1 Long-term Renewables Planning Methodology, Inputs and Assumptions for the 2010 Long-Term...

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Long-term Renewables Planning Methodology, Inputs and Assumptions

for the 2010 Long-Term Procurement Plan Proceeding

California Public Utilities CommissionJune 18, 2010

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• 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

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Scope and Purpose

• Workshop scope: RPS planning in the LTPP system proceeding– Not the broader LTPP system planning

activities

• Workshop purpose:– 33% RPS Implementation Analysis – Review

study, comments– RPS Planning in the 2010 LTPP – Begin

refining assumptions and methodologies for an updated study

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Scope and Purpose

• Proceeding scope: LTPP system proceeding is not the forum for deciding RPS procurement obligations. Rather, results from RPS analyses could serve three purposes:

– Identify type and quantity of new system resources needed reliably integrate renewables – Decided in LTPP system proceeding

– Identify high-level (conceptual) transmission needs to meet renewable targets – Coordinated with ISO’s transmission planning process

– Generate alternative RPS procurement strategies – Inform the RPS proceeding

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Background

• Previous Commission Decisions– Since D. 05-07-039, the Commission has stated its intent to integrate long-

term RPS planning into the LTPP proceeding.– D.07-12-052 (2006 LTPP decision) directed parties to work with Energy

Division to refine a methodology for RPS resource planning and analysis

• February 14, 2008 Order Instituting Rulemaking (OIR) for the 2008 LTPP proceeding (R.08-02-007) – OIR launched to integrate and refine procurement policies, including further

analysis regarding the feasibility and cost of 33% renewables

• August 28, 2008 Assigned Commissioner’s Ruling (ACR) and Scoping Memo– Established separate track for Energy Division’s 33% RPS Implementation

Analysis project

• June 2009 33% RPS Implementation Analysis: Preliminary Report

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Background (cont’d)

• July 1, 2009 Amended ACR and Scoping Memo released the Energy Division Straw Proposal on LTPP Planning Standards (Staff Proposal)

• Working Principle – Resource plans should consider the scale of investment in transmission and flexible fossil resources to integrate and deliver new renewables– Commission “expect[s] the data produced out of RETI…to be utilized in the

[LTPP] proceeding.” (OIR at p. A-9)

– Transmission permitting based on TEAM decision relies on use of assumptions that are consistent with resource plans and system assumptions used in the procurement proceedings (D.06-11-018 at OP 1 and p. A-2)

• A single, statewide “Renewables and Transmission Study” is needed as a foundational element

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R.10-05-006 OIR (2010 LTPP)

• Three Tracks– Track 1: System– Track 2: Bundled– Track 3: Rule and Policy issues

• System track is “to indentify CPUC-jurisdictional needs for new resources to meet system or local resource adequacy need over the 2011-2020 planning horizon, including issues related to long-term renewables planning”

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R.10-05-006 (cont’d)

• Outlines several staff proposals which would be issued by ruling:– Planning Standards (Part 1)– Planning Standards (Part 2): RPS– Planning Standards (Part 3): EE

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Introduction, scope, context

• Terminology, high-level approach


• Results



Agenda

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Proposed Definitions

• Scenario – A possible future state of the world encompassing assumptions about policy requirements, market realities and resource development choices.

• Sensitivity – A test to measure the change in output variable (e.g., cost, resource need) due to a change in input assumptions and parameters.

• Case – A set of input assumptions and parameters (e.g., gas price, or electricity demand) under a given scenario that drives the selection of a given portfolio of resources.

• Portfolio – A set of electric resources, both supply-side and demand-side, that provides electric service to all system ratepayers, under a given scenario.

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Proposed Guiding Principles for RPS Planning

Inputs, Assumptions and Methodology

1. Assumptions should reflect the behavior of market participants, to the extent possible

2. Methodology should be consistent with previous regulatory decisions, to the extent applicable

3. Any proposal should explain the policy basis for the proposal

4. Any proposal must include supporting documentation

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Proposed Guiding Principles for RPS Planning

RPS Scenarios

5. RPS scenarios should be reasonably feasible and reflect plausible procurement strategies with associated (conceptual) transmission.

6. RPS scenarios should represent substantially unique procurement strategies resulting in material changes to corresponding (fossil) procurement needs and/or required (conceptual) transmission.

7. RPS scenarios should be limited to 3-5

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Proposed Approach to Scenario Development

RPS generation under dev’t

& contracted to CA byQ1 2010

Discounted Core

Cost-constrained

Scenario

Time-constrained

Scenario

Environmentally-constrained

Scenario

Trajectory Scenario

Balanced Scenario – determined

2011?

RPS generation

delivering to CA by

Q1 2010

33%of2020 Retail Sales

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Introduction, scope, context Terminology, high-level approach


• Results



Agenda

RPS Model Methodology

Arne Olson, Partner

Doug Allen, Consultant

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Contents

Updates to Previous 33% Implementation Analysis

Resource Potential, Cost, and Performance

Portfolio Selection Methodology

Updates to Previous 33% Implementation Analysis

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Current Analysis Compared to 2009 Implementation Analysis

33% RPS Implementation Analysis was focused on informing state RPS policy

Key tasks:

1. Develop “plausible scenarios” for achieving 33% by 2020

2. Estimate the net ratepayer costs associated with each plausible scenario

3. Highlight key obstacles to reaching the 33% goal, including the need for new transmission and the integration costs of new resources

The current analysis is focused on informing state RPS planning

Key tasks:

1. Develop “plausible scenarios” for achieving 33% by 2020

2. Estimate year-by-year resource build-outs under each alternative scenario

3. Feed information into LTPP proceeding to inform the Commission’s decisions regarding fossil procurement

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Weaknesses of Previous 33% Implementation Study

New transmission is assumed for most projects

No way to determine which projects could get built without new lines

Renewable projects are selected in aggregated “bundles” and could not be selected individually

Crude methodology for addressing potential out-of-state REC resources (“Out-of-State Early”, “Out-of-State Late”)

Did not look at operational impacts of renewables at such high levels of penetration

Integration costs for intermittent resources based on a rule of thumb

Lack of transparency in handling of short-listed CPUC projects

Project viability ratings not very scientific

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Key Improvements in Portfolio Development Methodology

Improved handling of transmission requirements for new renewable resources

Allows some resource to be delivered over existing transmission or with minor upgrades

Allows individual selection of Non-CREZ resources

Incorporation of unbundled REC resources

Can now model out-of-state REC-only resources as well as out-of-state CREZs

Incorporation of “Discounted Core” of commercial projects

Projects in advanced stage of permitting and development

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Other Updates to Analysis

Improved detail on Commercial projects in CPUC ED Database

CREZ assignments

2009 solicitations

Confidential projects either aggregated or excluded to improve transparency

New Aspen environmental scores

Updated resource list based on RETI Phase 2B analysis

Updated RPS Net Short based on:

2009 IEPR Load Forecast

New load decrements for EE and CHP calculated by CPUC

Existing renewable resources from 2008 Net System Power Report

Resource Potential, Cost, and Performance

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General Approach

Determine renewable resource gap (GWh) in 2020

Compile database of resources available to meet RPS target

Rank available resources based on cost, commercial interest, environmental sensitivity and timeline

Select resources to fill renewable resource gap

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Determining Demand for Renewables

Demand for renewables in California is based on 2020 RPS target, equal to 33% of eligible retail sales

2020 retail sales based on CEC 2009 IEPR load forecast

Excludes retail sales by small LSEs (<200 GWh/yr)

Estimate quantity of renewable resources online in base year

Used renewable resource “claims” from CEC 2008 Net System Power Report

Added new resources online in 2009 based on ED Database

RPS resource gap is the difference between the 2020 target and the 2009 renewables claims

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Renewable Net Short

33 33 33

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0

20

40

60

80

100

2009 2020, 20% RPS 2020, 33% RPS

Ren

ewab

le G

ener

atio

n (

TW

h)

Existing Resources RPS Net Short

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Sources of New Resources to Fill Resource Gap

1. Commercial Projects

ED Database of IOU projects

POU procurement plan data obtained from CARB

2. Additional “Theoretical” Projects

RETI pre-identified and proxy projects for California

WREZ projects for the rest of the WECC

3. Original Renewable DG resource potential estimates

Developed as part of 2010 LTPP

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Updated ED Database

Analysis incorporates the latest ED Database, including 2009 IOU solicitations

Contracted projects are included individually

Shortlisted projects are aggregated by resource type and zone in cases where there are at least three such projects to preserve confidentiality (otherwise they are left out)

Distribution of projects among zones has changed since previous analysis

CREZ MW GWh

Tehachapi 4,174 11,239

Northwest 1,805 4,137

Pisgah 1,700 3,974

NonCREZ 841 3,831

Imperial South 1,074 3,042

Riverside East 1,042 2,547

Alberta 886 2,422

Carrizo South 849 1,980

Mountain Pass 710 1,720

Nevada C 500 1,415

Colorado 420 1,301

San Diego South 415 1,293

Montana 300 820

Imperial North 109 770

Fairmont 296 752

Arizona 290 737

Solano 240 704

Kramer 250 584

Inyokern 242 566

Distributed Solar - PG&E 244 468

Distributed Solar - SCE 140 290

Round Mountain 86 281

New Mexico 32 238

Santa Barbara 83 238

Palm Springs 77 222

Nevada N 30 212

Imperial East 30 212

Utah-Southern Idaho 90 191

San Bernardino - Lucerne 49 170

Total 17,003 46,357

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Current Analysis Previous Analysis Current Analysis Previous Analysis

MW GWh MW GWh MW GWh MW GWh

Tehachapi 4,174 11,239 2,038 5,756 Palm Springs 77 222 37 107

Northwest 1,805 4,137 - - Nevada N 30 212 - -

Pisgah 1,700 3,974 800 1,954 Imperial East 30 212 560 1,367

NonCREZ 841 3,831 525 3,118 Utah-Southern Idaho 90 191 - -

Imperial South 1,074 3,042 792 1,944 San Bernardino - Lucerne 49 170 666 1,623

Riverside East 1,042 2,547 2,932 6,855 Baja - - - -

Alberta 886 2,422 - - Barstow - - - -

Carrizo South 849 1,980 - - British Columbia - - - -

Mountain Pass 710 1,720 1,480 3,523 Carrizo North - - - -

Nevada C 500 1,415 30 228 Cuyama - - - -

Colorado 420 1,301 - - Iron Mountain - - 368 897

San Diego South 415 1,293 225 650 Lassen North - - 53 384

Montana 300 820 - - Lassen South - - - -

Imperial North 109 770 569 2,472 Owens Valley - - 55 307

Fairmont 296 752 384 907 San Bernardino - Baker - - - -

Arizona 290 737 - - San Diego North Central - - 87 333

Solano 240 704 150 434 Twentynine Palms - - 67 194

Kramer 250 584 837 2,016 Victorville - - 160 342

Inyokern 242 566 - - Westlands - - - -

Distributed Solar - PG&E 244 468 - - Wyoming - - - -

Distributed Solar - SCE 140 290 - - Needles n/a n/a 747 1,911

Round Mountain 86 281 125 468 Out-of-State Early n/a n/a 2,062 6,617

New Mexico 32 238 - - Out-of-State Late n/a n/a 534 1,304

Santa Barbara 83 238 83 238 Total 17,003 46,357 16,363 45,950

CREZ CREZ

Changes in the ED Database

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Breakdown of the ED Database

Discounted Core Non-Discounted CoreExcluded from Model

to Preserve Confidentiality

Total ED Database Projects

MW GWh MW GWh MW GWh MW GWh

Biogas 12 84 28 195 - - 40 279

Biomass 158 1,176 8 56 20 149 186 1,381

Geothermal 70 494 439 3,101 336 2,370 845 5,965

Hydro - - 26 79 - - 26 79

Large Scale Solar PV 2,068 5,068 2,087 4,970 975 2,322 5,130 12,359

Small Solar PV 384 758 - - - - 384 758

Solar Thermal 2,744 6,414 1,305 3,050 153 358 4,202 9,822

Wind 3,684 10,049 3,991 10,862 1,098 2,987 8,772 23,898 Total 9,120 24,044 7,883 22,313 2,581 8,186 19,584 54,542

Signed - ApprovedSigned - Pending

ApprovalIn Negotiations

Total Projects Included in RES

CalculatorMW GWh MW GWh MW GWh MW GWh

Biogas 21 144 19 135 - - 40 279

Biomass 89 659 77 573 - - 166 1,232

Geothermal 219 1,547 290 2,048 - - 509 3,595

Hydro - - 26 79 - - 26 79

Large Scale Solar PV 1,138 2,724 1,421 3,591 1,596 3,722 4,155 10,037

Small Solar PV 7 14 268 536 109 209 384 758

Solar Thermal 1,615 3,775 2,434 5,689 - - 4,049 9,464

Wind 2,950 8,034 814 2,249 3,910 10,629 7,675 20,911 Total 6,039 16,896 5,349 14,900 5,615 14,560 17,003 46,357

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Treatment of Commercial Projects

Commercial projects are divided into two categories:

1. Discounted Core: Project has obtained or has made significant progress towards obtaining a permit

2. Non-Discounted Core: Project has made limited progress towards obtaining a permit

Discounted Core projects are given first priority in the resource selection sorts, reflecting their high probability of development

Non-Discounted Core projects are given priority over generic resources but are not guaranteed development

POU planned resources treated as Non-Discounted core

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POU Resources

E3 has included POU resource procurement plans in the development of the resource portfolios based on CEC data

POU resources are included as Non-Discounted Core commercial resources

In-State Out-of-State

MW GWh MW GWh

Biogas 145 1,013 - -

Biomass - - 2 12

Geothermal 550 3,884 42 299

Hydro - Small - - 156 478

Solar Thermal 358 836 - -

Solar PV - - - -

Wind 504 1,455 648 1,871

Total 1,557 7,188 848 2,660

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RETI Phase 2B Database

The updated RETI Phase 2B Database contains site-specific information for renewable resource potential, cost, and performance in California

Out-of-state resources from the WREZ Transmission Model have been incorporated with the RETI data

WREZ estimates of potential represent high-quality remote renewable resources that would require significant transmission upgrades to reach load centers

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Out of State Renewable Resource Data from E3 Models E3 maintains a database of renewable resource

cost and performance data in the West

Wind and solar data based on NREL GIS modeling

Geothermal and hydro data from EIA

Biomass aggregated from various sources

Additional resource data for BC and Alberta

Used to supplement WREZ data for out-of-state resources (Montana, Colorado, BC, Alberta)

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Estimates of Statewide DG Potential

As part of the 2010 LTPP, E3 and Black & Veatch collaborated to develop original estimates of the statewide potential of solar PV

The RPS model integrates these estimates, allowing it to evaluate the viability of the development of these resources

RegionEasy to

InterconnectHarder to

InterconnectTotal

North Coast 1148 1440 2588Central Valley 1237 5693 6931South Coast 1890 433 2323Mojave Desert 694 1600 2294TOTAL 4970 9167 14136

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Resource Cost and Performance

E3 used site-specific data on resource cost and performance where available (RETI and WREZ projects)

Generic assumptions were developed for resources without specific information based on averages of the RETI data (shown below)

Biogas - Landfill

Biogas - Other

Biomass GeothermalHydro - Small

Large Scale Solar

PV

Small Solar PV

Solar Thermal

Wind

Capital Cost ($/kW) 2,750$ 5,500$ 4,522$ 6,379$ 3,300$ 4,500$ 4,500$ 5,300$ 2,371$

Fixed O&M ($/kW-yr) 130$ 165$ 72$ -$ 25$ 50$ 50$ 66$ 60$

Variable O&M ($/MWh) -$ -$ 17$ 38$ -$ -$ -$ -$ -$

Heat Rate (Btu/kWh) 12,070 13,200 14,800 - - - - - -

Capacity Factor (%) 80.0% 80.0% 85.0% 80.6% 35.0% 27.8% 23.7% 26.7% 32.9%

On-Peak Availability (%) 100% 100% 100% 100% 65% 65% 65% 78%* 11%**

LCOE ($/MWh) 92$ 121$ 106$ 148$ 161$ 142$ 216$ 202$ 95$

* On-peak availability for solar thermal varies between 70% and 85% based on CREZ

** On-peak availability shown is for in-state resources; out-of-state wind resources have an on-peak availability value of 20% in California

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Generic Resource Cost Assumptions

$92 $95 $106$142 $148 $161

$202 $216

0

50

100

150

200

250

Biogas -Landfill

Wind Biomass LargeScale

Solar PV

Geo-thermal

Hydro -Small

SolarThermal

SmallSolar PV

20

20

LC

OE

in

20

08

$/M

Wh

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Transmission and Geographic Classification of Resources

Each resource is assigned one of three classifications

1. CREZ: resources located within one of the 48 Competitive Renewable Energy Zones (either in California or in other states)

2. Non-CREZ: resources in California or directly across the border that are not located within a CREZ and can be delivered with minor transmission upgrades

3. Out-of-State REC: out-of-state resources that would deliver energy to the local market

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Transmission Bundles

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

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Examples of Transmission Capacity Allocation

300

600

1500

400 361

1000

0

200

400

600

800

1000

1200

1400

1600

(1)

Ex

isti

ng

Tra

ns

mis

sio

n

(2)

Inc

rem

en

tal

Up

gra

de

(3)

Ne

wT

ran

sm

iss

ion

(1)

Ex

isti

ng

Tra

ns

mis

sio

n

(2)

Inc

rem

en

tal

Up

gra

de

(3)

Ne

wT

ran

sm

iss

ion

Example Buildup 1 Example Buildup 2

Av

aila

ble

Ca

pa

cit

y (

MW

)

Discounted Core Commercial Projects Theoretical Projects

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Examples of Transmission Capacity Allocation

0

500

1000

1500

2000

2500

3000

Example 1 Example 2 Example 3

Av

aila

ble

Ca

pa

cit

y (

MW

)

Existing Transmission Minor Upgrades New Line


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Out-of-State REC Resources

Out-of-State RECs previously included in two “zones” (“Out-of-State Early” and “Out-of-State Late”)

New model can select REC resources individually

Assume physical limitations on wind integration for each region

REC resources priced at long-run “Green Premium” or Cost minus Value

REC resources optimized for access to transmission, not for resource quality – RECs are allowed for average quality resources, not best sites

Pricing based on long-run cost, not REC market price forecast (analogous to in-state resources)

No pricing distinction between different types of RECs (bundled vs. unbundled, with or without delivery requirement)

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Unbundled Out-of-State REC-Only Transaction

Leg 1: Developer to Mid-C

Mid-C Market

Leg 2: CAISO to load

Pure REC transaction with no energy purchase requirement and no delivery requirement

Developer sells energy at Mid-C

California LSE purchases REC from developer at LCOE minus Mid-C price

Separately, California LSE arranges for energy transaction from CAISO market to load

California LSE never owns energy

No incremental imports to California

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Out-of-State REC with Delivery Requirement

Leg 1: CA utility to

Mid-C

Mid-C Market

Leg 2: CAISO to load

REC transaction with energy purchase requirement and delivery requirement

California LSE purchases energy and REC from developer at LCOE of wind facility and sells energy at Mid-C

Separately, California LSE arranges for energy transaction from CAISO market to load

California LSE rebundles REC with transaction from Mid-C to CAISO that would have occurred anyway!

No incremental imports to California

Leg 3: Mid-C to CAISO

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Pricing of Out-of-State REC vs. In-State Resource

In-State Resource priced at LCOE, ratepayer impact is cost relative to market value or “Green Premium”

Out-of-State REC priced directly at “Green Premium”

Energy and capacity values vary by market (higher in California)

Pricing is the same for all flavors of RECs

In-State Wind Resource

Out-of-State Wind REC

Levelized Cost of Wind Energy $ 90.00 $ 75.00

Integration Costs in Local Market $ 6.00 $ 6.00

Energy Value in Local Market (Mid-C or Palo Verde) $ (55.00) $ (45.00)

Capacity Value in Local Market (Mid-C or Palo Verde) $ (5.00) $ -

Net Cost to CA Ratepayers ("Green Premium") $ 36.00 $ 36.00

REC Price $ - $ 36.00

Example of In-State vs. REC-only Pricing

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Physical Limits on Out-of-State REC SupplyM

arke

t V

alu

e o

f W

ind

En

erg

y $/

MW

h

MW of Intermittent Renewables

Initially, wind displaces gas resources

More wind reduces market prices and raises integration costs

Value decreases significantly as wind displaces baseload

There is a practical limit to how much intermittent energy each zone can easily accept

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Physical Limits on Out-of-State REC Supply

There is a practical limit to how much intermittent energy each zone can easily accept

Mar

ket

Val

ue

of

Win

d E

ner

gy

$/M

Wh

MW of Intermittent Renewables

Initially, wind displaces gas resources

More wind reduces market prices and raises integration costs

Value decreases significantly as wind displaces baseload

E3 limited the REC supply based on a simplified representation

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Limits on Wind Penetration

Ability to easily absorb wind is limited to load served with flexible generation

E3 estimated hourly flexible generation in each zone:

Load – Nuclear – Coal – Base Hydro + Export Transmission Capacity

Wind limit is min value

Other regions also have RPS requirements – assume CA can soak up 50% of each region’s limit

6,461 MW2,257 MW

738 MW404 MW

1,231 MW461 MW

229 MW47 MW

0 MW0 MW

3,665 MW1,371 MW

3,968 MW1,939 MW

2,135 MW 947 MW

1,700 MW850 MW

2,211 MW808 MW

13,745 MW

Total limit on wind in regionWind available to California

Portfolio Selection Methodology

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Resource Selection Methodology

1. Calculate project score for each resource

2. Allocate lowest-scoring out-of-state theoretical projects to other states until all non-CA WECC RPS targets for 2020 are satisfied

3. Rank remaining CREZ projects and select to fill transmission bundles

4. Calculate aggregate score for each transmission bundle

5. Rank transmission bundles against individual non-CREZ and REC resources

6. Select resources and bundles to meet 33% RPS target in 2020

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Detailed Portfolio Development

Resource Sort for Local Use

Potential CREZ ResourcesPotential Non-CREZ and

REC Resources

Resource Sort for CA Use as RECs

Resource Sort for CA Use Towards RPS

Resources Remaining After Local Sort

Resource Sort for Existing Tx

Resources on Existing Transmission

Resources Remaining After Existing Tx Sort

Resource Sort for New Tx

New Transmission Bundles

Resources Remaining After Local Sort

Non-CREZ and REC Resource Rankings

Resources Selected for Local Use

Resources Selected for CA RPS Portfolio

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Project Scoring Methodology

Each project is scored on a 0-100 scale based on four metrics (0 is better):

Net Cost

Environmental Score

Commercial Interest Score

Timing Score

Final score for each project is a weighted average of the four individual metrics

Weights are user-defined and vary by scenario

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Net Cost Score

Cost score is based on a modified version of the RETI Ranking Cost

Includes integration and T&D avoided costs

Scores are converted to 0 – 100 scale, bounded by the model’s lowest and highest net cost resources

Modified RETI Ranking Cost

+ Levelized cost of energy

+ Interconnection (gen-tie) costs

+ Deemed integration costs

+ Levelized, per-MWh incremental transmission costs

– T&D avoided costs

– Energy value

– Capacity value

= Final project ranking cost

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Environmental Score

Handicaps resources in areas where environmental issues might hinder development

Considers a variety of factors:

Disturbed lands

Right-of-Way

Significant species

Air quality

Others

Scores for each resource in each CREZ on 0-100 scale

CREZ NameTotal for Biomass

Total for Geotherm

alTotal for Solar PV

Total for Solar

ThermalTotal for

WindPV Rural

DGPV Urban Ground

PV Urban Roof

Barstow 40.3 34.2 34.2 35.3 28.9 24.5 9.9 0.0Carrizo North 32.1 27.1 25.5 26.5 24.4 21.1 8.8 0.0Carrizo South 31.5 26.9 25.1 25.8 25.6 22.0 10.0 0.0Cuyama 35.5 28.8 29.0 30.8 27.2 24.5 10.0 0.0Fairmont 30.9 30.1 35.7 36.4 29.0 24.8 9.4 0.0Imperial East 41.1 31.2 26.2 27.2 25.4 22.5 9.9 0.0Imperial North-A 35.9 26.1 21.4 21.8 24.5 18.1 7.8 0.0Imperial North-B 49.9 34.8 28.6 29.5 34.7 22.4 8.5 0.0Imperial South 46.2 31.7 24.1 24.7 27.5 19.9 8.5 0.0Inyokern 30.9 29.4 33.4 33.9 26.3 24.6 9.9 0.0Iron Mountain 38.5 28.6 22.4 22.5 22.0 21.1 10.0 0.0Kramer 22.8 22.2 27.2 27.6 19.7 17.5 6.2 0.0Lassen North 30.5 31.1 33.0 34.2 31.7 25.6 10.0 0.0Lassen South 24.7 32.5 45.7 52.9 49.7 20.3 5.0 0.0Mountain Pass 40.3 33.5 35.8 36.3 29.4 25.8 9.7 0.0Owens Valley 38.3 30.5 25.4 26.7 24.4 20.9 10.0 0.0Palm Springs 50.5 33.0 29.2 31.8 29.1 21.3 6.8 0.0Pisgah 37.5 27.2 21.1 21.3 20.8 20.5 10.0 0.0Riverside East 28.9 23.8 20.6 20.7 20.5 20.1 9.8 0.0Round Mountain-A 23.1 22.5 23.7 24.3 23.1 21.8 10.0 0.0Round Mountain-B 40.3 36.3 39.5 43.7 35.4 27.1 10.0 0.0San Bernardino - Baker 38.3 29.3 23.5 24.2 22.8 20.9 10.0 0.0San Bernardino - Lucerne 42.4 38.0 43.0 44.1 31.9 27.9 9.8 0.0San Diego North Central 57.3 51.9 69.1 75.3 73.6 41.1 9.5 0.0San Diego South 34.1 31.2 34.3 37.0 29.5 24.6 9.9 0.0Santa Barbara 27.1 23.8 26.9 31.1 22.7 15.4 4.9 0.0Solano 34.6 25.0 25.0 26.6 36.3 16.6 5.0 0.0Tehachapi 29.8 25.6 23.2 23.8 23.5 20.6 9.7 0.0Twentynine Palms 38.9 29.6 24.4 25.1 23.2 21.5 10.0 0.0Victorville 39.2 34.2 38.4 38.9 28.0 25.8 9.4 0.0Westlands 26.4 16.7 10.5 10.9 10.1 9.5 4.5 0.0Arizona 36.2 27.8 23.1 23.5 22.7Nevada 36.8 37.4 43.1 46.2 41.9Oregon 45.9 39.6 36.9 37.6 36.3Baja 45.7 41.6 51.7 56.2 51.5Other 45.9 39.6 36.9 37.6 36.3

Median for CA NonCREZ 35.9 29.6 26.9 27.6 26.3 21.5 9.8 0.0

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Commercial and Timing Scores

Commercial Score: Scale of 0-100 reflecting contracting activity of California utilities

Commercial projects receive a score of 0, while generic projects receive a score of 100

POU-planned projects considered “Commercial” and receive score of 0

Timing Score: Gives better score to resources that can be developed on a relatively short time scale

Online date < 2010 gets 0, > 2021 gets 100

For ED database projects, online dates filed with the applications

For other resources, dates based on size and type of project

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Selection of RPS Portfolio

Each transmission bundle is assigned an aggregate score based on an average of the constituent resources and compared against individual non-CREZ and RECs resources

Discounted Core Projects are selected first unless in New Transmission bundle

After Discounted Core, resources & bundles with the lowest score are selected to fill the 2020 RPS gap

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• Results



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Proposed Approach to Scenario Development

RPS generation under dev’t

& contracted to CA byQ1 2010

Discounted Core

Cost-constrained

Scenario

Time-constrained

Scenario

Environmentally-constrained

Scenario

Trajectory Scenario

Balanced Scenario – determined

2011?

RPS generation

delivering to CA by

Q1 2010

33%of2020 Retail Sales

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Approach to Discounted Core

• Goals:– Capture the projects most likely to be online by 2020

– Transparency – rely on public, objective data

• Propose to include projects with both:– PPA signed and approved or under review by CPUC

– Major permit filed and deemed data adequate at relevant permitting agency (Energy Commission, County, etc.)

• Tested other cores:– All projects with PPAs signed and approved/under review

– All projects with certain objective level of developer experience

– Model allows users to to test these other cores

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Makeup of Possible Discounted Cores

Core DefinitionTotal GWh

Total MW

In State

Solar PV

GWh

Solar Thermal

GWhWind GWh

Geo-thermal

GWhBiomass

GWhARRA

Projects

1New/repowered with PPA signed

34,206 11,830 75% 18% 35% 33% 5% 4% 22

2

New/repowered with PPA signed and permit application deemed data adequate

24,406 8,906 72% 19% 27% 46% 2% 5% 18

3New/repowered with PPA signed and permit application approved

11,442 3,798 59% 7% 10% 78% 3% 3% 5

4

New/repowered with PPA signed and a minimum levels of project development and ownership/O&M experience, and technical feasibility

22,088 7,487 79% 13% 32% 44% 6% 4% 15

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• Results



Agenda

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• Results



Agenda

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• Results



Agenda

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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

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Examples of Transmission Capacity Allocation (review)

300

600

1500

400 361

1000

0

200

400

600

800

1000

1200

1400

1600

(1)

Ex

isti

ng

Tra

ns

mis

sio

n

(2)

Inc

rem

en

tal

Up

gra

de

(3)

Ne

wT

ran

sm

iss

ion

(1)

Ex

isti

ng

Tra

ns

mis

sio

n

(2)

Inc

rem

en

tal

Up

gra

de

(3)

Ne

wT

ran

sm

iss

ion

Example Buildup 1 Example Buildup 2

Av

aila

ble

Ca

pa

cit

y (

MW

)


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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

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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


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• Results



Agenda

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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

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Example – Aspen Environmental Group research into generation timelines

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Example – Research into transmission timelines

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33% RPS Reference Case – Timeline 3

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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.

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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


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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

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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

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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?

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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

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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

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

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

• Results



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