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J A N U A R Y 1 8 , 2 0 1 7 | W E S T B O R O U G H , M A

Marianne Perben

S Y S T E M P L A N N I N G

Preliminary high-level order of magnitude transmission development costs

Scenario 6 update

2016 Economic Studies

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Background

• Discussions concerning the 2016 NEPOOL Economic Study request are ongoing – Monthly PAC presentations have been made since April 2016 to review

scope of work, assumptions, metrics and study results

• During these discussions, the ISO committed to developing high-level order of magnitude cost estimates for the transmission needed to integrate renewable resources during on-peak load periods – At the October 2016 PAC meeting, the ISO presented preliminary high-

level order of magnitude transmission cost estimates for scenarios 1 through 5

https://www.iso-ne.com/static-assets/documents/2016/10/2016_economic_studies_high_level_transmission_costs_rev1.pdf

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Purpose of Today’s Presentation

• At the November 2016 PAC meeting, the ISO presented additional economic study results for sensitivity cases that had been requested by RENEW – Initially named scenario “S2_Sensitivity”, then renamed “Scenario 6” – Presentation available at:

https://www.iso-ne.com/static-assets/documents/2016/11/2016_economic_study_draft_results_sensitivity.pdf

• The purpose of today’s presentation is to present preliminary high-level order of magnitude transmission development costs to integrate renewable resources in New England for scenario 6 – These cost estimates are very preliminary and based on judgement

• They include costs that would be incurred beyond individual plant interconnection costs

– They do not fully account for operational issues caused by the development of large-scale inverter based resources during off-peak load periods

– This cost analysis does not develop transmission expansion plans

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PRELIMINARY HIGH-LEVEL ORDER OF MAGNITUDE TRANSMISSION DEVELOPMENT COSTS

Scenario 6 (compared to Scenario 2) - Integration of on-shore Maine resources

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Transmission Needed to Integrate Renewable Resources – Collector and Interconnection System

• Plant collector system – System tying each individual wind

turbine generator or photovoltaic generator to the collector system station

– May include generator step-up transformers, collector strings , collector substation, collector step-up transformer, supplemental static and/or dynamic reactive devices

• Interconnection system – Transmission system tying the collector

system station to the Point of Interconnection (POI)

– May include high-voltage AC generator lead, high-voltage substation, supplemental static and/or dynamic reactive devices

• Four categories of transmission upgrades are needed to integrate renewable resources

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Transmission Needed to Integrate Renewable Resources – Integrator System

• Integrator system – Transmission system tying the POI to

the interconnected power system – May include new high-voltage AC

and/or high-voltage DC lines and converter stations and supplemental static and/or dynamic reactive devices

– Conceptually, similar type of upgrades to those considered in the on-going 2016 Maine Resource Integration Study • Available at https://smd.iso-

ne.com/operations-services/ceii/pac/2016/09/a3_maine_resource_integration_study.pdf

POIs

Integrator System AC Power System

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Transmission Needed to Integrate Renewable Resources – Congestion Relief System

• Congestion relief system – Transmission system that allows the

removal of 100% of the transmission congestion that prevents full energy production from the renewable resources

– Assume HVDC tie(s) tying the integrator system to the hub, located at Millbury, MA • HVDC tie(s) sized to remove congestion

observed in the energy production runs • Ancillary devices/services to control

impact of high penetration of converter based resources

– Special controls on power electronic devices

– High inertia synchronous condensers – System protection upgrades – Additional storage

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Cost Estimates For Renewable Resources Integration - Assumptions

• A full cost estimate would include costs for all four categories of transmission upgrades – Plant collector system – Interconnection system – Integrator system – Congestion relief system

• Plant collector and interconnection system costs are specific to each generation interconnection project – They will not be addressed as part of this presentation

• Integrator and congestion relief system costs depend on the design of the integrator and congestion relief systems

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Maine Nameplate Onshore Wind Injections

• For the purpose of this costing exercise, it is assumed that the size of the integrator system will be proportional to the size of the nameplate renewable injection

Scenario 2 Scenario 6

2030 Maine Nameplate Onshore Wind Injections (MW) 12,872 5,959

Slide 9 – November PAC presentation, available at https://www.iso-ne.com/static-assets/documents/2016/11/2016_economic_study_draft_results_sensitivity.pdf

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Sizing of the Maine Integrator System

• Scenario 6 – As in case of scenario 2, due to

the very large size of the Maine renewable nameplate injection, it is assumed that no AC integrator system could be designed to tie the POI into the interconnected power system without a complete overhaul of the AC power system • Instead, we assume that the

renewable resources will be tied directly into several HVDC connectors that will also serve as congestion relief systems

POIs

AC Power System

HVDC Ties

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Sizing of the Maine Congestion Relief System

• The MW congestion relief need is based on on-peak conditions (Winter and Summer) – The difference in simultaneous interface flows between the 2030

unconstrained and constrained scenarios provides information on the amount of required congestion relief • See slides 12 and 13 for reference • For example, in scenario 6, the Surowiec-South flow in the summer peak hour

is 2,898 MW in the unconstrained case and 1,500 MW in the constrained case. The congestion relief need on the Surowiec-South interface is 1,398 MW

• The total need is based on the highest simultaneous need across all northern interfaces – Surowiec-South, ME-NH and North-South interfaces

Needed Congestion Relief Capacity Scenario 2 Scenario 6

2030 Winter Peak 9,043 MW 3,596 MW

2030 Summer Peak 3,854 MW 1,398 MW

Higher of Winter/Summer 9,043 MW 3,596 MW

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Simultaneous Interface Flows for Winter Peak Hour, comparing to Scenario 2

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Simultaneous Interface Flows for Summer Peak Hour, comparing to Scenario 2

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Characteristics of the Congestion Relief System

• For the purpose of this analysis, we assumed that the congestion relief system would be composed of – DC portion: parallel overhead HVDC ties

• Bipolar design • Voltage-source converters (VSC) • 1,200 MW capacity

– To respect 1,200 MW New England loss of source – Among largest capacities seen for VSC technology

• DC voltage of 300/320 kV • Assumed HVDC costs:

– Converter: $300 million/converter – DC line: $3.5 million/mile – Miscellaneous costs for additional control, filters, undergrounding or right-of-

way requirements: $200 million/tie

– Ancillary AC upgrades • Fast-responding dynamic reactive devices • 345 kV substation and network upgrades

Costs described here are preliminary high-level order of magnitude costs and are based on judgement. Also, they do not account for individual plants’ interconnection costs or potential costs from system operational issues.

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Ancillary AC Upgrades Associated with the Congestion Relief System • Sending end

– Fast-responding dynamic reactive devices • Synchronous condensers (to increase system’s short circuit strength and/or

maintain system’s voltage performance) or • Statcom devices (to maintain system’s voltage performance) • Assumed need of 1/3 of MW capability • Assumed cost of $0.25 million/MVAR

– 345 kV upgrades • Assumed $40 million per new substation (to connect the POIs to the converter

station at each HVDC station) in Scenarios 2 and 6

• Receiving end – Fast-responding dynamic reactive devices in all three scenarios

• Assumed need of 1/3 of MW capability • Assumed cost of $0.25 million/MVAR

– 345 kV substation upgrades • Assumed cost of $10 million per terminal expansion in all scenarios

– 345 kV system upgrades on receiving network • Assumed additional generic cost of $1.5 billion in Scenario 2 and $1 billion in

Scenario 6

Costs described here are preliminary high-level order of magnitude costs and are based on judgement. Also, they do not account for individual plants’ interconnection costs or potential costs from system operational issues.

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Total Cost Breakdown of the Maine Congestion Relief System

Congestion Relief System Scenario 2 Scenario 6

9,043 MW (8 HVDC Ties) 3,596 MW (3 HVDC Ties)

Equipment $ per Unit Quantities Total $ Quantities Total $

DC Portion

HVDC Overhead Lines $3.5 million/mile 5 * 400 + 3* 300 =

2,900 mi. $10.15 bn

2 * 400 + 1* 300 = 1,100 mi.

$3.85 bn

Converters $300 million/converter 16 $4.8 bn 6 $1.8 bn

Misc. DC Additional Equipment

$200 million/tie 8 $1.6 bn 3 $0.6 bn

Total – DC Portion -- -- $16.55 bn -- $6.25 bn

AC Portion

Sending End - Reactive Devices

$0.25 million/MVAR Approx. 1/3*9,000 =

3,000 MVAR $0.75 bn

Approx. 1/3*3,600 = 1,200 MVAR

$0.3 bn

Sending End – New AC Substations

$40 million/AC substation 8

(to connect POI to converter station at each tie)

$0.32 bn 3

(to connect POI to converter station at each tie)

$0.12 bn

Receiving End - Reactive Devices

$0.25 million/MVAR Approx. 1/3*9,000 =

3,000 MVAR $0.75 bn

Approx. 1/3*3,600 = 1,200 MVAR

$0.3 bn

Receiving End – AC Terminations

$10 million/terminal expansion (assumed 2 terminal expansions per tie)

8 * 2 = 16 $0.16 bn 3 * 2 = 6 $0.06 bn

Receiving End – Additional Upgrades on AC Network

Assumed generic cost for each scenario -- $1.5 bn -- $1 bn

Total – AC Portion -- -- $3.48 bn -- $1.78 bn

AC and DC Portions

Total – Congestion Relief System

-- -- $20 bn -- $8 bn

Total Cost + 50% Margin -- -- $30 bn -- $12 bn

Costs described here are preliminary high-level order of magnitude costs and are based on judgement. Also, they do not account for individual plants’ interconnection costs or potential costs from system operational issues.

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PRELIMINARY HIGH ORDER OF MAGNITUDE TRANSMISSION DEVELOPMENT COSTS Scenario 6 (compared to Scenario 2) - Integration of off-shore SEMA/RI resources

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SEMA/RI Nameplate Offshore Wind Injections

• The size of the nameplate renewable injection in scenario 6 is more than 4 times the size of the injection in scenario 2

Scenario 2 Scenario 6

2030 SEMA/RI Nameplate Offshore Wind Injections (MW) 1,219 5,370

Slide 10 – November PAC presentation, available at https://www.iso-ne.com/static-assets/documents/2016/11/2016_economic_study_draft_results_sensitivity.pdf

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Need for an Integrator and/or Congestion Relief Systems in SEMA/RI • In scenarios 1, 2 and 3, flows on the SEMA/RI export interface

were never as high as the interface limit of 3,400 MW – Therefore no integrator or congestion relief systems were contemplated

• In scenario 6, flows on the SEMA/RI export interface were at or above the interface limit up to 10% of the time

Slide 31 – November PAC presentation, available at https://www.iso-ne.com/static-assets/documents/2016/11/2016_economic_study_draft_results_sensitivity.pdf

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Geographic Location of Off-Shore Wind Energy Areas

Off-shore wind energy areas off of the coast of Rhode Island are located approximately 50 miles off the coast. Geographically, the high-voltage AC grids in Rhode Island, Southeast Massachusetts or Connecticut may offer equivalent points of interconnection.

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Available Points of Interconnection for the Offshore Injections

• Under the economic study assumptions, by 2030, approximately 4,400 MW of resources will be assumed retired at points of interconnection that could be suitable for offshore wind interconnection – Geographically close to the coast line

POI Location Resource(s) Amount (MW) Comment

Millstone 345 kV Connecticut Millstone 1 641 Pre-FCM Retirement

(2002 Summer Capability)

Montville 115 kV Connecticut Montville 5 & 6 486

Assumed Retired by 2030 in Scenario Analysis

(FCA 10 Summer Qualified Capacity)

Brayton Point 115 and 345 kV

SEMA/RI Brayton Point 1

through 4 1,525

Recent Non-Price Retirements (FCA 8 Summer Qualified Capacity)

Canal 345 kV SEMA/RI Canal 1 & 2 1,092

Assumed Retired by 2030 in Scenario Analysis

(FCA 10 Summer Qualified Capacity)

Pilgrim 345 kV SEMA/RI Pilgrim 677 Recent Non-Price Retirements

(FCA 10 Summer Qualified Capacity)

-- Total (approx.) 4,421 --

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Sizing of the SEMA/RI Integrator System in Scenario 6

• Given the large amount of assumed retirements, carefully choosing the points of interconnection of the offshore wind resources in scenario 6 may alleviate the need for a significant integrator system in SEMA/RI

Suggested POI for Scenario 6 Off-shore Resources

Location Amount of Assumed

Retired Generation at the POI (MW)

Example of Possible Nameplate

Interconnections (MW)

Millstone/Montville 345 kV Connecticut 1,127 1,400

Kent County 345 kV SEMA/RI --- 800

Brayton Point 345 kV SEMA/RI 1,525 1,600

Pilgrim/Canal 345 kV SEMA/RI 1,769 1,600

-- -- Total 5,400

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Sizing of the SEMA/RI Congestion Relief System in Scenario 6

• Interface flows during the Summer or Winter Peak hours (slides 12 and 13) do not show a need for a congestion relief system in SEMA/RI

• Looking at the SEMA/RI interface duration curve, the maximum flow on the interface in the unconstrained case is 5,000 MW, which translates into an absolute maximum congestion relief need of 1,600 MW

• However, the need for such a high export out of SEMA/RI is very marginal and would be mostly alleviated by interconnecting 1,400 MW or more of offshore wind, in Connecticut, outside of the SEMA/RI export constraint

Slide 42 – November PAC presentation, available at https://www.iso-ne.com/static-assets/documents/2016/11/2016_economic_study_draft_results_sensitivity.pdf

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SUMMARY

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Summary • In scenario 6, assuming that the interconnection of the offshore wind resources is

carefully planned and split between Connecticut, Rhode Island and Southeast Massachusetts, the need for any integrator or congestion relief systems from the offshore wind integration may be fully alleviated

• Under this same assumption, the cost to integrate renewable resources (excluding plant collector and interconnection system costs) in scenario 6 would be driven exclusively by the cost of integrating Maine on-shore wind resources and would be significantly reduced, as compared to scenario 2 – Integrating renewable resources in the SEMA/RI area, close to the New England load centers and

where large retirements have been assumed is a more cost-effective approach

• Costs presented in this analysis are a high level order of magnitude since they were developed based on a very high-level, un-tested, view of the necessary transmission expansion needed to accommodate renewable integration

• In other presentation, the ISO has identified potential transmission planning issues that will need to be addressed for the development of large-scale inverter based resources, including operational issues presented by off-peak load periods – Regulation, ramping, and reserves – Low short circuit availability, power quality, voltage control, stability performance – Control interactions between many power electronic devices

• The costs presented in this analysis do not fully account for all of those issues

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Summary, cont.

Scenario 1 Scenario 2 Scenario 3 Scenario 6

2030 Maine Nameplate Wind Injection (MW)

2,955 MW 12,872 MW 3,652 MW 5,959 MW

Needed Congestion Relief Capacity (MW)

1,471 MW 9,043 MW 1,839 MW 3,596 MW

Integrator System (Description)

1 AC parallel 345 kV path

--- 2 AC parallel 345 kV

paths ---

Integrator System (Cost $ Bn)

1.5 --- 3 ---

Congestion Relief System (Description)

Connecting Larrabee 345 kV to the Millbury hub

Connecting POIs directly to the Millbury hub

Connecting Larrabee 345 kV to the Millbury hub

Connecting POIs directly to the Millbury hub

Congestion Relief System (Cost $ Bn)

3.7 20.0 3.7 8.0

Total Cost ($ Bn) 5.2 20.0 6.7 8.0

Total Cost ($ Bn) + 50% margin

7.8 30.0 10.0 12.0

Costs described here are preliminary high-level order of magnitude costs and are based on judgement. Also, they do not account for individual plants’ interconnection costs or potential costs from system operational issues.

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