MISO Process
Regional Transmission System Planning
December 12-13, 2012 John Lawhorn
XM Conference, Medellin 12/12/12
Overview of the Process Beginning of Slides
Agenda Item 7
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Note: need David’s review and assistance with slide 10
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MISO Overview
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MISO Reliability Coordination Area, January 2012
• Regional Transmission Operator (RTO) /Independent System Operator (ISO)
• 2001 - Reliability Coordinator • 2005 - Energy Markets • 2009 – Ancillary Services • Large Footprint – 1,000,000
square kilometers • 11,000 MW of Wind Generation • 140+ Wind Sites
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Carmel Indiana – Control Room
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Scope of Operations as of January 1, 2012
• Generation Capacity – 131,010 MW (market) – 142,930 MW (reliability)
• Historic Peak Load (set July 20, 2011)
– 103,9750 MW (market) – 110,032 MW (reliability)
• 49,641 miles of transmission • 11 states, 1 Canadian
province
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• 5-minute dispatch
• 1,911 pricing nodes
• 1,242 generating units (market)
• 5,930 generating units (network model)
• $23.6 billion gross market charges (2011)
• 363 market participants serving 40 million people
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MISO – Expanded Area December 2013
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Value Based Planning
Regional Transmission System Planning
Planning Objectives and Principles
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• Make the benefits of an economically efficient energy market available to customers by providing access to the lowest electric energy costs
• Provide a transmission infrastructure that safeguards local and regional reliability and supports interconnection-wide reliability
• Support state and federal energy policy objectives by planning for access to a changing resource mix
• Provide an appropriate cost mechanism that ensures the realization of benefits over time is commensurate with the allocation of costs
• Develop transmission system scenario models and make them available to state and federal energy policy makers to provide context and inform the choices they face
MISO Board of Director Planning Principles
Fundamental Goal
The development of a comprehensive expansion plan that meets reliability needs, policy needs, and economic needs
MISO Planning Objectives
XM Conference, Medellin 12/12/12
Bottom Up Planning
(Locally driven)
Policy Assess-
ment (Inform
and comply)
Top Down Planning (MISO driven)
Access Planning* (Customer
driven, MISO led)
Is Transmission Needed? MISO Planning Approach
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• The MISO planning approach combines a top down / bottom up approach to planning with generator interconnection and a policy needs assessment
• This combined approach ensures all needs are met
• All analysis occurs through an open and transparent process
MISO Planning Approach
XM Conference, Medellin 12/12/12
Bottom Up Planning
Operations Planning
(XM)
Policy Assess-ment, (CNO)
Top Down Expansion Planning
(CREG/UPME driven)
Access Planning* (Customer driven, ??
led)
Is Transmission Needed? MISO Planning Approach Applied To Columbia
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• The MISO planning approach combines a top down / bottom up approach to planning with generator interconnection and a policy needs assessment
• This combined approach ensures all needs are met
• All analysis occurs through an open and transparent process
Colombia Planning Approach
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Total Cost ($) Minimum Total Cost:
Energy, Capacity and Transmission
High Capacity Cost Low Transmission Cost
Goal
Capacity Cost H L
Transmission Cost H L
High Transmission Cost Low Capacity Cost
Focus is to Minimize the Total Cost of energy Delivered to Consumers …
XM Conference, Medellin 12/12/12
Policy consensus
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Before transmission is built a number of conditions must be met - Increased consensus on
energy policies (current and future)
- A robust business case that demonstrates value sufficient to support the construction of the transmission project
- A regional tariff that matches who benefits with who pays over time
- Cost recovery mechanisms that reduce financial risk
… and Ensure Valuable Transmission is Built Conditions Precedent to Increased Transmission
XM Conference, Medellin 12/12/12
Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
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Capacity Versus Energy Modeling
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Capacity Modeling – Power Flow
• Detailed Reliability analysis • AC and DC solution options • Select 4-5 scenarios to represent
most system condition for a given year
• Fixed economic dispatch of generation
• Interregional coordination limited to defined/scheduled transfers
• Model energy resources at a specified capacity level
• Used to evaluate user defined dispatch for one hour
Energy Modeling – Production Cost
• Reliability screen with selected security constraints
• DC solution only • 8760 hour simulation • Captures economics on the system • Interregional energy flow dictated by
economic energy trading • Energy resources can be modeled
to capture full potential operating conditions during a given year
• Used to optimize dispatch to demonstrate economic value for an entire year
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What is needed to perform effective long-term planning?
• No single tool can be used to find complete planning solutions without input from other tools – Each tool provides different information that is required for a comprehensive
planning approach
Inputs • Demand and Energy • Resource Mix • Location of Load and
Resources • Transmission System • Policy • Stakeholder Review
Planning Models (Tool) • Probabilistic (GE Multi Area Reliability
Simulation) • Resources Expansion (EPRI Electric
Generation Expansion Analysis System) • Production Cost (PROMOD, Plexos) • Reliability (PSSE/MUST/DSA Tools)
Outputs • Identification of
solutions that provide reliability, economic, and policy benefits
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A Holistic Value Based Planning Process for Energy Resources
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
XM Conference, Medellin 12/12/12
STEP 1 – Regional Resource Forecasting (RRF)
• Long term transmission planning requires a Regional Resource Forecasting process
• Approach provides reasonable assumptions for future generation types, timing and location
• Is performed on a regional level and provides a “MACRO” view of the system
• The goal is to provide a broad range of outcomes, rather than single expected forecast
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Regional Resource Forecasting (Futures Development)
• Regional resource forecasting is needed to obtain multiple long term views of theoretical supply and demand resource availability given different policy and economic drivers
• Future scenarios and underlying assumptions are developed collaboratively with stakeholders through the Planning Advisory Committee
• The goal is for the range of Futures to be linked to likely real-life scenarios and provide an envelope of outcomes that is significantly broad, rather than a single expected forecast
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Narrow and less useful Broad and more useful
Years Years
MW
MW
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Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
XM Conference, Medellin 12/12/12
Evaluation Process Focuses on Scenario Modeling
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Load Forecast
Demand – side options
Supply – side options
Resource Expansion
Sensitivity Analysis
Risk Analysis Results
DR/EE Study
EPA Study
Wind Integration Initiative
Address Business Implications Resource
Adequacy
XM Conference, Medellin 12/12/12
Uncertainty Variables
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• Capital cost ($kW) • Program cost ($/kW) • $/MMBtu • %/year • %/year • %/year • $/ton by pollutant • as a % of energy • Varies
• Supply Side Resources • Demand Side Resources • Fuel costs • Escalation rates • Demand growth rates • Energy growth rates • Environmental costs • RPS levels • Carbon constraint level
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Example Siting: Supply Side Resources
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Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
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STEP 3 – Transmission Overlay Development
• Objective is to develop solutions that meet reliability, public policy, and economic needs with Lowest total cost of energy delivery
• To employ both economic transmission expansion process – “top-down” view and conventional reliability transmission expansion process - “bottom-up” view
• Approach – Chorological production cost simulations
• Copper Sheet- unconstrained energy flow • Constrained energy flow present transmission
– Analyze difference to develop new transmission • Energy Sources and Sinks • Interface Flows • Forecasted LMPs • Targeted Economic Potentials
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Copper Sheet • Energy market forces differ from the present existing system
transfer capability in where and in what quantity energy would flow if it could.
• The Copper Sheet method relieves constraints in the reference model by raising ratings to high levels and not monitoring flow gates.
– Energy sinks and sources are defined by the difference between
the unconstrained case and the reference case. The quantity of energy is defined. The benefit of this energy to load is defined. The Net Generator Revenue to the supplier is defined. Benefits occur to both loads and generators in an energy market.
– Lines can be monitored around an area or through a boundary to determine hourly interface flows. The hourly flows with the highest peak hours determine the power or rate of energy delivery to an area or through a boundary. The transfer capacity from source to sink can be estimated with this information.
– The exact paths of the flow of energy are not of interest. . – LMP contour maps assist in selecting line routings.
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Energy Sources and Sinks (Example)
• Year 2024• Gas price 8$/Mbtu• Demand Growth Rate 1.28%• Energy Growth Rate 1.5%
• Year 2026• Gas price 4.5$/Mbtu• Demand Growth Rate 0.75%• Energy Growth Rate 1.0%
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Forecasted LMPs (Example)
• Year 2024• Gas price 8$/Mbtu• Demand Growth Rate 1.28%• Energy Growth Rate 1.5%
• Year 2026• Gas price 4.5$/Mbtu• Demand Growth Rate 0.75%• Energy Growth Rate 1.0%
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“Copper sheet” calculations provide the magnitude of the flow and existing flow paths as the energy flows according to an unconstrained Energy Market dispatch.
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Interface Contour: Annual Energy Difference Unconstrained Case Minus Constrained Case (Example)
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Transmission Overlay Development Samples • MISO Regional Generation Outlet Study (RGOS)
– Objective is to develop transmission plan that facilitate approximately 15% state renewable energy mandates in the Midwest ISO footprint to meet reliability, policy and economic needs
– Outcomes: two distinct transmission strategies • Native voltage solution (345 kV only except in areas where 765
kV is considered native voltage) • 765 kV solution (which will include reasonable 345 kV
supporting transmission)
• Eastern Wind Integration and Transmission Study (EWITS) – 4 transmission overlays with 800 kV HVDC as preferred “backbone”
• A Combination of HVDC and EHV AC transmission expansion could be a good choice for high renewable penetration levels
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RGOS Transmission Overlay Strategies
765 kV Solution
Native Solution
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EWITS - Overlays for 4 Scenarios
October 2, 2009 EIWTS Technical Review Committee Webinar
Scenario 2
Scenario 3
Scenario 1
Scenario 4
Scenario 2
20% Strong High Plains 20% Hybrid
30% On and Offshore 20% Strong East - offshore
XM Conference, Medellin 12/12/12
Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
XM Conference, Medellin 12/12/12
RGOS Bookend Analysis
Transmission Overlays
Policy Driven Futures
Bookend Sensitivity Scenarios
765kV Plan
BAUHDE S1
COMB S3
RPS S2
BAUMLDE S4
Carbon Constraint S5 High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
Native Plan
BAUHDE S1
COMB S3
RPS S2
BAUMLDE S4
Carbon Constraint S5 High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
High Gas Low Gas
Base Case
High Load Low Load
STEP 4 – Robustness Testing Decision Tree
XM Conference, Medellin 12/12/12
Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
XM Conference, Medellin 12/12/12
STEPs 5&6 – Transmission Consolidation and Sequencing
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Objective is to look for compatibility and flexibility regardless of future policy changes- by making a set of investments with relatively low risk/reward ratio
RGOS Native Voltage Plan
Market Efficiency
Studies RGOS 765kV Plan
Best-fit Solution
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After additional intensive analysis, the candidate portfolio was refined into a final Multi Value Project Portfolio
39 Multi Value Project Portfolio
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Steps 5/6 – Reliability Analyses Performed Base Dispatch AC Contingency Analysis:
– All (n-1) explicitly defined contingencies evaluated – RT-Ops EMS explicitly defined contingencies evaluated – Single automated contingencies were evaluated per control area (>100 kV) – Select (n-2) explicitly defined contingencies evaluated – Category C1, C2, and C5 – Automated bus double branch, double ties (>200 kV) evaluated – Generator doubles per control area evaluated
Critical Interface Voltage Stability (PV) Analysis: – 5 interfaces studied based on operational/planning experience – Up to (n-4) involving line and generator outages (most n-2 or n-3)
Large Load Area Voltage Stability (QV) Analysis: – 2 large industrial/metro areas studied based on operational/planning experience – Supplements PV analysis for power factor sensitivity and critical bus information
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Analysis Performed
First Contingency Incremental Transfer Capability (FCITC) Analysis:
– First Contingency Incremental Transfer Capability – 15 Transfer directions studied – Evaluates maximum steady state flow levels
Wind Generation Sensitivity Analysis:
– 12, 594 MW of installed wind capacity for 2012-13 Winter – MISO Wind to MISO Non-wind per merit order
IROL Analysis:
– All NERC defined category B, C1, C2, and C5 contingencies – Facilities loading of more that 125% of the emergency rating – 24 potential events were analyzed
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XM Conference, Medellin 12/12/12
Value Based Planning Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario
– The “best” transmission plan may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
STEP 6: EVALUATE CONCEPTUAL
TRANSMISSION FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL
TRANSMISSION OVERLAYS BY FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN
POWERFLOW MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
XM Conference, Medellin 12/12/12
In the MISO cost allocation approach the business case (i.e. benefits) defines the spread of dollars
– Benefits of Multi Value Projects are spread regionally consistent with the widespread benefits from regional plan
– Economic benefits of Market Efficiency Projects spread farther beyond the local zone
– Reliability benefits of Baseline Reliability Projects primarily stay in the zone in which the reliability issue exists
– Generator Interconnection Projects paid primarily by Interconnection Customer
– Participant funded projects are paid by the party proposing the project
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Participant Fund
Baseline Reliability
Market Efficiency
Multi Value
Generator Interconnec
tion
Regional
Local
STEP 7 – MISO Transmission Cost Allocation Approach seeks to match the business case with the allocation method
XM Conference, Medellin 12/12/12
44 1. Market Efficiency Project cost allocation methodology currently under review by stakeholders
Allocation Category Driver(s) Allocation to Beneficiaries Participant Funded (“Other”)
Transmission Owner identified project that does not qualify for other cost allocation mechanisms.
Paid by requestor (local zone)
Generator Interconnection Project
Interconnection Request Paid for by requestor; 345 kV and above 10% postage stamp to load
Market Efficiency Project1 Reduce market congestion when benefits are 1.2 to 3 times in excess of cost
Distribute to planning regions commensurate with expected benefit; 345 kV and above 20% postage stamp to load
Baseline Reliability Project
NERC Reliability Criteria Primarily shared locally through Line Outage Distribution Factor Methodology; 345 kV and above 20% postage stamp to load
Multi Value Project Address energy policy laws and provide widespread benefits across footprint
100% postage stamp to load
STEP 7 – MISO Transmission Cost Allocation Approach seeks to match the business case with the allocation method
XM Conference, Medellin 12/12/12
Overview of the Process End of Slides
Agenda Item 7
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Multi-Regulatory Collaboration
Example Cost Allocation Regional Planning
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Appendix A
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Multiple Jurisdictions
• 11 State Regulatory Commissions – Approve cost recovery
• 25 Load Serving Entities – Responsible for
generation expansion • MISO
– Day ahead/RT market – Real time operations – Transmission expansion
• CNO – Technical standards – Input to CREG
• CREG – Generator expansion
• UPME – Transmission
expansion planning • XM
– Day to day real time (RT) operations
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MISO Process Columbia Process
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario – The “best” transmission plan
may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
MISO Value Based Planning
STEP 6: EVALUATE CONCEPTUAL TRANSMISSION
FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL TRANSMISSION OVERLAYS BY
FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN POWERFLOW
MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
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Definitions For Steps 1 and 2
• What is a Future? – A prediction of what “could be” which guides the assumptions made
about the variables within a model – Could also refer to it as a “scenario”
• What is an Uncertainty? – A variable which can change from future to future based on the
assumptions made about the variable in the future definition
• Outcome – A fully-characterized set of futures to perform Regional Resource
Forecasting with multiple input assumptions – Scenario based analysis - Different futures yield different “best plans”
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Futures Defines in CARP Process
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Business as Usual Models the Status Quo. This future models the power system as it exists today with values and trends based on recent historical data while preserving existing standards for resource adequacy, existing renewable mandates and environmental legislation.
Federal RPS
Represents a 20% federal RPS. This case will be modeled to meet the federal RPS with wind resources. Wind location will be regional as much as possible including off-shore capability on the east coast. However, this scenario will assume that the Midwest ISO will have sufficient capacity installed to export to other portions of the country.
Carbon Policy with Energy Efficiency
Cap and Trade policy at a mid-level carbon cost and a mid-level cap on carbon production. This would be coupled with increased energy efficiency penetration by lowering the demand and energy growth levels to mid-low or low values.
Federal RPS with increased storage capability
Represents a 20% federal RPS. This case will be modeled to meet the federal RPS with wind resources. Wind location will be regional as much as possible including off-shore capability on the east coast. However, this scenario will assume that the Midwest ISO will have sufficient capacity installed to export to other portions of the country. Storage penetration will allow for XYZ% penetration to help meet the off-peak energy production of the increased renewable wind units.
Smart Grid Includes DR
Increased Demand Resources to twice there current penetrations within the markets as well as reducing demand growth due to price sensitive knowledge base of consumers (this would also include a lesser reduction in energy usage - not all curtailed peak energy will be eliminated, some will see payback during off-peak hours)
Moderate Green Cap and Trade policy at a mid-level carbon cost and a mid-level cap on carbon production. This would be coupled with a 20% federal RPS to be met primarily with wind resources.
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Uncertainty Variables and Values
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Uncertainty Unit Low Mid/Low Mid Mid/High High
Coal Fired Capacity ($/KW) 2,249CC ($/KW) 1,036CT ($/KW) 732
Nuclear ($/KW) 3,626Wind-Onshore ($/KW) 2,101
IGCC ($/KW) 2,599IGCC w/Sequestration ($/KW) 3,820
CC w/Sequestration ($/KW) 2,065Demand Response ($/KW) 0
Storage ($/KW) 0Photovoltaic ($/KW) 6,598
BioMass ($/KW) 4,115Hydro ($/KW) 2,450
Wind-Offshore ($/KW) 4,208Distributive Generation-Peak ($/KW) 1,798
Capital Costs
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Uncertainty Variables and Values - continued
52
Uncertainty Unit Low Mid/Low Mid Mid/High High
Demand Growth Rate % 1.28Energy Growth Rate % 0.5 1 1.51 2 2.5
Demand Response Penetration as % of peak load % 3.31
Energy EfficiencyMid Energy Growth rate
Mid-low Energy Growth rate
Low Energy Growth rate
Gas ($/MBtu)PowerBase+4% annual escalattion
Oil ($/MBtu)PowerBase+4% annual escalattion
Coal ($/MBtu)PowerBase+2% annual escalattion
Uranium ($/MBtu)PowerBase+2% annual escalattion
SO2 ($/ton) PowerBaseNOx ($/ton) PowerBaseCO2 ($/ton) 0 25 50 100
Hg ($/ton) 0 PowerBase
Demand and Energy
Fuel Prices
Emissions
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Uncertainty Variables and Values - continued
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Uncertainty Unit Low Mid/Low Mid Mid/High High
Discount Rate % 6 8 10Inflation Rate % 2 3 6
Uneconomic Coal Retirement
MISO %
RPS requirements repealed as of
2015Existing RPS Requirements
RPS Requirements increased to a
MISO 30% valueNational % 0 10 20 30
CO2 % 0 20 40Carbon Reduction Requirements from Baseline Level
Economic Variables
Wind Penetration as a percentage of total energy delivered
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Futures Matrix
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Carbon
Future CC
CT Coal
Fire
d Ca
paci
ty
IGCC
Win
d O
nsho
re
Nucl
ear
CC w
/Seq
uest
ratio
n
IGCC
w/s
eque
stra
tion
Dem
and
Resp
onse
Stor
age
Phot
ovol
taic
BioM
ass
Win
d O
ffsho
re
Dist
ribut
ive
Gen
erat
ion
- Pea
k
Hydr
o
Dem
and
grow
th R
ate
Ener
gy G
row
th R
ate
Dem
and
Resp
onse
Pen
etra
tion
Ener
gy E
ffici
ency
Gas
Oil
Coal
Uran
ium
SO2
NOx
CO2
Hg Infla
tion
Disc
ount
Rat
e
Unec
onom
ic C
oal R
etire
men
t
MIS
O W
ind
Pene
tratio
n M
anda
te
Nat
iona
l Man
date
% R
educ
tion
Business as Usual M M M M M M M M M M M M M M M M M L L M M M M M M L L M M L M L LAggressive MISO State Only RPS Strategy M M M M MH M M M M MH MH MH M M MH M M L L MH MH ML M M M L L M M ML H L LAggressive Carbon MH MH ML MH MH H MH MH MH MH MH MH M M MH L L L L MH MH ML H M M H L H M H M L MHCap N Trade for Carbon MH MH ML MH MH H MH MH MH MH MH MH M M MH ML ML L L MH MH ML MH M M M L MH M MH M L MCarbon Policy with Energy Efficiency MH MH ML MH MH H MH MH MH MH MH MH M M MH ML L L H MH MH ML MH M M M L MH M MH M L MCarbon Reduction by 2050 M M ML ML MH H MH MH M MH MH M M M MH L L M H H MH L H M M H M H M H H L HCarbon Tax MH MH ML MH MH H MH MH MH MH MH MH M M MH ML ML L L MH MH ML MH M M MH L MH M MH M L LConnect Supply-side and Demand-side EfficiencyFed RPS with Energy Efficiency M M M M H M M M M M M M M M M ML L L H MH MH ML M M M L L M M ML M M LFederal RPS M M M M H M M M M M M M M M M M M L L MH MH ML M M M L L M M ML M M LFederal RPS with increased storage capability M M M M H M M M M H M M M M M M M L L MH MH ML M M M L L M M ML M M LGreen Heaven MH MH ML MH H H MH MH MH MH MH MH M M MH L L L L MH MH ML H H H H H H M H M M HLow Green M M M M M M M M M M M M M M M M M L L M M M M M M ML L M M L M L LLow Renewable M M M M MH M M M M M M M M M M M M L L M M M M M M L L M M L M ML LModerate Green MH MH ML MH MH H MH MH MH MH MH MH M M MH ML ML L L MH MH ML MH M M M L MH M MH M M MMWDRI initiatives M M M M M M M M M M M M M M M ML L H H ML ML M M M M L L M M L M L LSmart Grid Includes DR M M M M M M M M H M M M M M M L M H ML M M M M M M L L M M L M L LVery low demand high energy M M M M M M M M M M M M M M M L H L L M M M M M M L L M M L M L LEnergy Efficiency coupled with the RPS M M M M H M M M M M M M M M M ML L L H MH MH ML M M M L L M M ML H L LState RPS Requirements repealed M M M M L M M M M M M M M M M M M L L M M M M M M L L M M L L L L
UncertaintiesCapital Costs Demand and Energy Fuel Growth Rates Emissions Cost Economic Wind
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Forecast & Economic Models
• EGEAS – Capacity expansion – 1-30 year expansion – Uses hourly load shape – Uses same data as
PROMOD + additional information for capital costs and financial analysis
– Needs long-term load forecast
• PROMOD (energy) – Production cost – Normally run for 1 year
at a time – Chronological – Uses hourly load
shapes and loads for the year being analyzed
– Takes hours to days to run a single year
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Reliability Models
• PSS/E (capacity) – Single hour based off of
market dispatch – Run all contingencies
and monitored elements
– On-peak and shoulder – Run in iterative fashion
with the economic models
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• PSLF – GE power flow • VSAT – voltage
stability • Others
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Overview of Technical Process
• Economic models (EGEAS, PROMOD) depend on a plethora of economic assumptions
• Data sources may vary but the starting point for much of the data comes from two primary sources – Powerbase (commercial product) – EIA (USA government publication)
• This presentation addresses, in more detail, some of the characteristics of the static and uncertainty variables to be used within the models
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Powerbase
• Powerbase is a Database Software from Ventyx • Provides data used within PROMOD, Strategist, and other
related programs • Powerbase contains comprehensive multi year
information on: – Demand & Energy – Generation – Fuel – Effluents
• Default data is updated as desired • Data with updates is used to populate Regional
Resource Forecasting and Production Cost Models • One universal data source allows for consistent
assumptions to be applied to all regions and models
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Powerbase Data Sources
• FERC Form 1, 714 • EIA Forms
860,867,411,412 • ES&D • GADS • EPA • ISO, OASIS Sites • Others
• Data Sources in Columbia ?
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Two (2) Types of Variables
• 1) - Static Variables – Once defined, the values do not change from future to future
• 2) - Uncertainty Variables – The values can change from future to future, and reflect the
definition of a future being modeled
• Following slides will show a proposal for values used within the CARP analysis.
• Values for use in Columbia are unique
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Static Variables
• Study Period • Area Definitions • Demand & Energy • Generation
Resources • Wind Generation • Generation
Retirements
• Existing Generation Data – Fixed Cost – Variable Cost – Unit Maintenance – Forced Outage Rate
• Must Run Status • Firm Interchange • Financial Variables • Reserve Margins
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Study Period
• Regional Resource Forecast Period (EGEAS) – 2010-2029
• Economic Transmission Analysis (PROMOD)
– 2025
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Modeled Regions
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Midwest ISO West
•Alliant East
•Alliant West
•Great River Energy
•Hutchinson Utilities Commission
•Madison Gas & Electric
•Minnesota Power
•Montana Dakota Utilities
•Northern States Power
•Otter Tail Power
•Southern MN Municipal Power
•We Energies (includes UPPC)
•Wisconsin Public Power, Inc.
•Wisconsin Public Service
Midwest ISO Central
•Ameren CILCO
•Ameren CIPS
•Ameren IP
•Ameren UE
•City Water Light & Power
•Duke (Cinergy)
•Hoosier Energy
•Indianapolis Power & Light
•Southern Illinois Power
•Vectren (SIGE)
Midwest ISO East
•Consumers Energy
•Detroit Edison
•First Energy Ohio
•Lansing Board of Water &Light
•Northern Indiana Public Service
•Wolverine Power Supply
MAPP
•Dairyland Power Coop
•MidAmerican Energy Co
•Muscatine Power & Water
•WAPA
* Naming convention for companies is based off the naming convention used in PowerBase
Area Assumptions*: MISO Region
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Area Assumptions* Entergy Region
•Central Entergy •Eastern Entergy •Entergy North •Entergy South •Amite South - New Orleans •NRG Louisiana Generating LLC •Entergy West
* Naming convention for companies is based off the naming convention used in PowerBase
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Demand and Energy • As a static variable, this refers to the value of the
first year demand and energy requirements (the starting point)
• Historically, the MISO has used reported data reported to MISO by each Load Serving Entity
• For EGEAS modeling, the individual company requirements are added together with coincidence factored to get to the sub-regional and regional values
• Powerbase data is used for outside Midwest ISO
regions
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Demand and Energy 2010 Starting Values
Region 2010 DEMAND (MW) 2010 ENERGY (GWh)
Midwest ISO Central 39,118 211,661
Midwest ISO East 39,957 197,103
Midwest ISO West 35,581 181,665
MAPP 9,756 51,564
PJM 140,785 741,108
NYISO 33,667 173,687
ISO-NE 29,201 140,387
TVA 49,108 261,553
SERC 98,833 491,642
SPP 47,755 228,355
Entergy 28,560 146,960
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Generation – 4 possible Status’
• Active – Existing online Generation including committed and uncommitted units. Does not include generation which has been mothballed or decommissioned.
• Planned - a generator which is not online, has a future in-service date, is not suspended or postponed and has proceeded to a point where construction is almost certain, such as it has a signed Interconnection agreement, all permits have been approved, all study work has been completed, state or administrative law judge has approved, etc.
– These units are used in the model to meet future demand requirements prior to the economic expansions
• Future – Generators with a future online date that do not meet the criteria of the “planned” status. Generators with a future status are typically under one of the following categories, proposed, feasibility studies, permits applied, etc.
– These generators are not used in the models but are considered in the siting of future generation.
• Canceled – Generators which have been suspended, canceled, retired or mothballed.
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Generation Assumptions: Wind
• 15% of maximum capacity counts toward reserve margin • 33% capacity factor for existing wind units for EGEAS
Modeling • PROMOD modeling uses NREL data for specific unit modeling
• Regional capacity factors used for EGEAS modeling • PROMOD modeling uses NREL data for specific unit modeling
• Wind mandate requirements are based on energy and energy is based on the Capacity factors of the units and capacity factors are dependent on location – Existing RPS is met in state
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Generation Retirements
• Re-licensing is assumed on all Nuclear Units
• Publically known retirements will be assumed for the study
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Existing Generation Data
• Fixed O&M • Variable O&M • Unit Maintenance • Forced Outage Rate • Fuel Cost • Etc.
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Must Run & Minimum Operating Capacity
• All Coal units are Must Run at minimum operating capacity
• All Nuclear units are Must Run at full load capacity
• All units use the default Powerbase minimum capacity values
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Firm Interchange
• Firm Interchanges: – MISO-MRO Canada: 1,500 MW into Midwest growing to 3,000
MW over study period – ISO-NE – Canada: up to 5,000 MW into New England from
Canadian neighbors by end of study period – All other areas = 0
• Firm Interchange provides resource adequacy contribution to the systems to reduce overall internal capacity needs over time
• Except for the above interchanges, it is assumed that each modeled region will build generation capacity to meet its own resource adequacy needs
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Financial Variables
Rate (%) Composite Tax Rate 39.00 Insurance Rate 0.50 Property Tax Rate 1.00 AFUDC Rate 9.00
• Financial variables are used during the economic calculation process of the EGEAS model
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Reserve Margins
• Midwest ISO – 15 % – Midwest ISO West – 9% – Midwest ISO East – 9% – Midwest ISO Central – 9%
• PJM – 15.5 % • TVA – 15 % • SPP – 15% • ISO-NE – 16% • All Other Areas – 15%
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Uncertainty Variables
• Generator Alternative Data – Cost and Operating data – Book and Operating Life – Expenditure Schedule – Alternative Emission Rates
• Demand & Energy • Fuel Prices • Environmental Allowance Costs • Economic Variables • Wind Penetration • Carbon Reduction
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Generator Alternative Data
• De-Commissioning Costs not Modeled • Fixed O&M has fuel reservation capacity charge for:
– CC $20/kW – CT $5/kW
• No transmission connection charges included
Type Size
Overnight Construction
Cost Fixed O&M
Variable O&M Heat Rate
Lead Time Maint FOR
MW $/kW $/kW-Yr $/MWh Btu/kWh Years Hours % Coal 600 2,249 30.08 5.02 8,740 6 500 5.92 CC 400 1,036 34.64 2.19 6,800 3 467 3.25 CT 160 732 16.97 3.46 10,450 2 401 5.34
Nuclear 1,350 3,626 98.37 0.54 10,434 11 710 2 Wind Onshore 50 2,101 33.11 5.46 - 2 - -
IGCC 550 2,599 42.26 3.19 7,450 6 500 5.92 IGCC/Seq 380 3,820 50.40 4.85 8,307 6 500 5.92 CC/Seq 400 2,065 21.75 3.21 7,493 3 467 3.25
Demand Response 1 Storage
Photovoltaic 5 6,598 12.76 5.46 - 2 Biomass 80 4,115 70.43 7.33 7,765 4 - -
Hydro 500 2,450 14.89 2.66 - 4 - - Wind Offshore 100 4,208 97.78 5.46 - 3 - -
Distributive Generation - Peak 1 1,798 17.52 7.78 9,880 2 401 5.34 * EIA data in 2010 dollars
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Generator Type
Operating Life (Years)
Book Life (Years)
Tax Life (Years)
Coal 60 40 20
CC 30 30 15
CT 30 30 15
Wind 25 25 15
Nuclear 60 40 20
IGCC 30 30 20 IGCC w/Seq 30 30 15
CC w/Seq 30 30 15
Demand Response 25 25 15
Storage 60 40 20
Photovoltaic 25 25 15
Biomass 30 30 15
Hydro 60 40 20
Wind Offshore 25 25 15
Distributive Generation - Peak 25 25 15
Book and Operating Life
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Generator Expenditure Schedule
Year Coal CC Nuclear CT IGCC CC/Seq IGCC/Seq Wind Demand
Response Storage Photovoltaic Biomass Hydro Wind
Offshore
Distributive Generation –
Peak
1 0.02 0.25 0.01 0.5 0.02 0.25 0.02 0.5 1 0.5 0.2 0.2 0.5 0.5
2 0.03 0.5 0.01 0.5 0.03 0.5 0.03 0.5 0.5 0.3 0.3 0.5 0.5
3 0.25 0.25 0.01 0.25 0.25 0.25 0.3 0.3
4 0.3 0.01 0.3 0.3 0.2 0.2
5 0.3 0.01 0.3 0.3
6 0.1 0.02 0.1 0.1
7 0.03
8 0.2
9 0.3
10 0.3
11 0.1
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Alternative Emission Rates SO2 NOx Hg CO2
#/MMBTU #/MMBTU #/MMBTU #/MMBTU
Coal 0.05 0.08 1.22 x 10-6 201
IGCC 0.03 0.06 8.05 x 10-7 195
Nuclear 0 0 0 0
CC 0 0.03 0 120
CT 0 0.03 0 120
Wind 0 0 0 0
CC w/Sequestration 0 0 0 18
IGCC w/Sequestration 0.03 0.06 0 30
Demand Response
Storage 0 0 0 0
Photovoltaic 0 0 0 0
Biomass
Hydro 0 0 0 0
Wind Offshore 0 0 0 0
Distributive Generation - Peak 0 0.03 0 120
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Fuel Prices Applied to Existing Units
• Gas – Indexed price starts at $6 with 4% annual escalation
applied – Each region has a +/- transportation adder to reflect
the delivered cost • Coal
– 2009 Price for each unit with a 2% annual escalation – Each unit has a unique cost that represents the
delivered contracts • Uranium
– $1.07 price with a 2% annual escalation
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Chart of NG Price Growth Options
Natural Gas Forecast Options
$-
$5.00
$10.00
$15.00
$20.00
$25.00
2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032Year
$/M
MB
TU
PowerBase Nomial $ EIA Nomial $ NYMEX Nomial $ 6$ w/ 4% esc Nomial $ Historical
Historical Forecasted
NYMEX Future gas prices pulled on March 3, 2009. NYMEX Future gas prices only available untill 2021. Forecast period from 2022-2030 for NYMEX estimated using the EIA annual escalations.
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Chart of Coal Price Growth Options
Coal Forecast Options
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032Year
$/M
MB
TU
Average PowerBase Coal Basin Nominal $ EIA Average Minemouth Nominal $$1.80 w/ 2% Annual esc Nominal $ Historical
ForecastedHistorical
Average PowerBase Coal Basin price is the average of all coal basin index prices within PowerBase.
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Demand & Energy
• Each region to be studied will have a unique demand and energy growth rates (Some energy growth rates were capped at demand growth rate due to previous stakeholder comments)
Region DEMAND GROWTH
ENERGY GROWTH
Midwest ISO Central 1.24% 1.24%
Midwest ISO East 1.03% 1.00%
Midwest ISO West 1.90% 1.62%
MAPP 1.20% 1.20%
PJM 1.90% 1.65%
NYISO 0.92% 0.77%
ISO-NE 2.27% 1.69%
TVA 2.27% 0.89%
SERC 2.37% 2.04%
SPP 1.34% 1.34%
Entergy 1.80% 1.66%
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Demand Response & Energy Efficiency
• Demand Response is represented by the Interruptible Demand & Direct Load Control in the default Powerbase with adjustments made by individual Stakeholders
• The 2008 level of participation for Demand
Response will be maintained for the 20 year study period as the definition of low values
• Existing Efficiency programs are reflected in the
demand and energy forecasts. Increased energy efficiency will result in a reduction in Energy and Demand Growth for modeling purposes
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Demand Response
300576
893
2772
121
3239
1745
686
50
868
319
2309
-
500
1,000
1,500
2,000
2,500
3,000
3,500
IESO MISOCentralRegion
MISO EastRegion
MISOWest
Region
MRO US PJM SERC SPP ENTERGY NEISO NYISO TVA
Region
MW
DLC Interruptible Load
2008 Interruptible Demand & Direct Load Control
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2008 Interruptible Demand & Direct Load Control
% Demand Response of Peak Load
1.20% 1.46% 2.20%
7.77%
0.75%2.27% 1.82% 1.66%
0.18% 0.00%
4.85%
0.00%1.00%2.00%3.00%4.00%5.00%6.00%7.00%8.00%9.00%
IESO
MISO C
entra
l Reg
ion
MISO E
ast R
egion
MISO W
est R
egion
MRO US
PJMSER
CSPP
ENTERGY
NEISO
NYISO TV
A
Region
% o
f Pea
k L
oad
% DLC % Interruptible Load
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Environmental Allowance Costs
• SO2, NOx, and Hg will use Powerbase allowance costs when applicable
• CO2 may have two costing methodologies • CO2 tax: Applies $/ton to all CO2 production on the
system • Carbon Cap and Trade: Applies an allowance cost
based on the determined future values
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Effluent Cost Charts Effluent Costs
0
500
1000
1500
2000
2500
3000
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025Year
$/to
n
CAIR Annual NOx CAIR SO2
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Economic Variables
• Inflation Rate – Applies to the growth of all costs within the model over time
• Discount Rate – Used for present value calculations – Must be applied at the same rate for all regions – Recommend that this does not change between scenarios
• Uneconomic Coal Retirement – EGEAS has the ability to retire capacity by replacing with a pre-
specified alternative (such as replace coal capacity with nuclear capacity)
– Limitations within the modeling require a few definitions: • What units are candidates for retirement (recommend picking units by a
combination of age and size) • Must have some limit on how much capacity allowed to retire per region
(example: no more than 5,000 MW per region) – Only to be tied with a carbon legislation future
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Wind Penetration
• MISO – Current RPS requirements will be assumed as a mid
level penetration – Increase in RPS requirements can model additional
or strengthened RPS requirements – Can also model reduced requirements as of a certain
date in the future • National
– Determine penetration on a national level – Understanding of impact on Midwest ISO footprint
• Will the Midwest ISO be exporting to remote needs?
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Carbon Cap
• Carbon caps will be applied using the first year economic dispatch carbon production as the baseline and then reduce the cap allowance over time at a linear rate to reach planning period cap reduction
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Generation Siting Methodology
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Siting Software
• Vendor: Ventyx • Velocity Suite - a catch all term for Ventyx’s map and database products • Energy Velocity (EV) - refers to a specific set of map data and tools
designed for the North American energy industry – EV Energy Map – EV Power – Includes New Entrants Data – EV Market-Ops – EV Fuels
• EV Energy Map – Mapping and spatial analysis software • MapInfo – Main software package used for siting analysis.
– Possible to perform regional boundary queries, line length calculations etc. – Also much easier to perform custom layer modifications
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Geographic Data Available
• Power Plants • Transmission Lines • Substations • Railroads • Natural Gas Pipelines • Rivers & Lakes • Urban Areas • Class 1 Lands • Non Attainment Regions • Wind Areas by Class • Satellite Imagery • User proprietary data
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Generation Siting Priority
• Future sites (Queue Generators without a signed IA, etc) – Permitted – Feasibility – Proposed
• Brownfield sites which are expandable • Retired sites • Greenfield Sites
– Canceled – Postponed
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Generation Siting Priority: Brownfield Sites
• Existing Coal – Only consider Existing/Planned sites that are greater than 200 MW – Only consider sites outside the 25 mi buffer of a major urban area – Check Global Energy Database for Original Design for Expansions
• CC – Only consider Existing/Planned 200MW sites built since 2000 – Limit Maximum size of CC to be no greater than 800 MW (Consider 100-500MW to expand) – Expand in 300 MW increments
• CT – Use 100MW sites built since 1990 – Prefer sites Near Urban Areas REG Case – No Greenfield CT’s – use all Brownfield
• Nuclear
– Use sites which have been identified as potential expansions first – Then use existing brownfield – Re-define Reference future to include Proposed nuclear!!
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Brownfield Criteria
• Wind – Reference Future will site wind within states with existing
mandates which will be carried forward to all futures – Although states may not have requirement for siting wind within
the state, try to site mandated wind within the state – States with goals/proposals will try to be sited within the states in
the 20% & 30% Wind futures – Work with DOE on identifying “preliminary” maximum potential
by state including offshore potential – Focus on Queue Sites – Nebraska, IA & SD are high wind but little queue – When Siting wind for 20/30%, use some weighting for
Capacity Factors/existing & Queued Gen for siting
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Siting: General Methodology
• Transmission is not an initial siting factor, but may be used as a weighting factor all things being equal
• Site by region with the exception of wind • “Share the Pain” mentality. Not all generation in a region
can be placed in one state and one state cannot be excluded from having generation sited.
• Site baseload units in 600 MW increments, & Nuclear at 1,200 MW
• Limit the total amount of expansion to an existing site to no more than an additional 2,400 MW
• Restrict greenfield sites to a total size of 2,400 MW
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Greenfield Siting Criteria: Coal and IGCC
• Required Criteria “Must Haves”: – Within 1 mile of railroad or navigable waterway – Within 1/2 mile of a major river or lake – Outside 20 mile buffer of Class I lands – Outside air quality non attainment region – Outside 25 mile buffer surrounding an major urban area (a
population greater than 50,000 and an area larger than 25 mi2) • Optional Criteria “Like to Haves”:
– Within 20 miles of coal mine or Dock capable of producing more than 2 million tons per year.
– Access to gas pipeline – Multiple railroad lines – MN and WI prefers build for minimum coal need – IL, IN, ND, SD, KY want to build coal
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Greenfield Siting Criteria: CC
• Required Criteria “Must Haves”: – Within 1 mile of railroad or navigable waterway – Within 2 miles of a major river or a lake – Within 10 miles of a gas pipeline – Outside 20 mile buffer of Class I lands
• Optional Criteria “Like to Haves”: – Close to Urban Area (Within 25 mile buffer)
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Greenfield Siting Criteria: CT
• Required Criteria “Must Haves”: – Within 20 miles of railroad or navigable waterway – Within 5 miles of a gas pipeline – Outside 20 mile buffer of Class I lands
• Optional Criteria “Like to Haves”: – Within 1 mile of river or navigable waterway – Within 2 miles of a major river or a lake
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Greenfield Siting Criteria: Wind
• Required Criteria “Must Haves”: – Follow 80/20 rule: 80% of wind sited in areas of
Class 3 wind speed or greater and 20% can be sited at Class 2 or greater at 50 meters, and no sites in areas less than class 2
– Outside 10 mile buffer of Class I lands – Outside 25 mile buffer surrounding an major urban
area • Optional Criteria “Like to Haves”:
– Within 20 miles of railroad or navigable waterway
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Greenfield Siting Criteria: Nuclear
• Use Existing or Proposed Sites only • Work with regions to site nuclear • All States considered • States with Restrictions on New Nuclear Build
– Minnesota – Wisconsin – Kentucky
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End Appendix A
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Development of Multi Value Project Portfolio
Example of Regional Transmission System Planning
106
Appendix B
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The Road to the First Multi Value Project Portfolio
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2005
2006
2007
2010
Board of Directors Guiding Principles
2008
Value-Based Planning Process
MTEP 06 Energy Market Planning Analysis
Joint Coordinated System Plan
2009
FERC Order 890
6 States in MISO have Renewable Portfolio Standards
10 States in MISO have Renewable Portfolio Standards
Regional Generation Outlet Study I
Regional Generation Outlet Study II OMS Cost Allocation and Regional Planning Work Group Created
Multi Value Project FERC Order Candidate Multi Value Project Portfolio Analysis
2011
FERC Order 1000
Multi Value Project Tariff Development
Upper Midwest Transmission Development Initiative Created
Midwestern Governors Association supports Energy Zones Methodology
2003 MTEP03 Exploratory Study
MTEP 05 Exploratory Study
First Multi Value Project Portfolio approved by BOD
Explorations of the policy, processes, and transmission solutions required to provide the best value for consumers began in 2003
MISO Governors request Generation Interconnection Queue Reform
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Policy Consensus Current State Renewable Portfolio Standards As of 07/27/2011
Planned and Existing Wind as of 3/28/2011
• MISO believes an informal
consensus has been reached regarding appropriate planning for energy policies.
• This belief is based on the widespread implementation of Renewable Portfolio Standards across the MISO footprint and the work of many stakeholders, spearheaded by the: Midwest Governor’s
Association Upper Midwest Transmission
Development Initiative Organization of Midwest ISO
States Cost Allocation and Regional Planning
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This methodology resulted in a set of energy zones used as the locations for incremental generation in continuing analyses
109
These energy zones were created by balancing relative wind capacities along with distances from natural gas pipelines and existing transmission infrastructure
Natural Gas Pipelines and Incremental Energy Zones
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To meet the MISO planning goal of providing consumers with access to the lowest cost electric energy, analyses were performed to determine the costs associated with different wind generation siting methodologies
The low cost approach to wind generation siting, when both generation and transmission capital costs are considered, is a combination of local and regional generation locations.
110
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• Objective of value based planning is to develop the most robust plan under a variety of scenarios – not the least-cost plan under a single scenario – The “best” transmission plan
may be different in each policy-based future scenario
– The transmission plan that is the best-fit (most robust) against all these scenarios should offer the most future value in supporting the future resource mix
MISO Value Based Planning
STEP 6: EVALUATE CONCEPTUAL TRANSMISSION
FOR RELIABILITY
STEP 5: CONSOLIDATE & SEQUENCE TRANSMISSION
PLANS
STEP 7: COST ALLOCATION ANALYSIS
STEP 4: TEST CONCEPTUAL TRANSMISSION FOR
ROBUSTNESS
STEP 3: DESIGN CONCEPTUAL TRANSMISSION OVERLAYS BY
FUTURE IF NECESSARY
STEP 2: SITE-GENERATION AND PLACE IN POWERFLOW
MODEL
STEP 1: MULTI-FUTURE REGIONAL RESOURCE
FORECASTING
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Summary of MVP Portfolio Initiative
• Used the MISO 7 Step Value Based Planning Process.
• Started with the Futures developed in the Multi-Regulatory Collaboration example in Appendix A
• Regulatory decision makers were part of the process and had significant involvement
• 35,000 MISO staff engineering man-hours over a 4 year period required to achieve the results
• Outcome – 17 new transmission projects developed as a portfolio.
• $5.2 billion • Benefits exceed costs for
all MISO regions
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MISO Multi Value Portfolio
113
Multi Value Project Portfolio
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Multi Value Projects create a variety of economic benefits
114
Con
gest
ion
and
F
uel S
avin
gs
1
Ope
ratin
g
Res
erve
s
2
Tra
nsm
issi
on
Lin
e Lo
sses
6
Sys
tem
P
lann
ing
R
eser
ve
Mar
gins
5
Fut
ure
T
rans
mis
sion
Inv
estm
ent
4
Tota
l Ben
efits
Increased Market Efficiency Deferred Generation
Investment Other Capital Benefits
Win
d Tu
rbin
e
Inv
estm
ent
3
Tota
l Cos
ts
(Sum
of A
nnua
l R
even
ue
Req
uire
men
ts)
Net
Ben
efits
Benefit by Value Driver (20 to 40 year present values, in 2011$ Million)
$12,404- $40,949 $28-$87
$1,354-$2,503
$1,023-$5,093 $111-$396
$226-$794
$15,540- $49,204
$8,789- $16,407
$6,750- $32,797
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Multi Value Projects create benefits that are spread across MISO in a manner commensurate with costs
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MISO Local Resource Zones
1.6 – 2.9
2.0 – 3.3 1.6 - 2.8 1.8 - 2.8 1.8 - 3.2 1.8 - 3.0 1.7 - 3.0
Zone 1: MN, MT, ND, SD,
Western WI
Zone 2: Eastern WI and Upper
MI
Zone 3: IA
Zone 4: IL
Zone 5: MO
Zone 6: IN, KY, OH
Zone 7: Lower MI
Benefit/Cost Ratio Ranges Local Resource Zones
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End Appendix B
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Renewable Energy Generation Optimization – With Hydro
Example of Regional Transmission System Planning
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Appendix C
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Study Drivers
• The variable and non-peak nature of wind creates integration challenges within MISO. – 13GW wind online, 17GW active wind projects in Queue
• Manitoba Hydro (MH) system can be considered as a super-sized pumped storage plant: – Very low minimum load – Very fast ramping rate
• Stakeholders requested MISO to study the potential of MH system. – 5,500MW existing generation, 4,500MW winter peaking demand – 1,850MW export capability to MISO – 2,230MW new hydro generation in next 15 years
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Study Objectives
• Model and benchmark hydraulic energy in PLEXOS tool • Investigate alternative ways of using the existing transmission
between MH and MISO – Enable bi-directional RT market participation through EAR
• Evaluate the benefit of potential transmission expansion options between MH and MISO – Impact will include both generation and transmission expansion
within 15-20 years horizon – Evaluate impact on operating reserve requirements
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Scope of Work
120
Phase 1: Data collection, Model Building and validation of MH system operation
Phase 2: Evaluate the impact of MH existing hydro system with expanded market participation through MH external asynchronous resource (EAR)
Phase 3: Determine the value of increasing hydro storage and transmission to deliver the increased energy in conjunction with MISO wind
Phase 4: Sensitivity and Risk Assessment leading to Recommendations
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HVdc
System Map Total Installed Capacity ~5500 MW 6 Groupings
Jenpeg
Selkirk Brandon
Grand Rapids
Limestone
Long Spruce Kettle
Laurie River
Kelsey
Pine Falls Great Falls McArthur Falls Seven Sisters Pointe du Bois Slave Falls
Lake Winnipeg
Southern Indian Lake
Split L.
Stephens L.
St. Leon
Wuskwatim
St. Joseph
Dispatchable Hydro
Dispatchable Hydro
Energy Input Hydro
Energy Input Hydro Energy Input Thermal Energy Input Wind
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Methodology
• PLEXOS will be the primary simulation tool for this study. • Hourly and 5-min simulation will be performed to evaluate the
impact on energy and reserve market. • 3 hydrologic conditions and appropriate MTEP futures will be
considered as sensitivities. • Decision tree will be used to calculate the potential benefit. • A Technical Review Group (TRG) will advise on study
methodology, verify the models, design the solutions and review results.
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Deliverables
• The deliverables of the study include: – The economic potential of MH’s existing system with expanded
market participation. (Year 2012) – The benefit of potential MH generation/transmission expansion
to both MISO and MH. (Year 2027) – Best-fit transmission expansion options between MH and MISO
• Benefits including but not limited to:
– Production cost reduction – Load cost reduction – Operating reserve cost reduction – Wind energy curtailment reduction – Thermal generator cycling changes
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Phase I Summary
• Successfully simulated the complex structure of the MH water storage system
• Successfully simulated the DA practices of the MISO market with MH participation
• RT wind and load profiles were created based on their historical DA/RT divergence patterns
• The simulation of MH’s RT participation yields reasonable results – Tiered bidding method is implemented – Lowest export price is used in the RT tiered bidding.
• Showed both MISO and MH benefit from MH dynamic RT participation
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Phase 2 Summary • Objective: Evaluate the value of expanding MH’s real time market
participation through the External Asynchronous Resource (EAR) product.
• Key model improvements: – DA/RT interleave method – Incorporating Value of Water in Storage (VWS) curve in DA/RT
market simulations
• Key findings: – With extended EAR participation, MISO has lower production
costs/load payment. – The model improvements ensure the accurate representation of
hydro system’s market operations.
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Phase II Modeling Challenges
• Simulate the DA/RT divergence – RT activities have impacts on future DA simulation – Deviation from the DA schedule affects the bid price for the next
day – Deviation from the DA schedule affects the water storage level
for the next day
• Consider the opportunity cost of water in storage in the simulation
• Develop a method to model the current and expanded EAR
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Model Improvement 1 – Interleave Method
• Previously the model passed data only in a single direction from the DA market to the RT market
• The current model will act more like the MISOs actual market operation, after every DA run, the RT will be simulated and passed into the next day
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Old vs. New (Interleave) Method
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Model Improvement 2 - Value of Water in Storage (VWS) Curve • Previously used a daily storage target developed by looking at
long term market activity along with predicted water inflows
• Now a VWS curve is developed with the same information, but isn’t locked into a day by day limit, which is closer to MH’s actual market operation
• The VWS curve is used to create a daily price for water with which MH can participate in the DA market
• Gives the long term opportunity cost for the water
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The Storage Link
130
Price
Stor
age
Volu
me
Top of reservoir
Bottom of reservoir
• Continuous linkage between the
current use and future use through storage
• Value of Water in Storage
(VWS) is the mechanism that maintains the linkage
• Relationship between end of day storage level and the marginal future value of the resource
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131 Price
Wat
er in
S
tora
ge
Average
For multiple configurations
. . .
…end of current period
Now (Modeled) Future
Future (MH Modeled Separately)
Defining Value of Water in Storage
• Evaluate the future net benefit contribution of individual storage segments for a configuration
• Future context, with a variety of input configurations develop an expected VWS relationship
Storage Segments
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Flowchart for PLEXOS Interleave Simulation
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Daily Cycle
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External Asynchronous Resource (EAR)
• Asynchronous DC tie between MH and MISO
• MH’s Lower Nelson River generation
• Energy, Regulation, Contingency Reserves
• Dispatched by MISO • MH only allowed to sell through
the EAR • Price-MW offers (and bids*) in Day
Ahead and Real Time * Pending implementation bi-directional EAR
MISO Control Room Carmel, Indiana
HVDC Jenpeg
SelkirkBrandon
Kelsey
LakeWinnipeg
Southern Indian Lake
Split L.
St. Leon
Wuskwatim
St. Joseph
Lower Nelson R. Generation
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Phase 3 Introduction • Objective:
– Evaluate the benefit of transmission options that connect MH hydro generation to MISO market.
• Approach: – Use MTEP12 2027 Powerbase database as the starting point
with 28GW wind in MISO
– Add additional 2,300MW hydro generation in Manitoba Hydro in the base case
– TRG to recommend transmission options to be studied
– Perform PLEXOS simulation to determine the value of transmission options
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Renewable Energy Generation Optimization – With Hydro
Example Regional Transmission System Planning
135
End of Appendix C
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