Avoided Cost and E3 Calculator Workshops

Energy and Environmental Economics, Inc.

October 3, 2005

Review of E3 Avoided Costs

Background Overview of the Methodology Valuation of Peak Hours Utility-specific Data

Information on New Avoided Costs

Spreadsheets and reports can be downloaded free from the E3 website:

http://www.ethree.com/cpuc_avoidedcosts.html

Avoided Cost Objectives Goals:

Provide objectively derived estimates of avoided costs that are suitable for evaluating PUC funded programs

Develop a transparent and repeatable costing methodology that does not rely on either proprietary data or models

Deliverables: Transparent and defensible avoided cost methodology

Separate presentations with proposals for each cost component Make use of existing studies and data to the extent possible

Provide software to update estimates of avoided costs Provide a report describing methodology, results, and data to

support estimates

Summary of Project Requirements

Forecast values (2004-2023) for:

X = RFP Requirement; R = E3 Recommendation

Annual Values

Monthly Values

Hourly Values

Vary by Location

Traditional avoided costsElectric generation X RElectric T&D X R RNatural gas procurement X R RNatural gas transportation X R R

Environmental externality X RReliability adder XDemand Reduction Benefit X R

Additional avoided costs (gas and electric)

Electric Avoided Cost Dimensions

UtilitiesPG&ESCESDG&E

Voltage LevelTransmissionPrimarySecondary

Dimensions of the Electric Avoided Cost(8760 Hours from 2004 to 2023)

PG&E: 9 | 18SCE: 8 | 5SDG&E: 4 | 1

Climate Zones | Planning Areas

Avoided Cost Selection NPV InputsComponent Included in

Hourly Calculation

Utility 1 Life (Years) 20

Climate Zone Discount Rate 8.15%

Division 3 Annualization 10%

Voltage Level 3

Utility Control Panel

PG&E

Secondary

Weighted Average

4

Prior Electric and Gas Avoided Costs

Prior Electric and Gas Avoided Costs

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

Env.Ext.

T&D

Gen

Electric Electric ($/kWh)($/kWh)

Gas Gas ($/Therm)($/Therm)

$0.00

$0.10

$0.20

$0.30

$0.40

$0.50

$0.60

$0.70

$0.80

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

Env.Ext.

T&D

Commodity

Source:Energy EfficiencyPolicy Manualp 24-2511/29/01

The New Costing Framework

200?: 2.84% * $60.00/MWh = $1.70/MWh of load

Conceptual Framework

Electric Avoided Costs / BenefitsElectric Avoided Costs / Benefits

Gas Avoided Costs / BenefitsGas Avoided Costs / Benefits

Where a = area, t = time dimension (e.g., hour, TOU period), y = year.

TotalBenefita,h,t = GenMCa,t,y + Externalitya,t,y + TransMCa,t,y + DistMCa,t,y

+ Reliabilitya,t,y + DemandReductionBenefita,t,y

TotalBenefita,t,y = Commoditya,t,y + Transportationa,t,y + Externalitya,t,y

+ DistMCa,t,y + DemandReductionBenefita,t,y (if available)

Formulation of Avoided CostElectric

Period 1 (2004-2008)Platt’s / NYMEX

Period 2Transition

Period 3 (2008-2023)LRMC

1 + Ancillary Services (A/S)

Period 1 (2004-2008)NYMEXPeriod 2

TransitionPeriod 3 (2008-2023)

Long-run Forecast

1 + LUAF + Compression

Commodity

Natural GasCommodity

Market Multiplier

1 + Energy Losses

T&D Costs (1 + Peak Losses )

Environment (1+ Energy Losses)

T&D Costs

Environment

+

+

+

+

• “NYMEX” = “New York Mercantile Exchange”• “LRMC “ = “Long-run marginal cost” = all-in cost of a combined cycle gas turbine (CCGT)• “LUAF “ = “Loss and unaccounted for”

Components that Contribute to Shape

Components with Peak Shape

Energy and capacity Ancillary Services Market Elasticity Transmission and Distribution Capacity Losses Emissions

Inputs that Vary by Utility

Energy and capacity (A/S, environment)Northern and Southern California

T&DVaries by 16 climate zones in the State

LossesAverage and peak losses by IOU

Commodity Shape: Example NP15

1

5

9

13

17

21

1 2 3 4 5 6 7 8 9 10 11 12

0.00

10.00

20.00

30.00

40.00

50.00

60.00

70.00

Hours

MonthsHour

Ave

rag

e o

f H

ou

rly

Val

ues

by

Mo

nth

Price Duration Curve

0

20

40

60

80

100

120

140

160

1

484

967

1450

1933

2416

2899

3382

3865

4348

4831

5314

5797

6280

6763

7246

7729

8212

8695

Hours

NP

15 M

arke

t P

rice

Sh

ape

Average of period 4/1/1998 through 3/31/2000 – Matched by Daytype

Market Price Forecast Results Annual Average Forward Price Estimate

Market Price Forecast by Utility

0

10

20

30

40

50

60

70

80

90

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

Year

Mar

ket

Pri

ce (

No

min

al $

/MW

h)

PG&E

SDG&E

SCE

Market LRMC

Market Prices Updated as of October 15, 2003

Example of Capacity Separation Integral of the light blue area is the

capacity cost.

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

1

251

501

751

1001

1251

1501

1751

2001

2251

2501

2751

3001

3251

3501

3751

4001

4251

4501

4751

5001

5251

5501

5751

6001

6251

6501

6751

7001

7251

7501

7751

8001

8251

8501

8751

Hours

$/M

Wh

CT Energy Margin

CT Operating Costs

NP15 2005 Market Prices

Average CEC Variable Cost

827 Hours of CT Operation

Energy Losses by TOU PeriodPG&E LossesDescription Transmission Primary SecondarySummer On-Peak 1.024 1.058 1.109Summer Shoulder 1.010 1.042 1.073Summer Off 1.012 1.036 1.057Winter On-Peak - - -Winter Shoulder 1.012 1.039 1.090Winter Off 1.017 1.040 1.061

SDG&E LossesDescription Transmission Primary SecondarySummer On-Peak 1.009 1.036 1.081Summer Shoulder 1.009 1.034 1.077Summer Off 1.007 1.027 1.068Winter On-Peak 1.010 1.038 1.083Winter Shoulder 1.008 1.033 1.076Winter Off 1.007 1.027 1.068

SCE LossesDescription Transmission Primary SecondarySummer On-Peak 1.029 1.061 1.084Summer Shoulder 1.027 1.057 1.080Summer Off 1.025 1.050 1.073Winter On-Peak - - -Winter Shoulder 1.027 1.054 1.077Winter Off 1.024 1.047 1.070

A/S Cost Computation

Average of A/S costs as share of total energy costs, during non-crisis period (8/99-5/00, 8/01-7/03): 2.84%

Apply 2.84% to shaped hourly energy price 2004: 2.84% * $45.57/MWh = $1.29/MWh of load 2005: 2.84% * $46.65/MWh = $1.32/MWh of load

A/S Costs are the same multiplier for the entire state.

Market Elasticity Estimates

Month On-Peak Off-PeakJanuary NA 1.30February NA 1.35March NA 1.40April NA 1.32May 1.60 1.42June 1.85 1.62July 1.30 1.57August 1.47 1.44September 1.73 1.27October 1.05 1.02November NA 1.19December NA 1.30

On-Peak Off-PeakJanuary 100% 100%February 100% 100%March 100% 100%April 100% 100%May 108% 100%June 109% 100%July 107% 100%August 107% 100%September 109% 100%October 105% 100%November 100% 100%December 100% 100%

On-Peak: 8am to 6pm, Working Weekdays, May to OctoberOff-Peak: All Other Hours

Market ElasticityMarket Multiplier

(On Peak RNS = 5%)

T&D Formulation

T&D Capacity T&D Capacity

Cost ($/kW-yr)Cost ($/kW-yr)

YearYear

UtilityUtility

Planning AreaPlanning Area

PeakPeak

AllocationAllocation

HourHour

Climate ZoneClimate Zone

(1 + Losses)(1 + Losses)

UtilityUtility

Voltage levelVoltage level

T&D Capacity T&D Capacity

Cost ($/kW-hr)Cost ($/kW-hr)

YearYear

HourHour

UtilityUtility

Planning AreaPlanning Area

Climate ZoneClimate Zone

Voltage LevelVoltage Level

** ** ==

Item

Item

Dim

en

sio

Dim

en

sio

nn

T&D Capacity $/kW-year{Year}

T&D Allocation{Climate Zone,

Hour}

1 + Peak Losses{Utility, Voltage

Level}

Transmission andDistribution

{Utility, ClimateZone, Voltage

Level, Hour, Year}

* *

T&D Capacity $/kW-year{Year}

T&D Allocation{Climate Zone,

Hour}

1 + Peak Losses{Utility, Voltage

Level}

Transmission andDistribution

{Utility, ClimateZone, Voltage

Level, Hour, Year}

* *

Climate zones and planning

areas

North Valley

NorthCoast Sierra

Sacra-mento

Stockton

Kern

Yosemite

Fresno

LosPadres

CentralCoast

North Valley

Sacramento

North Coast

De Anza

Stockton

Yosemite

San JosePeninsula

EastBay

Diablo

Central Coast

San Francisco Mission

See detail map for divisions in San

Francisco Bay Area

San Francisco Bay Area detail map

PG&EServiceTerritoryDivision

Map

NorthBayNorth

Valley

NorthCoast Sierra

Sacra-mento

Stockton

Kern

Yosemite

Fresno

LosPadres

CentralCoast

North Valley

Sacramento

North Coast

De Anza

Stockton

Yosemite

San JosePeninsula

EastBay

Diablo

Central Coast

San Francisco Mission

See detail map for divisions in San

Francisco Bay Area

San Francisco Bay Area detail map

PG&EServiceTerritoryDivision

Map

NorthBay

Dominguez Hills

Foothill

Rural

Santa Ana

Ventura

CEC Title 24

Climate Zones

T&D Avoided Costs by Planning Division

SDG&E

$77.76

SCE

$36.00

$21.00

$5.00

PG&E

$70.00

$38.00

$5.00

Calculation of the PCAFs is based on Load Duration Curve of Each Area

1 125 …8,600 8,700 8,760

Hours

LOAD

KW

PCAF’s

1 Std Deviation

PCAF weights are assigned proportionally to how high the load is compared to the peak.

Load Duration Curve

Only highest load hours (top standard deviation) receive any weight.

Allocation of T&D Based on Temperature by Climate Zone

Temperature Loads T&D Capacity Cost

Drives Drives

Load Information Missing or Difficult to Obtain in Many Areas

Temperature

Use temperature as a proxy for load, and as the basis for allocating costs to

hours of the year.

T&D Capacity Cost

T&D AllocationActual Load vs. Temperature

Fresno

Yellow8am to 10pm

Similar analysis done on 33 PG&E areas as part of CEC Title 24 development

PCAF / Load Relationship Shown Chronologically

-

50

100

150

200

250

300

6/1/99 6/21/99 7/11/99 7/31/99 8/20/99

Date

Lo

ad (

MW

)

0%

2%

4%

6%

8%

10%

12%

PC

AF

Wei

gh

t

Load (MW)

PCAF

Example Results for PG&E Stockton based on TMY Weather

15

913

1721

14

710

$0

$50

$100

$150

$200

$250

Hour

Month

Levelized Avoided Cost by Month and Hour ($/MWh)

$200.00 - $250.00

$150.00 - $200.00 $100.00 - $150.00

$50.00 - $100.00

$- - $50.00

Peak Losses

Utility Avoided CostTransmission Primary Secondary

PG&E Distribution 0 1 1.0065Transmission 1 1.0318 1.0385

SDG&E Distribution 0 1 1.0140Transmission 1 1.0251 1.0395

SCE Distribution 0 1 1.0218Transmission 1 1.0364 1.0591

Customer Level

Environmental Cost Formulation

NOx $/MWh{Hour, Year}

PM10 $/MWh{Hour, Year}

CO2 $/MWh{Hour, Year}

NOx Cost $/Ton{Year}

Emission RateTon/MWh

{Hour}

PM10 Cost $/Ton{Year}

PM10Emission Rate

Ton/MWh{Hour}

CO2 Cost $/Ton{Year}

CO2 EmissionRate Ton/MWh

{Hour}

Emissions{Voltage Level,

Hour, Year}

* * *

1+Energy Losses{Voltage Level,TOU Period}

* 1+Energy Losses{Voltage Level,TOU Period}

1+Energy Losses{Voltage Level,TOU Period}

* *

$/MWh Emissions Costs & Plant Heat Rate

02000400060008000

10000120001400016000

$- $2.00 $4.00 $6.00 $8.00 $10.00

$/MWh

He

at

Ra

te

Emission Prices & Plant Heat Rates

• Includes NOx, PM-10, and CO2 emission credit prices• Lower bound of heat rate is set at a 6,240 heat rate, upper bound is set at a

14,000 heat rate

Putting the Components Together:Base Case Results

Total Avoided Cost - 8760 hours by 20 years

{Utility, Climate Zone, Voltage Level, Hour, Year}

Commodity{Utility, Voltage

Level, Hour, Year}

Transmission andDistribution

{Utility, ClimateZone, Voltage

Level, Hour, Year}

Emissions{Voltage Level,

Hour, Year}

14

710

1316

1922

14

710

$0

$50

$100

$150

$200

$250

Hour

Month

San Jose: Levelized Avoided Cost by Month and Hour ($/MWh)

$200.00 - $250.00

$150.00 - $200.00

$100.00 - $150.00

$50.00 - $100.00

$- - $50.00

T&D Costs

Total Electric Avoided Costs

Shape is Based on PG&E’s San Jose Planning Division

3 Day Snapshot of Disaggregated Electric Avoided Costs

Total Avoided Costs

$-

$50

$100

$150

$200

$250

1 8

15

22 5

12

19 2 9

16

23

Hour of Day

$/M

Wh

Distribution

Transmission

CO2

PM10

NOX

Multiplier

AS

Generation

14-Jul 15-Jul 16-Jul

2004

Avoided Cost is Based on PG&E’s San Jose Planning Division

Comparison of Efficiency Programs

• Levelized Avoided Cost ($/MWh) over 16 Year Life for All Devices• AC Load Shape Based on SEER 12 to SEER 13 Change in Fresno• New Avoided Costs are based on PG&E, Climate Zone 13, Secondary• Based on hourly simulated AC data, proxy outdoor lighting, flat refrigeration

Comparison of Avoided Costs for 3 Example Measures

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

New

Existin

gNew

Existin

gNew

Existin

g

We

igh

ted

Ave

rag

e

Avo

ide

d C

os

t(L

ev

eli

zed

$/M

Wh

)

$0.00

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

Le

ve

lize

d $

/kW

h

Generation T&D Environment $/kWh

AirConditioning

OutdoorLighting

Refrigeration