Copyrighted © 2000 PG&E All Rights Reserved CASE Initiative Project TDV Economic Update Brian Horii...

Copyrighted © 2000 PG&E All Rights Reserved

CASE Initiative Project

TDV Economic Update

Brian Horii and Snuller PriceEnergy & Environmental Economics, Inc.

forPacific Gas & Electric Co.

Codes & Standards Program



Agenda

Methodology Overview Conceptual Framework Detail on TDV Derivation

• Electricity• Natural Gas• Propane



Methodology Overview of TDV

TDV Method the Same for All Energy,Sum of• Commodity Costs• Marginal T&D Costs• Rate Adjustments• Air Emissions Externalities• “1992 Adder”

Hourly Lifecycle values for each area, class, and energy type



Commodity Costs Marginal T&D Costs Rate Adjustments Air Emissions “1992 Adder”

Formulation Based on TDV Goals

Include New Market Structure

System Efficiency Utilization

Improve Environment

Don’t Relax Standards

Cost Component TDV Goal

Total TDV Value

TDV values made with publicly available data.



This is What it Looks Like!

Example of Electric TDV Spreadsheet

Down for 8760 Hours

Res Com Res Com Res Com Res Com Res ComHour 30-Year NPV 15 Year NPV 30-Year NPV 15 Year NPV 30-Year NPV 15 Year NPV 30-Year NPV 15 Year NPV 30-Year NPV 15 Year NPV

1 2.20$ 1.14$ 2.03$ 1.11$ 2.09$ 1.08$ 2.28$ 1.20$ 1.94$ 0.97$ 2 2.19$ 1.13$ 2.02$ 1.10$ 2.07$ 1.07$ 2.26$ 1.19$ 1.92$ 0.96$ 3 2.17$ 1.12$ 2.00$ 1.09$ 2.05$ 1.06$ 2.25$ 1.18$ 1.90$ 0.95$ 4 2.17$ 1.12$ 2.00$ 1.09$ 2.06$ 1.07$ 2.25$ 1.19$ 1.91$ 0.95$ 5 2.22$ 1.15$ 2.05$ 1.12$ 2.10$ 1.09$ 2.29$ 1.21$ 1.95$ 0.98$ 6 2.29$ 1.20$ 2.12$ 1.16$ 2.18$ 1.14$ 2.37$ 1.26$ 2.03$ 1.02$ 7 4.77$ 2.80$ 9.93$ 6.13$ 5.55$ 3.32$ 23.03$ 14.04$ 28.26$ 17.98$ 8 3.77$ 2.15$ 10.25$ 6.34$ 5.66$ 3.38$ 7.17$ 4.23$ 18.56$ 11.70$ 9 3.02$ 1.66$ 5.42$ 3.26$ 5.69$ 3.40$ 3.10$ 1.71$ 2.24$ 1.15$

10 2.65$ 1.42$ 2.35$ 1.30$ 4.30$ 2.50$ 2.60$ 1.40$ 2.26$ 1.16$ 11 2.53$ 1.34$ 2.36$ 1.31$ 3.49$ 1.98$ 2.61$ 1.40$ 2.27$ 1.17$ 12 2.52$ 1.34$ 2.35$ 1.30$ 2.41$ 1.28$ 2.60$ 1.40$ 2.26$ 1.16$

ShastaElectric TDV Values - 10/1/2000 - $/kWh - Year 2001 Dollars - Present Value

Oakland China Lake Fresno Long Beach



How TDV Works in Evaluation

$/kWh

Monday Friday

With flat energy costing a kW saved is valued the same for every hour of the day

With TDV costing a kW saved during a high-cost peak hour is valued more highly than a kW saved during an off-peak hour

Flat Energy Costing

Time Dependent Energy Costing

Environment

Building up the Electric TDVs

$/kWhT&D

PX

Rate Adder

1. Start with the PX Commodity Costs2. Add the marginal T&D delivery costs3. Use flat adder to bring to rate levels4. Add environmental externality of reduced air pollution5. Add 1992 adder to bring to current standard levels



1992 Adder

Building up Gas and Propane TDVs

$/MMBtu

Environmental Externality1992 Adder (Nat. Gas Only)

Commodity Cost

January December

Rate Adder

1. Start with the Gas Commodity Costs2. Use flat adder to bring to rate levels3. Add environmental externality of reduced air pollution4. Add 1992 adder to bring to current standard levels





Annualized Rate Components of Electric TDV Values

Weighted Average Electric TDV for Shasta

Shasta Commercial Electric TDV Breakdown

$0.000

$0.020

$0.040

$0.060

$0.080

$0.100

$0.120

Annualized Rate ComponentLev

eliz

ed A

nn

ual

Ele

ctri

c T

DV

$/k

Wh

Environment

T&D

PX Generation

Rate Adder

1992 Adder

34%

21%

8%

6%

31%



Annualized Rate Components of Natural Gas TDV Values

Weighted Average Gas TDV for Shasta

Shasta Commercial Natural Gas TDV Value Breakdown

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

Annualized Rate Component

Levelized

An

nu

al G

as T

DV

$/M

MB

tu

Environment

Commodity

Rate Adder

1992 Adder

48%

38%

8%

6%

No T&D Component for natural gas or propane



Annualized Rate Components of Propane TDV Values

Weighted Average Propane TDV for Shasta

Shasta Commercial Propane TDV Breakdown

$0.000

$2.000

$4.000

$6.000

$8.000

$10.000

$12.000

$14.000

Annualized Rate Component

Lev

eliz

ed A

nn

ual

Pro

pan

e T

DV

$/M

MB

tu

Environment

Commodity

Rate Adder

49%

45%

6%

No 1992 Adder for propane



Electric TDV Summary

Res Com Res Com Res Com Res Com Res ComMin 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$

Average 0.75$ 0.45$ 0.74$ 0.45$ 0.75$ 0.45$ 0.74$ 0.45$ 0.75$ 0.45$ Max 3.14$ 1.91$ 3.13$ 1.90$ 3.14$ 1.91$ 3.13$ 1.90$ 3.14$ 1.91$ Min -$ -$ -$ -$ -$ -$ -$ -$ -$ -$

Average 0.21$ 0.14$ 0.37$ 0.17$ 0.32$ 0.19$ 0.13$ 0.07$ 0.47$ 0.31$ Max 95.18$ 61.56$ 129.80$ 82.72$ 150.01$ 97.02$ 73.51$ 45.50$ 637.40$ 412.26$

Rate Adder Flat 1.03$ 0.28$ 0.74$ 0.32$ 0.91$ 0.23$ 1.20$ 0.55$ 0.76$ 0.11$ 1992 Adder Flat 0.48$ 0.43$ 0.60$ 0.37$ 0.48$ 0.43$ 0.38$ 0.23$ 0.48$ 0.43$

Min 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ Average 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$

Max 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ Min 1.67$ 0.82$ 1.51$ 0.79$ 1.56$ 0.76$ 1.76$ 0.89$ 1.41$ 0.65$

Average 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ Max 97.66$ 62.87$ 132.26$ 84.08$ 152.37$ 98.27$ 76.07$ 46.87$ 639.56$ 413.36$

Total TDV

TDV Lifecycle Cost Components $/kWh

Shasta

Commodity Cost

T&D Cost

Environmental Adder




Natural Gas TDV Summary

TDV Values by Service AreaTDV Lifecycle Cost

Components $/MMBtuZone PG&E Socal Gas SDG&E

TDV Component Class Res Com Res Com Res Com

Min $56.02 $31.46 $53.26 $29.62 $53.01 $29.48

Avg $60.03 $33.41 $59.91 $32.91 $59.78 $32.90Commodity Cost

Max $63.44 $35.63 $67.77 $37.69 $70.31 $39.11

Rate Adder Flat $62.55 $40.79 $70.52 $25.22 $70.54 $37.03

1992 Standard Adder Flat $53.73 $5.04 $45.88 $21.12 $45.98 $9.31

Environmental Adder Flat $11.90 $7.25 $11.90 $7.25 $11.90 $7.25

Min $184.19 $84.55 $181.56 $83.20 $181.43 $83.07

Avg $188.20 $86.49 $188.20 $86.49 $188.20 $86.49Total TDV

Max $191.61 $88.71 $196.07 $91.27 $198.73 $92.69



Propane TDV Summary

Statewide Propane ValuesTDV Lifecycle Cost

Components $/MMBtuClass Res Com

Min $115.87 $50.93

Avg $128.95 $53.97Commodity

Max $137.89 $58.51

Rate Adder Flat $117.42 $82.96

Environment Flat $14.08 $8.58

Min $247.38 $142.47

Avg $260.46 $145.51Total TDV

Max $269.39 $150.04



Details of theElectric TDV Estimation



Electric Costs

Time Dependent Components• Generation - Commodity• Transmission and Distribution• Emissions

Attributes- Level- Shape

Fixed Components• Rate Adder• 1992 Adder



The Commodity Component:Generation Market Price - Level

Price based on the “all-in” cost of a combined cycle gas turbine

Gas price forecast is the major driver

-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

2030

Year

All-

in M

ark

et

Pri

ce (

$/M

Wh

)

Fuel Cost ($/MWh) Variable O&M ($/MWh) Levelized Capital & Fixed O&M





The Commodity Component: Generation Market Price - Shapes

Price[m,h] = All-in Cost * Monthly Price Ratio[m] * Typical Shape[m,h]

-

0.50

1.00

1.50

2.00

2.50

3.00

1 11 21 31 41 51 61 71 81 91 101 111 121 131 141 151 161

Jan

Feb

Mar

Apr

May

June

July

Aug

Sept

Oct

Nov

Dec

Monthly Typical Shapes (normalized to average 1.0)Monthly Typical Shapes (normalized to average 1.0)



The Commodity Component: Combining Level and Shape Yield the Hourly Prices

Shapes mapped to 1997 chronology

-

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

180.00

1

349

697

1045

1393

1741

2089

2437

2785

3133

3481

3829

4177

4525

4873

5221

5569

5917

6265

6613

6961

7309

7657

8005

8353

8701

Hour of the year

Gen

erat

ion

Pri

ce (

$/M

Wh

)



The T&D Component: T&D Marginal Cost - Levels

Marginal costs will always be in flux. Use the most recent values available.• SCE PTRD Proposal• PG&E 1999 GRC Phase II

Use full “ratemaking” marginal costs• DSM marginal costs can be lower

– Timeframe of impacts– Pervasiveness of impacts



The T&D Component: T&D Cost - Shape

Concept• T&D systems are built for peak loads• Peak load is driven largely by weather• Peak Capacity Allocation Factors (PCAFs) are

used to allocate the marginal costs to the high load hours

– Used by PG&E and SCE

• Want price signals highest when load is highest in an area. PCAFs reflect this.

– Allocate cost to hours in the peak period. The higher the relative load, the higher the allocated cost.



The T&D Component: PCAFs and Temperature

Temperature Loads PCAFsDrives Drives

Load Information Missing or Difficult to Obtain in Many Areas

Temperature PCAFs

We used temperature as a proxy for load, and as the basis for allocating

costs to hours of the year.



The T&D Component: PCAF / Load Relationship

PCAFs focus on the highest load hours

-

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



The T&D Component: Temperatures Drive the Peaks

Milpitas illustrates the strong correlation of weekday temp with peak loads.

-

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

20

40

60

80

100

120

Tem

per

atu

re

Load (MW)

Temp

Sunday



The T&D Component: Results of Load & Temperature Correlation

Peak period is all weekday hours with temperatures within 15 degrees of the highest observed temperature in the area (weekday only).

This 15 degree span defines the hours that could drive peak demand, and thus drive the need for capacity expansion.

This definition is independent of climate zone. This definition is spot-on with PCAFs in the

summer



CONCORD DPA in DIABLO Division. Weather Station: Concord

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

20 40 60 80 100 120

Temp

Cum

ulat

ive

PC

AF

Actual PCAFs Estimated Shape

The T&D Component: Sample Summer PCAF Results

Similarly good correlation was obtained for all summer peaking areas:• San Jose• Bakersfield



The T&D Component: Same Principles Apply to the Winter - w/ Refinements

Same 15 degree bandwidth Only consider 7am to 9pm

MONTEREY 21 KV DPA in CENTRAL COAST Division. Weather Station: Monterey

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

20 40 60 80 100 120

Temp

Cum

ulat

ive

PC

AF


K-X DPA in EAST BAY Division. Weather Station: Oakland

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

20 40 60 80 100 120

Temp

Cum

ulat

ive

PCA

F




The T&D Component: Winter PCAF Timing

Winter Areas• Current areas peak in the evening. Do we need

to worry about a morning peak?

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

10 15 20

Hour of the Day

PC

AF

To

tals

by

Ho

ur

of

the

Da

y

NORTH PEN WEST 12 KV

MONTEREY 21 KV

SEASIDE MARINA 12 KV

K-X (Oakland)

RADIAL (SF)

-0.1

0

0.1

0.2

0.3

0.4

0.5

0.6

10 15 20

Hour of the Day

PC

AF

To

tals

by

Ho

ur

of

the

Da

y

NORTH PEN WEST 12 KV

MONTEREY 21 KV

SEASIDE MARINA 12 KV

K-X (Oakland)

RADIAL (SF)



The T&D Component: Hourly Costs

Hourly Cost is the T&D capacity cost (from the utilities) times the temperature weight.

Temp weight is the total PCAF for each degree F, divided by the number of hours that are at that degree F.

Temph = temperature category for that hour. (nearest whole degree) TotalPCAF[Temph] = total % of capacity cost allocated to that temp category NumberofHours = # of hours that fall into that temp category in the year CapacityCost = T&D marginal capacity cost in $/kW-yr a = Area, h = hour

)(

)(& ,

h

haha TempursNumberofho

TempTotalPCAFstCapacityCoDCostT

)(

)(& ,

h

haha TempursNumberofho

TempTotalPCAFstCapacityCoDCostT



The T&D Component: Winter PCAF Problems

Assigning costs to the winter (in summer peaking areas) doubles the T&D costs for the area• Favors measures that save in summer and

winter --- bit issue? Spreading actual costs over summer and

winter would undervalue summer reductions



Environmental Adder: Emissions

A realistic valuation of NOx emissions is on the order of $3000-12,300/ton, centered on $7500-8000/ton..

A reasonable, albeit very tentative and highly uncertain, range of values for CO2 emissions is about $5-13/ton-CO2. Thus, the $9/ton-CO2 value used in both the 1994 and 1998 CEC valuations appears to be reasonable.

E3 concludes that a realistic valuation of environmental externalities should be closer to the CEC ER94 valuations, but perhaps at the lower end of this range.

For common electric generation plants in California, this level of externality valuation corresponds to a total emission cost, or energy adder, of about $10/MWh.



Environmental Adder: Emission Cost Estimates

0

10

20

30

40

50

60

701 3 5 7 9 11 13 15 17 19 21 23

Hour of the Day

Mar

ke

t P

rice

or

Emis

sio

n C

os

t ($

/MW

h)

2005 Market Price

ER94

CEC 1998

Other States Min

Other States Max

E3 Recommendation

Table 1: Emission Cost Scenarios

Cost $/ton NOx SO2 VOC PM-10 CO2

ER94 9120 4490 4240 4610 9CEC internal 1998estimate

1800 1780 530 910 9

Other States Min 850 150 1010 330 1Other States Max 7500 1700 5900 4600 24E3 Recommendation 3000 9

“Other States” refers to values used in Massachusetts, Minnesota, Nevada, New York, and Oregon.





Rate Adder

Example for Fresno Commercial Building

$-

$0.01

$0.02

$0.03

$0.04

$0.05

$0.06

$0.07

$0.08

$0.09

$0.10

2001

2004

2007

2010

2013

2016

2019

2022

2025

2028

Fo

reca

st in

200

1 $/

kWh

Total Marginal Cost

Current RetailForecast

Flat adder to adjust marginal cost up to retail rate levels.

Shape still represents underlying social marginal costs.



1992 Adder: Comparison of Electric Rate Forecasts

Current rate forecast is much lower than existing.

Adder up to existing levels removes any IOU rate differentials

Electricity Comparison of Existing Standard Basis and Current Forecast

$-

$0.02

$0.04

$0.06

$0.08

$0.10

$0.12

$0.14

$0.16

19

89

19

91

19

93

19

95

19

97

19

99

20

01

20

03

20

05

20

07

20

09

20

11

20

13

20

15

20

17

20

19

An

nu

al

Av

era

ge

Pri

ce

$2

00

1 $

/kW

h

Existing Standard Basis Current CEC Forecast



Electric TDV Summary

Res Com Res Com Res Com Res Com Res ComMin 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$ 0.03$ 0.02$

Average 0.75$ 0.45$ 0.74$ 0.45$ 0.75$ 0.45$ 0.74$ 0.45$ 0.75$ 0.45$ Max 3.14$ 1.91$ 3.13$ 1.90$ 3.14$ 1.91$ 3.13$ 1.90$ 3.14$ 1.91$ Min -$ -$ -$ -$ -$ -$ -$ -$ -$ -$

Average 0.21$ 0.14$ 0.37$ 0.17$ 0.32$ 0.19$ 0.13$ 0.07$ 0.47$ 0.31$ Max 95.18$ 61.56$ 129.80$ 82.72$ 150.01$ 97.02$ 73.51$ 45.50$ 637.40$ 412.26$

Rate Adder Flat 1.03$ 0.28$ 0.74$ 0.32$ 0.91$ 0.23$ 1.20$ 0.55$ 0.76$ 0.11$ 1992 Adder Flat 0.48$ 0.43$ 0.60$ 0.37$ 0.48$ 0.43$ 0.38$ 0.23$ 0.48$ 0.43$

Min 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ 0.11$ 0.06$ Average 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$ 0.14$ 0.09$

Max 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ 0.24$ 0.14$ Min 1.67$ 0.82$ 1.51$ 0.79$ 1.56$ 0.76$ 1.76$ 0.89$ 1.41$ 0.65$

Average 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ 2.60$ 1.39$ Max 97.66$ 62.87$ 132.26$ 84.08$ 152.37$ 98.27$ 76.07$ 46.87$ 639.56$ 413.36$

Total TDV

TDV Lifecycle Cost Components $/kWh

Shasta

Commodity Cost

T&D Cost

Environmental Adder




Details of the Natural Gas Estimation



The Commodity Component: Monthly Natural Gas Shape

Monthly, not hourly variation for natural gas.

Seasonal Allocation Factors for Natural Gas

0

0.2

0.4

0.6

0.8

1

1.2

1.4

Jan

ua

ry

Fe

bru

ary

Ma

rch

Ap

ril

Ma

y

Jun

e

July

Au

gu

st

Se

pte

mb

er

Oct

ob

er

No

vem

be

r

De

cem

be

r

Allo

ca

tio

n F

ac

tors

PG&E Socal Gas SDG&E



The Commodity Component: Long Run Forecast

Residential Core Natural Gas Forecast

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

1999

2001

2003

2005

2007

2009

2011

2013

2015

2017

2019

Re

tail

Co

st

$200

1/M

MB

tu

PG&E Socal Gas SDG&E

Long run residential natural gas rate forecast



Environmental Adder:Externality for Natural Gas

Natural Gas Externalities• 0.058 ton-CO2/MMBtu• 0.045 lb NOx/MMBtu.

Scenario $/MMBtu 15 Year NPV 30 Year NPVER94 $ 0.73 $8.94 $14.68CEC Internal 1998 Estimate $ 0.56 $6.92 $11.36Other States Min $ 0.08 $0.95 $1.56Other States Max $ 1.56 $19.19 $31.51E3 Recommendation $ 0.59 $7.25 $11.90



Rate Adder

Example for Commercial Fresno Customer

$-

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

20

00

20

03

20

06

20

09

20

12

20

15

20

18

20

21

20

24

20

27

20

30

Fo

rec

as

t $

20

01

$/M

MB

tu

Marginal Cost

Retail Rate


No T&D component in marginal cost, assumption is flat allocation across hours.



1992 Adder:Comparison of Gas Forecasts

Natural GasComparison of Existing Standard Basis with Current Forecast

0

2

4

6

8

10

12

14

1989

1991

1993

1995

1997

1999

2001

2003

2005

2007

2009

2011

2013

2015

2017

2019

$2

00

1 D

olla

rs p

er

MM

Btu

Existing Current Forecast



Natural Gas TDV Summary

TDV Values by Service AreaTDV Lifecycle Cost

Components $/MMBtuZone PG&E Socal Gas SDG&E

TDV Component Class Res Com Res Com Res Com

Min $56.02 $31.46 $53.26 $29.62 $53.01 $29.48

Avg $60.03 $33.41 $59.91 $32.91 $59.78 $32.90Commodity Cost

Max $63.44 $35.63 $67.77 $37.69 $70.31 $39.11

Rate Adder Flat $62.55 $40.79 $70.52 $25.22 $70.54 $37.03

1992 Standard Adder Flat $53.73 $5.04 $45.88 $21.12 $45.98 $9.31

Environmental Adder Flat $11.90 $7.25 $11.90 $7.25 $11.90 $7.25

Min $184.19 $84.55 $181.56 $83.20 $181.43 $83.07

Avg $188.20 $86.49 $188.20 $86.49 $188.20 $86.49Total TDV

Max $191.61 $88.71 $196.07 $91.27 $198.73 $92.69



Details of the Propane Estimation



The Commodity Component:Long Run Trend for Propane

EIA Crude Oil Forecast Used Going Forward

Propane Prices Follow Crude O ilPropane Prices Follow Crude O il

15

35

55

75

95

115

135

Jan-

86

Jan-

87

Jan-

88

Jan-

89

Jan-

90

Jan-

91

Jan-

92

Jan-

93

Jan-

94

Jan-

95

Jan-

96

Jan-

97

Jan-

98

Jan-

99

Jan-

00

Cen

ts p

er G

allo

n

WTI Crude Propane (M. Belvieu)

No. 2 (USGC) SHOPP Propane

PMM Propane

Source: DRI Platt's Spot Prices

Retail/Spot PricesRetail/Spot Prices



The Commodity Component:Monthly Shape of Propane

Based on EIA Historical California Propane Prices

Propane Seasonal Shape(Based on Historical California Prices)

0%

20%

40%

60%

80%

100%

120%

140%

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Sea

son

al A

dju

stm

ent

Fac

tors



Environmental Adder:Propane Externalities

Propane Externalities• 0.07 ton-CO2/MMBtu• 0.045 lb NOx/MMBtu

Scenario Annual $/MMBtu 15 Year NPV 30 Year NPVER94 $ 0.84 $10.27 $16.86CEC Internal 1998 Estimate $ 0.67 $8.24 $13.54Other States Min $ 0.09 $1.10 $1.80Other States Max $ 1.85 $22.73 $37.32E3 Recommendation $ 0.70 $8.58 $14.08



Rate Adder

Example for Commercial Customer

$-

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

20

00

20

03

20

06

20

09

20

12

20

15

20

18

20

21

20

24

20

27

20

30

Fo

rec

as

t $

20

01

$/M

MB

tu

Marginal Cost

Retail Price


No T&D component in marginal cost, assumption is flat allocation across hours.



Propane TDV Summary

Statewide Propane ValuesTDV Lifecycle Cost

Components $/MMBtuClass Res Com

Min $115.87 $50.93

Avg $128.95 $53.97Commodity

Max $137.89 $58.51

Rate Adder Flat $117.42 $82.96

Environment Flat $14.08 $8.58

Min $247.38 $142.47

Avg $260.46 $145.51Total TDV

Max $269.39 $150.04

Copyrighted © 2000 PG&E All Rights Reserved CASE Initiative Project TDV Economic Update Brian Horii...

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