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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

2

Note: need David’s review and assistance with slide 10


MISO Overview

3

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


Carmel Indiana – Control Room

4


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

5

• 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

XM Conference, Medellin 12/12/12 XM Conference, Medellin 12/12/12

MISO – Expanded Area December 2013

6


Value Based Planning

Regional Transmission System Planning

Planning Objectives and Principles

7


8

• 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


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

9

• 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


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

10

• 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

11

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 …


Policy consensus

12

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


Value Based Planning Process

13

• 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


Capacity Versus Energy Modeling

14

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


15

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


16


A Holistic Value Based Planning Process for Energy Resources

17







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


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

18


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

19

Narrow and less useful Broad and more useful

Years Years

MW

MW



20







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


Evaluation Process Focuses on Scenario Modeling

21

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


Uncertainty Variables

22

• 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


23


24

Example Siting: Supply Side Resources



25







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


26

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


27

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.


28

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%


29

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%


30

“Copper sheet” calculations provide the magnitude of the flow and existing flow paths as the energy flows according to an unconstrained Energy Market dispatch.


31

Interface Contour: Annual Energy Difference Unconstrained Case Minus Constrained Case (Example)


32

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


33

RGOS Transmission Overlay Strategies

765 kV Solution

Native Solution


34

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



35







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


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



37







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


STEPs 5&6 – Transmission Consolidation and Sequencing

38

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


After additional intensive analysis, the candidate portfolio was refined into a final Multi Value Project Portfolio

39 Multi Value Project Portfolio


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

40


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

41



42







PLANS



ROBUSTNESS




POWERFLOW MODEL


FORECASTING


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

43

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


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


Overview of the Process End of Slides

Agenda Item 7

45


Multi-Regulatory Collaboration

Example Cost Allocation Regional Planning

46

Appendix A


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

47

MISO Process Columbia Process


48

• 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


MISO Value Based Planning

STEP 6: EVALUATE CONCEPTUAL TRANSMISSION

FOR RELIABILITY


PLANS



ROBUSTNESS

STEP 3: DESIGN CONCEPTUAL TRANSMISSION OVERLAYS BY

FUTURE IF NECESSARY

STEP 2: SITE-GENERATION AND PLACE IN POWERFLOW

MODEL


FORECASTING


49

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”


Futures Defines in CARP Process

50

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.


Uncertainty Variables and Values

51

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


Uncertainty Variables and Values - continued

52


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


Uncertainty Variables and Values - continued

53


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


Futures Matrix

54

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


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

55


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

56

• PSLF – GE power flow • VSAT – voltage

stability • Others


57

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


58

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


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 ?

59


60

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


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

61


62

Study Period

• Regional Resource Forecast Period (EGEAS) – 2010-2029

• Economic Transmission Analysis (PROMOD)

– 2025


63

Modeled Regions


64

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


65

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


66

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


67

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


68

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.


69

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


70

Generation Retirements

• Re-licensing is assumed on all Nuclear Units

• Publically known retirements will be assumed for the study


71

Existing Generation Data

• Fixed O&M • Variable O&M • Unit Maintenance • Forced Outage Rate • Fuel Cost • Etc.


72

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


73

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


74

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


75

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%


76

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


77

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


78

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


79

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


80

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


81

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


82

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.


83

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.


84

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%


85

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


86

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


87

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


88

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


89

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


90

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


91

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?


92

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


93

Generation Siting Methodology


94

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


95

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


96

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


97

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!!


98

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


99

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


100

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


101

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)


102

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


103

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


104

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


End Appendix A

105


Development of Multi Value Project Portfolio

Example of Regional Transmission System Planning

106

Appendix B


The Road to the First Multi Value Project Portfolio

107

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


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

108


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


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


111

• 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


MISO Value Based Planning

STEP 6: EVALUATE CONCEPTUAL TRANSMISSION

FOR RELIABILITY


PLANS



ROBUSTNESS

STEP 3: DESIGN CONCEPTUAL TRANSMISSION OVERLAYS BY

FUTURE IF NECESSARY

STEP 2: SITE-GENERATION AND PLACE IN POWERFLOW

MODEL


FORECASTING


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

112


MISO Multi Value Portfolio

113

Multi Value Project Portfolio


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


Multi Value Projects create benefits that are spread across MISO in a manner commensurate with costs

115

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


End Appendix B

116


Renewable Energy Generation Optimization – With Hydro

Example of Regional Transmission System Planning

117

Appendix C


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

118 MSC, 10/2012


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

119 MSC, 10/2012


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

MSC, 10/2012

XM Conference, Medellin 12/12/12 121

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

MSC, 10/2012


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.

122 MSC, 10/2012


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

123 MSC, 10/2012


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

124 MSC, 10/2012


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.

125 MSC, 10/2012


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

126


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

127


Old vs. New (Interleave) Method

128


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

129


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


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


Flowchart for PLEXOS Interleave Simulation

132

Daily Cycle


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

MSC, 10/2012


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

134 MSC, 10/2012


Renewable Energy Generation Optimization – With Hydro

Example Regional Transmission System Planning

135

End of Appendix C

XM S.A. E.S.P.€¦ · XM Conference, Medellin 12/12/12 . Scope of Operations . as of January 1,...

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