BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application of Southern California Edison )
Company (U 338-E) for Authority to )
Institute a Rate Stabilization Plan with a ) Application 00-11-038
Rate Increase and End of Rate Freeze ) (Filed November 16, 2000)
Tariffs. )
- -------------------------------------------------------------)
)
Emergency Application of Pacific Gas and Electric Company to ) Application 00-11-056
Adopt a Rate Stabilization Plan. (U 39 E) ) (Filed November 22, 2000)
- -------------------------------------------------------------)
)
Petition of THE UTILITY REFORM NETWORK for Modification of ) Application 00-10-028
Resolution E-3527. ) (Filed October 17, 2000
)
- -------------------------------------------------------------
SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E)
COMMENTS ON PROPOSED CPA CALCULATION
STEPHEN E. PICKETT
ANN P. COHN
FRANK J. COOLEY
JAMES P. SCOTT SHOTWELL
Attorneys for
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
Post Office Box 800
Rosemead, California 91770
Telephone: (626) 302-3115
Facsimile: (626) 302-7740
E-mail: Frank.Cooley@sce.com
Dated: March 29, 2001
TABLE OF CONTENTS
Section Title Page
- ------- ----- ----
I. INTRODUCTION..........................................................................................1
II. Discussion............................................................................................4
A. The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For
Adjustments Based On Actual Costs................................................................4
B. The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For
The Entire Net-short position Of The Utility's Customers.........................................6
C. The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low...........................6
D. Authorized Generation-Related Costs Are Improperly Excluded......................................9
E. The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In
Ordering Paragraph No. 10 Overturns Existing Commission Decisions And Is
Contrary To State Law...........................................................................13
F. The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified.....................15
G. The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable
Assumptions.....................................................................................16
1. Calculation Of The CPA Based On The CPUC's Methodology.................................16
2. Calculation Of The CPA Based On Realistic And Appropriate Assumptions
And Methodology........................................................................16
H. The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR.........................17
III. CONCLUSION...........................................................................................18
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application
BEFORE THE PUBLIC UTILITIES COMMISSION OF THE
STATE OF CALIFORNIA
Application of Southern California Edison )
Company (U 338-E) for Authority to )
Institute a Rate Stabilization Plan with a ) Application 00-11-038
Rate Increase and End of Rate Freeze ) (Filed November 16, 2000)
Tariffs. )
- -------------------------------------------------------------)
)
Emergency Application of Pacific Gas and Electric Company to ) Application 00-11-056
Adopt a Rate Stabilization Plan. (U 39 E) ) (Filed November 22, 2000)
- -------------------------------------------------------------)
)
Petition of THE UTILITY REFORM NETWORK for Modification of ) Application 00-10-028
Resolution E-3527. ) (Filed October 17, 2000
)
- -------------------------------------------------------------
SOUTHERN CALIFORNIA EDISON COMPANY'S (U 338-E)
COMMENTS ON PROPOSED CPA CALCULATION
I.
INTRODUCTION
The Southern California Edison Company (SCE) comments on Decision No. 01-03-081 regarding the proposed
calculation of the California Procurement Adjustment (CPA).1/
SCE appreciates the importance of determining the revenue stream available to compensate the California
Department of Water Resources (DWR) for its purchases on behalf of our customers pursuant to Senate Bill 7X and
Assembly Bill 1X. Nevertheless, it is singularly important that the California Public Utilities Commission (CPUC
or Commission) make this determination correctly. The Commission should acknowledge the critical interdependence
between the allocation of revenues to DWR and full-cost recovery of SCE's Commission-authorized costs.
- -----------------------
1/ D.01-03-081, Ordering Paragraph 10, mimeo, p.37.
Page 1
The calculation of the CPA cannot be considered in isolation. The CPA is one aspect of the three
decisions issued March 27, 2001. In the limited time available to consider the impact of the decisions, SCE
estimates that revenues going forward will not be sufficient to cover retained generation and power purchase
costs.2/ In fact, Figure 1 on the next page shows that the net effect of the rate increases, the QF decision and
the payments ordered to be made to DWR result in a shortfall in the CPA calculation of $1.2 billion for SCE.
Accordingly, it is even more critical that the calculation of the CPA properly reflects all the costs allocated
to the utility.
SCE continues to urge the Commission to establish three dedicated rate components with two-way balancing
accounts and triggers as the best way to ensure that DWR receives adequate funding and the utilities' financial
health does not deteriorate even further. The three dedicated rate components would be for SCE's retained
generation, QF and bilateral contracts and payments to DWR.
The proposed calculation of the CPA set forth in D.01-03-081, Sections C and D, does not properly
reflect all relevant generation costs. If the Commission were to adopt such a calculation and later allocate a
portion of the CPA to the Fixed DWR Set Aside, it would materially exacerbate the utility's revenue shortfall.
In these comments SCE identifies several important corrections that must be made to the CPA calculation.
- --------------------
2/ SCE is commenting on the portions of D.01-03-081 as directed by the
Commission. In so doing, SCE does not necessarily agree with, and reserves
it right to challenge, these and other portions of D.01-03-081 and other
decisions issued by the Commission on March 27, 2001.
Page 2
Page 3
II.
DISCUSSION
A. The Proposed CPA Is Fixed For An Indefinite Period With No Mechanism For Adjustments Based On Actual
Costs
The proposed CPA is a fixed rate. More importantly, the CPA is a fixed rate based on a one-time
calculation of costs. The Commission is effectively converting the revenue recovery for all generation to a
rate, rather than an absolute cost. So, for example, assuming a fixed demand, if output from Utility Retained
Generation (URG) decreases and delivery from DWR increases by a like amount, the State will receive an increment
in its revenue and SCE will receive a decrease,3/ even though its costs may not have decreased at all. This
effectively puts SCE's shareholders at risk for generation performance. Put another way, SCE's shareholders are
at risk for replacement power cost, at least to the extent of its generation rate. In stark contrast, assuming
no imprudence in the operation of URG, past Commission ratemaking decisions would provide recovery of increased
replacement power costs through the Energy Cost Adjustment Clause (ECAC). There would be no decrease in
generation revenue as a result of a decrease in output.
It is indisputable that SCE's retained generation and purchased power will change significantly over
time. The Commission's objective in setting a fixed rate is to achieve a stable source of revenue that will
allow DWR to finance its revenue bonds. Unfortunately, the stable source of revenue the Commission and DWR
desire is achieved at SCE's expense. By failing to allow for adjustments in costs and generation levels for
retained generation and purchased power, the proposed method for calculating the CPA transfers this cost
variability risk to the utilities. In our current financial condition, SCE cannot bear this risk. Moreover, it
creates perverse incentives for the utilities to avoid expenditures on retained generation units that may be the
least costly sources of supply.
- --------------------
3/ For purposes of this document, we assume that a portion of the CPA will be allocated
to the Fixed DWR Set Aside.
Page 4
The goals of achieving stable revenues for DWR and maintaining SCE's financial health are not mutually
exclusive. SCE offered an alternative that would allow the CPUC to achieve both objectives. The Commission
should establish three dedicated rate components with balancing accounts and triggers. The dedicated rate
components would be for utility retained generation, QF and bilateral contracts, and DWR purchases. The
advantages of this approach are compelling and were explained in SCE's response to the March 19, 2001 Assigned
Commissioner's Ruling.
Under SCE's proposed dedicated rate components, DWR would have an assured revenue stream that will allow
it to finance revenue bonds. The Commission could provide an assurance that the CPA rate would remain available
to repay the revenue bonds over their life. Revenue to pay DWR would be generated by the DWR's dedicated rate
component. This approach would contribute positively to SCE's financial health by removing the necessity to
finance large amounts of undercollections if they accumulate due to volatile costs. Triggers set at
appropriately low levels given SCE's weakened financial condition would assure lenders that a mechanism is in
place to recover power purchase costs and adequately fund CPA payments to DWR.
The approach envisioned by the proposed CPA is not practical. The fixed CPA rate does not reflect
likely variations in the cost of purchased power. There is no procedure for updating purchased power cost
factors. The upshot of the proposed CPA is to place the financing burden associated with these variations on the
financially weakened utility. SCE simply does not have the ability to finance any sizable undercollections.
Because the proposed CPA approach would deleteriously impact the utility's financial condition, DWR's ability to
finance power purchases would be affected.
Page 5
B. The Proposed CPA Ignores DWR's Failure To Assume Financial Responsibility For The Entire Net-short
position Of The Utility's Customers
It is unclear what portion of our customers' net-short position DWR is going to be financially
responsible for. The proposed CPA calculation implicitly assumes that DWR is financially responsible for
covering all of our customers' net-short position. While SCE understands and expects that DWR has this
responsibility, DWR has not formally acknowledged this responsibility, as reflected in D.01-03-082.4/ DWR has
stated that it will only pay the portion of our customer's net short costs that DWR considers to be reasonable.
DWR's reasonableness standard is not defined. Whatever portion of our customer's net-short position that is not
being covered by DWR must be included in the calculation of the CPA. SCE does not have the ability to finance an
undercollection of procurement costs. If, despite the intent and requirements of AB1X-1, the financial burden
for the uncovered net short is placed on SCE, the calculation of the CPA must reflect this fact. The proposed
CPA calculation does not.
C. The CPA Is Inflated Because The Assumed Cost Of QF Payments Is Too Low
The proposed CPA is based on an assumed QF price of $80 per MWH. This price is unrealistic and
inconsistent with the CPUC's own decision modifying the QF energy payment formula. Reasonable estimates of QF
payments based on the Commission's modifications to the QF energy payment formula would yield substantially
higher payments to QFs and a consequently lower estimate of the amount available to fund the CPA.
- ----------------------
4/ D. 01-03-082, p. 14. D.01-03-082 also affirms that the CPUC cannot require
DWR to purchase the entire net short on behalf of SCE's customers. Id.
Page 6
When SCE provided its scenarios based on the $80 per MWH price, there were ongoing negotiations with QFs
that everyone hoped would lead to a settlement near that price. Those negotiations failed and D.01-03-067 (the
QF Decision) recognizes this fact. In fact, it is only because the negotiations failed that the Commission was
forced to address the issue of QF energy payments. Unfortunately for California ratepayers, the energy payment
formula authorized by the Commission will result in higher payments to QFs than $80 per MWH that was assumed for
illustrative purposes.
Table 1 provides SCE's estimate of QF prices based on the formula adopted by the Commission and gas
prices as forecast by Data Resources Inc. (DRI):
Table 1
QF Price Forecast
($/MWH)
--------------------------- ------------------- -----------------
Month CPUC SCE
Assumed Forecast
--------------------------- ------------------- -----------------
May, 2001 80 121.30
June, 2001 80 111.10
July, 2001 80 172.90
August, 2001 80 187.20
September, 2001 80 193.40
October, 2001 80 187.20
November, 2001 80 94.60
December, 2001 80 98.50
Page 7
This forecast includes a forecast of QF energy, capacity and contract buyout payments. For energy
payments, QFs are divided into three types of contracted energy payments terms: (1) posted avoided cost of
energy; (2) fixed energy prices; and (3) heat rate floors ("IER Amendments"). In general, energy prices other
than the fixed priced contracts are determined by a base energy price, a border gas price, and a gas price
factor. Line loss factors, based on the generator meter multipliers (GMM), distribution loss factors (DLF), and
system GMM, are also applied to energy prices where appropriate.
QFs paid the posted avoided cost of energy are subject to the conditions in established in D.01-03-067.
For these contracts the Malin border gas price including a gas intrastate transportation rate to the Southern
California Gas Company interconnection point is used to determine the posted avoided cost of energy. In
addition, the gas price factor is adjusted monthly according the decision. The energy payments to QF subject to
"IER Amendments" are forecast using base energy prices, border gas price, and a gas price factor. The energy
payments to the fixed-priced contracts are forecast subject to specific contract terms. The border gas price
forecasts are taken from DRI's gas price forecast for March 2001. For all contracts, energy is forecast based on
historical behavior. The forecast of capacity payments is based on contract terms and historical payments and
the forecast of contract buyout payments is based on Commission-approved buyout payment schedules.
The Commission should recognize in its calculation of the CPA the fact that its QF decision, issued the
same day as D.01-03-081, earlier Commission decisions and specific QF contract terms increase the price of QF
power above the assumed $80 per MWH price. This would increase the costs to be deducted from generation-related
revenues used in the calculation of the CPA by approximately $1.6 billion in 2001.
Page 8
D. Authorized Generation-Related Costs Are Improperly Excluded
The proposed CPA improperly excludes legitimate generation-related costs. This unfairly inflates the
amount of the CPA. All authorized generation-related costs should be included in the calculation of the CPA to
properly implement the Legislature's intent.
Excluding certain authorized generation-related costs from the calculation of the CPA overstates the
amount of the CPA. For example, D.01-03-081 claims that franchise fees and uncollectibles should be excluded
from the calculation. With respect to franchise fees, the decision asserts that these costs "attach to all
retail revenues." This makes no sense. "All revenues" includes SCE's generation-related revenues. What SCE
proposed to deduct from generation-related revenues was the pro rata share of our total franchise fees that
relates to the generation-related revenues. The Commission in D. 97-08-056 explicitly ordered SCE and other
utilities to exclude from their distribution revenue requirement the portion of its revenue requirement
associated with generation revenues. The proposed calculation of the CPA is at odds with the Commission's
earlier treatment of these costs. Alternatively, DWR must assume financial responsibility for paying the
franchise fees associated with their "revenues."
The proposed calculation of CPA also excludes restructuring implementation costs, employee-related
transition costs, losses on sales and QF shareholder incentives. The decision claims that because these costs
are not enumerated in Code Section 360.5, they must be excluded. This assertion is disingenuous. The Commission
is intimately familiar with what is included in SCE's rates. Generation related rates have heretofore included
these costs. The Legislature could reasonably be excused from knowing precisely what is in SCE's generation
rates. The Commission is not so easily excused. In D.99-09-064 the Commission ordered recovery of these costs
Page 9
through the operation of the TRA. The effect of this treatment is to require them to be recovered through the
residually determined generation rate component. Consistent and fair treatment would remove these costs from the
generation related rate in the calculation of the CPA.
With respect to direct access implementation costs, the decision claims that these costs must be
excluded from the calculation of the CPA. This is contrary to the Commission's decisions implementing
restructuring. The Commission authorized recovery of direct access implementation costs from the TRA. Since the
generation rate is by Commission decisions residually determined under the rate freeze, in so doing the
Commission reduced the generation rate by a corresponding amount to maintain the rate freeze. This reduction can
not be ignored now in calculating the CPA. Direct access implementation costs were in SCE's "rates" on January
5, 2001 and must therefore be taken out of the generation-related rate to properly calculate the CPA. If instead
of recovering the direct access implementation costs through the TRA an unbundled rate component for their
recovery were established, then the residually determined generation rate would have been smaller and these costs
would not have been reflected in the January 5 generation rate.
Conversely, by inputing the Rate Reduction Bond (RRB) revenues , the Commission effectively increased
the generation rate. The proposed CPA should include these inputed amounts as well even though they were not
listed in Code Section 360.5. The RRBs are not included because they are generation costs but because the
Commission effectively authorized the reduction of the generation rates to allow recovery of these items.
The proposed CPA excludes customer service and information expenses, and administrative and general
costs because they "are not generation related costs and do not fall within the scope of the four items in Code
Page 10
Section 360.5."5/ These costs are in the same category as direct access implementation costs and the inputed RRB
amounts. For example, A&G costs associated with SCE's generating facilities include: pensions and benefits for
employees at the generating plants, payroll taxes for the employees at the generating plants, insurance for
property damage and personal injury, and worker's compensation. These costs are reasonable costs of operating
SCE's generating facilities. No business can operate without paying payroll taxes and pensions and benefits for
its employees. In addition, it would be imprudent for SCE to operate its generating facilities without insurance
for property damage and personal injury.
D.96-04-059, adopting the present SONGS 2&3 ratemaking mechanism, and D.96-12-083, adopting the present
Palo Verde ratemaking mechanism, provide for recovery of A&G costs associated with these nuclear generating
facilities. D.97-12-131 established the Hydroelectric Generating Facilities revenue requirement. Advice
Letter 1285-E-B, approved by the Commission by letter, dated June 25, 1999, implemented D.97-12-131. Advice
Letter 1285-E-B expressly includes A&G as part of the revenue requirement of SCE's hydroelectric generating
facilities. D.99-09-064 established "going-forward" costs of SCE's coal-fired generating facilities to be
recovered through market revenues. Advice Letter 1409-E-A, approved by the Commission by letter, dated
February 10, 2000, expressly includes A&G expenses as part of the legitimate operating costs of SCE's coal-fired
generating facilities eligible for recovery through market revenues. The Commission should not exclude such
legitimate generation costs in the calculation of the CPA because to do so would be inconsistent with past
Commission decisions and standard utility ratemaking practices. Moreover, they do fall within any reasonable
definition of the costs of "the utility's own generation" which Public Utilities Code Section 360.5 expressly
allows to be subtracted from SCE's generation-related revenue requirement in any calculation of the CPA.
- -----------------------
5/ D.01-03-081, p.19.
Page 12
In D.97-08-056 the Commission examined SCE's total C&I and A&G costs and allocated a portion of them to
the generation function. It is contrary to that decision and common sense to now exclude consideration of these
costs in the generation related rate. The Commission prohibited SCE from recovery of the generation related CS&I
and A&G costs through distribution rates and is now attempting to exclude them from recovery through the
generation rates by inflating the CPA. This is obviously unfair and should be corrected.
Finally the proposed calculation of the CPA ignores the reliability must run (RMR) costs that SCE must
pay to the ISO. SCE agrees that RMR costs are not generation related, but in D.98-04-019 the Commission allowed
for recovery of RMR costs through the TRA during the rate freeze. This treatment was in lieu of SCE filing with
the FERC to establish a separate rate component for RMR recovery. Had SCE done so, the residually determined
generation rate would have been smaller. The Commission in D.99-10-057 stated that in the post-transition period
SCE must request recovery of these costs through a FERC-approved rate component. SCE filed an application with
the FERC (Docket No. ER01-315-000, filed November 1, 2000) for adoption of an RMR rate component. For this
reason, the Commission should subtract the RMR costs from its generation rate before calculating the CPA. This
would result in the same outcome as SCE continuing to recover RMR costs through the residual generation revenues
recorded in the TRA.
Page 12
E. The Potential Exclusion From The CPA Of SONGS 2&3 ICIP Revenues Requested In Ordering Paragraph No. 10
Overturns Existing Commission Decisions And Is Contrary To State Law
Several changes contained in Ordering Paragraph No. 10 were not in the Alternate Decision issued March
26, 2001 that was ultimately adopted as D.01-03-081. These changes were not available for timely review as noted
by several Commissioners from the dais on March 27, 2001. The changes to the CPA calculation directed in
Ordering Paragraph No. 10 are not lawful. They would overturn existing Commission decisions regarding SONGS 2&3
Incremental Cost Incentive Pricing (ICIP) and are contrary to state law. SCE would have identified this serious
legal error in its March 26, 2001 oral argument if it had been on notice of this proposed change at that time.
These changes represent significant material revisions, not mere typographical corrections. The Commission
should not countenance such "star chamber" ratemaking.
Ordering Paragraph No. 10 states:
Comments on sections VI.C and D and section VIII of this decision and the
corresponding proposed findings of fact and proposed conclusions of law shall
be filed and served no later than 5:00 p.m. on Thursday, March 29, 2001. Each
utility shall include in its comments a revised version of that portion of the
Spreadsheet included as Attachment E to this Decision that relates to that
utility. This revised spreadsheet shall exclude in its calculation of Utility
Related Costs those nuclear incentive amounts (e.g., Diablo Canyon ICIP
payments) in excess of actual costs, and be accompanied by appropriate
supporting work papers. Any party asserting that the figures contained in
Attachment E contain miscalculations should submit a revised version of
Attachment E correcting the alleged errors, which should be accompanied by
appropriate work papers.
Page 13
The implication of the paragraph is that the Commission intends to exclude some portion of SONGS 2&3 ICIP
revenues from the CPA calculation. It directs the utilities to remove "actual generation costs" from their
calculation of Utility Related Costs in the CPA calculation. The Commission adopted SONGS 2&3 ICIP prices as the
operating cost of SONGS 2&3 and the Legislature affirmed these prices as the SONGS 2&3 actual costs in Public
Utilities Code Section 367(a)(4).
SONGS 2&3 ICIP is, by its very nature as acknowledged in its title, a cost-based rate. The ICIP assigns
all operational and financial risk to SCE, while offering a strictly limited opportunity for profit6/ based upon
excellent performance at the plants. SCE cannot assure continuation of recent (1996-2000) excellent performance,
as the current SONGS 3 outage demonstrates. The risk currently borne by SCE is evidenced by the $800,000 per day
of lost revenue to the company due to the present SONGS 3 outage.
As SCE stated on page 7 of its Motion to Strike Comments filed by TURN on California Procurement
Adjustment, dated March 9, 2001, in the Rate Stabilization Plan (RSP) docket:
In the SONG 2&3 ICIP mechanism, shareholders take on the operational risk of
plant performance. Under this ratemaking approach the opportunity for profits
must be commensurate with the risk of losses. SONGS 2&3 ICIP opportunity for
profits is commensurate with the higher risk of losses assumed by shareholders.
Furthermore, SCE's opportunity for profit is limited by the design and operation limits of the plants.
- ------------------------
Page 14
6/ SCE's realized "profit" under SONGS ICIP has been around 9% to date (RSP,
Phase 1, Tr. Worder, 15/1982.)
7/ RSP, Phase 1, SCE, Worden, Tr. 15/20/2015, lines 22-26. (Ratepayers would
be protected if the plants performed better than the historic capacity
factors because the ratepayer exposure and shareholder oppotunity is capped
by the physical limitations of the plant.")
Page 14
The Commission adopted present SONGS 2&3 ICIP pricing in D.96-01-011 and D.96-04-059. The Legislature
affirmed the SONGS 2&3 ICIP pricing in Assembly Bill 1890, at Public Utilities Code Section 367(a)(4), which
states:
Nuclear Incremental Cost Incentive plans for the San Onofre Nuclear Generating
Station shall continue for the full term as authorized by the Commission in
Decision 96-01-011 and Decision 96-04-059; provided that the recovery shall
not extend beyond December 31, 2003.
The Commission would unlawfully ignore its own orders and state law if it changes SCE's ratemaking for SONGS 2&3.
F. The Ratemaking Treatment Of Previously-Authorized Costs Should Be Clarified
As discussed in the previous sections, many of the costs that are excluded from the proposed CPA
calculation are authorized generation-related costs. If these costs are not allowed recovery through the
generation-related component of SCE's rates, it is not clear where SCE would get recovery of them. These costs
are reasonable and authorized costs. The Commission has previously allowed recovery of them through the
residually determined generation rates. There is nothing in the record that would in any way justify
disallowance of these costs. Yet, there is no readily apparent mechanism for their recovery. The Commission
should immediately clarify where and how these costs will be recovered to avoid any further negative harm to
SCE's financial condition.
Page 15
G. The Methodology for Calculating The CPA Is Flawed And Is Based On Unreasonable Assumptions
1. Calculation Of The CPA Based On The CPUC's Methodology
If the Commission makes no modifications to its CPA methodology, it should nevertheless adopt
reasonable estimates, including a reasonable estimate of QF costs. SCE estimates, based on the
methodology adopted in D. 01-03-08_, that its QF payments will be $1.629 billion higher than the
estimate included in Attachment E to D. 01-03-081. SCE's Attachment A contains a table that shows the
CPA including this correction, as well as a minor correction to gross generation revenues to correct the
amount shown in Column D of Table E. In addition, pursuant to Ordering Paragraph No. 10 of D.01-03-081,
an adjustment has been made to reflect the difference between the SONGS ICIP revenue requirement and
estimated costs. With these changes, the CPA would be zero cents per kWh.
2. Calculation Of The CPA Based On Realistic And Appropriate Assumptions And Methodology
The proposed calculation of the CPA rejects numerous adjustments that should be made to
accurately calculate the CPA. If these adjustments are made, the CPA would be higher than the corrected
CPA factor discussed above. The proposed adjustments are reasonable and consistent with prior CPUC or
FERC decisions which allocated these costs to the generation related component of SCE's rates.
Attachment A describes each of the adjustments that should be made to reflect an accurate
calculation of the CPA. The adjustment and the authority for making the adjustment are shown in the
table. If these adjustments are made, the CPA would continue to be zero cents per kWh. It should be
noted that the largest adjustments (for the imputed 10% bill credit and the imputed trust transfer
amount) will no longer exist in 2002. These adjustments increase the amount of the CPA in 2001. Their
absence in 2002 will decrease the calculated CPA in 2002. For this reason, if the Commission chooses to
make SCE's proposed adjustments, the CPA calculation will need to be updated for at least the
elimination of the 10% bill credit and the imputed Trust Transfer Amount revenue in 2002.
Page 16
H. The Fixed DWR Set Aside Should Not Be Applied To Energy Supplied By DWR
In its calculation of the CPA, the Commission used a denominator equating to SCE's total bundled sales.
One effect of this approach is to allocate the utility's costs against the generation revenues which are already
required to be forwarded to DWR. This is a double calculation and would effectively send the revenue requirement
to DWR twice. Either the CPA calculation should be modified to replace the denominator with only kwhs provided
by SCE, or, in the aternative, the DWR Set Aside should only be applied to kwhs supplied by the DWR.
Page 17
III.
CONCLUSION
For the reasons discussed above, SCE urges the Commission to modify the calculation of the CPA
consistent with SCE's recommendations in Attachment A.
Respectfully submitted,
STEPHEN E. PICKETT
ANN P. COHN
FRANK J. COOLEY
JAMES P. SCOTT SHOTWELL
Frank J. Cooley
-------------------------------------------------
By: Frank J. Cooley
Attorneys for
SOUTHERN CALIFORNIA EDISON COMPANY
2244 Walnut Grove Avenue
Post Office Box 800
Rosemead, California 91770
Telephone: (626) 302-3115
Facsimile: (626) 302-7740
E-mail: Frank.Cooley@sce.com
March 29, 2001
Page 18
APPENDIX A
A B C D E
- ----- ------------------------- ------------------- ---------------------------------------- ------------------ -----------------
Gross Gen-Related Rev
Gen-Related Revs Based on
Line Total Sales Reported in Bundled Reported in Bundled Service
Nos. Description Generation-Related Utilities' ABX1 Data (GWh) Service Utilities ABX1 Sales ($000s)
Rate (c/kWh) Sales ((GWh) Data ($000s)
- ----- ------------------------- ------------------- ---------------------------------------- ------------------ -----------------
A=D/B/10 E=A*C*10
1 As Attached to 7.277 84,400 76,466 6,141,557 5,564,251
D01.03-081 (For SCE)
Adjustments Pursuant to
Ordering Paragraph 10
of D.01-03-081
2 Corrects Amount shown 8,116
in column D
3 Updated QF payment
amounts based on
D.01-03-081
4 Adjustment to SONGS
Generation (GWh) due to
outage after fire
5 To reflect forecast of
SONGS O&M (Non-ICIP)
- ----- ------------------------- ------------------ ------------------------------------------ ------------------ -------------
6 Adjusted Commission CPA 7.286 84,400 76,466 6,149,673 5,571,604
Calculation
- ----- ------------------------- ------------------- ------------------------------------------- ------------------ -------------
Additional Authorized
Adjustments:
Authority for Inclusion
7. Reverse Line 5 above PU Code Section PU Code Section 367 (a)(4)
which results in 367 (a)(4) states that "Nuclear
authorized SONGS ICIP D.96-02-011 and Incremental Cost Incentive
revenue requirement D.96-04-059 plans for SONGS shall
continue for the full
term as authorized by the
Commission in D.96-01-011
and D.96-04-059."
8 Franchise Fees and D.97-08-056, p.59 The Commission ordered (62,498)
Uncollectibles that the utilities
distribution revenue
requirement should be
reduced to recognize a
fair allocation of FF&U
costs between
distribution, transmission
and generation.
9 Reliability Services FERC Docket No. Reliability Service costs (39,551)
ER01-315-000 are FERC authorized that
are currently being
recovered through
generation rates.
10 Restructuring D.99-09-064 The Commission ordered the (33,606)
Implementation recovery of Industry
Restructuring costs
through the operation of
the TRA. Thus these costs
are actually recovered
through the residually
determined generation rate
component.
11 Demand Responsiveness D.01-03-xxx The Commission ordered SCE (38,440)
and Self Generation to increase its
Amount distribution revenue
requirement without
modifying current overall
rates. The adjustment is
needed to account for the
resultant reduction to
generation-related
revenues during the rate
freeze period. 1/
12 Imputed 10% Bill Credit D.97-09-056 The frozen generation rate 361,582
has been reduced by the
amount of the 10% bill
credit. This adjustment
is necessary in order to
remove the impact of the
RRB transaction from the
generation rate consistent
with the ratemaking
adopted by the Commission.
13 Imputed Trust Transfer The frozen generation rate 294,891
Amount has been reduced by the
amount of the TTA. This
adjustment is necessary in
order to remove the impact
of the RRB transaction
from the generation rate
consistent with the
ratemaking adopted by the
Commission.
14 Add-back CS&I and A&G RE: CS&I Costs The Commission ordered
related to SCE Retained D.97-08-056, p.59 that the utilities
Generation distribution revenue
requirement should be
reduced to recognize a
fair allocation of
customer service and
marketing costs between
distribution, transmission
and generation.
Res. E-3536 The Commission adopted a
generation allocation of
customer service and
marketing costs for hydro.
A&G Costs The Commission ordered
D.97-08-056, p. 59 that the utilities
distribution rev req
should be reduced to
recognize a fair
allocation of A&G costs
between distribution,
transmission and generation.
D.97-11-074, p. Commission defined
26-27 going-forward costs as all
costs necessary to
continue to operate the
plant. Going forward
costs may include both
fixed and variable costs.
This interpretation most
closely matches the
standards articulated in
the statue and our own
preference for market
recovery of such costs.
"Therefore, going forward
costs will be defined as
all costs that are
necessary for the
continued or future
operation of the plant...,
and include, but are not
limited to, all costs
associated with fuel
transportation and fuel
supply, administrative and
general, and operation and
maintenance, with the
statutory exceptions
established in Section 367
(c)(1) and (c)(2).
D.00-02-048 and Approved costs recorded in
D.00-10-047 GMA's including A&G and
CS&I
A=E/C/10 Sum lines X-Y
15 CPA as Proposed by SCE 7.917 76,466 6,053,982
- ----- ------------------------- ------------------- ------------------------------------------- ---------------- -----------------
Note: 1/ Similar adjustments will be necessary during the rate freeze
period to reflect the impact on generation-related revenues that result from
changes in non-generation revenues.
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
F G H I
Utility
Utility Related Costs CPA
Line Description Related less CSI and Revenues CPA Rate
Nos. Costs A&G ($000s) ($000s) (c/kWh)
($000s)
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
H=E-G I=H/C
1 As Attached to 4,798,902 4,762,381 801,870 1.049
D01.03-081 (For
SCE)
Adjustments
Pursuant to
Ordering
Paragraph 10 of
D.01-03-081
2 Corrects Amount
shown in column D
3 Updated QF 1,629,446 1,629,446
payment amounts
based on
D.01-03-081
4 Adjustment to (131,671) (131,671)
SONGS Generation
(GWh) due to
outage after fire
5 To reflect (55,400) (55,400)
forecast of SONGS
O&M (Non-ICIP)
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
6 Adjusted 6,241,277 6,204,756 (633,152) (0.828)
Commission CPA
Calculation
- ----------------------------------------- --------------------------- ------------- --------------- ---------------- -------------
Additional Authorized Adjustments
Authority for Inclusion
7. Reverse Line 5 PU Code Section PU Code Section 367 55,400 55,400
above which 367 (a)(4) (a)(4) states that
results in D.96-02-011 and "Nuclear Incremental Cost
authorized SONGS D.96-04-059 Incentive plans for SONGS
ICIP revenue shall continue for the
requirement full term as authorized
by the Commission in
D.96-01-011 and
D.96-04-059."
8 Franchise Fees D.97-08-056, p.59 The Commission ordered
and that the utilities
Uncollectibles distribution revenue
requirement should be
reduced to recognize a
fair allocation of FF&U
costs between
distribution,
transmission and
generation.
9 Reliability FERC Docket No. Reliability Service costs
Services ER01-315-000 are FERC authorized that
are currently being
recovered through
generation rates.
10 Restructuring D.99-09-064 The Commission ordered
Implementation the recovery of Industry
Restructuring costs
through the operation of
the TRA. Thus these costs
are actually recovered
through the residually
determined generation
rate component.
11 Demand D.01-03-xxx The Commission ordered
Responsiveness SCE to increase its
and Self distribution revenue
Generation Amount requirement without
modifying current overall
rates. The adjustment is
needed to account for the
resultant reduction to
generation-related
revenues during the rate
freeze period. 1/
12 Imputed 10% Bill D.97-09-056 The frozen generation
Credit rate has been reduced by
the amount of the 10%
bill credit. This
adjustment is necessary
in order to remove the
impact of the RRB
transaction from the
generation rate
consistent with the
ratemaking adopted by the
Commission.
13 Imputed Trust The frozen generation
Transfer Amount rate has been reduced by
the amount of the TTA..
This adjustment is
necessary in order to
remove the impact of the
RRB transaction from the
generation rate
consistent with the
ratemaking adopted by the
Commission.
14 Add-back CS&I and RE: CS&I Costs The Commission ordered 36,521
A&G related to D.97-08-056, p.59 that the utilities
SCE Retained distribution revenue
Generation requirement should be
reduced to recognize a
fair allocation of
customer service and
marketing costs between
distribution,
transmission and
generation.
Res. E-3536 The Commission adopted a
generation allocation of
customer service and
marketing costs for hydro.
A&G Costs The Commission ordered
D.97-08-056, p. that the utilities
59 distribution rev req
should be reduced to
recognize a fair
allocation of A&G costs
between distribution,
transmission and
generation.
D.97-11-074, p. Commission defined
26-27 going-forward costs as
all costs necessary to
continue to operate the
plant. Going forward
costs may include both
fixed and variable
costs. This
interpretation most
closely matches the
standards articulated in
the statue and our own
preference for market
recovery of such costs.
"Therefore, going forward
costs will be defined as
all costs that are
necessary for the
continued or future
operation of the plant...,
and include, but are not
limited to, all costs
associated with fuel
transportation and fuel
supply, administrative
and general, and
operation and
maintenance, with the
statutory exceptions
established in Section
367 (c)(1) and (c)(2).
D.97-11-074, Commission ordered
pg.26-27 tracking of the
above-mentioned going
forward costs in GMAs.
D.00-02-048 and Approved costs recorded
D.00-10-047 in GMA's including A&G
and CS&I.
H=E-G I=H/C
- ---------------------------------------- --------------------------- ------------- --------------- ---------------- ------------
15 CPA as Proposed 6,292,677 6,296,677 (242,695) (0.317)
by SCE
- ---------------------------------------- --------------------------- ------------- --------------- ---------------- ------------
Note: 1/ Similar adjustments will be necessary during the rate freeze
period to reflect the impact on generation-related revenues that result from
changes in non-generation revenues.
April 2, 2001
VIA FACSIMILE & U.S. MAIL
Docket Office
California Public Utilities Commission
505 Van Ness Avenue
San Francisco, CA 94102
Re: A.00-11-038 - - Correction to Figure re. CPA
Docket Office:
On March 29, 2001 Southern California Edison (SCE) commented in response to Decision No.
01-03-081. Included in our comments was a "waterfall chart" showing the financial impact of two decisions issued
by the Commission - - D.01-03-081 and D.01-03-082.
Subsequent to issuing our comments, we discovered language was added to Ordering Paragraph
No. 1 which increased payments to the California Department of Water Resources after March 27, 2001 from 7.277
cents per kilowatt-hour to 10.277 cents per kilowatt-hour. We were unaware that this requirement was added to
D.01-03-082.
Attached is an updated chart showing the finiancial impact of the Commission's decisions based
on the mailed version of D.01-03-082. The financial impact of the mailed version of D.01-03-082 is to increase
the amount by which total expenses exceed SCE's total revenues in 2001 by $700 million.
If you have any questions regarding this matter, please call me at (626) 302-3115.
Very truly yours,
Frank J. Cooley
----------------------------
Frank J. Cooley
cc: All Parties of Record
President Loretta Lynch and Commissioners
Gary Cohen, General Counsel
Enclosure
