opsi midwest iso planning & cost allocation972 15,600 8,400 6,000 3,600 10,800 4,163 6,000 2,400...

OPSIOPSIMidwest ISO

Planning & Cost Allocation

Charleston, WV,April 7, 2010

Midwest ISO Reliability Footprint

2

Midwest ISO provides a variety of valued services to the Midwest Regionthe Midwest Region

What We Do Implications

Provide independent transmission system access

>Equal and non-discriminatory access>Compliance with FERC requirements

Deliver improved reliability coordination through efficient market operations

>Improved regional coordination>Enhanced system reliability>Lowest cost unit commitment, dispatch, and congestion management

Coordinate regional planning>Integrated system planning>Broader incorporation of renewables

Foster platform for wholesale energy markets

>Encouragement of infrastructure investments>Facilitation of regulatory initiatives

3

The Midwest ISO 2009 Value Proposition

Benefit by Value Driver1(in $ millions)

$4-$7

$58-$72$249-

$311

$1,210-$1,558

$184-$194

$932-$1,146

$217-$272

$76-$81 ($250)

$682-$896

$199-$213

$210-$264

$263-$394

$ 3

Benefits Driven byL d / S l B l$394 Load / Supply Balance

Impr

oved

R

elia

bilit

y

Dis

patc

h of

En

ergy

Unl

oade

d C

apac

ity

Reg

ulat

ion

Spin

ning

R

eser

ves

Foot

prin

t D

iver

sity

Dyn

amic

Pr

icin

g

p

Dire

ct L

oad

Con

trol

-In

terr

uptib

les

Gro

ss B

enef

its

Net

Ben

efits

Mid

wes

t ISO

C

ost S

truc

ture

pGen

erat

or

Ava

ilabi

lity

Impr

ovem

ent

Adj

uste

d N

et

Ben

efits

1Figures shown reflect annual benefits and costs that can be expected in 2009

1 2 3 4 5 7 9

I

10

G C

6

Market – Commitment and Dispatch

8

Generation Investment Deferral

Demand Response

4

Electric System Development – Historical View

• Traditional Electric System Development (Generation and Transmission)– Planned at a single company levelg p y– Designed for single company use– Funded at company / state level

• Decision basis– Meet local requirements (i.e., load growth)– With local natural resourcesWith local natural resources– Few national policy issues – Limited regional use

• Last major build out of base-load capacity and transmission ended in the early 1980s

5

Xcel Energy Transmission

6

GRE Transmission System

Integrated with:

XcelMinnesota Power

Voltage Mileage

69 kV or less 2,952Otter Tail PowerAlliant

69 kV or less 2,952115 kV 306161 kV 52230 kV 498345 kV 92500 kV 70

Total AC transmission 3,970±400 kV DC 435

Total transmission line 4,405

Original investment $617,138,038Net book value $336,103,516$ , ,

as of 12/31/01

7

Regional Transmission

8

Midwest ISO Transmission Map

9

Drivers

• Energy Independence• Energy Independence

• Climate Change

• Green House Gas Reductions

• Carbon Free Electricity

S t G id• Smart Grid

10

The “Otter Tail Problem”

RPS

RPS

RPS

800 MW Load800 MW Load

10 000 12 000 MW G ti10,000 – 12,000 MW Generation

11

TomorrowTomorrow

Today

Coal Nuclear Natural Gas Wind Demand Response

Coal Nuclear Natural Gas Wind Other

12

Yearly Hourly Avg Load Vs WindS t b 2007 A t 2008

Operational Issues must also be addressedSeptember 2007 - August 2008

64 000

67,000

70,000

720

750W

ind

58,000

61,000

64,000

Load

(MW

)

660

690

d Generation (M

W

LoadWind

52,000

55,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

H

600

630

W)

Hour

Mismatch between wind and load profile, coupled with the lack of wind dispatch flexibility, results in:

• Additional on-line capacity needed to follow changes in both wind output d l dand load

• Commitment of quick-start capacity to maintain adequate ramp• Minimum generation events when load is low and wind output high

13

MIDWEST ISO PLANNING APPROACH

14

Midwest ISO Planning Objectivesg j

FundamentalGoal

The development of a comprehensive expansion plan that meetsreliability needs, policy needs, and economic needs

• Make the benefits of a competitive energy market available to customers by providing access to the lowest possible electric

y , p y ,

customers by providing access to the lowest possible electric energy costs

• Provide a transmission infrastructure that safeguards local and regional reliability and supports interconnection-wide reliability

• Support state and federal renewable energy objectives by planningMidwest ISOBoard of Support state and federal renewable energy objectives by planning

for access to all such resources (e.g. wind, biomass, demand side management)

• Provide an appropriate cost allocation mechanism• Develop a transmission system scenario model and make it

Board ofDirectorPlanningPrinciples

p yavailable to state and federal energy policy makers to provide context and inform the choices they face

15

Planning Model Evolution

In order to achieve its planning objectives , the Midwest ISOhas transformed its transmission expansion planning model;

Reliability-Based Model Value-Based Model

this process will continue to mature as experience is gained

e ab ty ased ode

• Focused primarily on grid reliability • Typically considers a short time

horizon

Value Based Model• Focused on value while maintaining

reliability• Reflects appropriate project timeo o

• Seeks to minimize transmission build

scales • Seeks to identify transmission

infrastructure that maximizes value• Identification of the comprehensive

value of projects

16

Planning Cycles

• Short-Term– 5 year NERC Reliability Standards (10 yr screens)

Mid T• Mid-Term– Targeted studies to address specific topics of concern in the 5-10

year horizon (Regional Generation Outlet, Top Congested Flow Gates etc )Gates, etc.)

• Long-Term– 10-20 year Economic (value-based) studies required by FERC

O d 890Order 890– Joint Coordinated System Plan

Midwest ISO Transmission Expansion Plan (MTEP) Report is an annual snapshot of current planning status and results of all completed planning studies

17

Relationship of Planning Tools

MTEP

Long-termEconomicSt di

Short-termReliabilitySt di Studies

TargetedStudies

Studies

Project Identification by:Midwest ISO Transmission OwnersLoad Serving Entities Other StakeholdersLoad Serving Entities Other StakeholdersSub Regional Planning Meetings

Note that the MTEP Report itself is a annual snapshot of all of these planning activities 18

Transmission Projects in MTEPj

• Appendix A– Transmission projects recommended (annually) to the Board of

Directors for Construction• Appendix B

– Transmission projects for which a need has been identified but project has not been fully studied and/or alternatives evaluated

– Transmission projects for which a need has been identified, and h b f ll tt d b t f h i th f t th thave been fully vetted, but are far enough in the future that approval is not yet required

• Appendix C– Conceptual projects; ideas to solve specific problems for which

further evaluation is necessary to build business case

19

Midwest ISOMidwest ISO Transmission Expansion Plan

2009 Summary

20

New Appendix A Project Summary

MTEP09 contains 274 new projects totaling $903 million in investment

262300

EastCentral

222

131

200

mill

ions

EastWest

116

4034

87

64

3

1

100$, in

m

0BaselineReliability

GeneratorInterconnection

Other RegionallyBeneficial

TransmissionDelivery

Service Project24Number of Projects 27 11 1 0 11 38 96 64 0 0 11 0 0

The 12 Generator Interconnection projects being recommended would enable the connection of 1,294 MW of generation, of which 1,102 is wind

21

Economic Assessment

• The Midwest ISO conducts an annual assessment of planned and proposed (Appendix A and B) projects to determine their ability to provide market congestion benefits

• Although projects in MTEP 09 Appendices A and B are primarily driven by reliability they are expected to provide economic benefitsdriven by reliability they are expected to provide economic benefits– Market Congestion savings of nearly $1 billion annually beginning in

2014• Equivalent to a 1 2 Benefit to Cost ratio based on cost of the modeledEquivalent to a 1.2 Benefit to Cost ratio based on cost of the modeled

transmission projects and a 20% annual revenue requirement– Value associated with deferring the construction of a 123 MW

generating plant, due to a reduction in capacity losses, will provide an additional benefit of $90 - $166 million

– 2.1 million ton decrease in carbon emissions in 2014

22

MTEP09 Futures Overview

• Reference Future– assumes future economic and political conditions remain consistent

with the recent past – Includes State RPS mandates as of Jan. 1, 2008 (approx. 15,000 MW)

• Renewable Future – assumes that 20% of the energy consumed in the Midwest ISO by 2024 gy y

will be supplied by Wind

• Environmental Future – assumes that starting in 2010 a $25 per ton cost will be added to CO2 g p

emissions escalated at inflation and a 25% higher mercury cost– Annual energy growth rate is reduced by 25%

• Gas Future– restricts future capacity additions to gas generators sited near load – Includes same regional wind generation sited in Reference Future

23

Rate Impacts of Future Scenarios12

2.110 73 0 55

0.78

0.72

8.418.67 8.70

9.56

10.30

10

12

2 40

2.21 4.02

2.11 2.112.11

2.110.58 0.73 0.55

2.11

6

8

ents

/kw

h (2

009$

)

3.14 3.422.89

4.463.46

2.57 2.40 3.15

2

4

ce

0Midwest ISO Current

Retail RateReference Future Gas Future Renewable Future Environmental Future

Generation Capital Generation Production Distribution Transmission

• The impact to rates of the various scenarios is expected to range from 3.1% for the Reference Future to 23.2% for the Environmental Future• Which impact is ultimately experienced by consumers is a function of which energy policy, or combination thereof, is ultimately pursued

24

Stakeholder Forums

• Subregional Planning Groups (East, Central, West)g g p ( , , )– Localized input of issues– Localized review of analyses and alternatives

• Planning Subcommittee– Consolidated technical review of Subregional

input/recommendationsinput/recommendations

• Planning Advisory CommitteePolicy level input and advice on planning issues– Policy level input and advice on planning issues

25

VALUE BASED PLANNINGVALUE BASED PLANNING

26

Process Inputs Bottom-up Plans from Transmission Owners

Short Term

• Documents and validates the need and sufficiency ofDocuments and validates the need and sufficiency of transmission projects identified by the member Transmission Owners

• Ensures plans:– Are sufficient to address reliability standards– Form an efficient set of expansions to meet identified needs– For cost shared projects, meet need criteria

R i l t h i k lid ti f b tt• Regional cost sharing makes validation of bottom-up developed plans increasingly important

27

Long-Range Planning:T D ViTop-Down View

T t ff ti f i t l• Test effectiveness of input plans

• Develop solutions for outstanding needs– Example: studies to address the required

transmission to meet Renewable Portfolio Standards

• Seek to combine input local plans into more efficient regional plans

28

MTEP 09 Generation Expansion

Generation Name plate Expansion 2008-2024

94,032100,000

p

1,184

1,184

74,432

70,000

80,000

90,000

(MW

)

8 400 12 000

12,000

42,000

64,000

12,000

12,000 12,0001,184

1,184 1,1841,184

50,43250,432

49,232 40,832

40,000

50,000

60,000

amep

late

Exp

ansi

on (

12,048 12,048 12,048 12,0483,972

15,6008,400 6,000 3,600

10,800

4,163

6,000

2,400

12,000

8,400

10,80010,800 6,000

12,000 13,200

12,048 12,0482,235 374

1,305

12,048

0

10,000

20,000

30,000Na

0

Midwes t ISO BaseLine/Planned Queue

Midwes t ISOR eference

Midwest ISO 20%Mandate

Midwest ISO 30%Mandate

Midwest ISOEnvironmental

Midwes t ISO Lim itedInves tm ent

Midwes t ISO Gas Only

Queue/Planned Coal Nuclear CC CT Wind IGCC IGCC/Seq DR

29

Conceptual Progression of Plans

Queue

1 year 20 yearPlanning Horizons

RGOS JCSPJCSP

30

Queue Development Continues with near term upgrades…1 Pl i H i

Queue


31

…Until RGOS Aggregate Plans better informs…1 Pl i H i1 year 20 yearPlanning Horizons

RGOS

32

…Consistent with an inter-regional plan with a longer term view

1 Pl i H i

JCSP


33

Queue Evolution*

3

67

Currently Active:

• 371 Requests representing 66.6 GW

• With Wind representing 321 requests and 55.3 GW

2

5

2

3

3

3

54

552

2326

14

45

22

85

8

2

128

4 8

2005 2006 2007 2008 2009 YTD Current Queue

Wind Coal Natural Gas Nuclear Other7190 131 214 163

# ofRequests

* All requests received as of September 2, 2009 34

Regional Generation Outlet Study Overview

• Develop transmission alternative needed to implement Renewable Portfolio Standards and goals at the least gcost for Midwest ISO consumers while continuing to reliably serve load

• Perform analysis in an open and transparent fashion involving stakeholders throughout

Regulatory involvement through Upper Midwest Transmission– Regulatory involvement through Upper Midwest Transmission Development Initiative and Midwest Governors Association

• Coordinate with neighboring systemsCoordinate with neighboring systems– PJM and MAPP companies within Midwest ISO states involved

directly in process

35

RGOS Overview

• RGOS I focuses on meeting the renewable energy requirements for the states of IA, IL, MN, WI

– Transmission designs in development for• 15 GW and 25 GW of wind injection (345 kV, 765 kV, DC)• 45 GW of wind injection (high level conceptual)

• RGOS II focuses on meeting the renewable energy requirements or goals for the states of MO, IL, IN, MI and OH and incorporates RGOS I design

– Indicative transmission designs developed for three zone scenarios• Local: use only resources within each RGOS II state• Combination: use resources from RGOS I and II states (50/50 split)

R i l l f RGOS I t t• Regional: use only resources from RGOS I states

• Moving forward, RGOS I and II to be combined into a single study

36

RGOS II Zones - Combination

37

RGOS Zones and Transmission – Combination 765 kV Plan

38

Midwest ISO is Actively Engaged in Planning from Regional to National Levels

EIPCScope: Develop comprehensive planning process/group for Eastern Interconnection-wide planning

RGOS IRGOS II,MTEPRGOS Phase I

Participants: 22 Planning Authorities in the Eastern Interconnection

JCSPEWITS

RGOS Phase IScope: Develop transmission for mandates in IA, IL, MN, WI; 11-16 GW, Completion Q4 ’09

Participants: MISO

RGOS Phase IIScope: Develop transmission for mandates in IA, IN, MI, MO, OH; ~23 GW, Completion TBD

MTEP Renewable Scenario

EWITSScope: Operating impacts of JCSP; End of August ’09;stakeholders, regulators,

governors, PJMLead: MISO for MTEP09; UMTIDI (Phase I) and MGA

Who’s Watching: State Regulators, Governor

GW, Completion TBDParticipants: MISO stakeholders, regulators, governors, PJM

Lead: MISO and MGAWho’s Watching: State Regulators, Governor Offices (UMTDI, MGA),

Scope: Develop MISO Transmission: 15-50 GW (20% scenario); on-going

Participants: MISO stakeholders

Lead: MISOWho’s Watching:

JCSPScope: Develop Eastern Interconnect transmission; 50-91 GW (20% scenario)

Participants: MISO, PJM, SPP, TVA, MAPP, Utilities

JCSP; End of August 09; 50-91 GW (20% scenario)

Participants: MISO, PJM, SPP, TVA, MAPP, Utilities, Enernex, Ventyx

Lead: Enernex for Dept. of Energy

Who’s Watching: UtilitiesOffices (UMTDI, MGA), FERC, State Transmission Authorities

( , ),FERC, State Transmission Authorities

gStakeholders Lead: MISO for Dept. of

EnergyWho’s Watching: Utilities, ISOs/RTOs

Who s Watching: Utilities, ISOs/RTOs

RGOS = Regional Generation Outlet StudyMTEP= Midwest ISO Transmission Expansion PlanJCSP = Joint Coordinated System Plan

EWITS = Eastern Wind Integration and Transmission StudyEIPC = Eastern Interconnection Planning Collaborative

40

P d Mid ISOProposed Midwest ISO Cost Allocation Design DraftCost Allocation Design Draft

41

Current Issue

• Introduction of Renewable Portfolio Standards (currently 23 000 MW) hi hli ht d i t t i i t~23,000 MW) highlighted gap in current transmission cost

allocation methodologies– No sharing for regional plans such as the Regional Generation Outlet Study

I iti i t h i th d d f G t I t t P j t– Inequities in cost sharing method used for Generator Interconnect Projects

• In July 2009, Midwest ISO filed a solution which shifted bulk of interconnection costs to the generatorof interconnection costs to the generator– Accepted by the Federal Energy Regulatory Commission in October 2009,

but deemed “interim”– Long-term solution due to be filed July 15, 2010g y

43

State Regulatory Initiatives

• UMTDI:– Upper Midwest Transmission Development Initiative – 5 State initiative (ND SD IA MN WI)– 5 State initiative (ND, SD, IA, MN, WI)– 2 goals by year end 2009

• Regional Generation Outlet Plans to meet RPS’C t All ti f th l• Cost Allocation for those plans

• OMS Cost Allocation and Regional Planning:MISO wide state initiative to evaluate transmission– MISO-wide state initiative to evaluate transmission impacts of future energy policies and develop a cost allocation proposal

– Eye towards impact of existing and possible state and– Eye towards impact of existing and possible state and federal renewable standards, and carbon reduction legislation

44

Timing of Future Transmission Investment Approval

32.7

RGOSPhase III

RGOSPhase IVApprovedINDICATIVE

19 7 20.2 20.7

26.2 26.7 27.2

RGOSPhase II

Approved

Approved

13.2 13.7 14.2

19.7

RGOSPhase I

Approved

7.2 7.7

2006 to 2009

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

MTEP 06 to 09 Total Cost of Approved Projects Annual Reliability Investment Phase‐In of RGOS Overlay

Note: Dates of actual transmission investment approval will vary based on decisions made in the future. 45

Guiding Principles for New Methodology

• Eliminate / minimize free riders• Ensure the “right” loads pay• Reflect changing system usage over timeReflect changing system usage over time• Balance attributes of system use

– Cost causer vs. beneficiaryLocal vs regional– Local vs. regional

– Access (demand) vs. Usage (energy)

A fair cost allocation system to enable transmission development to support renewable integration public policy reliability andto support renewable integration, public policy, reliability and

economic goals while maintaining the Midwest ISO Value Proposition

46

Injection / Withdrawal: A different way of thinking about it

• Hypothesis: Whoever uses the system is who benefits– Can define multiple use types to balance extremes

(i.e. capacity vs. energy, regional vs. local, etc.) and better define which aspects of the system are being usedused

47

Midwest ISO Cost Allocation Proposal

Load

$/MWhRegional

Exports$/MWh

All revenue i t

Regional(Entire Footprint)

requirements associated with I/W qualified future

$/MW

future transmission

Local(23 P i i Z )

Load

$/MW(23 Pricing Zones)Generation

*Some additional exclusions may apply; new generators pay higher of local rate or local new interconnection upgrade cost

48

Midwest ISO Cost Allocation Proposal

• All Appendix A projects post July 15, 2010 will get I/W cost sharing treatment unless that project meets the pre-defined exclusion criteria

Effectively leaves you with Baseline Reliability Regionally Beneficial– Effectively leaves you with Baseline Reliability, Regionally Beneficial and Multipurpose projects (aka overlays)

– Benefit evaluations will be left to the “build” decision process and not a prerequisite for I/W eligibilityprerequisite for I/W eligibility

• Annual Revenue Requirements will be shared through charges at two layers, Regional and Local– The Regional layer will be a usage ($/MWh) charge applied to load and

exports– The Local layer will be an access charge ($/MW) to be shared by

generators and load within a pricing zonegenerators and load within a pricing zone– Generation Interconnection Projects will pay higher of the local portion

of network upgrade costs or local access rate

49

Midwest ISO Cost Allocation Proposal contMidwest ISO Cost Allocation Proposal, cont.

L l d R i l ill b l l t d th h T i i• Local and Regional usage will be calculated through a Transmission Usage Analysis for each branch at three regions (West, Central and East) and at three AC voltage classes plus DC

– Class 1, branches greater than or equal to 100 kV but less than 300 kV,

– Class 2, branches greater than or equal to 300 kV but less than 400 kV

– Class 3, which is branches greater than or equal to 400 kV

– DC lines will be allocated 100% to the Regional Rate

50

Regional Layer

Wh t h l d d ti ?• Why not charge load and generation?– Market efficiency impacts such as those identified in the LECG

reportC• Charging generators provides market to market distortion based on variable charges showing up in LMP

• Charging generators causes issues for standard contracts

– But not charging generators potentially causes free rider problem– But not charging generators potentially causes free rider problem for exports

• How do you address the free rider export issue?• How do you address the free rider export issue?– Cross-Border Cost Sharing with PJM was prior attempt to solve

• Effectiveness has been limited

– File point-to-point export rate• We’ll keep working on longer term solution with less potential distortion

51

Local Layer

• Why charge generators?– Having the generator pay targets the cost at the “right

load” which may be outside the zone Like loads generators receive benefits from the– Like loads, generators receive benefits from the system upgrades such as maintenance of system reliability and increased transfer capability

• What about potentially inefficient retirement decisions?– Will monitor for impacts, with an eye to Module E as

the backstop

52

Generation Interconnection Projects

• Generation Interconnection Projects will pay higher of the local portion of network upgrade costs or local access rate

• Why?– Helps ensure the right load pays

B f th di ti t iti f t i• Because of the disproportionate siting of certain resources, such as wind, the higher of methodology protects the local load

– Mitigates “next project free rider”

53

N t StNext Steps

• Continue to address open issues and refine the proposal based on feedback

• Share remaining sections of the detailed business rules in the coming weeks for stakeholder review and feedbackfeedback

54

Midwest ISOMidwest ISO Long-Term Load Forecasting

55

Long-Term Forecasting Mechanicsg g

• Midwest ISO recognizes that sub-regional and local factors (econometric, others) contribute significantly to the development of accurate long-term load forecasting models

• State requirements for forecasting and Resource Adequacy vary• State requirements for forecasting and Resource Adequacy vary

• LSEs possess best knowledge of key forecast drivers

• Midwest ISO aggregates LSE forecasts and reviews for consistency with expected trends

• Midwest ISO assess each LSE forecast for accuracy compared to• Midwest ISO assess each LSE forecast for accuracy compared to actual peak demand

56

Key Process DriversKey Process Drivers

Mid t ISO Pl i Obj ti• Midwest ISO Planning Objectives– Investment in Generation and Transmission

• Resource Adequacy– Planning Reserve Margin (PRM)– Loss of Load Expectation (LOLE) analysis

• Demand Response

57

Balancing Generation and Transmission Investment

Increased transfer capability, in conjunction with appropriately located generation, could allow for reduced reserve margins, and thus reduced overall cost

Minimum

Minimum Reserve

Margin Limit

Current reserve margins and congestion cost

Today? Goal

and thus reduced overall cost

Total

Cost

($)

Total Cost:, energy,

capacity and transmission

cost

Reserve Margin (%)H L

Transfer Capability (MW) HL

58

Resource Adequacy

• Resource Adequacy Plans are created to help– Ensure reliability, and– Promote investmentPromote investment

• Partnership with state utility commissions

• Midwest ISO establishes PRM through LOLE analysisg y

• LSE demand forecasts set capacity requirements• LSE designate capacity to cover demand forecast plus the PRM• Owned GenerationOwned Generation• Owned Demand Resources• Bilateral Contracts• Voluntary Capacity Auctiony p y• Generation values base on historical performance (unforced

capacity – UCAP)

59

Determination of Reserve ObligationsDetermination of Reserve Obligations

Planning Reser e Margin (PRM) determination• Planning Reserve Margin (PRM) determination– LOLE Study

• LOLE is the expected number of days per year for whichLOLE is the expected number of days per year for which available generating capacity is insufficient to serve the daily peak demand (load).

• One day in ten years or 1 day/yearOne day in ten years or .1 day/year

– PRM Unforced Capacity• Values on next slideValues on next slide

60

Planning Reserve Margin

NON – COINCIDENT LOAD BASED

COINCIDENT LOAD BASED

Basis of PRM PRM UCAP (%) PRM LSEIGEN (%) PRM SYSIGEN (%)

Total PRM2009-2010 5.35 % 12.69 % 15.4 %

T t l PRMTotal PRM2010-2011 4.5 % 11.94 % 15.4 %Load Diversity for 2009-2010 = 2.35%Load Diversity for 2010-2011 = 3.00%ySystem Average XEFORd 09/10 = 6.83 %System Average XEFORd 10/11 = 6.75 %

61

Midwest ISO Demand Response

Midwest ISO employs demand response for:• Economic Demand Response - reduce loads whose values p

to end use customers are less than costs of serving those loads

• Operating Reserves – provide regulation or contingency reserves

E D d R (EDR) d d d• Emergency Demand Response (EDR) – reduce demand during emergencies

Planning Resources Demand Resources (DR) are used to• Planning Resources - Demand Resources (DR) are used to reduce LSE’s capacity obligations

62

Forecast Accuracy Assessment

• LSE peak demand forecasts drive capacity requirements

• Assessment process required to incent accuracy in long-term forecasts provided by the LSE

• Compare forecast to actual peak demand normalized for weather, price and retail choice load shifting

• One standard deviation allowed

• Under forecasts outside of 1 standard deviation are• Under forecasts outside of 1 standard deviation are reported to state authority

63

Benefits of Midwest ISO Model

• Leverages LSE expertise and knowledge of forecastLeverages LSE expertise and knowledge of forecast drivers

• Recognizes states utility commission authority overRecognizes states utility commission authority over Resource Adequacy

• Encourages development of Demand Response• Encourages development of Demand Response

• Incentivizes accurate forecasting through assessment processprocess

64

Appendix Summary

N A di A i MTEP 09 274 j t ti $903 illi• New Appendix A in MTEP 09: 274 projects costing $903 million– Appendix A now contains 576 projects and $4.3 billion in investment for

implementation by 2019

Si th i ti f MTEP i 2003 $7 2 billi i i t t h b• Since the inception of MTEP in 2003, $7.2 billion in investment has been recommended for approval with $2.7 billion of that already in-service.

• Appendices A and B now contain $5.8 billion of investment – $4.3 billion in Appendix A

$1 5 billi i A di B– $1.5 billion in Appendix B

• Appendices A and B now contain 4,530 miles of transmission lines with in-service dates through 2019

2 350 f th il d ti 4 6% f th i ti li il– 2,350 of those miles are upgrades, representing 4.6% of the existing line miles under Midwest ISO functional control

– Remaining 2,150 miles are for new transmission corridors

An additional $35 billion in potential in estment resides in Appendi C• An additional $35 billion in potential investment resides in Appendix C– Some projects may be targeted at addressing same underlying issue– Major contributor to Appendix C is a $14 billion extra high voltage conceptual

transmission overlay

65