CPUC Avoided Cost Workshop
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1
CPUC Avoided Cost Workshop
T&D Avoided Cost
2
T&D Comment Areas
“Adopted T&D Costs, not a uniform methodology”
Are time and location differences worth the effort?
Need for $/kW-yr capacity cost Avoided cost only if DSM/CEE reductions are
reliable Generic T&D costs should not be used
3
Goals for the T&D Methodology
Disaggregate information by area and time to facilitate detailed analyses where appropriate
Use publicly available data, or information that can be easily provided by utilities
Transparent method Easily updated (not necessarily on an annual basis)
Working group deliberated on several alternative approaches for methodology
Conclusion was that results were similar across several approaches (Present Worth, DTIM, TIM)
4
PW Method is Based on Deferral of Investments
Year
Loa
d
Build Year
Capability
Area Loads
Loa
d
Change Year
Capability
InvestmentPV = $7.35M
Base Plan
Shifted Plan
Load Change
InvestmentPV = $7.93M
Load decrease delays investment need
PV value of deferral is PV(base plan) - PV(change plan)
5
PG&E Total T&D Marginal Costs
$0
$10
$20
$30
$40
$50
$60
$70
CE
NT
RA
L C
OA
ST
DE
AN
ZA
DIA
BLO
EA
ST
BA
Y
FR
ES
NO
KE
RN
LOS
PA
DR
ES
MIS
SIO
N
NO
RT
H B
AY
NO
RT
H C
OA
ST
NO
RT
H V
ALL
EY
PE
NIN
SU
LA
SA
CR
AM
EN
TO
SA
N F
RA
NC
ISC
O
SA
N J
OS
E
SIE
RR
A
ST
OC
KT
ON
YO
SE
MIT
E
Sys
tem
Ave
rage
Present Worth
TIM
DTIM
PG&E’s Electricity T&D: Comparison of Methods
Annualized MCs fell within a tight band using the DTIM, TIM or PW methods
MCs varied significantly by
planning division. Transmission MCs on
a system average basis only
1999$/ kW-yr
NOTE: Results exclude new business primary distribution marginal costs, which are borne by the customer and therefore not avoidable by the utility.
6
SCE Electric Distribution: Comparison of Methods
Southern California Total Distribution Marginal Costs
$0
$20
$40
$60
$80
$100
$120
Do
min
gu
ez
Hill
s
Fo
oth
ill
Ve
ntu
ra
Sa
nta
An
a
Ru
ral
Present Worth
DTIM
TIM
RCN*
2004$/ kW-yr
Under RCN, rural distribution has a high value because $14.5MM of investment for 20MW of new capacity
Transmission avoided costs exclude economic projects
SCE Transmission Marginal Costs
18.81
15.80 16.21
10.24
-
5
10
15
20
Present Worth
DTIM TIM RCN
2004
$/kW
-yr
7
SDG&E Electric T&D: Comparison of Methods
When E3 calculated distribution marginal costs using 2002-2007 data, the 3 methods yielded similar results
Transmission: Although SDG&E uses embedded costs, it has clarified which investments are demand-related
SDG&E Electric T&D Marginal Costs
0
10
20
30
40
50
60
70
80
Distribution Transmission
20
04
$/k
W-y
ea
r
PW
DTIM
TIM
8
SCE's T&D Costs by Area, Climate Zone: Blended
0
20
40
60
80
100
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
$/kW
-yr
Dominguez Hills (CZ 6,8)Foothills (CZ 10,16)Ventura (CZ 5,6,9)Santa Ana (CZ 6,8)2001 EE ValuesRural (CZ 14,15,16)System Average
Extrapolation of T&D Avoided Cost Estimates
Long RunTransition
PG&E: Retain cost differentials SCE: Blended Long Term Forecast Approach (shown below)
2001 EE Values
Rural
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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
10
Recommendation: Methods
“Use adopted T&D marginal costs, not a uniform methodology” PW, DTIM, and TIM all produce comparable results, so
using adopted values based on these methods would be fine --- provided that the adopted values retain the area differentiation
RCN can produce very different results, and should not be used.
“Are time and location differences worth the effort?” Location does reveal significant cost differences for
PG&E as well as SCE’s Rural area. Other SCE areas are less clear.
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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
12
Summer PeakLoad vs. Temperature
Fresno
Yellow8am to 10pm
Similar analysis done on 33 PG&E areas as part of CEC Title 24 development
13
Example Results for PG&E Stockton
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
$- - $50.00
14
PG&E: Allocation by TOU Period
Low avoided costs in Oakland climate zone allocated much more evenly across TOU periods due to temperate weather
PG&E Oakland Climate Zone
2004$/kW-yr TOU Period
Total Costs($000)
Total Load by TOU Period
(MWh)
T&D Marginal Costs (by TOU, PCAF)
($/kWh)Summer 24.50 1 On Peak 409,732 24,852,856 0.016
2 Shoulder 127,102 19,887,184 0.0063 Off Peak 130,397 58,181,254 0.002
Winter 24.50 4 On Peak - - 5 Shoulder 232,677 36,539,717 0.0066 Off Peak 361,739 53,490,832 0.007
PG&E Fresno Climate Zone
2004$/kW-yr TOU Period
Total Costs($000)
Total Load by TOU Period
(MWh)
T&D Marginal Costs (by TOU, PCAF)
($/kWh)Summer 34.31 1 On Peak 770,741 24,852,856 0.03101
2 Shoulder 9,001 19,887,184 0.000453 Off Peak 145,719 58,181,254 0.00250
Winter 34.31 4 On Peak - - 5 Shoulder 432,758 36,539,717 0.011846 Off Peak 390,232 53,490,832 0.00730
(From working group presentations)
Oakland on-peak is about half of Fresno.
15
Recommendation: Hourly Costs
Need for $/kW-yr capacity cost Not needed if hourly costs are used, but could
be more accurate when costs are averaged into TOU periods.
Caution must be exercised, however, to avoid overestimating capacity reductions.
Are time and location differences worth the effort? Time difference can be dramatic in comparing
coastal and inland areas.
16
Recommendation: Other T&D Issues
Avoided cost only if DSM/CEE reductions are reliable Two aspects to this issue:
“Do you expect the reduction when you need it?” This is addressed by the hourly costs (or hourly peak allocation factors)
“What happens if the reduction is not there when you need it?” This is probably not an issue for DSM because of the high diversity of DSM reductions. This can be an issue for other proceedings, in which case the avoided cost should be de-rated.
Generic T&D costs should not be used Do not see a need for individual studies for DSM
program evaluation.
17
Gas T&D Findings
18
Gas Results are Simpler Than Electric Results are by IOU, not sub-area Hourly allocations are not needed because of the
natural storage capability of gas pipe. Allocation of costs to winter peak months (November
through March) when peak loads occur Results are shown by customer class to reflect the
usage pattern differences of the classes. Results can also be provided at a system average level
19
Gas T&D Avoided Costs
Gas T&D annual average avoided costs can vary widely by utility, with PG&E having the highest costs
Results significantly above California 2001 energy efficiency values (about $0.03/therm)
20
No Gas Storage Costs in these Avoided Cost Estimates Need for inventory expansions to support future growth driven
by: Growth in core demand for firm withdrawal as core peak day
demand rises Varying attractiveness of storage depending on
summer/winter price differentials and the national storage market
To a considerable extent, storage and backbone transmission capacity are substitutes
The appropriateness of including storage will depend upon the extent to which peak capacity requirements are driving the need for the project.
21
Monthly Average Residential Throughput (%)
3%
5%
7%
9%
11%
13%
15%
17%
Jan
Fe
b
Ma
r
Ap
r
Ma
y
Jun
Jul
Au
g
Se
p
Oct
No
v
De
c
PG&E SoCal SDG&E
Gas T&D Costs Allocated to Winter Season
Aggregate throughput by utility by summer and winter seasons. Allocate marginal costs to winter months when peak loads occur
SummerWinter Winter
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Winter Allocations by Utility
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