AND PUBLIC COMMENTS TECHNICAL MEMO SITE C CLEAN ENERGY PROJECT commit. As a result, of the roughly 400 MW of capacity contracted, there was approximately 56 MW available for F2012 and F2013. For a capacity option to be considered for long term planning it must be dependable. Given the restrictions imposed on the load curtailment options contracted, they are not considered dependable. For industrial load curtailment to be available as a long term planning option, it would require customer capital investment in infrastructure to allow for interruption of operation as and when required. BC Hydro concludes that the DSM capacity initiatives are not viable alternatives to the Project for the reasons set out in section Industrial customer load curtailment programs that entail a long-term commitment by the industrial customer to interrupt operations as and when required and DSM capacity programs are BC Hydro s first major exploration of these types of potential DSM initiatives, and as a result experience will need to be gained to increase the certainty of the anticipated capacity savings. Summary DSM is BC Hydro s preferred resource and as a result it is the first resource looked at to address gaps between customer demand and available supply. The need for the Project is based on BC Hydro s comprehensive and aggressive DSM target, which is expected to defer the need for additional resources by seven years. BC Hydro reviewed additional DSM options that provided additional energy and capacity savings as part of the analysis of alternatives to determine the appropriate balance between DSM s relatively low cost and environmental benefits against the risk that forecasted DSM energy and capacity savings do not materialize. The additional DSM options present government and customer acceptance issues, and entailed a significant level of delivery risk. As a result, BC Hydro concluded that the current DSM target was appropriate. Related Comments / Information Requests: This technical memo provides information related to the following Information Requests: pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ pub_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ ab_ TECHNICAL MEMO DEMAND-SIDE MANAGEMENT Page 6

308 BRITISH COLUMBIA UTILITIES COMMISSION Resource Planning Guidelines Issued: December 2003