GREENSTONE-MARATHON Integrated Regional Resource Plan

Inaugural Local Advisory Committee Meeting

June 29, 2015

• 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

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

The Three Levels of Electricity Planning

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Background – Bulk System 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.

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

• Mining development

• Gas to oil pipeline conversion project

• Recovery of forestry industry

• Growth in communities

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Drivers

• 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

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

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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

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

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

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

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

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

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

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)

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)

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)

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

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)

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)

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

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)