rebuttal testi mony in phase · 2 1 the context of the market-based framework in which sce operates...

ApplicatiExhibit NWitnesse

ion No.: No.: es:

I.12-10SCE-37Colin C

Rebut

Before the

Public Uti

0-013 7 Cushnie

(U

ttal Testi

e

ilities Comm

U 338-E)

imony in

mission of th

n Phase

he State of C

1a

California

Roseemead, CalifJuly 24,

fornia2013

Rebuttal Testimony in Phase 1a

Table Of Contents

Section Page Witness

-i-

I. SONGS 2012 RECORD PERIOD REBUTTAL TESTIMONY .......................1 C. Cushnie

A. Overview Of Market-Related Costs Associated With The SONGS Outages ....................................................................................1

B. Definition Of Replacement Energy Costs ..............................................2

C. Re-stated Replacement Energy Cost Estimate .......................................6

D. Re-stated Foregone Energy Sales Net Revenue Estimate ......................8

E. Re-statement Of The Treatment Of Planned Refueling And Maintenance Outages ...........................................................................10

F. Other Market-Related Cost Estimates .................................................10

1. Congestion Revenue Rights .....................................................12

2. Auxiliary Load Costs and Associated PIRP Allocation Charges ...................................................................14

G. Miscellaneous TURN Proposals ..........................................................15

1. Price Benchmarks ....................................................................15

2. Demand Response ....................................................................17

3. NEIL Claims ............................................................................18

4. Alleged Downward Biases In SCE’s Estimates.......................18

H. WEM’s Supplemental Testimony ........................................................20

1. Establishing 2011 Market Costs As A Cap On 2012 Market Costs ............................................................................20

2. Use Of Preferred Resource Costs As A Replacement Cost Benchmark .................................................20

3. Use Of Energy Efficiency Funding..........................................21

4. Quantifying GHG And Emission Costs ...................................21

5. Examination Of Market Price Spikes ......................................22

6. Unit 2 Nuclear Fuel ..................................................................22


Table Of Contents (Continued)

Section Page Witness

-ii-

7. Costs Associated With Market Gaming By JP Morgan .....................................................................................22

8. Huntington Beach Power Plant Costs ......................................23

Appendix A Witness Qualifications ................................................................................


List Of Tables

Table Page

-iii-

Table I-1 Illustrative Examples of Replacement Energy Cost Calculations ................................................4

Table I-2 SONGS OII-2012 OMA Entries for Replacement Energy Costs ................................................8

Table I-3 SONGS OII-Separate Reporting of Forgone Excess Energy Sales .............................................9

Table I-4 Estimated Replacement Energy Costs and Forgone Energy Sales Net Revenue

During Scheduled Outages ..................................................................................................................10

Table I-5 Updated 2012 Miscellaneous Market-Related Costs .................................................................11

1

I. 1

SONGS 2012 RECORD PERIOD REBUTTAL TESTIMONY 2

A. Overview Of Market-Related Costs Associated With The SONGS Outages 3

Southern California Edison Company (SCE) submits this rebuttal testimony to the reply 4

testimony of Division of Ratepayer Advocates (DRA)1 and The Utility Reform Network (TURN),2 and 5

to the supplemental testimony of Women’s Energy Matters (WEM)3 on the market-related costs 6

associated with the San Onofre Nuclear Generating Station (SONGS) outages in 2012. This rebuttal 7

testimony supplements SCE’s Energy Resource Recovery Account (ERRA) Review Of Operations, 8

2012, Chapter XVII (Updated) testimony, dated July 8, 2013 (SCE 2012 Updated ERRA Testimony),4 9

and SCE’s Rebuttal to TURN’s Testimony dated April 22, 2013 (SCE Rebuttal to TURN),5 unless 10

explicitly indicated. 11

As a general matter, the scope of Phase 1a of the Commission’s Order Instituting Investigation 12

Regarding San Onofre Nuclear Generating Station Units 2 and 3 (I.12-10-013) is limited to the 13

quantification of what have been deemed as the 2012 “replacement power costs” associated with the 14

SONGS outages. Recovery of ERRA-eligible costs determined in Phase 1a to be SONGS-related will 15

be addressed in Phase 3 of I.12-10-013.6 However, any consideration in Phase 3 of the recovery of 16

SCE’s ERRA-eligible costs determined to be associated with the SONGS outages should be examined in 17

1 Reply Testimony on San Onofre Nuclear Generating Station (SONGS) 2012 Replacement Power Cost Calculation

Method, I.12-10-013/A.13-04-001, Exhibit No. DRA-02, Witness Y. Lasko, dated July 10, 2013. (DRA Reply Testimony)

2 Reply Testimony of Kevin Woodruff on Behalf of The Utility Reform Network Addressing Replacement Power Costs Incurred in 2012 Due to Outages at the San Onofre Nuclear Generating Station, Phase 1, I.12-10-013, Witness Kevin Woodruff, dated July 10, 2013. (TURN Reply Testimony)

3 Women’s Energy Matters Supplemental Testimony on Replacement Resources, I.12-10-013, Witness Barbara George, dated July 10, 2013. (WEM Supplemental Testimony)

4 Energy Resource Recovery Account (ERRA) Review of Operations, 2012, Chapter XVII (Updated), A.13-04-001 (consolidated into I.12-10-013), Exhibit No. SCE-03 (Updated), Witness C. Cushnie, dated July 8, 2013.

5 SCE’s Rebuttal to TURN’s Testimony, I.12-10-013, Exhibit No. SCE-8, Witness Colin Cushnie, dated April 22, 2013.

6 See ALJ Wilson’s electronic ruling dated July 9, 2013. See also, e.g., I.12-10-013, Phase 1A Hearing Room Ground Rules, dated July 22, 2013 (“The scope of Phase 1A does not include . . . argument about who should bear the costs of replacement power (this will be decided in Phase 3) . . . .”).

2

the context of the market-based framework in which SCE operates utility-owned cost-of-service 1

generation and the Commission’s findings in Phase 2 of this proceeding (I.12-10-013).7 SCE reserves 2

the right to present in Phase 3 its definition of the type and amount of costs that should properly be 3

considered for cost recovery in SCE’s regulated cost-of-service ratemaking framework, given the 4

competitive wholesale market environment in which utility-owned assets operate. 5

Intervenor testimony in Phase 1a conflates, at times, the “quantification” of 2012 power 6

procurement costs associated with the SONGS outages that is the objective of Phase 1a, and any cost 7

recovery determination that is properly scoped for Phase 3 of this proceeding. Accordingly, this rebuttal 8

testimony does not generally address cost recovery proposals that are outside the scope of Phase 1a. 9

However, SCE does address in a limited manner certain cost recovery proposals that are presented by 10

intervenors as the basis for recommended calculations of replacement energy costs. 11

B. Definition Of Replacement Energy Costs 12

TURN argues that “replacement power costs” should be defined broadly to include the economic 13

harm the SONGS outages had on SCE’s customers due directly or indirectly to the SONGS outages.8 14

TURN’s general premise that replacement power costs should be broadly defined as the economic harm 15

that is directly or indirectly incurred by SCE’s customers as a result of the SONGS outages should be 16

rejected as being inconsistent with the direction provided in I.12-10-013. TURN’s proposal is also 17

inconsistent with a practical interpretation of the concept of replacement energy for forced outages. 18

TURN is essentially arguing that a utility should be held potentially responsible for all the direct and 19

indirect costs associated with a forced plant outage. This is an extreme position. Traditionally, a 20

7 Prior to California’s electric industry restructuring in April 1998, SCE owned or controlled sufficient resources to meet

all of its planned electrical energy demands, and the costs of such were recovered from all SCE customers. In the event of a forced outage, SCE would rely on a less economic resource within its portfolio to meet its customers’ requirements. The cost impact of such an outage would be the difference in production cost between the committed unit(s) and the unit on forced outage. In the current electric market structure, a generation unit on forced outage cannot participate in the market, but SCE continues to procure all of its bundled customers’ demand from the California Independent System Operator’s organized markets. Accordingly, the Commission’s Phase 3 determinations should take into account the changes in market structure in which utility cost-of-service generation assets currently participate.

8 TURN’s Reply Testimony, pages. 4, 13-15, and 20.

3

replacement energy cost calculation would consider the incremental fuel and/or energy a utility utilized 1

to serve load as a result of an outage. For example, if a 200 MW gas-fired power plant was not able to 2

operate for a specified period of time, but would have otherwise been utilized to serve customer demand, 3

the utility would have needed to operate another power plant and/or purchase replacement energy. In 4

this example, the replacement power cost would have been the difference between (i) the cost of 5

operating the unavailable 200 MW gas-fired power plant and (ii) the cost of operating the replacement 6

power plant or the purchase expense of the replacement energy.9 If a replacement gas-fired power plant 7

was utilized, the replacement power cost would have essentially been the difference in fuel burn, i.e., the 8

increased fuel burned by utilizing a replacement power plant with a higher heat rate.10 This difference in 9

fuel burn would generally be a small fraction of the overall generation cost of the replacement gas-fired 10

power plant. Similarly, if the utility made a market purchase for the 200 MW of needed energy for the 11

outage period, the difference in cost between (i) the avoided fuel burn and (ii) purchase of replacement 12

energy would be considered the replacement energy cost. This difference would also generally be a 13

small fraction of the total purchase cost of the replacement energy. Table I-1 provides an illustrative 14

example for these calculations. 15

9 In practice, a combination of replacement power plant generation and purchased power could be employed to replace the

output of an unavailable power plant. For simplicity, this discussion explains the cost differences assuming that the replacement energy need is met entirely with a replacement power plant or exclusively from replacement purchased power.

10 Minimal variable operating cost differences may also be realized.

1

2

3

4

5

6

7

8

9

T

stark con

inconsist

market-re

power ex

3 of I.12-

outages,

costs be c

inconsist

Illu

TURN’s prop

ntrast to the t

tent with the

elated negati

xpense,” whi

-10-013 rega

but its attem

considered “

tent with the

ustrative Ex

posal to cons

traditional ca

general con

ive conseque

ich is overly

arding SCE’

mpt to circum

“replacemen

concept of r

xamples of R

sider all dire

alculation of

ncept of repla

ences of the

broad and p

s ability to r

mvent this Ph

t power cost

replacement

4

Table

Replaceme

ct and indire

f replacemen

acement ene

SONGS out

punitive. TU

recover any m

hase 3 consid

ts” at the out

t energy cost

e I-1

ent Energy

ect costs as r

nt energy cos

ergy costs. T

tages should

URN can ma

market-relat

deration by p

tset should b

ts.

Cost Calcu

replacement

sts, and shou

TURN is effe

d be consider

ake any argum

ted costs asso

proposing th

be rejected a

ulations

power costs

uld be reject

fectively argu

red a “replac

ment it wish

ociated with

hat all direct

as premature

s stands in

ed as being

uing that all

cement

hes in Phase

h the SONGS

and indirect

and

S

t

5

For purposes of Phase 1a of I.12-10-013, replacement energy costs should be limited to the costs 1

that SCE incurred to replace lost SONGS generation for hours in which SCE had a “short” energy 2

position in the California Independent System Operator’s (CAISO) Integrated Forward Market (IFM).11 3

Presumably in recognition of the market environment in which California investor-owned utilities 4

(IOUs) now operate, the Commission required SCE to separately report in its OMA its “replacement 5

generation costs,” “all excess energy sales foregone (actual or estimated),” and “the costs of other 6

energy products or services to provide reliable electric service during the period of the outage (including 7

Demand Response programs).”12 Contrary to TURN’s expansive definition of “replacement power 8

costs,” the Commission has attempted to separate the market-related costs associated with the SONGS 9

outages into three general buckets: (1) costs related to replacing SONGS energy to meet customer 10

demand; (2) the opportunity cost associated with foregone energy sales (i.e., foregone net revenue 11

associated with the sale of SONGS energy when SCE’s bundled customer portfolio would have been 12

long had SONGS been operating); and (3) other market-related costs incurred to maintain reliable 13

electric service as a result of the SONGS outages. SCE’s OMA reporting and presentation of costs in its 14

2012 ERRA Review proceeding and I.12-10-013 testimony submittals have attempted to maintain 15

consistency and compliance with these three cost categories.13 TURN’s attempt to categorize all direct 16

and indirect market-related costs as “replacement power costs” is inconsistent with the Commission’s 17

stated scope for Phase 1a of I.2-10-013 and the direction provided in I.12-10-013 to separately report 18

replacement energy costs, foregone energy sales, and other market-related costs to ensure reliable 19

electric service. Accordingly, TURN’s proposals in this regard should be rejected. 20

11 See SCE 2012 Updated ERRA Testimony, pages. 1-3.

12 I.12-10-013, dated October 25, 2012, pages 10-13.

13 SCE provides a formulaic estimate of its replacement energy costs for all its assessed “short” hourly energy positions and a formulaic estimate of its foregone energy sales net revenue for all its assessed “long” hourly energy positions. The balance of SCE’s costs estimates, including SCE’s capacity-related costs, are categorized as belonging in SCE’s “other” market-related cost estimates. In contrast, DRA and TURN usually refer to “replacement power costs,” and seek to include all three categories of market-related costs into their expansive definition.

6

C. Re-stated Replacement Energy Cost Estimate 1

DRA proposes that the avoided cost of nuclear fuel that SCE subtracted from its calculation of 2

estimated replacement energy costs be eliminated because SONGS Units 2 & 3 will not be returned to 3

service.14 SCE concurs with DRA’s proposal. At the time SCE recorded its estimated 2012 replacement 4

energy costs in SCE’s SONGS Outage Memorandum Account (OMA) and presented its initial 5

testimony on this matter in April 2013, SCE was attempting to return SONGS Units 2 & 3 to service. In 6

light of SCE’s June 7, 2013, announcement that it will be permanently closing SONGS Units 2 & 3, it is 7

no longer appropriate to retain the avoided nuclear fuel adjustment SCE employed in its estimate of 8

replacement energy costs.15 9

DRA also identifies an error in a worksheet in SCE’s calculation of the 10-year historical outage 10

rate for SONGS.16 SCE concurs with DRA that the worksheet contained an error for one of the reported 11

forced outages, and that the correct 10-year historical forced outage rate is 2.15%, instead of the 2.8% 12

rate that SCE originally utilized. However, SCE contests DRA’s recommendation to remove two forced 13

outage events from the calculation of the 10-year historical outage rate for SONGS because of DRA’s 14

assertion that the two outage events are outliers.17 SCE also disagrees with DRA that use of a 5-year 15

historical forced outage rate is a better indicator of the expected availability of SONGS than SCE’s 16

proposed use of a 10-year period. 17

Forced outages occur for numerous reasons and for varying durations. Arbitrarily removing the 18

two longest-duration outages from the 10-year historical outage period as DRA proposes will result in a 19

higher-than-realized historical availability factor. DRA does not present any affirmative evidence to 20

support the removal of the two longest-duration outages from the calculation of the historical forced 21

outage rate for SONGS, and its proposal to do so should therefore be rejected. Similarly, DRA’s 22

14 DRA Reply Testimony, pages 8-9.

15 In Phase 2, SCE is presenting its proposal for amortization of nuclear fuel costs in rates, along with a carrying cost consistent with existing ratemaking.



7

proposal to limit the historical availability calculation to the most recent five-year period seems to be 1

outcome-based, as the 5-year average yields a forced outage rate of 1.21% compared to the corrected 10-2

year forced outage rate of 2.15%. Although there is not a definitive time period in which one should 3

calculate historical outage rates, DRA’s proposal to use a much shorter time period, or alternatively, 4

eliminate the longest-duration outages from a 10-year calculation period, should be rejected as outcome-5

oriented and inferior to the use of actual data over a reasonably sufficient period of time. By way of 6

comparison, the SONGS 10-year forced outage rate of 2.15% is consistent with the approximate 2% 7

forced outage rate that the Nuclear Regulatory Commission reports is the U.S. nuclear industry average 8

for the most recent 10-year and 5-year historical periods.18 9

Based on the foregoing, the estimated replacement energy cost for each hour in which a net short 10

position is assumed to exist can be expressed using the following formula: 11

Q * P = Hourly Replacement Energy Cost 12

Where, 13

Q = Portion of SCE’s forecast hourly net short position which could be attributed to the SONGS 14

outages, adjusted for the 2.15% historical outage rate for SONGS (expressed in MWh); and 15

P = daily average SP-15 index price (expressed in $/MWh). 16

As a result of removing the avoided cost of nuclear fuel from SCE’s estimate of replacement 17

energy costs and correcting the 10-year forced outage rate as described above, SCE’s estimate of 2012 18

replacement energy costs associated with the 2012 SONGS outages increases from $200,597,24519 to 19

$259,222,843. Table I-2 provides the monthly and annual sum for 2012 replacement energy costs 20

associated with the SONGS outages.20 21

18 Nuclear Regulatory Commission, Policy Issue Information, Fiscal Year 2012 Results of the Industry Trends Program for

Operating Power Reactors, SECY-13-0038, Enclosure 1, Fiscal Year 2012 Long-Term Industry Trend Results, Figure 5, page 3. The 10-year forced outage rate for 2003 to 2012 calculates to 2.01% and the five-year forced outage rate for 2008 to 2012 calculates to 1.98%. See www.nrc.gov/reading-rm/doc-collections/commission/secys/2013/2013-0038scy.pdf.

19 SCE 2012 Updated ERRA Testimony, page 6.

20 Table I-2 replaces Table XVII-1 of the SCE 2012 Updated ERRA Testimony.

1

2

3

4

5

6

7

8

9

10

11

12

D. R

S

nuclear f

adjustme

the estim

in which

expressed

Q

Where,

Q

adjusted

P

SO

Re-stated Fo

imilar to the

fuel cost com

ents should b

mated net ene

a net long p

d using the f

Q * (P – E) =

Q = Portion o

for the 2.15%

= daily aver

ONGS OII-2

oregone Ene

e re-statemen

mponent and

be performed

ergy revenue

position is as

following for

= Hourly For

of SCE’s for

% historical

rage SP-15 i

2012 OMA

ergy Sales N

nt of SCE’s e

correcting th

d on SCE’s e

e that was no

ssumed to ha

rmula:

regone Net E

ecast hourly

outage rate

index price (

8

Table

Entries for

Net Revenue

estimate of r

he 10-year f

estimate of f

ot realized as

ave existed if

Energy Reve

y net long po

for SONGS

(expressed in

e I-2

r Replacem

e Estimate

replacement

forced outag

foregone ene

s a result of f

f SONGS w

enue

osition if SON

(expressed

n $/MWh); a

ment Energy

t energy cost

ge rate, SCE

ergy sales ne

foregone ene

was available

NGS had be

in MWh);

and

y Costs

ts to remove

concurs that

et revenue. A

ergy sales fo

to operate c

een available

the avoided

t the same

Accordingly

or each hour

can be

e to operate,

d

,

1

2

3

4

5

6

7

E

$/MWh).

A

rate as de

outages i

foregone

a net long

21 SCE 2

22 Table

E = estimated

.

As a result of

escribed abo

increases fro

energy sale

g position ha

SON

2012 Updated E

I-3 replaces Ta

d price elasti

f removing th

ove, SCE’s e

om $95,304,8

s and associ

ad SONGS b

NGS OII-Se

ERRA Testimo

able XVII-2 of

icity impact

he avoided c

stimate of 20

82521 to $13

iated net reve

been availab

eparate Rep

ony, page 8.

f the SCE 2012

9

of SONGS n

cost of nucle

012 foregon

1,347,158.

enue for 201

ble to operate

Table

porting of F

2 Updated ERR

not being av

ear fuel and c

ne energy sal

Table I-3 pr

12 for hours

e.22

e I-3

Forgone Ex

RA Testimony.

vailable to op

correcting th

les associate

rovides SCE

in which SC

xcess Energ

.

perate (expre

he 10-year fo

d with the 2

’s estimate o

CE was assum

gy Sales

essed in

orced outage

012 SONGS

of the

med to have

e

S

e

10

E. Re-statement Of The Treatment Of Planned Refueling And Maintenance Outages 1

As a result of SCE’s re-statement of its estimated replacement energy costs and foregone energy 2

sales net revenue described above, SCE has to make corresponding revisions to its estimate of such costs 3

and foregone revenue during periods in which SONGS Units 2 and 3 would have otherwise been 4

scheduled for planned refueling and maintenance outages.23 In the case of SONGS Unit 2, replacement 5

energy costs and foregone energy sales net revenues during the scheduled refueling and maintenance 6

outage period of January 9, 2012, through March 5, 2012, should not be considered. Similarly, the 7

replacement energy costs and foregone energy sales net revenues for SONGS Unit 3 should not be 8

considered for the period October 8, 2012, through December 2, 2012, when the unit was otherwise 9

scheduled to be unavailable for a refueling and maintenance outage. Table I-4 provides the estimated 10

replacement energy costs and foregone energy sales net revenues that were incurred during the identified 11

scheduled refueling and maintenance outage periods for SONGS Units 2 and 3 in 2012.24 12

Table I-4

Estimated Replacement Energy Costs and Forgone Energy Sales Net Revenue During

Scheduled Outages

F. Other Market-Related Cost Estimates 13

The majority of the 2012 market-related costs associated with the SONGS outages are captured 14

in SCE’s estimates for replacement energy, foregone energy sales, and capacity-related costs. However, 15

23 See SCE 2012 Updated ERRA Testimony, pages 11-12 for more detail.

24 Table I-4 supercedes Table XVII-5 and Table XVII-7 of the SCE 2012 Updated ERRA Testimony.

Scheduled Refueling & Maintenance Outage

Replacement Energy Costs

Forgone Energy Sales Net Revenue Total

Unit 2 (01/09/12 through 03/04/12) $13,307,056 $13,100,266 $26,407,322 Unit 3 (10/08/12 through 12/02/12) $34,905,029 $4,513,655 $39,418,684

Total $48,212,084 $17,613,922 $65,826,006

11

SCE also provided estimates of other market-related costs pursuant to the OMA reporting requirements 1

of I.12-10-013.25 SCE originally provided an estimate of $16,858,483 for miscellaneous 2012 market-2

related costs associated with the SONGS outages.26 In SCE 2012 Updated ERRA testimony, SCE 3

provided a net negative adjustment of $1,256,613 for these same miscellaneous market-related costs as a 4

result of subsequent settlement true-ups and additional cost estimate analysis.27 SCE has since 5

performed additional review and analysis that has resulted in a further reduction of $4,334 to its estimate 6

of Participating Intermittent Resource Program (PIRP) allocation charges. The net resulting estimate of 7

$15,597,536 for miscellaneous 2012 market-related charges associated with the SONGS outages is 8

provided in Table I-5. 9

Table I-5

Updated 2012 Miscellaneous Market-Related Costs

These “other” market-related costs are associated with the SONGS outages, but for the most part, 10

they were not incurred to replace SONGS generation to meet bundled customer demand. The on-site 11

auxiliary load costs and associated PIRP allocation charges were incurred to maintain safe plant 12

operations (e.g., cooling pump load).28 The congestion revenue rights (CRRs) charges were incurred for 13

25 SCE 2012 Updated ERRA Testimony, pages 9-13.

26 Energy Resource Recovery Account (ERRA) Review of Operations, 2012, Chapter XVII, A.13-04-001 (consolidated into I.12-10-013), Exhibit No. SCE-03, dated April 2, 2013, page 10.

27 SCE 2012 Updated ERRA Testimony, pages 12-13.

28 SONGS auxiliary load is served by the on-site generation when one or both units are operating, but has to be served through the CAISO’s imbalance energy market when both units are unavailable.

Charge Description Amount

Real‐Time Imbalance Energy Charges for Day‐Ahead Schedule Deviations $39,208

Congestion Revenue Rights Charges $9,936,084

On‐site Auxiliary Load Costs $5,524,919

PIRP Allocation Charges to SONGS $97,325

Total Adjustment $15,597,536

Updated 2012 Miscellaneous Market‐Related Costs Associated with the SONGS Outages

12

CRRs that were acquired prior to the SONGS outages, and therefore the concept of replacement energy 1

costs does not apply. Only the real-time imbalance energy charges for the Day-Ahead schedule 2

deviations for the January 31, 2012 to February 1, 2012 period for Unit 3 (i.e., the first two days of the 3

Unit 3 forced outage) were related to replacing energy that was intended to benefit bundled customers. 4

In contrast, DRA and TURN contend that all the market-related costs SCE identified should be 5

included in the calculation of “replacement power costs.” DRA’s and TURN’s arguments fail for 6

numerous reasons, including the reasons provided above in Section B which addresses an appropriate 7

definition of replacement energy cost. DRA’s and TURN’s arguments are, at best, suited for 8

consideration in Phase 3 of I.12-10-013 when the Commission will address cost recovery issues. 9

Nonetheless, SCE rebuts below the expansive definition of “replacement power costs” that DRA and 10

TURN propose. 11

1. Congestion Revenue Rights 12

DRA and TURN argue that CRR charges should be considered a component of SCE’s 13

“replacement power costs.”29 As SCE has described in previous testimony, CRRs are a financial hedge 14

and should not be considered a component of SCE’s replacement energy costs. As an initial matter, 15

SCE’s SONGS CRRs were acquired prior to the SONGS outages and therefore do not constitute 16

replacement energy expense.30 SCE’s SONGS CRRs normally provide revenue to offset the marginal 17

cost of congestion to deliver SONGS energy to load. During the SONGS outages, however, SCE’s 18

SONGS CRRs incurred net charges in the amount of $9,936,084 for 2012. SCE suspects that DRA and 19

TURN would not be advocating to include the net value of SCE’s SONGS CRRs in SCE’s estimate of 20

replacement energy costs if the CRRs yielded net revenues in 2012. Indeed, it stands to reason that 21

many of SCE’s financial hedges that were entered into prior to the SONGS outages yielded greater value 22

29 DRA Reply Testimony, pages 5-6. TURN Reply Testimony, pages 16-17.

30 As a result of load migration between Scheduling Coordinators that operate within the CAISO’s organized markets, the CAISO performs monthly minimal adjustments to SCE’s CRR holdings, including SCE’s SONGS CRR holdings. The CAISO performed load migration adjustments on SCE’s SONGS CRRs subsequent to the SONGS outages, but the resulting change in SCE’s SONGS CRR holdings were negligible.

13

as a result of the SONGS outages, but DRA and TURN have not advocated that SCE’s estimate of 1

replacement energy costs be reduced by the calculated benefit. Instead, DRA and TURN are 2

inappropriately “cherry picking” the SONGS CRRs because they have yielded a net cost for 2012. Such 3

an outcome-based argument should be rejected. 4

To the extent that any consideration is provided to DRA’s and TURN’s proposal to treat 5

the 2012 SONGS CRR congestion charges as replacement energy costs, and SCE is ultimately not 6

allowed to recover such costs in Phase 3 of I.12-10-013, SCE contends that as a matter of equity all 7

CRR revenue and charges realized by SCE during hours in which the CRR-associated resource was not 8

operating should be retained by SCE, regardless of the availability status of the resource.31 To do 9

otherwise puts SCE in an untenable cost recovery position, and presents a significant disincentive for 10

SCE to acquire CRRs for the benefit of bundled customers. CRRs provide a valuable hedge for 11

customers, and any replacement energy cost estimate methodology should not create perverse 12

disincentives for IOUs to secure CRRs for their customers. 13

Finally, TURN’s claim that the 2012 SONGS CRR charges should be considered a 14

component of SCE’s “replacement power costs” because SCE categorized the CRR charges as “market-15

related” should be rejected.32 As previously explained, the Commission has required SCE to identify all 16

market-related costs related to the SONGS outages. As a result, SCE’s identification of all market-17

related costs does not mean that parties should assume that SCE agrees that the entirety of the costs 18

should be considered to be a component of SCE’s replacement energy costs. SCE has separated the 19

SONGS market-related costs into the replacement energy cost, foregone energy sales net revenue, and 20

“other” market-related cost categories as required by the Commission (SCE considers its reported 21

capacity-related costs to be a component of the “other” market-related cost category). SONGS CRR 22

31 For example, SCE’s Mountainview Generating Station Unit 3 realized $272,364 of net CRR revenue and SCE’s

contracted Blythe Energy PPA realized $472,789 of net CRR revenue during hours on non-operation in 2012. Using DRA’s and TURN’s logic, SCE’s shareholders should retain these net revenues because the power plants were not operating at the time the revenues were realized.

32 TURN Reply Testimony, page 17.

14

charges fall squarely into the “other” market-related cost category. Contrary to TURN’s argument, not 1

all “market-related” costs should be considered replacement energy costs. 2

2. Auxiliary Load Costs and Associated PIRP Allocation Charges 3

DRA and TURN contend that auxiliary load costs and the associated PIRP allocation 4

charges should be included in the calculation of SCE’s “replacement power costs.”33 SONGS has 5

numerous on-site electrical demand requirements that are served by station generation when one or both 6

units are operating. During a dual-unit outage event, the auxiliary station load is served through the 7

CAISO’s Real-Time imbalance energy market. SCE originally reported its 2012 ownership share of the 8

on-site plant energy costs as $7,089,443, but this estimate was erroneously provided on a 100% plant 9

cost basis.34 Based on revised CAISO settlement statements, the total current auxiliary load costs are 10

$7,064,210 (100% Level) compared to the previously submitted $7,089,443. Therefore, SCE’s actual 11

ownership share of the 2012 auxiliary load costs as a result of the SONGS outages was $5,524,919. 12

As a result of correcting SCE’s ownership share of the total 2012 SONGS on-site 13

auxiliary load costs incurred as a result of the SONGS outages, SCE also had to update its estimate of 14

the allocation of PIRP allocation charges (CAISO Charge Types 721 and 752). PIRP charges are 15

assessed on net negative uninstructed deviations. SONGS incurs net negative uninstructed deviations 16

from the SONGS auxiliary load that is served in the CAISO’s Real-Time market. The revised lower 17

estimate of auxiliary load costs resulted in a lower estimate of allocated PIRP charges associated with 18

the SONGS outages. SCE’s updated estimate for PIRP charges associated with the SONGS outages is 19

$97,325.35 20

33 DRA Reply Testimony, pages 4-5. TURN Reply Testimony, pages 9-10.

34 See SCE 2012 Updated ERRA Testimony, pages 11-12 for more detail.

35 SCE’s updated estimate of $97,325 does not equate to the sum of the PIRP allocation charges that SCE provided in Table XVII-4 and Table XVII-7 of the SCE 2012 Updated ERRA Testimony because Table XVII-4 was originally provided without a PIRP allocation charge estimate for December 2012, and the updated adjustment provided in Table XVII-7 inadvertently failed to fully capture the PIRP allocation charge estimated for December 2012.

15

Auxiliary load costs and associated PIRP allocation charges were incurred as a result of 1

the need to replace on-site SONGS generation. However, these costs were not incurred to meet bundled 2

customer demand. Instead, these costs were incurred to maintain safe plant operations while SCE 3

attempted to return the SONGS units to service. As such, they do not meet the traditional replacement 4

energy cost definition of replacing unavailable generation to serve customer load. SCE believes the 5

consideration of these replacement energy costs is unique to SONGS because of the magnitude of the 6

auxiliary load requirements at a nuclear generation station. Rather than combine the SONGS auxiliary 7

load costs and associated PIRP allocation charges with SCE’s estimate of replacement energy costs 8

incurred to meet bundled load requirements, SCE recommends that these costs be classified as 9

reliability-based costs, and be considered accordingly in the context of “other” market-related costs 10

incurred for reliability-based reasons (e.g., Demand Response to bolster grid reliability in the western 11

sub-area of the Los Angeles Basin). 12

G. Miscellaneous TURN Proposals 13

1. Price Benchmarks 14

TURN continues to advocate that SCE utilize Default Load Aggregation Point (DLAP) 15

prices for SCE’s estimate of replacement energy costs and foregone energy sales net revenue. TURN 16

has not provided an affirmative rationale for doing such, and instead cites SCE’s previous testimony 17

indicating that “SP-15 index prices are also a reasonable proxy for SCE’s DLAP within the CAISO’s 18

control area, which is the load weighted price that SCE pays the CAISO to serve its bundled load.” 36 19

TURN’s reliance on this SCE statement is misplaced, as SCE provided multiple reasons as to why the 20

use of an SP-15 day-ahead index price is the most appropriate benchmark, and was only indicating that 21

SP-15 day-ahead index prices are similar to SCE DLAP prices in that both are day-ahead prices and 22

reflect the market cost impact of the SONGS outages.37 Moreover, the use of the SCE DLAP price to 23

estimate foregone energy sales net revenue would be conceptually inaccurate because generation sales 24

36 TURN Reply Testimony, pages 20-21.

37 Exhibit No. SCE-03 (updated), page 3.

16

are made at the generator’s generation price node within the CAISO market, or relative to a generation 1

or bilaterally-traded price index (such as the day-ahead SP-15 index proposed by SCE). The SCE 2

DLAP price represents the load-weighted price that SCE’s load pays, and would not be the price basis 3

for generation that SCE could have sold from SONGS. 4

The use of the day-ahead SP-15 index price is a reasonable benchmark given the many 5

ways and timeframes in which SCE procures to meet customer demand. SCE’s bundled customer 6

portfolio is actively managed within a five-year window. SCE conducts periodic solicitations for 7

seasonal, annual and multi-year products. SCE also trades for annual, quarterly, monthly, intra-month, 8

daily, and hourly products. SCE’s forecast of its net open position is also continuously being reassessed 9

and updated. As a result, there is not a single, static price benchmark that is reflective of SCE’s 10

incremental cost to serve bundled customer demand or replace generation due to the unavailability of 11

specific generation units. However, SCE contends that the use of day-ahead SP-15 index prices is most 12

representative of the short-term markets in which SCE transacts to both serve load and sell generation. 13

TURN and DRA seem to concur that the use of the day-ahead CAISO IFM hourly 14

generation node prices for SONGS Units 2 & 3 would not appropriate because those prices would not be 15

reflective of the value of SONGS generation during an outage because the units are not operating. 16

Additionally, generation node prices tend to be lower than DLAP prices. This creates a challenge when 17

the purpose of the price benchmark is to price both the replacement energy cost to meet load and the 18

opportunity cost of foregone energy sales of excess generation. Rather than selecting a purely 19

generation-based price index (such as the SONGS generation nodes or the CAISO’s Existing Zone 20

Generation (EZ Gen) Trade Hub price), or a purely load-based price point such as the SCE DLAP 21

(which TURN advocates), SCE has proposed using the Platt’s SP-15 day-ahead index price.38 Day-22

ahead index prices reflect the market price that both buyers and sellers were willing to transact hours 23

prior to the operation of the CAISO’s Day-Ahead IFM, and is a market in which SCE regularly transacts 24

38 DRA supports SCE’s use of Platt’s SP-15 Day-Ahead index price. DRA Reply Testimony, pages 6-8.

17

to reduce its net open position prior to the CAISO daily IFM. SP-15 day-ahead index prices are 1

commonly used to settle financial transactions for energy transacted for delivery in southern California, 2

and provide a reasonable balance between the load-based DLAP purchase price benchmark and the 3

generation-based sales price benchmark of SP-15 EZ Gen Trade Hub or individual generation price 4

nodes. 5

2. Demand Response 6

TURN proposes that the approximate $2.8 million of Demand Response costs SCE 7

incurred and recorded in its SONGS OMA be considered “replacement power costs” on the grounds that 8

the costs were incurred as a result of the SONGS outages.39 As SCE has explained previously, TURN is 9

seeking an inappropriately broad definition of replacement energy costs. The subject Demand Response 10

costs were incurred by SCE to enhance the local area reliability of the western sub-area of the LA Basin 11

electrical grid. These costs were not incurred to meet an hourly net short position for SCE’s bundled 12

customer portfolio. The Commission may elect to consider SCE’s eligibility to recover these costs in 13

Phase 3 of I.12-10-013, but the Commission should not find in Phase 1a that these reliability-based 14

Demand Response costs are replacement energy costs to serve bundled customer demand. 15

TURN also suggests that the Demand Response costs were “a substitute for SONGS 16

capacity,” which means they should potentially be treated similar to SCE’s other capacity costs. This 17

argument is flawed. SCE’s reported capacity-related costs are attributable to California’s Resource 18

Adequacy (RA) program. SCE procured replacement RA capacity and incurred Standard Capacity 19

Product (SCP) charges for its SONGS RA capacity as a result of the SONGS outages. In contrast, there 20

were no RA rights associated with the Demand Response programs SCE implemented to enhance local 21

area reliability as a result of the SONGS outages. TURN’s comparison of the subject Demand Response 22

programs to enhance local area reliability for all customers to SCE’s estimate of its capacity-related 23

costs to meet bundled customer RA requirements is not applicable. And even if such a comparison were 24


18

valid, SCE does not consider its capacity-related costs to be part of its energy replacement costs. SCE’s 1

capacity-related costs are more appropriately considered to be part of SCE’s “other” market-related 2

costs. 3

3. NEIL Claims 4

TURN states that “the Commission should make its findings regarding the disallowance 5

of ‘replacement power costs,’ as broadly defined herein, expeditiously and without regard to whether 6

SCE’s and SDG&E’s claims with NEIL are yet resolved.”40 As previously identified, Phase 1a of I.12-7

10-013 is limited to the calculation of market-related costs associated with the SONGS outages. The 8

Commission will consider cost recovery of SCE’s market-related costs associated with the SONGS 9

outages in Phase 3 of I.12-10-013. TURN’s testimony regarding recommended disallowances is not 10

properly in scope at this time. 11

4. Alleged Downward Biases In SCE’s Estimates 12

TURN continues to assert that SCE’s estimates of market-related costs associated with 13

the SONGS outages contain a downward bias. SCE refutes these assertions. 14

The first downward bias asserted is that SCE’s use of the day-ahead SP-15 index price 15

creates a downward bias in “replacement power costs” because it implicitly assumes that load and 16

generation are priced the same.41 SCE explains above its rationale for using day-ahead SP-15 index 17

prices, which in part is based on the premise that the price index is reflective of prices that buyers and 18

sellers are willing to transact. So, rather than being a downward bias, as TURN alleges, the use of the 19

index provides a reasonably balanced price basis because SCE is estimating both replacement energy 20

costs (a buyer’s price) and foregone energy sales net revenue (a seller’s price). Moreover, SCE actively 21

transacts in the bilateral market that underlies the day-ahead SP-15 index to reduce its daily net-open 22

positions, which often entails buying energy to reduce a net short position. Accordingly, the day-ahead 23



19

SP-15 index price is an appropriate and unbiased indicator of SCE’s day-ahead price opportunity for 1

purchases and sales. 2

The second downward bias TURN asserted is that SCE’s use of its actual “without 3

SONGS” day-ahead net open energy position potentially understates SCE’s estimated “power 4

replacement costs.”42 However, TURN is not proposing that SCE utilize a different forecast 5

methodology because TURN recognizes there are many factors that would impact a forecast of SCE’s 6

“without SONGS” net open position. SCE contends that there are too many factors to consider to 7

reliably assume a downward bias in SCE’s estimate of replacement energy costs and foregone energy 8

sales net revenue. Some of these factors related to the SONGS outages include changes to SCE’s 9

procurement prior to day-ahead trading, changes in market prices, changes in SCE’s remaining portfolio 10

dispatch, changes in CAISO market constraints, and changes in market participant bidding behavior. 11

The Commission should only consider reasonably quantifiable costs in considering market-related cost 12

estimates. 13

The third downward bias TURN identifies are the “non-quantifiable costs” associated with the 14

SONGS outages.43 TURN considers these “costs” to be related to the indirect economic harm argument 15

that TURN advances, and which SCE has rebutted above. The Commission should reject TURN’s 16

contention that a replacement energy cost calculation should be determined based on unquantifiable 17

indirect costs. Any estimate of replacement energy costs in Phase 1a of I.12-10-013 should be limited to 18

costs that can be reasonably identified and estimated, and which are directly related to meeting bundled 19

customer demand during hours in which SCE’s bundled customer portfolio has a net short energy 20

position. Estimates of market-related costs should not be biased by the uncertain and “secondary” (i.e., 21

consequential) effects of the outages as TURN proposes. 22

42 TURN Reply Testimony, page 19.


20

H. WEM’s Supplemental Testimony 1

WEM proposes eight modifications that it wants the Commission to order the utilities to 2

separately quantify or make to their replacement cost calculations associated with the 2012 SONGS 3

outages. For the most part, WEM’s recommendations are inconsistent with the procurement regulatory 4

framework that exists in California. SCE’s preferred resource procurement (i.e., Energy Efficiency, 5

Demand Response, Distributed Generation, renewable energy, and Combined Heat & Power) and 6

conventional procurement are governed under various technology-specific Commission proceedings. 7

The Commission provides substantial guidance through dedicated proceedings to SCE on its Energy 8

Efficiency and Demand Response programs. The Commission also oversees numerous Renewable 9

Portfolio Standard and Combined Heat & Power procurement programs. SCE’s conventional 10

procurement is conducted pursuant to a Commission-approved procurement plan consistent with 11

Assembly Bill (AB) 57. In recognition of California’s existing energy procurement regulatory 12

framework, the following responds to WEM’s specific proposals. 13

1. Establishing 2011 Market Costs As A Cap On 2012 Market Costs 14

WEM proposes a “reduction of all actual 2012 market costs to the levels of 2011, to 15

reflect that shortages were unnecessary and could have been avoided.”44 WEM’s proposal should be 16

rejected as being inconsistent with the AB57 Procurement Plan framework. Additionally, WEM’s 17

proposal fails to consider that market costs differ between years for a multitude of reasons, and that the 18

SONGS outages are only one contributing impact. WEM’s proposal is not well-reasoned and should be 19

rejected. 20

2. Use Of Preferred Resource Costs As A Replacement Cost Benchmark 21

WEM proposes that the levelized costs of SCE’s 2010-2012 Energy Efficiency portfolio 22

and the 2011 commodity prices that existed for Demand Response, CHP, and local solar be used in lieu 23

of SCE’s actual costs of capacity and energy when SCE was in a net short position.45 SCE’s 24

44 WEM Supplemental Testimony, page 2.


21

procurement of preferred resources is overseen through various Commission proceedings. To the extent 1

that SCE failed to meet the State’s goals in this regard, the Commission should address the deficiency in 2

the relevant Commission docket. Additionally, WEM’s proposal inappropriately assumes that all of 3

SCE’s net short position could have been feasibly met by preferred resources, nor does it limit the net 4

short position exposure to SCE’s ownership share of SONGS’s maximum capacity. WEM’s proposal is 5

also deficient in that it does not recommend how to apportion the various resource technology cost 6

benchmarks in estimating replacement energy costs. WEM’s incomplete proposal is inconsistent with 7

the Commission’s energy procurement regulatory oversight framework and should be rejected. 8

3. Use Of Energy Efficiency Funding 9

WEM proposes that the “entire cost of the utilities[sic] EE portfolio for 2010-2012 10

should be subtracted from any ratepayer recovery for replacement resources, since utilities failed to 11

target any of this existing funding for these programs in a way that would have reduced the need for 12

replacement power for SONGS (according to testimony in hearings in R1203014).”46 Because the 13

SONGS outages began in early 2012, the only opportunity to redirect Energy Efficiency savings to the 14

western sub-area of the LA Basin would have been in the third year of the 2010-2012 program period, 15

which was likely to be too late to be of use in 2012. More importantly, SCE’s 2010-2012 Energy 16

Efficiency program authorization was not designed to replace SONGS generation. Any consideration to 17

limit SCE’s cost recovery of its authorized Energy Efficiency programs should be considered in an 18

appropriate Energy Efficiency docket. WEM’s proposal is overly punitive and inconsistent with SCE’s 19

2010-2012 Energy Efficiency program authorization, and should therefore be rejected. 20

4. Quantifying GHG And Emission Costs 21

WEM proposes that SCE be required to quantify “[a]ll GHG-related costs and other 22

pollution charges due to the additional use of gas and system power, which should have been avoided by 23

the use of preferred resources.”47 SCE’s conducts its procurement consistent with California’s Preferred 24



22

Loading Order and the Commission’s Least Cost Dispatch standard. Also, California’s Cap and Trade 1

GHG program did not commence until 2013. Regardless, any applicable GHG-related costs or emission 2

costs would have been embedded in the market prices that SCE employed to calculate its estimate of 3

2012 replacement energy costs. As a result, it is not necessary to consider WEM’s proposal. 4

5. Examination Of Market Price Spikes 5

WEM proposes that SCE be required to identify why market prices “spiked at various 6

times of the year,” and to identify if SCE’s “testing” of the Unit 2 and 3 steam generators contributed to 7

the price spikes.48 Market prices vary for numerous reasons. However, SCE is very limited in what it 8

can ascertain with respect to price spikes because it does not have access to other market participants’ 9

bids and all CAISO market optimization constraints. The CAISO is best positioned to assess the cause 10

of market spikes in its markets. Separately, SCE did not operate its steam generators during the SONGS 11

outages. The Commission should not adopt WEM’s proposal due to its impractical objective. 12

6. Unit 2 Nuclear Fuel 13

WEM proposes that SCE subtract the cost of the Unit 2 fuel cycle costs from its 14

“replacement power costs.”49 As discussed above, SCE has removed its avoidable nuclear fuel 15

assumptions from its estimates of replacement energy costs and foregone energy sales net revenue. 16

7. Costs Associated With Market Gaming By JP Morgan 17

WEM proposes that SCE quantify all the costs it incurred as a result of market gaming by 18

JP Morgan subsidiary brokers which SCE allegedly “failed to prevent.”50 As a threshold matter, the 19

Federal Energy Regulatory Commission (FERC) is responsible for monitoring and preventing gaming 20

by wholesale market participants. SCE does not have any authority in this regard. WEM’s proposal is 21

also inconsistent with the scope of Phase 1a, and should therefore be rejected. 22




23

8. Huntington Beach Power Plant Costs 1

WEM proposes that SCE quantify all costs associated with returning Huntington Beach (HB) 2

Generating Station Units 3 and 4 to service. WEM also suggests that SCE may have engaged in 3

procurement “irregularities” because it procured from HB without competitive bidding.51 The CAISO, 4

and not SCE, contracted for and oversaw the return to service of HB Units 3 and 4 for summer 2012 5

operations. Furthermore, HB Units 3 and 4 continue to be owned and operated by AES. The 6

Commission already requires SCE to report in its SONGS OMA the amount of costs incurred for 7

contracting with HB Units 3 & 4. There is no need to further consider WEM’s proposal in this regard. 8


Appendix A

Witness Qualifications

A-1

SOUTHERN CALIFORNIA EDISON COMPANY 1

QUALIFICATIONS AND PREPARED TESTIMONY 2

OF COLIN E. CUSHNIE 3

Q. Please state your name and business address for the record. 4

A. My name is Colin E. Cushnie, and my business address is 2244 Walnut Grove Avenue, 5

Rosemead, California 91770. 6

Q. Briefly describe your present responsibilities at the Southern California Edison Company. 7

A. I am the Director of the Portfolio Planning & Analysis Department in SCE’s Power Supply 8

Organizational Unit. My department’s responsibilities include demand and price forecasting, 9

contract and solicitation analysis and valuation, portfolio analysis and risk management, 10

portfolio reporting, CRR portfolio management, and fundamental model analysis. 11

Q. Briefly describe your educational and professional background. 12

A. I earned a Bachelor of Arts Degree in both Economics and Business Administration from 13

Whittier College in 1986. I was hired by SCE in January 1987 and held various positions related 14

to the procurement of material, equipment, and services until October 1993. Since October 15

1993, I have held positions of increased responsibility related to SCE’s natural gas and electrical 16

energy planning, procurement, and regulatory advocacy and support. In my current position, I 17

manage a staff of approximately 45 energy professionals. I have previously testified before the 18

California Public Utilities Commission. 19

Q. What is the purpose of your testimony in this proceeding? 20

A. The purpose of my testimony in this proceeding is to sponsor Exhibit SCE-37, entitled Rebuttal 21

Testimony in Phase 1a, as identified in the Table of Contents thereto. 22

Q. Was this material prepared by you or under your supervision? 23

A. Yes, it was. 24

Q. Insofar as this material is factual in nature, do you believe it to be correct? 25

A. Yes, I do. 26

A-2

Q. Insofar as this material is in the nature of opinion or judgment, does it represent your best 1

judgment? 2

A. Yes, it does. 3

Q. Does this conclude your qualifications and prepared testimony? 4

A. Yes, it does. 5

rebuttal testi mony in phase · 2 1 the context of the market-based framework in which sce operates...

Documents