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

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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