GREENSTONE-MARATHON Integrated Regional Resource Plan Inaugural Local Advisory Committee Meeting June 29, 2015
Presentation Outline • Introduction to the Ontario Electricity Sector • Electricity planning in Northwestern Ontario • Summary of findings from the Greenstone-Marathon Integrated Regional Resource Plan (IRRP) • Community engagement • Next steps • Discussion of long-term needs and community priorities 2
IESO - Who We Are and What We Do The Independent Electricity System Operator (IESO) works at the heart of Ontario's power system – ensuring there is enough power to meet the province's energy needs in real time while also planning and securing energy and its delivery for the future. It does this by: • Planning • Ensuring supply • Operating the grid • Engaging communities • Promoting conservation The IESO and the former Ontario Power Authority (OPA) merged on January 1, 2015 under the name Independent Electricity System Operator 3
Key Participants in Ontario’s Electricity Sector Ministry of Energy System Operation, Planning and Regulation Procurement Ontario Energy Board Ontario Electricity Customers Generation Distribution Transmission OPG and other generators LDCs, Hydro One Distribution and other distribution utilities Hydro One, GLP, Five Nations and others 4
ELECTRICITY PLANNING IN NORTHWEST ONTARIO 5
The Three Levels of Electricity Planning
Background – Bulk System Planning 7
What is Regional Planning? • A process for identifying and meeting local electricity needs; objective of maintaining a safe and reliable electricity supply • It is the link between provincial bulk system planning (led by the IESO) and local distribution system planning (led by LDCs) • Operates in the context of existing criteria and frameworks – Applies the IESO’s reliability standards – Aligns with planning policies – Accounts for local interests • Integrated approach: looks at conservation, generation, wires and other innovative solutions • A Working Group has been established to develop regional plans – for Greenstone-Marathon this includes the IESO and Hydro One Networks Inc. 8
Background – Integrated Regional Resource Planning • Engagement meetings in Thunder Bay in fall 2014 to kick-off scoping process for: – Thunder Bay – West of Thunder Bay – Greenstone-Marathon • Following a public comment period, the final Scoping Report was posted in January 2015 and the IRRP process begun for the three planning areas 9
The IRRP Process Data Gathering Technical Study Options Actions Process Data includes: Assess system capability Consider solutions that Actions include: against planning standard: integrate the followings: • Area electricity demand • Initiate regulatory • Maintain sufficient supply to • Conservation and • Local community growth process for near-term meet future growth distributed generation projects • Local economic • Minimize customer • Local generation • Monitor the growth and development interruptions during power • Infrastructure expansion update the plan for the • Electricity infrastructure outage long term equipment Outcomes Near-Term Investments & Electricity Electricity Needs Solution Options Demand Forecast & Timing Longer-term Roadmap Municipalities and First Nations and Métis communities engaged at various points in the process 10
GREENSTONE-MARATHON INTERIM IRRP (PRESENT-5 YEARS) 11 11
Introduction to the Greenstone-Marathon IRRP • An IRRP is being developed to provide recommendations to municipalities, First Nation communities, Métis community councils, and industry stakeholders related to what the most economic and technically feasible electricity solutions are for the region • An Interim IRRP report has been developed with community input to facilitate decision making related to electricity supply for near- term industrial and community developments in the area • The medium and long term plan will also be developed with community input and informed by this LAC 12
Local Electricity System 13
Drivers • Mining development • Gas to oil pipeline conversion project • Recovery of forestry industry • Growth in communities 14
Near-term (present-5 years) Needs • Greenstone sub-system: – Industrial customers drive the need for additional capacity requirements in the near term • North Shore sub-system: – Existing system expected to be adequate to supply all forecasted demand scenarios (see Appendix A) • Marathon Area sub-system: – Existing system expected to be adequate to supply all forecasted demand scenarios (see Appendix B) – Confirmed by System Impact Assessment for Marathon PGM- Cu project 15
Near-term (present-5 years) Needs: Greenstone Subsystem Forecast Scenarios Scenario A Scenario B Scenario C • LDC demand growth • LDC demand growth • LDC demand growth (including two sawmill re- (including two sawmill re- (including two sawmill re- starts) from existing starts) from existing starts) from existing stations stations stations • No large industrial • Geraldton area mining • Geraldton area mining projects materialize project: project: • phase 1 mine (2018) • phase 1 mine (2018) • phase 2 mine (2020) • phase 2 mine (2020) • Pipeline conversion project: • 4 oil pumping stations (2020) The Greenstone-Marathon IRRP working group does not consider these forecast scenarios to be of greater or lesser likelihood. 16
Near-term (present-5 years) Needs: Greenstone Sub-system Greenstone Sub-system Forecast Scenarios 120 115 110 Scenario C: approx. 90 MW incremental LMC required 105 100 95 90 85 80 75 Demand [MW] 70 65 60 55 Scenario B: approx. 30 MW incremental LMC required 50 45 40 35 30 25 20 15 10 Scenario A: Existing System is sufficient 5 0 2015 2016 2017 2018 2019 2020 Year Scenario C Scenario B Scenario A Load Meeting Capability 17 LMC: Load Meeting Capability
Greenstone-Marathon IRRP: Engagements prior to developing near-term plan Date Engagement October 2014 Series of engagement meetings in Thunder Bay January 2015 Posting of Scoping Process Outcome Report and Terms of Reference April 2015 Municipal meetings in Marathon and Geraldton May 2015 First Nation meetings 18
Scenario B – Alternatives Analysis NPV Cost Alternative ($ millions) 1) Install power equipment to support service Option B1 quality needs at customer mining site (reactive 55 compensation device providing +40 MVar) 2) Install customer-generation (2x10 MW) at customer mine site Option B2 1) Customer self-generation (off-grid) 200 1) Install power equipment to support service Option B3 quality needs at customer mining site (reactive 40 compensation device providing +40 MVar) 2) Replace existing line with higher capacity line Notes: 1. Scenario A does not require the development of alternatives because the existing system is capable of supplying growth while meeting all planning criteria 2. Maps of alternatives are included in Appendix C 19
Scenario C – Alternatives Analysis NPV Cost Alternative ($ millions) 1) Install power equipment to support service quality Option C1 needs at customer mining site (reactive 170 compensation device providing +40 MVar) 2) New 230 kV Line to Longlac 3) Off-grid gas generation for two pumping stations Option C2 1) Install power equipment to support service quality needs at customer mining site (reactive 165 compensation device providing +40 MVar) 2) New 230 kV Line to Longlac 3) New 115 kV line Manitouwadge-Longlac 1) Grid-connected gas-fired generating plant Option C3 350 (6x18 MW) 2) New 115 kV line Manitouwadge-Longlac 1) Customer self-generation (off-grid) at mine Option C4 510 2) Customer self-generation (off-grid) at four pumping stations Notes: 1. Maps of alternatives are included in Appendix C 20
Alternative Analysis: Observations • All economic alternatives have a common first stage: – Install reactive compensation (+40 MVar synchronous condenser or STATCOM) at the Geraldton mine site to accommodate phase 1 of the mine. • Grid-connected alternatives are more cost-effective than off-grid alternatives • Large grid-connected generation is more costly than transmission reinforcement • A new 230 kV transmission supply is the most cost-effective way to supply the Geraldton mine and the pipeline conversion project for 2020 (Scenario C) 21
Recommended Near-term Plan Recommendation Scenario Stage 1 (for 2018) Stage 2 (for 2020) Scenario A No new facilities required Install customer-generation (2x10 MW) at customer mine Scenario B site or replace existing line with higher capacity line Install power equipment to support service quality needs at customer mining site Install new 230 kV line to (reactive compensation device Longlac, new 115 kV line providing +40 MVar) Manitouwadge-Longlac, and Scenario C required transformation, switching, and compensation devices 22
Recommended Near-term Plan: Stage 1 Scenario B and C (i.e. common to both) • Geraldton mine phase 1 materializes Recommendation • Install +40 MVar reactive compensation Reactive (either synchronous condenser or Compensation STATCOM) at mine site In-service date • 2018 Net present value cost • $5 million 23
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