GREENSTONE-MARATHON Integrated Regional Resource Plan · GREENSTONE-MARATHON Integrated Regional...
Transcript of GREENSTONE-MARATHON Integrated Regional Resource Plan · GREENSTONE-MARATHON Integrated Regional...
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GREENSTONE-MARATHON Integrated Regional Resource Plan
Inaugural Local Advisory Committee Meeting
June 29, 2015
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• 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
Presentation Outline
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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
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Key Participants in Ontario’s Electricity Sector
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Ontario Energy
Board
Ontario Electricity
Customers
Regulation
Generation Distribution
Transmission
System Operation,
Planning and
Procurement
Hydro One, GLP, Five Nations
and others
LDCs, Hydro One Distribution
and other distribution utilities
OPG and other generators
Ministry of Energy
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ELECTRICITY PLANNING IN NORTHWEST ONTARIO
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The Three Levels of Electricity Planning
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Background – Bulk System Planning
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• 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.
What is Regional Planning?
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• 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
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Background – Integrated Regional Resource Planning
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The IRRP Process
Municipalities and First Nations and Métis communities engaged at various points in the process
Electricity Demand Forecast
Electricity Needs & Timing
Solution Options
Near-Term Investments &
Longer-term Roadmap
Pro
ce
ss
Ou
tco
me
s
Data GatheringData includes:
•Area electricity demand•Local community growth
•Local economic development
•Electricity infrastructure equipment
Technical StudyAssess system capability against planning standard:
•Maintain sufficient supply to meet future growth
•Minimize customer interruptions during power outage
OptionsConsider solutions that integrate the followings:
•Conservation and distributed generation
•Local generation
•Infrastructure expansion
ActionsActions include:
•Initiate regulatory process for near-term projects
•Monitor the growth and update the plan for the long term
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GREENSTONE-MARATHON INTERIM IRRP (PRESENT-5 YEARS)
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• 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
Introduction to the Greenstone-Marathon IRRP
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Local Electricity System
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• Mining development
• Gas to oil pipeline conversion project
• Recovery of forestry industry
• Growth in communities
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Drivers
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• 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
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Near-term (present-5 years) Needs
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Scenario A
• LDC demand growth (including two sawmill re-starts) from existing stations
• No large industrial projects materialize
Scenario B
• LDC demand growth (including two sawmill re-starts) from existing stations
• Geraldton area mining project:
• phase 1 mine (2018)
• phase 2 mine (2020)
Scenario C
• LDC demand growth (including two sawmill re-starts) from existing stations
• Geraldton area mining project:
• phase 1 mine (2018)
• phase 2 mine (2020)
• Pipeline conversion project:
• 4 oil pumping stations (2020)
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Near-term (present-5 years) Needs: Greenstone Subsystem Forecast Scenarios
The Greenstone-Marathon IRRP working group does not consider these
forecast scenarios to be of greater or lesser likelihood.
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Near-term (present-5 years) Needs: Greenstone Sub-system
05
101520253035404550556065707580859095
100105110115120
2015 2016 2017 2018 2019 2020
Dem
and
[M
W]
Year
Greenstone Sub-system Forecast Scenarios
Scenario C Scenario B Scenario A Load Meeting Capability
Scenario A: Existing System is sufficient
Scenario B: approx. 30 MW incremental LMC required
Scenario C: approx. 90 MW incremental LMC required
LMC: Load Meeting Capability
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Greenstone-Marathon IRRP: Engagements prior to developing near-term plan
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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
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Scenario B – Alternatives Analysis
Alternative NPV Cost
($ millions)
Option B1 1) Install power equipment to support service quality needs at customer mining site (reactive compensation device providing +40 MVar)
2) Install customer-generation (2x10 MW) at customer mine site
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Option B2 1) Customer self-generation (off-grid) 200
Option B3 1) Install power equipment to support service quality needs at customer mining site (reactive compensation device providing +40 MVar)
2) Replace existing line with higher capacity line
40
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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
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Scenario C – Alternatives Analysis
Alternative NPV Cost
($ millions)
Option C1 1) Install power equipment to support service quality needs at customer mining site (reactive compensation device providing +40 MVar)
2) New 230 kV Line to Longlac 3) Off-grid gas generation for two pumping stations
170
Option C2 1) Install power equipment to support service quality needs at customer mining site (reactive compensation device providing +40 MVar)
2) New 230 kV Line to Longlac 3) New 115 kV line Manitouwadge-Longlac
165
Option C3 1) Grid-connected gas-fired generating plant (6x18 MW)
2) New 115 kV line Manitouwadge-Longlac 350
Option C4 1) Customer self-generation (off-grid) at mine 2) Customer self-generation (off-grid) at four pumping
stations 510
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Notes:
1. Maps of alternatives are included in Appendix C
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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)
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Recommended Near-term Plan
Scenario Recommendation
Stage 1 (for 2018) Stage 2 (for 2020)
Scenario A No new facilities required
Scenario B
Install power equipment to support service quality needs at customer mining site (reactive compensation device providing +40 MVar)
Install customer-generation (2x10 MW) at customer mine site or replace existing line with higher capacity line
Scenario C
Install new 230 kV line to Longlac, new 115 kV line Manitouwadge-Longlac, and required transformation, switching, and compensation devices
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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 (either synchronous condenser or STATCOM) at mine site
In-service date
• 2018
Net present value cost
• $5 million
Reactive
Compensation
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OR
New 115 kV line
New 230 kV line
Recommended Near-term Plan: Stage 2a
Scenario C
• In addition to the Geraldton mine, pipeline conversion project proceeds according to public 2020 date
Recommendation
• Install new 230 kV transmission supply
• Install new 115 kV connection line
In-service date
• 2020
Net present value cost
• $160 million
East of Nipigon
Route
West of Marathon
Route
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Recommended Near-term Plan: Stage 2b
Scenario B
• Geraldton mine phase 2 proceeds, but pipeline conversion project does not proceed by public 2020 date
Recommendation
• Install new customer generation in the form of two 10 MW natural gas gensets at the Geraldton mine site, or replace line sections of A4L
In-service date
• 2020
Net present value cost
• $35 M – Line Section Replacement
• $50 M – Customer Generation
New gas DG
Replacement 115 kV line
OR
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Implementation Considerations
• The plan elements are driven by industrial customer development and therefore, in accordance with the Ontario Energy Board’s Transmission System Code, benefitting customers are responsible for the related costs
• Lead-times can be accommodated, but new transmission would require urgent action by the benefiting customers for 2020 in-service, based on typical lead times
• The IESO is available to provide support for any regulatory and / or environmental approvals
• The IESO does not have a mandate to procure facilities for individual customers
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Greenstone-Marathon IRRP: Engagements for Mid to Long Term Planning
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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
May 2015 Advertisements for the establishment of a Local Advisory Committee (LAC)
June 2015 Released Near-Term Plan and Inaugural meetings of the Local Advisory Committees
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Next Steps
• Development of medium and long term plan with input from the Local Advisory Committees
– Discussion of medium to long-term needs
– Discussion of community priorities
– Engagement of broader community
• Release 20-year Greenstone-Marathon IRRP in first half of 2016
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• What key electricity demand drivers do you see for the 5 to 10 year period and beyond?
• Are there additional local priorities that need to be considered in the development of the longer-term plan?
• How can the broader community be engaged in this discussion?
Discussion of Long-term Needs and Community Priorities
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QUESTIONS
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APPENDICES
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Appendix A: North Shore Subsystem Forecast
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Appendix B: Marathon Area Subsystem Forecast
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APPENDIX C
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Scenario B – Alternatives Analysis • Option B1
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install 2x10 MW gas-fired gensets at the mine site coincident with phase 2 of the mine (2020)
• Option B2
– Install 6x9.5 MW off-grid gas generation plant at the Geraldton mine site (2018)
• Option B3
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Replace 117 km of existing circuit A4L from Nipigon to Longlac with higher capacity conductor coincident with phase 2 of the mine (2020)
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Scenario B – Alternatives Analysis
Alternative NPV Cost
($ millions)
Option B1 1) +40 MVar synchronous condenser or STATCOM 2) 2x10 MW customer-generation at mine 55
Option B2 1) 6x9.5 MW off-grid gas generation plant at mine 200
Option B3 1) +40 MVar synchronous condenser or STATCOM 2) 117 km replacement of circuit A4L 40
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Maps of alternatives are included in Appendix C
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Scenario B – Alternative Analysis: Option B1
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install 2x10 MW gas-fired gensets at the mine site coincident with phase 2 of the mine (2020)
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Reactive Compensation (2018)
New gas DG (2020)
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Scenario B – Alternative Analysis: Option B2
– Install 6x9.5 MW off-grid gas generation plant at the Geraldton mine site (2018)
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Off-grid Gas Generation (2018)
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Scenario B – Alternative Analysis: Option B2
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Reactive Compensation (2018)
A4L Replacement (2020)
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Replace 117 km of existing circuit A4L from Nipigon to Longlac with higher capacity conductor coincident with phase 2 of the mine (2020)
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Scenario C – Alternatives Analysis • Option C1
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install a new 230 kV transmission supply from the East-West Tie to Longlac TS coincident with phase 2 of the mine, and the pipeline conversion project (2020)
– Install two off-grid gas generating plants to supply two remote pumping stations from the pipeline conversion project (2020)
• Option C2
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install a new 230 kV transmission supply from the East-West Tie to Longlac TS coincident with phase 2 of the mine, and the pipeline conversion project (2020)
– Install a new 115 kV transmission connection line from Manitouwadge to Longlac TS to supply two remote pumping stations from the pipeline conversion project (2020)
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Scenario C – Alternatives Analysis • Option C3
– Install a grid-connected generation plant at near Longlac with a dependable capacity (i.e. considering unit outages and de-ratings) of 80 MW in 2018
– Install a new 115 kV transmission connection line from Manitouwadge to Longlac TS to supply two remote pumping stations from the pipeline conversion project (2020)
• Option C4
– Install 6x9.5 MW off-grid gas generation plant at the Geraldton mine (2018)
– Install four off-grid gas generation plants totalling approximately 80 MW at each of the pumping stations from the pipeline conversion project (2020)
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Scenario C – Alternatives Analysis
Alternative NPV Cost
($ millions)
Option C1 1) +40 MVar synchronous condenser or STATCOM 2) New 230 kV Line to Longlac 3) Off-grid gas generation for two pumping stations
1701
Option C2 1) +40 MVar synchronous condenser or STATCOM 2) New 230 kV Line to Longlac 3) New 115 kV line Manitouwadge-Longlac
165
Option C3 1) 6x18 MW grid-connected gas-fired generating plant
2) New 115 kV line Manitouwadge-Longlac 350
Option C4 1) 6x9.5 MW off-grid gas generation plant at mine 2) 2x9.5 MW off-grid gas generation plants at four
pumping stations 510
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1. Not fully secure if 230 kV line is lost
Maps of alternatives are included in Appendix C
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Scenario C – Alternative Analysis: Option C1
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install a new 230 kV transmission supply from the East-West Tie to Longlac TS coincident with phase 2 of the mine, and the pipeline conversion project (2020)
– Install two off-grid gas generating plants to supply two remote pumping stations from the pipeline conversion project (2020)
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OR
Reactive Compensation (2018)
New off-grid
gas generation
(2020) East of Nipigon
Route
West of Marathon
Route
New 230 kV line (2020)
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Scenario C – Alternative Analysis: Option C2
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OR
Reactive Compensation (2018)
New 230 kV line (2020)
New 115 kV line (2020)
East of Nipigon
Route
West of Marathon
Route
– Install +40 Mvar of reactive compensation in the form of either a synchronous condenser or a STATCOM at the Geraldton mine site coincident with phase 1 of the mine (2018)
– Install a new 230 kV transmission supply from the East-West Tie to Longlac TS coincident with phase 2 of the mine, and the pipeline conversion project (2020)
– Install a new 115 kV transmission connection line from Manitouwadge to Longlac TS to supply two remote pumping stations from the pipeline conversion project (2020)
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Scenario C – Alternative Analysis: Option C3
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New 115 kV line (2020)
West of Marathon
Route
– Install a new grid-connected gas-fired generating plant with a dependable capacity of 80 MW (2018). Dependable capacity for gas generation considers a single unit outage. For costing purposes, a 6x18 MW facility was assumed.
– Install a new 115 kV transmission connection line from Manitouwadge to Longlac TS to supply two remote pumping stations from the pipeline conversion project (2020)
New grid-connected gas generation
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Scenario C – Alternative Analysis: Option C4
– Install 6x9.5 MW off-grid gas generation plant at the Geraldton mine site (2018)
– Install four off-grid gas generating plants to supply the pumping stations from the pipeline conversion project (2020)
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New off-grid
gas generation
(2020)
Off-grid Gas Generation (2018)
New off-grid
gas generation
(2020)