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Applicati
Exhibit NWitnesse
ion No.:
No.: es:
A.13-04(consolI.12-10SCE-03C. Cush
EnergOf OpChapt
Before the
Public Uti
4-001 lidated into
0-013) 3 (Updated)hnie
gy Resouperationster XVII
e
ilities Comm
(U 338-E
urce Recs, 2012I (Updat
mission of th
E)
covery A
ted)
he State of C
Account
California
Rose
(ERRA)
emead, Calif
July 8,
) Review
fornia
2013
w
Energy Resource Recoery Account (ERRA) Review of Operations, 2012 Chapter XXVII
Table Of Contents
Section Page Witness
-i-
XVII SONGS RECORD PERIOD UPDATED SHOWING ........................................1 C. Cushnie
A. Market-Related Cost Impact Of SONGS Outages.................................1
B. Replacement Energy Cost Estimate .......................................................2
C. Foregone Energy Sales Net Revenue Estimate ......................................6
D. Capacity-Related Cost Estimate ............................................................8
E. Other Market-Related Cost Estimates ...................................................9
F. Treatment Of Planned Refueling And Maintenance Outages ..............11
G. Adjustments to Estimated 2012 Market-Related Costs Associated with SONGS ......................................................................12
Energy Resource Recoery Account (ERRA) Review of Operations, 2012 Chapter XVII
List Of Tables
Table Page
-ii-
Table XVII-1 ................................................................................................................................................6
Table XVII-2 ................................................................................................................................................8
Table XVII-3 ................................................................................................................................................9
Table XVII-4 ..............................................................................................................................................10
Table XVII-5 ..............................................................................................................................................12
Table XVII-6 ..............................................................................................................................................13
Table XVII-7 ..............................................................................................................................................13
-1-
XVII 1
SONGS RECORD PERIOD UPDATED SHOWING 2
A. Market-Related Cost Impact Of SONGS Outages 3
SCE is submitting this updated testimony to reflect the results of CAISO invoice settlement true-4
ups and updated analysis performed after SCE submitted its April 2, 2013, testimony on its estimated 5
2012 market costs associated with the SONGS outages. The update appears in section G below. There 6
are no other changes to the testimony. 7
The San Onofre Nuclear Generating Station (SONGS) did not operate for most of 2012 due to 8
unexpected tube wear in its replacement steam generators. Unit 2 commenced with a scheduled 9
refueling and maintenance outage on January 9, 2012,1 which was subsequently extended through 2012 10
as a result of the unexpected tube wear found in its two steam generators. Unit 3 experienced a small 11
tube leak on January 31, 2012, and remained out of service through 2012 because of the premature tube 12
wear findings. 13
Pursuant to the Commission’s Order Instituting Investigation Regarding San Onofre Nuclear 14
Generating Station Units 2 and 3 (I.12-10-013), SCE has recorded in its SONGS Outage Memorandum 15
Account (OMA) its estimated market-related costs to replace the lost generation output and capacity 16
from SONGS, as well as the energy sales that could have been made during hours in which the bundled 17
customer portfolio would have been “long” (i.e., hours in which aggregate SCE supply exceeded SCE’s 18
demand requirements) if SONGS was available to operate. Most of these costs must be estimated 19
because it is not possible to know with certainty what market prices would have been had SONGS not 20
been subject to an extended outage.2 Similarly, the operation of the balance of SCE’s energy portfolio 21
would have been different had the SONGS outages not occurred. It is also important to note that SCE 22
1 A gradual ramp-down of SONGS Unit 2 commenced in December 2011, with full shut-down occurring in Hour-Ending
21 on January 9, 2012. In some instances, SCE has stated that the Unit 2 outage commenced on January 10, 2012, because this was the first full day of the planned outage.
2 The dispatch of system resources would have been different with SONGS in operation, and market participants may have submitted different supply bids.
-2-
manages its bundled customer requirements on a portfolio basis, and therefore does not ascribe a 1
specific demand or need for its individual energy-related transactions. Therefore, it is not possible to 2
“tag” specific energy transactions as having occurred as a result of the SONGS outages. 3
The balance of this section identifies the cost and foregone energy sales components that SCE 4
estimated and/or quantified for purposes of recording market-related costs associated with its ownership 5
share of the SONGS outages in SCE’s OMA. SCE presents these amounts in compliance with the 6
Commission’s direction in I.12-10-013.3 SCE has provided here estimates of “replacement power costs” 7
that the Commission instructed SCE to track in the SONGS OMA, but SCE reserves the right to present 8
an alternative cost impact methodology in a subsequent phase of I.12-10-013 if such a calculation is 9
necessary. 10
B. Replacement Energy Cost Estimate 11
SCE is a participant in the CAISO’s organized markets. As a market participant, SCE bids or 12
schedules its generation resources into the CAISO’s energy and capacity markets, and purchases its 13
bundled customers’ energy requirements from the CAISO’s energy markets. As a result, generation 14
output from a resource like SONGS does not directly serve SCE bundled load, but instead is sold or 15
scheduled into the CAISO’s organized market. The generation these facilities provide, however, reduce 16
the procurement expense SCE incurs for serving its bundled customer load from the CAISO organized 17
markets. The difference between SCE’s aggregate energy schedules for generation and purchases for 18
serving bundled load is considered SCE’s net open position.4 If the sum of SCE’s awarded supply 19
position and “in the money” financial products are less than its bundled load requirements, the open 20
position is considered “net short.” Conversely, if the sum of SCE’s awarded supply position and “in the 21
money” financial products are greater than its bundled load requirements, the open position is 22
considered “net long.” For purposes of estimating the replacement energy cost associated with the 23
3 SCE anticipates that the Commission will consolidate this testimony on 2012 SONGS market-related costs and foregone
energy sales into its I.12-10-013 proceeding.
4 The net open position is also impacted by SCE’s financial product holdings.
-3-
SONGS outages that SCE recorded in the OMA, SCE only considered its ownership share of the energy 1
that SONGS could have generated had it been available to operate (measured on a MWh basis) that 2
would have reduced SCE’s net short position. 3
SCE proposes the use of SP-15 day-ahead index prices for purposes here of estimating the cost 4
of replacement energy.5 Because the SONGS units operate in a base-loaded manner (i.e., their 5
generation output does not change as a result of changes in market prices), it is not necessary under this 6
proxy for replacement energy to employ a unique hourly price for purposes of calculating an estimate of 7
replacement energy cost. SP-15 is an appropriate pricing point because the SONGS energy that would 8
have otherwise been produced would have generally served SP-15 load. Additionally, bilateral 9
transactions that SCE would make to cover bundled demand would generally be purchased with an SP-10
15 delivery or settlement price. Specifically, SP-15 day-ahead index prices are commonly used to settle 11
financial transactions for energy transacted for delivery in southern California. 12
SP-15 index prices are also a reasonable proxy for SCE’s Default Load Aggregation Point 13
(DLAP) within the CAISO’s control area, which is the load weighted price that SCE pays the CAISO to 14
serve its bundled load. To the extent that SCE has a net short energy position, and is effectively 15
procuring energy from the market to serve bundled customer load as a result of the outages at SONGS, 16
the price of replacement energy is reflected in the SP-15 day-ahead index price and the CAISO’s hourly 17
day-ahead Integrated Forward Market (IFM) prices at SCE’s DLAP. These prices are the result of 18
market outcomes realized while the SONGS units were unavailable, and are therefore reflective of the 19
impact that the SONGS outages had on market prices. In contrast, the CAISO’s hourly day-ahead IFM 20
prices at the SONGS generation nodes are not useful price benchmarks because SONGS is not 21
delivering energy at those nodes when the units are not operating, and SCE would not purchase 22
replacement energy at the SONGS generation nodes. 23
5 SCE used Platt’s MegaWatt Daily reported index prices for 2012.
-4-
Any net open energy position calculation has to include numerous assumptions as to how the rest 1
of SCE’s generation and purchased power portfolio would have operated had the SONGS outages not 2
occurred. A detailed net open energy position determination would require many procurement response, 3
unit-specific bid behavior, and system operating assumptions, as well as significant modeling effort to 4
simulate changes in SCE’s bundled customer portfolio under the assumption that both SONGS units 5
would have been available to operate. SCE does not believe that such an effort is warranted for 6
estimating replacement energy costs for recording to SCE’s OMA because of the significant number of 7
assumptions that would have to be made and the resulting uncertainty around the modeling results. 8
Instead, SCE believes its final assessed net open energy position prior to the commencement of its day-9
ahead spot market trading activity should be used as its “baseline” net open energy position. This net-10
open position calculation captures SCE’s best available load forecasts, price forecasts, and resource 11
availability knowledge prior to SCE’s day-ahead market activity, but it is not impacted by the bilateral 12
day-ahead trading that SCE performs to reduce its forecast hourly net open positions prior to each day’s 13
CAISO IFM operations. This net-open position calculation also incorporates the impact of SCE’s 14
financial transactions on SCE’s bundled customers’ exposure to day-ahead market prices. 15
The estimate of replacement energy costs associated with the SONGS outage should also be 16
adjusted to account for the historical availability of the SONGS generators. All power plants experience 17
forced outages from time-to-time, despite the employment of best maintenance practices. To account 18
for the fact that the SONGS Units 2 and 3 may have experienced occasional forced outages for reasons 19
unrelated to the current tube wear-related outages, and therefore would not have been available as part 20
of their normal course of operations, forecasts of replacement energy expense and other market-related 21
costs should be reduced by the historical forced outage rate of the SONGS units. For purposes of this 22
estimate, SCE has used a 2.8% annual average forced outage rate, which is reflective of the forced 23
outage rate experienced by SONGS Units 2 and 3 for the ten-year period 2002-2011. 24
The final component of SCE’s estimated replacement energy cost calculations is the treatment of 25
nuclear fuel. SCE subtracts the cost of nuclear fuel (expressed in a $/MWh basis) from SCE’s estimate 26
of replacement energy costs because the unused fuel can be used later in the event that the SONGS 27
-5-
generators are restarted. Stated differently, the unused nuclear fuel is an avoided cost if the SONGS 1
generators are restarted. Unit 2 nuclear fuel costs were assumed to be $7.533/MWh. Unit 3 nuclear fuel 2
costs were assumed to be $5.605/MWh for the period January 1, 2012 through October 31, 2012, and 3
$7.794/MWh for November 1, 2012 through December 31, 2012.6 4
Based on the foregoing, the estimated replacement energy cost for each hour in which a net short 5
position is assumed to exist can be expressed using the following formula: 6
Q * (P - F ) = Hourly Replacement Energy Cost 7
Where, 8
Q = Portion of SCE’s forecast hourly net short position which could be attributed to the SONGS 9
outages, adjusted for the 2.8% historical outage rate for SONGS (expressed in MWh); 10
P = daily average SP-15 index price (expressed in $/MWh); 11
F = the avoided cost of nuclear fuel (expressed in $/MWh).7 12
Table XVII-1 provides SCE’s estimate of replacement energy cost for 2012. 13
6 Nuclear fuel cost estimates are based on the cost of purchasing and manufacturing fuel rods for each fuel cycle for the
applicable generation unit, divided by the estimated amount of generation that will be delivered in the fuel cycle for the applicable generation unit.
7 Note that the assumed nuclear fuel expense differs for each unit, and the Unit 3 assumed cost changed during the year. This is because fuel is procured on different cycles, to align with refuel timing requirements.
1
2
3
4
5
6
7
8
9
10
11
12
13
C. F
S
was done
daily ind
calculatio
15 daily
sales bec
been ava
because m
environm
can be pr
resources
of betwee
Foregone En
CE’s estima
e on the sam
dex prices we
ons were per
index price b
cause market
ilable to the
market parti
ment in which
rovided by e
s. SCE’s pri
en $1.51/MW
nergy Sales N
ate of the for
me basis as SC
ere adjusted
rformed for h
by a price el
t prices woul
market. Th
cipants wou
h SONGS w
xamining pr
ice elasticity
Wh and $6.0
Tab
Net Revenu
regone energ
CE’s estimat
downward b
hours in whi
lasticity assu
ld have been
he actual pric
uld have undo
was not exper
revious chan
y analysis yie
01/MWh on
-6-
ble XVII-1
ue Estimate
gy sales and
te for replac
by a price ela
ich SCE had
umption is ap
n lower if 2,1
ce reduction
oubtedly bid
riencing an e
nges in mark
elded an esti
a calendar m
associated n
ement energ
asticity assu
d a forecast n
ppropriate w
150 MW of b
that would h
d and operate
extended ou
ket prices as a
imated chang
month basis f
net revenue f
gy costs, exc
umption, and
net long posi
when conside
baseload SO
have been re
ed their reso
utage, but an
a result of ch
ge in averag
for 2012, wi
for SCE’s OM
cept that (i) t
d (ii) the opp
ition. Reduc
ering foregon
ONGS gener
ealized canno
ources differe
estimate of
hanges in lo
ge hourly ma
ith an averag
MA entries
the SP-15
ortunity cost
cing the SP-
ne energy
ration had
ot be known
ently in an
the impact
ads and
arket prices
ge hour price
t
n
e
-7-
impact of approximately $4.81/MWh for the February through December 2012 period when SONGS 1
Units 2 and 3 were both unavailable. 2
The estimated net energy revenue that was not realized as a result of foregone energy sales for 3
each hour in which a net long position is assumed to have existed if SONGS was available to operate 4
can be expressed using the following formula: 5
Q * (P – E – F) = Hourly Foregone Net Energy Revenue 6
Where, 7
Q = Portion of SCE’s forecast hourly net long position if SONGS had been available to operate, 8
adjusted for the 2.8% historical outage rate for SONGS (expressed in MWh); 9
P = daily average SP-15 index price (expressed in $/MWh); 10
E = estimated price elasticity impact of SONGS not being available to operate (expressed in 11
$/MWh); 12
F = the avoided cost of nuclear fuel (expressed in $/MWh). 13
Table XVII-2 provides SCE’s estimate of the foregone energy sales and associated net revenue 14
for 2012 for hours in which SCE was assumed to have a net long position had SONGS been available to 15
operate. 16
1
2
3
4
5
6
7
8
9
10
11
12
13
D. C
T
Procurem
charges a
Charge (T
of each L
total load
CPM cha
South (T
incurred
SCP pena
requirem
availabili
Capacity-Re
The SONGS
ment Mechan
are allocated
TAC) areas
LSE represen
d in the appli
arges associa
AC_SOUTH
Resource A
alty charges
ments. Becau
ity bonus pa
elated Cost E
outages are
nism (CPM)
d to Scheduli
in which the
nted by a Sch
icable TAC
ated with the
H). In contra
dequacy (RA
were incurr
use SCP pena
ayment, SCE
Tab
Estimate
associated w
charges wer
ing Coordina
e need for th
heduling Co
areas. SCE’
e SONGS ou
ast, CAISO
A) replacem
red for the U
alty charge p
E netted the S
-8-
ble XVII-2
with three for
re incurred a
ators for LSE
he CPM aros
oordinator in
’s customers
utages for TA
Standard Ca
ent capacity
Unit 3 outage
payments are
SCP availabi
rms of capac
as a result of
Es that serve
e. The char
n the applicab
s were alloca
AC East Cen
apacity Produ
y costs were
e pursuant to
e disbursed t
ility bonus p
city-related c
f the outages
e load in the
rges are alloc
ble TAC are
ated their loa
ntral (TAC_E
duct (SCP) pe
only incurre
the CAISO
to all RA res
payments it r
costs. CAIS
s at Units 2 a
Transmissio
cated on the
eas as a perce
ad ratio shar
ECNTR) an
enalty charg
ed for the Un
’s SCP tariff
sources that
received that
SO Capacity
and 3. CPM
on Access
actual load
entage of
re of these
d TAC
ges and SCE-
nit 3 outage.
ff availability
received an
t were
M
-
y
1
2
3
4
5
6
7
8
9
10
11
funded b
procured
not incur
status wa
does not
result of
E. O
T
in SCE’s
the SONG
below.
8 SCE’s
availabSCE’s$14,29
y SCE’s SC
d replacemen
r SCP penalt
as classified
subject the u
the SONGS
Other Marke
The majority
s estimates fo
GS outages
s total Unit 3 Sbility bonus pas portfolio. As92,658.
P penalty ch
nt RA capaci
ty charges or
as “planned
unit to such
outages is p
et-Related C
of the 2012
or replaceme
also are asso
CP penalty cha
ayments that w a result, the ne
harges for Un
ity for some
r give rise to
” as part of i
costs. A sum
provided in T
Tab
Cost Estima
market-rela
ent energy, f
ociated with
arges were $18were funded fro
et SCP penalty
-9-
nit 3.8 To re
of the SONG
o RA replace
its January 9
mmary of th
Table XVII-
ble XVII-3
ates
ated costs ass
foregone ene
additional c
8,582,403, whim the SONGS
y charges assoc
educe SCP p
GS Unit 3 R
ement capaci
9, 2012 refue
he capacity-r
3.
sociated with
ergy sales, an
costs, which
ich was offset bS Unit 3 SCP peciated with the
penalty charg
RA capacity.
ity costs bec
eling and ma
related costs
h the SONG
nd capacity-
are summar
by the receipt oenalty charges SONGS Unit
ges at Unit 3
The Unit 2
cause the uni
aintenance o
incurred in 2
GS outages ar
-related costs
rized in Tabl
of $4,289,745 for eligible RA3 outage in 20
3, SCE also
outage did
it’s outage
utage, which
2012 as a
re captured
s. However,
le XVII-4
SCP A resources in 12 were
h
,
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
S
period H
imbalanc
schedule
charges o
S
Units 2 a
CAISO’s
through t
resources
load cent
generatio
operating
W
SCE’s D
congestio
most of 2
revenue o
SCE beli
isolate C
CE incurred
our-Ending
ce energy ch
s for Unit 3
of $967,748
CE incurred
and 3 CRR h
s annual and
the CAISO’s
s to hedge po
ters. CRRs c
on deliveries
g.
When SONG
efault Load
on costs asso
2012 as a res
obligations.
ieves they sh
RR costs du
d net imbalan
17 on Janua
arges consis
for this perio
for the same
d Congestion
holdings. Mo
d monthly CR
s annual and
otential cong
can, howeve
s. Conversel
GS is operatin
Aggregation
ociated with
sult of its du
Although th
hould not be
uring periods
Tab
nce energy c
ary 31, 2012,
sted of the re
od, which w
e period.
n Revenue R
ost of SCE’s
RR allocatio
d monthly CR
gestion costs
er, yield nega
ly, CRRs can
ng and conge
n Point (DLA
the SONGS
al unit outag
hese charges
considered w
s of generatio
-10-
ble XVII-4
charges of $2
, through Ho
eceipt of $94
was netted ag
Rights (CRR)
s SONGS CR
n process. A
RR auction p
s associated
ative revenu
n produce re
estion is incu
AP), the SON
S energy deli
ges, SCE’s S
s may be ass
when estima
on unavailab
27,245 for th
our-Ending 2
40,503 reven
gainst SCE’s
) charges of
RRs are acqu
A limited am
process. CR
with energy
ue (i.e., incur
evenues even
urred betwee
NGS CRRs
iveries. Whi
SONGS CRR
sociated with
ating replace
bility becaus
he Unit 3 for
24 on Februa
nues for CAI
Real-Time
$9,640,009
uired at no c
mount of SON
RRs are acqu
y deliveries f
r charges) du
n when the g
en the SONG
provide reve
ile SONGS w
Rs have gene
h the on-goin
ement costs.
se of the hed
rced outage e
ary 1, 2012.
ISO Day-Ah
imbalance e
in 2012 for
cost through
NGS CRRs
uired for gen
from generat
uring periods
generation fa
GS generatio
enue that off
was unavaila
erally incurr
ng SONGS o
It is not rea
dge function
event for the
The net
head energy
energy
its SONGS
the
are procured
neration
tion nodes to
s of
acility is not
on nodes and
fset the
able for
red negative
outages,
asonable to
CRRs
e
d
o
d
-11-
provide. Moreover, CRR revenues and costs are not direct replacement costs or lost opportunity costs. 1
Finally, as a matter of equity, any attempt to include CRR costs in replacement value calculations should 2
be offset by the CRR revenues that the IOU receives for periods in which CRR revenue exceeds the 3
congestion cost for all resources in the IOU’s portfolio, regardless of their operating status. To do 4
otherwise would impose an inequitable risk on the IOU (i.e., an inappropriate “cherry picking” of CRR 5
benefits and costs), effectively creating an untenable situation in which the IOU is potentially subject to 6
bearing CRR-related costs during periods of outage, but IOU customers receive the benefit of CRR 7
revenues regardless of whether the generation plant was available to operate. CRRs provide a valuable 8
hedge for customers, and any replacement cost estimate should not create perverse disincentives for 9
IOUs to secure CRRs for their customers. 10
SONGS has numerous on-site electrical demand requirements that are served by station 11
generation when one or both units are operating. During a dual unit outage event, the auxiliary station 12
load is served through the CAISO’s Real-Time imbalance energy market. SCE’s ownership share of the 13
on-site plant energy costs were $7,089,443 in 2012 as a result of the SONGS outages. 14
SCE has incurred $101,786 of Participating Intermittent Resource Program (PIRP) allocation 15
charges (CAISO Charge Types 721 and 752) as a result of the SONGS outages. These charges are 16
assessed on net negative uninstructed deviations. SONGS incurs net negative uninstructed deviations 17
from SONGS auxiliary load use in the CAISO’s Real-Time market. 18
F. Treatment Of Planned Refueling And Maintenance Outages 19
Pursuant to I.12-10-013, SCE recorded its estimated replacement energy costs, foregone energy 20
sales net revenue, capacity-related costs, and other costs identified above in its SONGS OMA for the 21
entire duration of the outages of both SONGS units in 2012. For Unit 2 those costs and foregone net 22
energy revenues were calculated for the period beginning January 9, 2012, the first day of the scheduled 23
refueling and maintenance outage for the unit. For Unit 3 those costs and foregone net energy revenues 24
were calculated for the period beginning Hour-Ending 17 on January 31, 2012, which was the 25
commencement of the forced outage event for the unit. 26
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
A
sales net
revenues
normally
costs.9 In
refueling
considere
be consid
schedule
foregone
SONGS
estimated
identified
G. A
A
April 2, 2
estimated
$1,597,54 9 As not
the cothat SC
Although SCE
revenues in
for time per
y planned ref
n the case of
g and mainten
ed. Similarl
dered for the
d to be unav
energy sale
to accommo
d replacemen
d scheduled
Adjustments
As a result of
2013, testim
d 2012 capac
48. This adj
ted, SCE reservst impact of thCE’s operation
E has estima
its SONGS
riods during
fueling and m
f SONGS Un
nance outag
y, such costs
e period Octo
vailable for a
s net revenu
odate require
nt energy co
refueling an
s to Estimat
f invoice sett
ony on its es
city-related c
justment con
ves the right toe SONGS outa
ns at SONGS w
ated and reco
OMA as req
which the u
maintenance
nit 2, costs a
e period of J
s and forego
ober 8, 2012
a refueling an
ues would ha
ed refueling
osts and foreg
nd maintenan
Tab
ted 2012 Ma
tlement true-
stimated 201
costs and mi
nsists of a re
o present, in a sages that is notwere imprudent
-12-
orded its rep
quired I.12-1
units would h
e outages sho
and foregone
January 09, 2
one energy sa
2, through De
nd maintena
ave been incu
and mainten
gone energy
nce outage p
ble XVII-5
arket-Relate
-ups and upd
12 market co
iscellaneous
eduction of $
subsequent phat based on the ct and directly l
placement en
10-013, cost
have otherw
ould not be u
e energy sale
2012, throug
ales net reve
ecember 2, 2
ance outage.
urred regard
nance outage
y sales net re
eriods for SO
ed Costs As
dated analys
osts associate
market-rela
$340,935 for
ase of I.12-10-costs recordeded to the SON
nergy costs a
ts and forego
ise been una
utilized in ca
es net revenu
gh March 5,
enues for SO
2012, when t
Replaceme
dless of the o
es. Table XV
venues that
ONGS Units
ssociated wi
is performed
ed with the S
ated costs sho
r capacity-re
013, a methodin the OMA ifGS outages.
and foregone
one energy s
available due
alculating rep
ues during th
2012, shoul
ONGS Unit 3
the unit was
ent energy co
operating sta
VII-5 summa
were incurre
s 2 and 3 in
th SONGS
d after SCE
SONGS outa
ould be redu
lated costs (
ology for the cf the Commissi
e energy
ales net
e to
placement
he scheduled
ld not be
3 should not
s otherwise
osts and
atus of
arizes the
ed during the
2012.
submitted it
ages, SCE’s
uced by
see Table
calculation of ion determines
d
e
s
s
1
2
XVII-6)
SONGS
and a reduct
outages (see
tion of $1,25
e Table XVII
56,613 for m
I-7).
Tab
Tab
-13-
miscellaneous
ble XVII-6
ble XVII-7
s market-relaated chargess associated with the