1 introduction, scope, context terminology, high-level approach methodology, inputs, assumptions...

1

Introduction, scope, context Terminology, high-level approach

• Methodology, Inputs, Assumptions– Portfolio development– Discounted core– Environmental scoring– PV assessment– Transmission sizing– Timing assessment

• Results

• Next steps for analysis

• Schedule, Summary

Agenda

2

Transmission Bundles (review)

Resources in CREZs are aggregated into transmission bundles in the following order:

1. Existing transmission bundle

2. Minor upgrade bundle

3. New transmission bundle

Discounted core projects given first priority to fill each transmission bundle

Non-core Commercial projects given next priority to fill the New Transmission bundle

Any remaining transmission capacity in the bundle is allocated to the lowest-scoring generic projects

Up to 3000 MW of new transmission allowed for each CREZ

3

Examples of Transmission Capacity Allocation (review)

300

600

1500

400 361

1000

0

200

400

600

800

1000

1200

1400

1600

(1)

Ex

isti

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Tra

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(2)

Inc

rem

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tal

Up

gra

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(3)

Ne

wT

ran

sm

iss

ion

(1)

Ex

isti

ng

Tra

ns

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(2)

Inc

rem

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Up

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(3)

Ne

wT

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Example Buildup 1 Example Buildup 2

Av

aila

ble

Ca

pa

cit

y (

MW

)

Discounted Core Commercial Projects Theoretical Projects

4

Transmission sizing and cost

• Weakness of previous study: assumed no capacity on existing transmission system; upgrades essentially all single or double circuit 500kV lines “trunklines”

• Updates:– ISO high-level assessment of capacity from various CREZs 1.)

over existing system; 2.) over relatively minor new upgrades

– Additional lines on case-by-case basis: 500kV for large and out-of-state zones, smaller lines for smaller zones close to loads. Cost = function of length and capacity

– Incorporation of RETI work has been difficult – many CREZs tied to single line segments; many line segments tied to single CREZs; but additional detail would help in cost and timing review

5

Transmission sizing and cost

• See:– California ISO assessment of capacity over existing system and

minor upgrades

– Zaininger Engineering assessment of capacity over RETI lines

• Available here:

http://www.cpuc.ca.gov/PUC/energy/Procurement/LTPP/ltpp_history.htm


6

Introduction, scope, context Terminology, high-level approach

• Methodology, Inputs, Assumptions– Portfolio development– Discounted core– Environmental scoring– PV assessment– Transmission sizing– Timing assessment

• Results



Agenda

7

33% RPS Implementation Analysis

• Timelines created for the 33% Reference Case – not for any of other 3 cases– Timeline 1: Historical experience, reforms/risk

– Timeline 2: Reforms, no risks

– Timeline 3: Reforms + external risks

• Goal: Better understand the tradeoffs between cost, risk, and time associated with particular procurement strategies

• Identify market and regulatory barriers to renewable development

• Identify solutions and their impacts on achievement of a 33% RPS

8

Example – Aspen Environmental Group research into generation timelines

9

Example – Research into transmission timelines

10

33% RPS Reference Case – Timeline 3

11

Timeline Tool

• Black & Veatch tool under development to automate timing considerations, create scenario timelines and supply curves

• Generic generation scheduling factors according to: – Technology– Project size– Land type– Location

• Generic transmission schedules for several types of lines

• User has ability to change/define inputs and timing assumptions; change default schedules and MW counts based on technology and other factors, etc.

12

Timeline Tool

• Data already incorporated– Contracts approved and pending approval – basic

project information– Proxy projects – RETI, others to be added

• ED staff updating tool for consistency with new scenarios still being added

• See mock-up of tool here:http://www.cpuc.ca.gov/PUC/energy/Procurement/LTPP/ltpp_history.htm


13

Generic generation timing assumptions

• Little change from Implementation Analysis:

Project Type

DevelopmentLength (months)

excludingtransmission

EstimatedCommercialOnline Date

Biogas/Biomass < 50 MW > 50 MW

6272

20152016

Geothermal < 50 MW > 50 MW

4664

20142015

Small Hydro 46 2014

Solar Thermal < 50 MW > 50 MW

5868

20152016

Solar PV < 50 MW > 50 MW

3236

20132013

Wind < 50 MW > 50 MW

3450

20132014

ED Database projects– Filed/approved by

CPUC (public)– Under negotiation

(confidential)

- Per public contract information

- Per generic estimates above

14

Transmission timing assumptions

Transmission ScheduleType

TransmissionPlanning by

CAISO/ POU/WECC(months)

ProjectDescription

Prep byUtility

CEQA/NEPA Review

ByCPUC/POU/

Feds

Final Reviewand Approval

by CPUC/POU/Feds

Final DesignAnd

Construction byUtilities

Total

Existing / Distributed 0 0 0 0 0 0

Typical 18 12 24 4 24 82

Typical - Short 12 6 12 3 18 51

Typical - Long 24 18 24 4 30 100

Long-Distance 24 18 24 6 30 102

Tehachapi 1-3 0 0 0 0 0 0

Tehachapi 4-11 0 0 0 0 24 24

Sunrise 0 0 0 0 24 24

Devers - CO River 0 0 0 0 30 30

15

Building scenario timelines

• Each zone and transmission bundle/increment is assigned to a transmission schedule→ no generation in that bundle is available before transmission

• Non-CREZ, distributed resources, and resources accessing existing capacity not reliant on transmission→ available per contract or generic generation schedule

• Each scenario is assigned an “online date” according to the availability of the last generation resource chosen for that scenario

• No “bottlenecks” considered now; what assumptions are appropriate?

16

Timeline Tool – Features to Come

• Aggregated portfolios for alternative cases presented with summary timelines and yearly generation charts

• Timelines for individual projects available for review

• Project development phases are broken out

Example Only

17

Timeline Tool – Features to come (cont’d)

• Yearly generation charts can be broken out by viability class – high, medium, and low viability

Yearly Generation by Viability

010,00020,00030,00040,00050,00060,00070,000

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Year

GW

h/yr

Low

Medium

High

Unscored

Example Only

18

Introduction, scope, context Terminology, high-level approach Methodology, Inputs, Assumptions

– Portfolio development– Discounted core– Environmental scoring– PV assessment– Transmission sizing– Timing assessment

• Results



Agenda

19

Preliminary Results

20

Environmental Score

-

10

20

30

40

50

60

70

Cost-Constrained

Environmentally-

Constrained

FastestTimeline

Trajectory Case

Commercial Interest Score

-

10

20

30

40

50

60

70

Cost-Constrained

Environmentally-

Constrained

FastestTimeline

Trajectory Case

Cost Score

-

10

20

30

40

50

60

70

Cost-Constrained

Environmentally-

Constrained

FastestTimeline

Trajectory Case

Timeline Score

-

10

20

30

40

50

60

70

Cost-Constrained

Environmentally-

Constrained

FastestTimeline

Trajectory Case

21

Total Net Cost* by Scenario

* Sum of each resource’s net cost, not the same as the portfolio cost calculated in 2009

$2,515

$4,876

$3,084 $3,070

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

Cost-Constrained Environmentally-Constrained

Fastest Timeline Trajectory Case

Bill

ion

s P

er

Ye

ar

22

Cost-Constrained Case: Resources by Type

In-State Out-of-State TotalBiogas 1,271 0 1,271Biomass 938 2,812 3,750Geothermal 8,617 5,022 13,639Hydro 0 48 48Large Scale Solar PV 7,454 864 8,317Small Solar PV 2,027 0 2,027Solar Thermal 2,202 935 3,137Wind 12,808 9,262 22,070Total 35,317 18,942 54,259Out-of-State Share of 33% Target: 25%

All Resources (GWh)

In-State Out-of-State TotalBiogas 181 0 181Biomass 126 378 503Geothermal 1,159 713 1,872Hydro 0 16 16Large Scale Solar PV 3,115 340 3,455Small Solar PV 1,052 0 1,052Solar Thermal 933 400 1,333Wind 4,339 3,354 7,693Total 10,905 5,200 16,105

All Resources (MW)

Project Status GWh MWDiscounted Core 21,213 8,073Commercial Non-Core 15,153 4,529Theoretical 17,894 3,503Total 54,259 16,105

Cost-Constrained Case Score RankCost Score 16 1 Environmental Score 27 4 Commercial Interest Score 33 2 Timing Score 45 2 Total Net Cost 2,515$ 1

23

Cost-Constrained Case: Resources by Location

Resources Selected (GWh)

Average REC Cost

($/MWh)Total (GWh and $Billions) 54,259 $ 2,515 Wyoming RECs 345 27.29$ New Mexico RECs 238 29.27$ Round Mountain 378 31.45$ Palm Springs 537 33.46$ British Columbia RECs 12 35.12$ Nevada N RECs 2,912 35.33$ Solano 995 35.42$ Tehachapi 12,216 38.49$ Imperial 6,733 38.98$ San Bernardino - Lucerne 785 42.58$ NonCREZ 5,557 42.79$ San Diego South 1,449 43.16$ Colorado RECs 3,705 43.81$ Carrizo South 2,092 47.13$ Arizona RECs 737 48.61$ Montana RECs 820 49.73$ Northwest RECs 5,543 50.26$ Nevada C RECs 2,873 53.61$ Utah-Southern Idaho RECs 528 54.11$ Riverside East 2,547 73.69$ Distributed Solar - PG&E 970 75.59$ Alberta RECs 1,230 76.85$ Distributed Solar - SCE 958 102.41$ Distributed Solar - SDGE 99 113.67$

Delivery Type GWh MWExisting Transmisssion 26,035 8,822Minor Upgrades 9,282 2,083New Corridors 0 0Out-of-State RECs 18,942 5,200Total 54,259 16,105

Key Indicators:

Total Solar MW: 5,800

Out-of-State RECs: 25%

Earliest compliance year: 2021

Much less solar than other cases

24

Cost-Constrained Supply Curve

Discounted Core 2020 RPS Net Short

0

5

10

15

20

25

30

35

40

45

0 8 16 24 32 40 48 56 64 72 80 88 96

Cumulative TWh

Ran

kin

g S

core

Biogas Biomass Bundled Transmission Geothermal

Small Hydro Incremental Upgrade Small Solar PV Large Scale Solar PV

Solar Thermal Wind

25

Environmentally-Constrained Case: Resources by Location

Delivery Type GWh MWExisting Transmisssion 25,052 11,020Minor Upgrades 3,046 1,400New Corridors 20,296 8,666Out-of-State RECs 5,865 2,256Total 54,259 23,342

Environmental Case Score RankCost Score 31 4 Environmental Score 18 1 Commercial Interest Score 56 3 Timing Score 52 3 Total Net Cost 4,876$ 4


Environmental Score (0-100)

Total (GWh and Average Score) 54,259 17.83 Distributed Solar - Other 2,852 1.77 Distributed Solar - SDGE 785 3.62 Distributed Solar - SCE 4,596 4.54 Distributed Solar - PG&E 3,280 5.79 Westlands 7,163 10.53 Riverside East 11,192 20.65 Pisgah 7,260 21.22 Remote DG - SCE 348 21.62 Remote DG - Other 283 21.62 Remote DG - PG&E 929 21.62 Remote DG - SDGE 40 21.62 Tehachapi 5,516 23.46 Arizona RECs 737 24.10 Carrizo South 2,092 25.08 Alberta RECs 1,230 26.76 Northwest RECs 1,376 26.76 Montana RECs 820 26.76 Utah-Southern Idaho RECs 191 28.02 Palm Springs 222 29.14 San Bernardino - Lucerne 121 31.91 NonCREZ 1,333 33.71 San Diego South 156 34.08 Nevada N RECs 212 35.26 Round Mountain 226 35.37 New Mexico RECs 238 36.70 Nevada C RECs 1,062 40.79

26

Environmentally-Constrained Case: Resources by Type

In-State Out-of-State TotalBiogas 84 0 84Biomass 938 238 1,176Geothermal 0 212 212Hydro 0 0 0Large Scale Solar PV 22,701 864 23,564Small Solar PV 13,112 0 13,112Solar Thermal 5,474 935 6,409Wind 6,085 3,616 9,701Total 48,394 5,865 54,259Out-of-State Share of 33% Target: 10%

All Resources (GWh)

In-State Out-of-State TotalBiogas 12 0 12Biomass 126 32 158Geothermal 0 30 30Hydro 0 0 0Large Scale Solar PV 9,696 340 10,036Small Solar PV 6,828 0 6,828Solar Thermal 2,333 400 2,733Wind 2,091 1,454 3,545Total 21,086 2,256 23,342

All Resources (MW)


Key Indicators:

Total Solar MW: 19,500 (16,800 PV)



Large-scale remote solar requires new transmission corridors

Remote small-scale PV is the marginal resource – not all is picked

27

Environmentally-Constrained Supply Curve


0

5

10

15

20

25

30

35

40

45

0 8 16 24 32 40 48 56 64 72 80 88 96

Cumulative TWh

Ran

kin

g S

core



Solar Thermal Wind

28

Time-Constrained Case: Resources by Location

Time-Constrained Case Score RankCost Score 20 3 Environmental Score 25 2 Commercial Interest Score 37 3 Timing Score 31 1 Total Net Cost 3,084$ 3

Delivery Type GWh MWExisting Transmisssion 24,224 9,140Minor Upgrades 4,338 1,725New Corridors 0 0Out-of-State RECs 25,697 9,079Total 54,259 19,944

Total (GWh and Average Score) 54,259 30.86 San Diego South 156 9.09 Round Mountain 226 9.09 NonCREZ 3,789 19.73 San Bernardino - Lucerne 710 22.62 Utah-Southern Idaho RECs 528 25.85 Palm Springs 537 27.03 Tehachapi 11,365 27.27 Imperial 2,945 28.15 Nevada N RECs 1,202 28.35 Montana RECs 1,923 28.61 Distributed Solar - PG&E 1,236 29.97 Alberta RECs 2,422 30.21 Distributed Solar - SDGE 173 31.16 Carrizo South 2,092 31.50 Distributed Solar - SCE 1,345 31.78 Northwest RECs 5,694 32.59 Riverside East 3,666 34.27 Wyoming RECs 345 36.36 New Mexico RECs 238 36.36 Colorado RECs 9,837 36.36 Distributed Solar - Other 322 36.37 Nevada C RECs 2,772 39.80 Arizona RECs 737 45.45

29

Time-Constrained Case: Resources by Type

Key Indicators:

Total Solar MW: 8,600 MW



Largest proportion of out-of-state resources

Out-of-state wind is a good resource if time is the only driver


In-State Out-of-State TotalBiogas 202 0 202Biomass 938 238 1,176Geothermal 2,048 3,363 5,412Hydro 79 0 79Large Scale Solar PV 13,515 864 14,378Small Solar PV 3,076 0 3,076Solar Thermal 2,202 935 3,137Wind 6,502 20,297 26,799Total 28,562 25,697 54,259Out-of-State Share of 33% Target: 33%

All Resources (GWh)

In-State Out-of-State TotalBiogas 29 0 29Biomass 126 32 158Geothermal 290 475 765Hydro 26 0 26Large Scale Solar PV 5,630 340 5,970Small Solar PV 1,604 0 1,604Solar Thermal 933 400 1,333Wind 2,228 7,832 10,061Total 10,865 9,079 19,944

All Resources (MW)

30

Time-Constrained Supply Curve


0

10

20

30

40

50

60

70

80

90

0 8 16 24 32 40 48 56 64 72 80 88 96

Cumulative TWh

Ran

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g S

core



Solar Thermal Wind

31

Trajectory Case: Resources by Location

Trajectory Case Score RankCost Score 19 2 Environmental Score 26 2 Commercial Interest Score 0 1 Timing Score 57 4 Total Net Cost 3,070$ 2

Delivery Type GWh MWExisting Transmisssion 25,667 8,839Minor Upgrades 7,786 2,025New Corridors 6,606 1,593Out-of-State RECs 14,201 5,201Total 54,259 17,659


Commercial Interest Score

(0-100)Total (GWh and Average Score) 54,259 0.21 Arizona RECs 737 0.00 Riverside East 2,547 0.00 New Mexico RECs 238 0.00 Pisgah 218 0.00 Alberta RECs 2,422 0.00 Round Mountain 226 0.00 Palm Springs 222 0.00 NonCREZ 6,502 0.00 Nevada C RECs 1,415 0.00 Nevada N RECs 212 0.00 San Bernardino - Lucerne 170 0.00 Tehachapi 12,024 0.00 Distributed Solar - PG&E 970 0.00 Montana RECs 820 0.00 Imperial 11,903 0.00 Northwest RECs 5,742 0.00 Solano 878 0.00 Colorado RECs 1,301 0.00 Utah-Southern Idaho RECs 528 0.00 San Diego South 1,250 0.00 Distributed Solar - SCE 958 0.00 British Columbia RECs 442 0.00 Wyoming RECs 345 0.00 Distributed Solar - SDGE 99 0.00 Carrizo South 2,092 5.34

32

Trajectory Case: Resources by Type

In-State Out-of-State TotalBiogas 1,292 0 1,292Biomass 938 250 1,188Geothermal 10,564 864 11,428Hydro 79 478 557Large Scale Solar PV 7,897 864 8,760Small Solar PV 2,027 0 2,027Solar Thermal 4,232 935 5,167Wind 13,029 10,810 23,839Total 40,059 14,201 54,259Out-of-State Share of 33% Target: 20%

All Resources (GWh)

In-State Out-of-State TotalBiogas 184 0 184Biomass 126 34 159Geothermal 1,496 122 1,618Hydro 26 156 182Large Scale Solar PV 3,289 340 3,629Small Solar PV 1,052 0 1,052Solar Thermal 1,800 400 2,200Wind 4,485 4,149 8,634Total 12,458 5,201 17,659

All Resources (MW)

Project Status GWh MWDiscounted Core 22,395 8,494Commercial Non-Core 31,753 9,114Theoretical 112 51Total 54,259 17,659

Key Indicators:

Total Solar MW: 6,800 MW



Most balanced scenario

Very few generic projects

33

Trajectory Case Supply Curve

Discounted Core

2020 RPS Net Short

0

10

20

30

40

50

60

70

0 8 16 24 32 40 48 56 64 72 80 88 96

Cumulative TWh

Ran

kin

g S

core



Solar Thermal Wind

34



Results



Agenda

35

IOU-specific allocations

• To provide direct input into 2010 LTPP, statewide portfolios will need to be “allocated” each IOU.

• Proposed approach:– Remove any POU resources from each portfolio;– Allocate public ED database projects to the IOUs with which

those projects have signed contracts (PUBLIC);– Allocate confidential ED database projects to the IOUs with

which those projects are negotiating contracts (CONF.);– Allocate generic projects to load on a pro-rata basis for each

resource type in each zone (PUBLIC);– Aggregate each IOU’s contracted, short-listed and generic

project allocations to generate IOU-specific RPS portfolios (PUBLIC, provided the aggregation sufficiently masks the confidential data).

36

Integration assessment

• California ISO developing model that estimates integration needs and costs associated with 33% Reference Case from 2009 Implementation Analysis

• PG%E has developed Renewable Integration Model (RIM) tool – not as analytically comprehensive, but simpler and spreadsheet-based.

• Tools may be introduced into LTPP proceeding later this year. Possible next steps:– Parties vet methodologies and results– Models are re-run to estimate integration needs of final RPS

scenarios adopted in Scoping Memo– Results inform Commission consideration of the amount and

types of resources to authorize in 2010 LTPP

37

Capacity Credit for Solar Resources

38

Overview

PG&E and CAISO integration studies are considering capital costs of resources needed for intermittent renewable resource integration in addition to variable costs of increased operating reserves

Capital costs driven by assumptions about how much capacity would already have been online during the planning year

Online capacity is a function of Planning Reserve Margin

For intermittent renewables, Net Qualifying Capacity (NQC) is used to estimate contribution toward meeting peak demand

Issue: Capacity credit of intermittent renewables, particularly solar, depends on how much is online

39

California Peak Load Hours

In California, peak loads occur during summer days when there are high air conditioning loads

Solar has been considered to have a high capacity credit because maximum output occurs during the hot day-time hours when load is highest The figure above shows the CAISO

load profile on June 20, 2008 which includes the annual system peak hour, 3-4 PM

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1 3 5 7 9 11 13 15 17 19 21 23

Hour Ending (HE)

Load

(M

W)

CAISO Load June 20, 2008

40

Peak Load Day (June 20, 2008) with High Solar Penetration

“Must Run Gen” is an approximation of nuclear, coal, and minimum hydro

Solar resources are simulated fixed-tilt utility-scale PV and solar through with no storage at high penetration for June 20, 2008

High penetration of solar generation moves the “net peak” load hour, when load must be met from dispatchable generation, into the nighttime

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1 3 5 7 9 11 13 15 17 19 21 23

PV

Must Run GenLoad

Net Load

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

1 3 5 7 9 11 13 15 17 19 21 23

CSP

Must Run GenLoad

Net Load

Load

(M

W)

Load

(M

W)

HEHE

41

Top 500 Net Load Hours under high PV Penetration Levels

0

2,000

4,000

6,000

8,000

10,000

27,000

31,000

35,000

39,000

43,000

47,000

0 100 200 300 400 500

Night Hours

Top 500 Net Load Hours with 0 MW PV

Top 500 Net Load Hours with 2,000 MW PV



Average PV Output Top 100 Hours with 6,000 MW PV



Average PV Output Top 100 Hours with 0 MW PV

Net

Loa

d (M

W)

Ranked Net Load Hour

Average P

V O

utput in Top 100 H

ours (MW

)

As PV penetration increases, the net load hours are re-sorted from highest to lowest and more nighttime hours are among the top 500 net load hours

42

Capacity Credit by Renewable Penetration

-40%

-20%

0%

20%

40%

60%

80%

100%

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Marginal Capacity Credit

CSP

PV

Wind

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000

Average Capacity Credit

CSP

PV

Wind

E3 calculated a capacity credit for the first 1000 MW of resource equal to the average production during top 100 load hours

Added 1000 MW of resource, re-sorted hours from highest to lowest net load, and re-calculated average production during top 100 net load hours

Capacity credit declines rapidly for solar resources as more high net load hours occur at night

Marginal Capacity Credit can be negative when high renewable generation hours are displaced from the top 100 net load hours

Cap

acity

Cre

dit

Penetration (MW)

43

Capacity Credit Depends on the Resource Mix

The previous slides assumed penetration of only one technology The figures above assume a diversified portfolio with 8 MW Wind to every 3 MW PV

and 3 MW CSP Combined portfolio receives average capacity credit of 31% at 10,000 MW of

penetration, higher than any of the three individual technologies

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

1,00

0

2,00

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3,00

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4,00

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5,00

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6,00

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8,00

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9,00

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10,0

00

11,0

00

12,0

00

13,0

00

14,0

00

Average Capacity Credit

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

0

1,00

0

2,00

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3,00

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4,00

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5,00

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6,00

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7,00

0

8,00

0

9,00

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10,0

00

11,0

00

12,0

00

13,0

00

14,0

00

Marginal Capacity Credit

Cap

acity

Cre

dit

Penetration (MW)

44

• CPUC and California ISO signed MOU on May 13, 2010 (http://www.caiso.com/2799/2799bf542ee60.pdf)– Agrees on certain elements of the ISO’s new proposed annual

Transmission Planning Process

– Commits to closer coordination between resource and transmission planning – ISO planning process considers scenarios provided by CPUC, CPUC gives substantial weight in the permitting process to projects consistent with ISO plan

• Umbrella LTPP proceeding considers EE, demand response, distributed generation, utility-scale renewables, fossil retirements, when determining overall system need– CPUC must consider these same things when assessing the need for

individual transmission projects, pursuant to statute

Transmission Assessment

44

http://www.caiso.com/2799/2799bf542ee60.pdf

45

Transmission assessment (cont’d)

“The CPUC and the ISO will review the results of the California Transmission Planning Group modeling phases and evaluate their implications for the transmission needs of the CPUC's Long Term Procurement Plan renewable resource scenarios. The ISO will subsequently seek, within the time and human resource constraints of Phase 2 of the transmission planning process, to provide the CPUC and other stakeholders with a formal assessment of the transmission planning needs within the ISO balancing authority area for the Long Term Procurement Plan renewable resource scenarios.”

- May 13, 2020 MOU between California ISO and CPUC

46



Results Next steps for analysis


Agenda

47

Schedule

• Comments due July 9

• Reply comments due July 16

– Ruling next week will request feedback on specific questions – please attempt to address these, in addition to your general comments

1 introduction, scope, context terminology, high-level approach methodology, inputs, assumptions...

Documents

transmission timelines33

mw of new transmission

new transmission bundleany

existing system

single crezs

rps reference case timeline

highlevel approachmethodology

smaller lines