PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E-3792

December 17, 2002

RESOLUTION

Resolution E-3792. Southern California Gas Company, Pacific Gas and Electric Company, San Diego Gas and Electric Company.

Pursuant to Public Utilities Code § 399.8, Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas and Electric Company, are directed to collect monies from customers to fund investments in energy efficiency, renewable energy, and research, development and demonstration projects, as specified herein.

__________________________________________________________

SUMMARY

Public Utilities (PU) Code § 399.8 requires the three major California investor owned electric utilities to assess a Public Goods Charge (PGC) to customers in order to fund certain public interest programs. It specifies that, starting January 1, 2002, $425.5 million is to be provided to these programs each year until January 1, 2012. However, § 399.8 does not specify how much of this annual total is to be allocated among the utilities except for the Energy Efficiency (EE) programs.

In this Resolution, we allocate the responsibility for funding the Public Goods programs to the electric utilities, and provide a schedule for the quarterly transfer of certain of these funds to the California Energy Commission (CEC). This Resolution also describes the rate cap imposed by the Code section, and provides guidance regarding implementation of that cap. We also describe how § 399.8 requires adjustments to this funding in future years, based on growth of electric sales and the national Gross Domestic Product (GDP) deflator. We direct these utilities to implement the appropriate surcharges and transfer funds as specified in this Resolution.

BACKGROUND

PU Code § 381,¹ effective September 24, 1996, funded certain Public Goods programs by establishing the PGC. Specifically, it required each of California's major investor-owned electric utilities - Southern California Edison Company (Edison), Pacific Gas and Electric Company (PG&E), and San Diego Gas and Electric Company (SDG&E) - to identify a separate, nonbypassable rate component to fund in part energy efficiency (EE) programs, renewable resource energy technology (Renewables), and public interest research and development (RDD), through the end of 2001. Section 381(a), (b), and (c)(1) required the following minimum funding levels for each program:

Table 1

PGC Funding by Program

1998-2001

($ million)

Source: P.U. Code § 381(c)

Note the lower total and change in distribution in 2001. Section 381(c) allocated the funding among the utilities' customers as follows:

Table 2

PGC Funding by Utility

1998-2001

($ million)

Source: P.U. Code § 381(c)

Table 3 shows the program allocation for 1998-2000, and Table 4 shows the 2001 allocation:

Table 3

Yearly Allocation to Programs by Utility

1998-2000

($ million)

Source: P.U. Code § 381(c)

Table 4

Allocation to Programs by Utility

2001

($ million)

Source: P.U. Code § 381(c)

Section 381 does not authorize collections from customers for these programs past the end of 2001. However, PG&E filed Advice Letter 2232-E on April 24, 2002, which sought "authorization to continue quarterly payments to the California Energy Commission (CEC) at 1998-2001 levels to fund the" RDD and Renewables programs until the Commission or Legislature acts to fix final payment levels consistent with § 399.8 (see below). PG&E proposed to continue forwarding to CEC $12 million quarterly for the Renewables programs and $7.425 million quarterly for the RDD programs, to be trued up when the Commission authorizes a final allocation among the utilities. The Energy Division approved this advice letter, effective June 3, 2002. No other utility has filed an advice letter on this matter with the Commission.

Funding for these programs through the PGC was extended through January 1, 2012 by PU Code § 399.8, effective January 1, 2002. The Commission is directed by § 399.8(d) to order the major electric utilities to continue to collect funds for these programs from customers through a nonbypassable PGC rate component, which is again based on the customer's electricity usage. Section 399.8(d)(1) specifies that the utilities are to collect, in aggregate, the following amounts for each year starting January 1, 2002 and ending January 1, 2012:

Table 5

Required Yearly Program Funding Starting 2002

($ million)

Source: P.U. Code § 399.8(d)(1)

DISCUSSION

A. Allocation of Utility Collection Obligations.

Section § 399.8 does not provide a complete allocation of the program costs among the three major electric utilities. Section 399.8(d)(1) does, however, provide an allocation for EE programs, as shown in the next table:

Table 6

Yearly Allocation of Collection Obligations

for Energy Efficiency Programs

($ million)

Source: P.U. Code § 399.8(d)(1)

While § 399.8 does not provide guidance regarding the allocation of target funding for Renewables and RDD programs among the utilities, § 399.8(c)(2) does specify that the rates used to collect these funds "may not exceed, for any tariff schedule, the level of the rate component that was used" to collect monies for these programs on January 1, 2000. These rate caps are discussed more thoroughly below.³ We propose to allocate the Renewables and RDD program costs among the utilities consistent with these rate caps. Table 10 estimates the total monies that would be raised by each utility if it combines the rates in effect on January 1, 2000, with the forecasted sales for each rate category. Using the estimates in the first column of Table 10 (Year 2002), the allocation of target funding to each utility for the Renewables and RDD programs, combined with the allocations for the EE programs already specified in § 399.8, are given in Table 7. This methodology thus incorporates the preferences expressed by the Legislature both in § 399.8(d)(1) and embodied in the rate caps, as weighed by the sales forecasts for 2002 developed by the individual utilities.

Table 7

Allocation to Programs by Utility

2002-2011

($ million)

By this Resolution, the utilities are directed to collect and track these program funds, along with interest earned on collected funds, in separate balancing accounts for each program. This tracking will begin with customer billings on January 1, 2002 forward. Monies for the Renewables and RDD programs shall continue to be forwarded quarterly to the CEC, starting with the first quarter of 2002, along with interest earned on collected funds, consistent with the treatment of these funds in P.U. Code § 381. EE programs will continue to be administered by this Commission, pursuant to § 399.4(a)(1). Payments to the CEC for Renewables and RDD programs will follow the following schedule for 2002:

Table 8

Schedule for Renewables Funding to CEC

2002

($ million)

Table 9

Schedule for RDD Funding to CEC

2002

($ million)

PG&E and SDG&E have continued to forward monies quarterly to the CEC for Renewables and RDD programs, with the intention of truing these amounts up once the Commission has issued the instructions contained in this Resolution. Edison must forward to CEC the appropriate quarterly payments for Renewables and RDD, as shown in Tables 8 and 9, for March 31, 2002, June 30, 2002, and September 30, 2002, and notify the Energy Division in writing when this task has been completed, no later than 14 days after the effective date of this resolution.

B. The Cap on Rates.

As discussed above, § 399.8(c)(2) states that the rate component used to raise these funds "may not exceed, for any tariff schedule, the level of the rate component that was used" for these programs on January 1, 2000. In other words, the utilities cannot impose PGC rates higher than those in effect on January 1, 2000.⁴ Table 10 estimates the yearly revenues that the application of the 2000 PGC rates⁵ taken from utility tariffs would yield when combined with sales forecasts obtained from the utilities:

Table 10

Estimated Revenues using 2000 PGC Rates

and Sales Forecasts from the Utilities

2002-2004

($ million)

Source: PGC rates and GWh usage forecasts from utilities.

Note that the total amounts estimated from the 2000 rates are somewhat higher than the $425.5 million per year the legislation mandates for these programs starting in 2002. This suggests that the constraint on PGC rates contained in

§ 399.8(c)(2) is unlikely to be significant, unless the inflation and growth adjustments described in § 399.8(d)(2) (see discussion below) increase these amounts significantly in future years.

At the same time, however, we note that retail rates should be designed to collect accurately the target amounts mandated under § 399.8 and specified in Table 7. These costs should be included in the ongoing rate cases for Edison and PG&E, and in the upcoming Annual Rate Design Window proceeding for SDG&E, and these rate components should be adjusted to reflect their application beginning in January, 2002.

C. Yearly Adjustments to Funding Obligations.

Section 399.8(d)(2) provides:

[t]he [target funding] amounts shall be adjusted annually at a rate equal to the lesser of the annual growth in electric commodity sales or inflation, as defined by the gross domestic product deflator.

The section does not identify when these adjustments should begin, but since the section extends these programs starting in January, 2002, we propose to begin applying the adjustment methodology one year later, in January, 2003. These adjustments will thus be based on changes in sales and prices during 2002.

It is reasonable that the changes in sales be defined for each utility, rather than for the entire state-wide electric system. That is, the adjustment to one utility's allocated amounts in Table 7 should be governed by changes in its own sales (assuming that this statistic is lower than the rate of inflation⁶), rather than by changes in the sales of all three utilities. This is because each utility can influence its own load growth through its own energy efficiency programs. Therefore we should not increase target funding amounts for one utility due to the higher load growth of another.

The following table gives statistics on the inflation variable for the years 1997-2003, and on the state-wide percent change in the sales variable for the years 2001-2004. Note the large drop (4.66%) in sales in 2001, while the forecasts provided by the utilities show an expected increase in the following years.

Table 11

Statistics on Inflation and Electric Sales

*forecasts

This table suggests that, if the forecasts are correct and there is not a great difference between utilities, changes in sales may be consistently lower than the inflation rate. Therefore, the change in sales may govern changes in the program authorizations of Table 7.

Edison, PG&E, and SDG&E should each determine the adjusted target funding amounts that result from this adjustment methodology and, on or before March 31, 2003, and for each subsequent year ending with 2011, file an advice letter with the Commission that adjusts the authorizations and allocations found in Table 7, consistent with § 399.8(d)(2).⁹ That is, the utility should:

1. determine the actual percentage change in its electric sales (based on quantity) from 2001 to 2002;

2. determine the percentage change in prices as measured by the change in the GDP deflator in 2002, as published by the U.S. Department of Commerce;

3. take the lower of these two statistics and adjust the authorized program expenditures in Table 7 by that change.

If the lower of sales change and price change is negative in any one year, authorizations for the subsequent year shall remain constant. If the GDP deflator statistics for 2002 are not finalized by the U.S. Department of Commerce by March 31, 2003, or for any subsequent year, the utilities should use the most recent published forecast for this advice letter filing and true-up their adjustment through an amended filing once the Department of Commerce publishes a final statistic.

NOTICE

To invite comments and responses by interested parties, the draft Resolution was noticed on the October 22, 2002, Commission Calendar and was also sent to parties in R.94-04-031/I.94-04-032 (Electric Restructuring); R.01-08-028 (Energy Efficiency); and A.02-05-002, A.02-05-003, and A.02-05-005 (AEAP). Comments were due no later than November 4, 2002.

COMMENTS

Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for the draft of this resolution was neither waived nor reduced. Accordingly, this draft resolution was mailed to parties for comments.

Comments on this draft Resolution were received from the CEC, Edison, PG&E, and SDG&E on November 4, 2002. Replies to comments were received from the CEC, PG&E, SDG&E, and Edison on November 12, 2002.

Edison states in its comments that it cannot pay to the CEC the amounts specified in Tables 8 and 9 of the draft Resolution. This is because the rate cap specified in § 399.8(c)(2) is lower than the rates required to raise the required amounts. The code section specifies that the rate components used to generate funds for these programs will be no higher than those rates in effect on January 1, 2000.

Edison argues that the rate that was in effect on January 1, 2000, was .203 cents per kWh, which, when combined with Edison's forecasted 2002 sales of 78,580 GWh will generate only $159.5 million, rather than the required $172.1 million. Edison derives the .203 cents per kWh figure by taking its target allocation for 2000 of $168.0 million (from § 381), and dividing this by actual year 2000 sales of 82,657 GWh.

The CEC points out in its reply comments that this methodology is not correct.¹⁰ The code section specifies that the cap is made up of the rates that were in effect, for each tariff schedule, at the beginning of 2000. These tariff rates, net of the CARE surcharge and miscellaneous small surcharges and provided to the Commission staff by Edison, are shown in the appendix to this Resolution. It is clear that most of these rates exceed the .203 cents per kWh estimate derived by Edison. Using 2002 sales forecast estimates provided by Edison in A.02-05-004,¹¹ and reasonable assumptions regarding the distribution of these sales within rate classes, these January 2000 rates would generate between $199 million and $213 million in 2002, far in excess of the $172.1 million required by Table 7 of the draft Resolution.

Both SDG&E and PG&E disagree with the allocation of funding responsibilities for the three programs among the three electric utilities found in Table 7 of the draft Resolution. Both utilities argue that the allocation in the draft increases SDG&E's share of the funding requirements without sufficient rationale. The allocation in the draft was based on the allocation of the first four years of these programs, as specified in § 381. We have changed the methodology for this allocation to reflect the impact of the rate caps specified in § 399.8(c)(2) and shown in Table 10.

PG&E recommends an alternative allocation based on funding for Renewables and RDD for the years 1998-2001. The following table compares the total percentage (for all three programs) allocated to each utility under § 381 for 1998-2001, the allocation proposed in the current draft Resolution for § 399.8, and the allocation recommended by PG&E for § 399.8.

Table 12

Percentage Total Allocation by Utility

As can be seen by inspection of Table 12, both the draft Resolution and the PG&E proposal make changes in the percentage allocation compared with that determined in § 381 for the years 1998-2001. The PG&E proposal transfers a significant portion of the total funding requirement from itself to Edison. The CEC argues in its reply that the transfer of burden contained in the PG&E proposal may result in a funding shortfall.¹² Edison opposes PG&E's proposal, saying in its reply that PG&E does not provide sufficient rationale for its adoption. Edison supports the draft Resolution's allocation, but suggests that, if the Commission wishes to change the allocation, it should consider one based on the energy efficiency target levels provided in § 399.8(d)(1) (see Table 6).¹³ We agree that PG&E's proposal is not sufficiently supported and will adopt the allocation proposed in the current draft Resolution, as it is based on the rate cap specified by the Legislature in § 399.8(c)(2).

All utilities argue that they should be allowed to retain funding for administration of utility transmission and distribution RDD programs, as authorized for § 381 in D.97-02-014. The CEC counters that this Commission is no longer legally authorized to order such retention, and that subsequent legislation¹⁴ has repealed this provision from § 381. Section 399.8 makes no such provision. The CEC is correct.

The CEC argues in its comments that the Resolution should specify that the yearly adjustment mechanism contained in § 399.8(d)(2) should not be used to lower the target amounts below those specified in Table 7 of the Resolution. The CEC states that the intent of the legislation was to adjust authorizations upward from these target amounts, but not downward. The CEC points out that the code section refers to "the lesser of the annual growth in electric commodity sales or inflation" (emphasis added).

The language of § 399.8(d)(2) does not specify that the amounts authorized in § 399.8(d)(1) are intended to be "base amounts," as suggested by the CEC. However, we will interpret the terms "growth" and "inflation" as being nonnegative metrics for the purpose of this adjustment mechanism.

PG&E states in its reply that it should not be responsible for "interest earned on collected funds" (p. 5 of the draft Resolution), since it did not know the precise amounts owed to the CEC under this program before the issuance of this Resolution. PG&E argues that interest payments should apply only when the utility is delinquent or late. We disagree. The utilities have been collecting and holding funds using existing PGC rates, and PG&E has earned interest on these monies. It is not in keeping with the intent of the legislation to allow the utilities to keep these interest earnings. Consistent with our decision in Resolution E-3769, we will require the utilities to forward interest earned on these funds to the CEC.

The CEC argues that the Commission should specify in its Resolution the precise amount of "interest earned on collected funds" owed to it by the utilities (p. 5 of the draft Resolution) and provides in its comments the calculations it has made regarding these payments. The utilities and the CEC have already established procedures for the determination and collection of these interest payments, and this Resolution is not the proper forum for this discussion.

FINDINGS

1. PU Code § 381, effective September 24, 1996, established the Public Goods Charge to fund certain Public Goods programs.

2. Each utility was required by § 381 to identify a separate, nonbypassable rate component. This charge was designed to fund in part energy efficiency programs, renewable resource energy technology programs, and public interest research and development through the end of 2001.

3. Section 381 does not authorize collections from customers for these programs past the end of 2001. However, § 399.8 extends these collections through January 1, 2012.

4. PG&E filed Advice Letter 2232-E on April 24, 2002, which sought authorization to continue sending the CEC quarterly payments for the RDD and Renewables programs until the Commission or Legislature acts to fix final payment levels consistent with § 399.8. The Energy Division approved this advice letter, effective June 3, 2002.

5. No other utility has filed an advice letter on this matter with this Commission.

6. The Commission is directed by § 399.8(d) to order the major electric utilities to continue to collect funds for these programs from customers through a nonbypassable PGC rate component, which is again based on the customer's electricity usage.

7. Section 399.8 requires the utilities to spend $425.5 million per year for EE programs, Renewables, and RDD, starting in 2002.

8. Section 399.8 only specifies the allocation of this cost among the utilities for the EE programs.

9. We propose to allocate the Renewables and RDD program costs among the utilities consistent with the capped rates specified in § 399.8(c)(2). This methodology thus incorporates the preferences expressed by the Legislature both in § 399.8(d)(1) and embodied in the rate caps, as weighed by the sales forecasts for 2002 developed by the individual utilities.

10. The utilities should be directed to collect and track these program funds, along with interest earned on collected funds, in separate balancing accounts. This tracking should begin with customer billings on January 1, 2002 forward.

11. Monies for the Renewables and RDD programs should continue to be forwarded quarterly from the utilities to the CEC, starting with the first quarter of 2002, along with interest earned on collected funds, consistent with the treatment of these funds in P.U. Code § 381. The schedule of payments should be as specified in Tables 8 and 9 in this Resolution.

12. PG&E and SDG&E continue to forward monies quarterly to the CEC for Renewables and RDD programs, with the intention of truing these amounts up once the Commission has issued the instructions contained in this Resolution.

13. Edison should forward to CEC the appropriate quarterly payments for Renewables and RDD, as shown in Tables 8 and 9, for March 31, 2002, June 30, 2002, and September 30, 2002, and should notify the Energy Division in writing when this task has been completed, no later than 14 days after the effective date of this Resolution.

14. EE programs should continue to be administered by this Commission.

15. Section 399.8(c)(2) states that the rate component used to raise these funds "may not exceed, for any tariff schedule, the level of the rate component that was used" for these programs on January 1, 2000.

16. A review of Table 10 suggests that this particular constraint is unlikely to be significant, unless the adjustments to the mandated amounts described in § 399.8(d)(2) increase these amounts significantly in future years.

17. Retail rates should be designed to collect accurately the amounts mandated under § 399.8 and specified in Table 7. These costs should be included in the ongoing rate cases for Edison and PG&E, and in the upcoming Annual Rate Design Window proceeding for SDG&E, and these rate components should be adjusted to reflect their application beginning in January, 2002.

18. Section 399.8(d)(2) provides:

[t]he [target funding] amounts shall be adjusted annually at a rate equal to the lesser of the annual growth in electric commodity sales or inflation, as defined by the gross domestic product deflator.

19. The section does not identify when these adjustments should begin, but since the section extends these programs starting in January, 2002, we propose to begin applying the adjustment methodology one year later, in January, 2003.

20. These adjustments will thus be based on changes in sales and prices during 2002.

21. Because each utility can influence their own load growth through their own energy efficiency programs, it is reasonable that the changes in sales be defined for each utility, rather than for the entire state-wide electric system.

22. We should not penalize one utility for the higher load growth of another.

23. Edison, PG&E, and SDG&E should each determine the adjusted target funding amounts that result from the adjustment methodology specified in this Resolution. On or before March 31, 2003, and for each subsequent year ending with 2011, each utility should file an advice letter with the Commission, for review by the staff, that adjusts the authorizations and allocations found in Table 7, consistent with § 399.8(d)(2).

24. If the lower of sales change and price change is negative in any one year, authorizations for the subsequent year shall remain constant.

25. If the GDP deflator statistics for 2002 are not finalized by the U.S. Department of Commerce by March 31, 2003, or for any subsequent year, the utilities should use the most recent published forecast for this advice letter filing and true-up their adjustment through an amended filing once the Department of Commerce publishes a final statistic.

26. Comments on this draft Resolution were received from the CEC, Edison, PG&E, and SDG&E on November 4, 2002. Replies to comments were received from the CEC, PG&E, SDG&E, and Edison on November 12, 2002.

27. Edison uses incorrect methodology when it argues that the rate caps contained in § 399.8(c)(2) prevent Edison from raising the funding mandated in Table 7.

28. The rate caps refer to the rates in tariffs on January 1, 2000. Such rates cannot be determined through the methodology used by Edison.

29. The allocation of funding requirements advanced by PG&E transfers a significant portion of the total funding requirement from itself to Edison.

30. Section 381 authorizes the utilities to retain funding for administration of utility transmission and distribution RDD programs. Subsequent legislation has removed this provision.

31. We will interpret the terms "growth" and "inflation" as being nonnegative metrics for the purpose of the adjustment mechanism contained in § 399.8(d)(2).

32. Consistent with our decision in Resolution E-3769, we will require the utilities to forward interest earned on these funds to the CEC.

33. This Resolution is not the proper forum to specify the precise amount of "interest earned on collected funds," as the utilities and the CEC have already established procedures for the determination of these amounts.

34. This Resolution should be effective today.

THEREFORE IT IS ORDERED THAT:

1. Edison, PG&E, and SDG&E are directed to collect and track program funds, along with interest earned on collected funds, as specified in this Resolution, in separate balancing accounts. This tracking will begin with customer billings on January 1, 2002 forward.

2. Monies for the Renewables and RDD programs shall continue to be forwarded quarterly to the CEC, starting with the first quarter of 2002, along with interest earned on collected funds, consistent with the treatment of these funds in P.U. Code § 381.

3. EE programs shall continue to be administered by this Commission.

4. Payments to the CEC for Renewables and RDD programs shall follow the schedule specified in Tables 8 and 9 in this Resolution.

5. Edison shall forward to the CEC the appropriate quarterly payments for Renewables and RDD, as shown in Tables 8 and 9, for March 31, 2002, June 30, 2002, and September 30, 2002, and shall notify the Energy Division in writing when this task has been completed, no later than 14 days after the effective date of this Resolution.

6. The funding amounts mandated in § 399.8 and this Resolution shall be included in the ongoing rate cases for Edison and PG&E, and in the upcoming Annual Rate Design Window proceeding for SDG&E, and rate components shall be adjusted to reflect their application since the beginning of 2002.

7. Edison, PG&E, and SDG&E shall each determine the adjusted target funding amounts that result from the adjustment methodology specified in this Resolution. On or before March 31, 2003, and for each subsequent year ending with 2011, each utility shall file an advice letter with the Commission, for review by the staff, that adjusts the authorizations and allocations found in Table 7, consistent with § 399.8(d)(2).

This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on December 17, 2002; the following Commissioners voting favorably thereon:

_____________________

WESLEY M. FRANKLIN

Executive Director

LORETTA M. LYNCH

President

HENRY M. DUQUE

CARL W. WOOD

GEOFFREY F. BROWN

MICHAEL R. PEEVEY

Commissioners

Appendix

PG&E Rates Net of CARE

		effective	effective
		for billing	for billing
		Aug '99	3/1/00
		CARE	CARE
		srchrg rate	srchrg rate
		0.00045	0.00042
		Effective	Effective
SCHEDULES		1/1/98	1/1/99
		Tariffed rates less above CARE srchrg rates
E1, EM, ES, ESR, ET		$0.00378	$0.00315
EL1, EML, ESL, ESRL, ETL		$0.00337	$0.00272
E7, EL7		$0.00320	$0.00269
EA7, ELA7		$0.00340	$0.00269
E8		$0.00323	$0.00271
EL8		$0.00281	$0.00229
E9A		$0.00324	$0.00270
E9B		$0.00350	$0.00291
E9C		$0.00315	$0.00262
E9D		$0.00254	$0.00210
A-1		$0.00418	$0.00347
A-6		$0.00312	$0.00260
A-15		$0.00884	$0.00730
TC-1		$0.00297	$0.00239
A10	T	$0.00345	$0.00235
A10	P	$0.00300	$0.00250
A10	S	$0.00314	$0.00261
E19, E25	T	$0.00257	$0.00211
E19, E25	P	$0.00239	$0.00200
E19, E25	S	$0.00277	$0.00231
E20	T	$0.00142	$0.00120
E20	P	$0.00210	$0.00176
E20	S	$0.00259	$0.00216
E36		$0.00286	$0.00238
E37		$0.00270	$0.00231
LS-1, LS-2, LS-3		$0.00359	$0.00287
OL-1		$0.00404	$0.00332
STANDBY	T	$0.00238	$0.00199
STANDBY	P	$0.00774	$0.00639
STANDBY	S	$0.00392	$0.00325
AG-1A		$0.00645	$0.00543
AG-RA		$0.00448	$0.00379
AG-VA		$0.00440	$0.00372
AG-4A		$0.00426	$0.00360
AG-5A		$0.00342	$0.00290
AG-6A		$0.00332	$0.00281
AG-7A	T1	$0.00655	$0.00551
AG-7A	T2	$0.00375	$0.00316
AG-1B		$0.00494	$0.00414
AG-RB		$0.00422	$0.00356
AG-VB		$0.00403	$0.00340
AG-4B		$0.00380	$0.00321
AG-4C		$0.00418	$0.00356
AG-5B		$0.00270	$0.00231
AG-5C		$0.00261	$0.00223
AG-6B		$0.00270	$0.00230
AG-7B	T1	$0.00462	$0.00392
AG-7B	T2	$0.00278	$0.00238

SOUTHERN CALIFORNIA EDISON

Public Purpose Program Charges - Public Goods Charges

As of January 1, 2000

Rate Schedule		PGC $/kWh
Residential
D		0.00279
D-CARE		0.00279
TOU-D		0.00279
TOU-EV		0.00279
General Service/Industrial
GS-1		0.00294
GS-2		0.00221
I-6	< 2kV	0.00183
I-6	2 kV to 5o kV	0.00160
I-6	> 50 kV	0.00096
RTP-2 & 3	< 2kV	0.00183
RTP-2 & 3	2 kV to 5o kV	0.00160
RTP-2 & 3	> 50 kV	0.00096
TOU-EV-3		0.00294
TOU-EV-4		0.00226
TOU-GS-1		0.00294
TOU-GS-2		0.00226
TOU-GS-2-SOP		0.00226
TOU-8 (All)	< 2kV	0.00183
TOU-8 (All)	2 kV to 5o kV	0.00160
TOU-8 (All)	> 50 kV	0.00096
Ag. & Pumping
PA-1		0.00271
PA-2		0.00188
PA-RTP		0.00171
TOU-PA		0.00171
TOU-PA-3		0.00171
TOU-PA-4		0.00171
TOU-PA-5		0.00149
TOU-PA-6		0.00171
TOU-PA-7		0.00171
TOU-PA-SOP		0.00171
TOU-PA-SOP-I		0.00171
Street Lighting
AL-1		0.00334
AL-2		0.00334
DWL		0.00334
LS (all)		0.00334
OL-1		0.00334
TC-1		0.00161

SDG&E Rates as of 1/1/00

						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE A
2		Basic Service Fee		$/Month		0.000
3		Energy Charge
4		Summer
5		Secondary		$/kWh		0.00368		0.00317
6		Primary		$/kWh		0.00368		0.00317
7		Winter
8		Secondary		$/kWh		0.00368		0.00317
9		Primary		$/kWh		0.00368		0.00317
10
11		SCHEDULE A-TC
12		Basic Service Fee		$/Month		0.000
13		Energy Charge		$/kWh		0.00368		0.00317
14
15		SCHEDULE A-TOU
16		Basic Service Fee
17		Basic		$/Month		0.000
18		Metering		$/Month		0.000
19		Energy
20		Summer On-Peak		$/kWh		0.00302		0.00251
21		Winter On-Peak		$/kWh		0.00302		0.00251
22		Semi-Peak		$/kWh		0.00302		0.00251
23		Off-Peak		$/kWh		0.00302		0.00251
24
25		SCHEDULE AD (CLOSED)
26		Basic Service Fee		$/Month		0.000
27		Demand Charge
28		Secondary		$/KW		0.000
29		Primary		$/KW		0.000
30		Power Factor		$/kvar		0.000
31		Energy Charge
32		Secondary		$/kWh		0.00302		0.00251
33		Primary		$/kWh		0.00302		0.00251
34		On-Peak Rate Limiter: Summer		$/kWh		0.000
		On-Peak Rate Limiter: Winter		$/kWh		0.000
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE AL-TOU
2		Basic Service Fee
3		Less than or equal to 500 kW
4		Secondary		$/Month		$0.00
5		Primary		$/Month		0.000
6		Secondary Substation		$/Month		0.000
7		Primary Substation		$/Month		0.000
8		Transmission		$/Month		0.000
9		Greater than 500 kW
10		Secondary		$/Month		0.000
11		Primary		$/Month		0.000
12		Secondary Substation		$/Month		0.000
13		Primary Substation		$/Month		0.000
14		Transmission		$/Month		0.000
15		Greater than 12 MW
16		Secondary Substation		$/Month		0.000
17		Primary Substation		$/Month		0.000
18		Distance Adjustment Fee OH - Sec. Sub.		$/foot/Month		0.000
19		Distance Adjustment Fee UG - Sec. Sub.		$/foot/Month		0.000
20		Distance Adjustment Fee OH - Pri. Sub.		$/foot/Month		0.000
21		Distance Adjustment Fee UG - Pri. Sub.		$/foot/Month		0.000
22		Non-Coincident Demand
23		Secondary		$/kW		0.000
24		Primary		$/kW		0.000
25		Secondary Substation		$/kW		0.000
26		Primary Substation		$/kW		0.000
27		Transmission		$/kW		0.000
28		Maximum On-Peak Demand: Summer
29		Secondary		$/kW		0.000
30		Primary		$/kW		0.000
31		Secondary Substation		$/kW		0.000
32		Primary Substation		$/kW		0.000
33		Transmission		$/kW		0.000
34		Maximum On-Peak Demand: Winter
35		Secondary		$/kW		0.000
36		Primary		$/kW		0.000
37		Secondary Substation		$/kW		0.000
38		Primary Substation		$/kW		0.000
39		Transmission		$/kW		0.000
40		Power Factor
41		Secondary		$/kvar		0.000
42		Primary		$/kvar		0.000
43		Secondary Substation		$/kvar		0.000
44		Primary Substation		$/kvar		0.000
45		Transmission		$/kvar		0.000
46		On-Peak Energy: Summer
47		Secondary		$/kWh		0.00302		0.00251
48		Primary		$/kWh		0.00302		0.00251
48		Secondary Substation		$/kWh		0.00302		0.00251
49		Primary Substation		$/kWh		0.00302		0.00251
50		Transmission		$/kWh		0.00302		0.00251
51		Semi-Peak Energy: Summer
52		Secondary		$/kWh		0.00302		0.00251
53		Primary		$/kWh		0.00302		0.00251
53		Secondary Substation		$/kWh		0.00302		0.00251
54		Primary Substation		$/kWh		0.00302		0.00251
55		Transmission		$/kWh		0.00302		0.00251
56		Off-Peak Energy: Summer
57		Secondary		$/kWh		0.00302		0.00251
58		Primary		$/kWh		0.00302		0.00251
58		Secondary Substation		$/kWh		0.00302		0.00251
59		Primary Substation		$/kWh		0.00302		0.00251
60		Transmission		$/kWh		0.00302		0.00251
61		On-Peak Energy: Winter
62		Secondary		$/kWh		0.00302		0.00251
63		Primary		$/kWh		0.00302		0.00251
63		Secondary Substation		$/kWh		0.00302		0.00251
64		Primary Substation		$/kWh		0.00302		0.00251
65		Transmission		$/kWh		0.00302		0.00251
66		Semi-Peak Energy: Winter
67		Secondary		$/kWh		0.00302		0.00251
68		Primary		$/kWh		0.00302		0.00251
68		Secondary Substation		$/kWh		0.00302		0.00251
69		Primary Substation		$/kWh		0.00302		0.00251
70		Transmission		$/kWh		0.00302		0.00251
71		Off-Peak Energy: Winter
72		Secondary		$/kWh		0.00302		0.00251
73		Primary		$/kWh		0.00302		0.00251
73		Secondary Substation		$/kWh		0.00302		0.00251
74		Primary Substation		$/kWh		0.00302		0.00251
75		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE AO-TOU (CANCELLED EFFECTIVE 1/1/02)
2		Basic Service Fee
3		Less than or equal to 500 kW
4		Secondary		$/Month		$0.00
5		Primary		$/Month		0.000
6		Primary Substation		$/Month		0.000
7		Transmission		$/Month		0.000
8		Greater than 500 kW				0.000
9		Secondary		$/Month		0.000
10		Primary		$/Month		0.000
11		Primary Substation		$/Month		0.000
12		Transmission		$/Month		0.000
13		Greater than 12 MW -- Pri. Sub.		$/Month		0.000
14		Distance Adjustment Fee		$/foot/Month		0.000
15		Distance Adjustment Fee UG		$/foot/Month		0.000
16		Non-Coincident Demand
17		Secondary		$/kW		0.000
18		Primary		$/kW		0.000
19		Primary Substation		$/kW		0.000
20		Transmission		$/kW		0.000
21		Maximum On-Peak Demand: Summer
22		Secondary		$/kW		0.000
23		Primary		$/kW		0.000
24		Primary Substation		$/kW		0.000
25		Transmission		$/kW		0.000
26		Maximum On-Peak Demand: Winter
27		Secondary		$/kW		0.000
28		Primary		$/kW		0.000
29		Primary Substation		$/kW		0.000
30		Transmission		$/kW		0.000
31		Power Factor
32		Secondary		$/kvar		0.000
33		Primary		$/kvar		0.000
34		Primary Substation		$/kvar		0.000
35		Transmission		$/kvar		0.000
36		On-Peak Energy: Summer
37		Secondary		$/kWh		0.00302		0.00251
38		Primary		$/kWh		0.00302		0.00251
39		Primary Substation		$/kWh		0.00302		0.00251
40		Transmission		$/kWh		0.00302		0.00251
41		Semi-Peak Energy: Summer
42		Secondary		$/kWh		0.00302		0.00251
43		Primary		$/kWh		0.00302		0.00251
44		Primary Substation		$/kWh		0.00302		0.00251
45		Transmission		$/kWh		0.00302		0.00251
46		Off-Peak Energy: Summer
47		Secondary		$/kWh		0.00302		0.00251
48		Primary		$/kWh		0.00302		0.00251
49		Primary Substation		$/kWh		0.00302		0.00251
50		Transmission		$/kWh		0.00302		0.00251
51		On-Peak Energy: Winter
52		Secondary		$/kWh		0.00302		0.00251
53		Primary		$/kWh		0.00302		0.00251
54		Primary Substation		$/kWh		0.00302		0.00251
55		Transmission		$/kWh		0.00302		0.00251
56		Semi-Peak Energy: Winter
57		Secondary		$/kWh		0.00302		0.00251
58		Primary		$/kWh		0.00302		0.00251
59		Primary Substation		$/kWh		0.00302		0.00251
60		Transmission		$/kWh		0.00302		0.00251
61		Off-Peak Energy: Winter
62		Secondary		$/kWh		0.00302		0.00251
63		Primary		$/kWh		0.00302		0.00251
64		Primary Substation		$/kWh		0.00302		0.00251
65		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE NJ
2		Basic Service Fee
3		Secondary		$/Month		$0.00
4		Primary		$/Month		0.000
5		Primary Substation		$/Month		0.000
6		Transmission		$/Month		0.000
7		Greater than 12 MW -- Pri. Sub.		$/Month		0.000
8		Distance Adjustment Fee OH		$/foot/Month		0.000
9		Distance Adjustment Fee UG		$/foot/Month		0.000
10		Non-Coincident Demand				0.000
11		Secondary		$/kW		0.000
12		Primary		$/kW		0.000
13		Primary Substation		$/kW		0.000
14		Transmission		$/kW		0.000
15		Maximum On-Peak Demand: Summer				0.000
16		Secondary		$/kW		0.000
17		Primary		$/kW		0.000
18		Primary Substation		$/kW		0.000
19		Transmission		$/kW		0.000
20		Maximum On-Peak Demand: Winter				0.000
21		Secondary		$/kW		0.000
22		Primary		$/kW		0.000
23		Primary Substation		$/kW		0.000
24		Transmission		$/kW		0.000
25		Power Factor				0.000
26		Secondary		$/kvar		0.000
27		Primary		$/kvar		0.000
28		Primary Substation		$/kvar		0.000
29		Transmission		$/kvar		0.000
30		On-Peak Energy: Summer
31		Secondary		$/kWh		0.00302		0.00251
32		Primary		$/kWh		0.00302		0.00251
33		Primary Substation		$/kWh		0.00302		0.00251
34		Transmission		$/kWh		0.00302		0.00251
35		Semi-Peak Energy: Summer
36		Secondary		$/kWh		0.00302		0.00251
37		Primary		$/kWh		0.00302		0.00251
38		Primary Substation		$/kWh		0.00302		0.00251
39		Transmission		$/kWh		0.00302		0.00251
40		Off-Peak Energy: Summer
41		Secondary		$/kWh		0.00302		0.00251
42		Primary		$/kWh		0.00302		0.00251
43		Primary Substation		$/kWh		0.00302		0.00251
44		Transmission		$/kWh		0.00302		0.00251
45		On-Peak Energy: Winter
46		Secondary		$/kWh		0.00302		0.00251
47		Primary		$/kWh		0.00302		0.00251
48		Primary Substation		$/kWh		0.00302		0.00251
49		Transmission		$/kWh		0.00302		0.00251
50		Semi-Peak Energy: Winter
51		Secondary		$/kWh		0.00302		0.00251
52		Primary		$/kWh		0.00302		0.00251
53		Primary Substation		$/kWh		0.00302		0.00251
54		Transmission		$/kWh		0.00302		0.00251
55		Off-Peak Energy: Winter
56		Secondary		$/kWh		0.00302		0.00251
57		Primary		$/kWh		0.00302		0.00251
58		Primary Substation		$/kWh		0.00302		0.00251
59		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE AY-TOU (CLOSED)
2		Basic Service Fee
3		Secondary		$/Month		$0.00
4		Primary		$/Month		0.000
5		Transmission		$/Month		0.000
6		Non-Coincident Demand				0.000
7		Secondary		$/kW		0.000
8		Primary		$/kW		0.000
9		Transmission		$/kW		0.000
10		Maximum On-Peak Demand				0.000
11		Secondary		$/kW		0.000
12		Primary		$/kW		0.000
13		Transmission		$/kW		0.000
14		Power Factor				0.000
15		Secondary		$/kvar		0.000
16		Primary		$/kvar		0.000
17		Transmission		$/kvar		0.000
18		On-Peak Energy
19		Secondary		$/kWh		0.00302		0.00251
20		Primary		$/kWh		0.00302		0.00251
21		Transmission		$/kWh		0.00302		0.00251
22		Semi-Peak Energy
23		Secondary		$/kWh		0.00302		0.00251
24		Primary		$/kWh		0.00302		0.00251
25		Transmission		$/kWh		0.00302		0.00251
26		Off-Peak Energy
27		Secondary		$/kWh		0.00302		0.00251
28		Primary		$/kWh		0.00302		0.00251
29		Transmission		$/kWh		0.00302		0.00251
32
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE A6-TOU
2		Greater than 500 kW
3		Primary		$/Month		$0.00
4		Primary Substation		$/Month		0.000
5		Transmission		$/Month		0.000
6		Greater than 12 MW -- Pri. Sub.		$/Month		0.000
7		Distance Adjustment Fee OH		$/foot/Month		0.000
8		Distance Adjustment Fee UG		$/foot/Month		0.000
9		Non-Coincident Demand				0.000
10		Primary		$/KW		0.000
11		Primary Substation		$/kW		0.000
12		Transmission		$/KW		0.000
13		Maximum Demand at Time of System Peak: Summer				0.000
14		Primary		$/KW		0.000
15		Primary Substation		$/kW		0.000
16		Transmission		$/KW		0.000
17		Maximum Demand at Time of System Peak: Winter				0.000
18		Primary		$/KW		0.000
19		Primary Substation		$/kW		0.000
20		Transmission		$/KW		0.000
21		Power Factor				0.000
22		Primary		$/kvar		0.000
23		Primary Substation		$/kvar		0.000
24		Transmission		$/kvar		0.000
25		On-Peak Energy: Summer
26		Primary		$/kWh		0.00243		0.00192
27		Primary Substation		$/kWh		0.00243		0.00192
28		Transmission		$/kWh		0.00243		0.00192
29		Semi-Peak Energy: Summer
30		Primary		$/kWh		0.00243		0.00192
31		Primary Substation		$/kWh		0.00243		0.00192
32		Transmission		$/kWh		0.00243		0.00192
33		Off-Peak Energy: Summer
34		Primary		$/kWh		0.00243		0.00192
35		Primary Substation		$/kWh		0.00243		0.00192
36		Transmission		$/kWh		0.00243		0.00192
37		On-Peak Energy: Winter
38		Primary		$/kWh		0.00243		0.00192
39		Primary Substation		$/kWh		0.00243		0.00192
40		Transmission		$/kWh		0.00243		0.00192
41		Semi-Peak Energy: Winter
42		Primary		$/kWh		0.00243		0.00192
43		Primary Substation		$/kWh		0.00243		0.00192
44		Transmission		$/kWh		0.00243		0.00192
45		Off-Peak Energy: Winter
46		Primary		$/kWh		0.00243		0.00192
47		Primary Substation		$/kWh		0.00243		0.00192
48		Transmission		$/kWh		0.00243		0.00192
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE A-V1 (CLOSED)
2		Signalling Equipment Charge		$/New Cust.		$0.00
3		Basic Service Fee <= to 500 kW
4		Secondary		$/Month		0.00
5		Primary		$/Month		0.00
6		Primary Substation		$/Month		0.00
7		Transmission		$/Month		0.00
8		Greater than 500 kW				0.00
9		Secondary		$/Month		0.00
10		Primary		$/Month		0.00
11		Primary Substation		$/Month		0.00
12		Transmission		$/Month		0.00
13		Greater than 12 MW -- Pri. Sub.		$/Month		0.00
14		Distance Adjustment Fee OH		$/foot/Month		0.00
15		Distance Adjustment Fee UG		$/foot/Month		0.00
16		Contact Closure		$/Month		0.00
17		Demand Charge				0.00
18		Non-Coincident Demand				0.00
19		Secondary		$/kW		0.00
20		Primary		$/kW		0.00
21		Primary Substation		$/kW		0.00
22		Transmission		$/kW		0.00
23		Power Factor				0.00
24		Secondary		$/kvar		0.00
25		Primary		$/kvar		0.00
26		Primary Substation		$/kvar		0.00
27		Transmission		$/kvar		0.00
28		Contract Minimum Demand				0.00
29		Secondary		$/kW\Month		0.00
30		Primary		$/kW\Month		0.00
31		Primary Substation		$/kW\Month		0.00
32		Transmission		$/kW\Month		0.00
33		Energy
34		Signaled Period 1G
35		Secondary		$/kWh		0.00302		0.00251
36		Primary		$/kWh		0.00302		0.00251
37		Primary Substation		$/kWh		0.00302		0.00251
38		Transmission		$/kWh		0.00302		0.00251
39		Semi-Peak
40		Secondary		$/kWh		0.00302		0.00251
41		Primary		$/kWh		0.00302		0.00251
42		Primary Substation		$/kWh		0.00302		0.00251
43		Transmission		$/kWh		0.00302		0.00251
44		Off-Peak
45		Secondary		$/kWh		0.00302		0.00251
46		Primary		$/kWh		0.00302		0.00251
47		Primary Substation		$/kWh		0.00302		0.00251
48		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE A-V2 (CLOSED)
2		Signalling Equipment Charge		$/New Cust.		$0.00
3		Basic Service Fee <= to 500 kW
4		Secondary		$/Month		0.00
5		Primary		$/Month		0.00
6		Primary Substation		$/Month		0.00
7		Transmission		$/Month		0.00
8		Greater than 500 kW				0.00
9		Secondary		$/Month		0.00
10		Primary		$/Month		0.00
11		Primary Substation		$/Month		0.00
12		Transmission		$/Month		0.00
13		Greater than 12 MW -- Pri. Sub.		$/Month		0.00
14		Distance Adjustment Fee OH		$/foot/Month		0.00
15		Distance Adjustment Fee UG		$/foot/Month		0.00
16		Contact Closure		$/Month		0.00
17		Demand Charge				0.00
18		Non-Coincident Demand				0.00
19		Secondary		$/kW		0.00
20		Primary		$/kW		0.00
21		Primary Substation		$/kW		0.00
22		Transmission		$/kW		0.00
23		Power Factor				0.00
24		Secondary		$/kvar		0.00
25		Primary		$/kvar		0.00
26		Primary Substation		$/kvar		0.00
27		Transmission		$/kvar		0.00
28		Contract Minimum Demand				0.00
29		Secondary		$/kW\Month		0.00
30		Primary		$/kW\Month		0.00
31		Primary Substation		$/kW\Month		0.00
32		Transmission		$/kW\Month		0.00
33		Energy
34		Signaled Period 1G
35		Secondary		$/kWh		0.00302		0.00251
36		Primary		$/kWh		0.00302		0.00251
37		Primary Substation		$/kWh		0.00302		0.00251
38		Transmission		$/kWh		0.00302		0.00251
39		Signaled Period 2G
40		Secondary		$/kWh		0.00302		0.00251
41		Primary		$/kWh		0.00302		0.00251
42		Primary Substation		$/kWh		0.00302		0.00251
43		Transmission		$/kWh		0.00302		0.00251
44		Semi-Peak
45		Secondary		$/kWh		0.00302		0.00251
46		Primary		$/kWh		0.00302		0.00251
47		Primary Substation		$/kWh		0.00302		0.00251
48		Transmission		$/kWh		0.00302		0.00251
49		Off-Peak
50		Secondary		$/kWh		0.00302		0.00251
51		Primary		$/kWh		0.00302		0.00251
52		Primary Substation		$/kWh		0.00302		0.00251
53		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE RTP-2 (CLOSED)
2		Basic Service Fees
3		Less than or equal to 500 kW
4		Secondary		$/Month		$0.00
5		Primary		$/Month		0.000
6		Primary Substation		$/Month		0.000
7		Transmission		$/Month		0.000
8		Greater than 500 kW				0.000
9		Secondary		$/Month		0.000
10		Primary		$/Month		0.000
11		Primary Substation		$/Month		0.000
12		Transmission		$/Month		0.000
13		Greater than 12 MW -- Pri. Sub.		$/Month		0.000
14		Distance Adjustment Fee OH		$/foot/Month		0.000
15		Distance Adjustment Fee UG		$/foot/Month		0.000
16		Demand Charge				0.000
17		Non-Coincident Demand				0.000
18		Secondary		$/kW		0.000
19		Primary		$/kW		0.000
20		Primary Substation		$/kW		0.000
21		Transmission		$/kW		0.000
22		Power Factor				0.000
23		Secondary		$/kvar		0.000
24		Primary		$/kvar		0.000
25		Primary Substation		$/kvar		0.000
26		Transmission		$/kvar		0.000
27		Contract Minimum Demand				0.000
28		Secondary		$/kW		0.000
29		Primary		$/kW		0.000
30		Primary Substation		$/kW		0.000
31		Transmission		$/kW		0.000
32		Energy
33		RTP Period
34		Secondary		$/kWh		0.00302		0.00251
35		Primary		$/kWh		0.00302		0.00251
36		Primary Substation		$/kWh		0.00302		0.00251
37		Transmission		$/kWh		0.00302		0.00251
38		On-Peak: Summer
39		Secondary		$/kWh		0.00302		0.00251
40		Primary		$/kWh		0.00302		0.00251
41		Primary Substation		$/kWh		0.00302		0.00251
42		Transmission		$/kWh		0.00302		0.00251
43		Semi-Peak: Summer
44		Secondary		$/kWh		0.00302		0.00251
45		Primary		$/kWh		0.00302		0.00251
46		Primary Substation		$/kWh		0.00302		0.00251
47		Transmission		$/kWh		0.00302		0.00251
48		Off-Peak: Summer
49		Secondary		$/kWh		0.00302		0.00251
50		Primary		$/kWh		0.00302		0.00251
51		Primary Substation		$/kWh		0.00302		0.00251
52		Transmission		$/kWh		0.00302		0.00251
53		On-Peak: Winter
54		Secondary		$/kWh		0.00302		0.00251
55		Primary		$/kWh		0.00302		0.00251
56		Primary Substation		$/kWh		0.00302		0.00251
57		Transmission		$/kWh		0.00302		0.00251
58		Semi-Peak: Winter
59		Secondary		$/kWh		0.00302		0.00251
60		Primary		$/kWh		0.00302		0.00251
61		Primary Substation		$/kWh		0.00302		0.00251
62		Transmission		$/kWh		0.00302		0.00251
63		Off-Peak: Winter
64		Secondary		$/kWh		0.00302		0.00251
65		Primary		$/kWh		0.00302		0.00251
66		Primary Substation		$/kWh		0.00302		0.00251
67		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE S
2		Contracted Demand
3		Secondary		$/kW		$0.00
4		Primary		$/kW		0.000
5		Primary Substation		$/kW		0.000
6		Transmission		$/kW		0.000
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE PA-T-1
2		Basic Service Fee		$/Month		0.000
3		Demand: On-Peak
4		Option A
5		Secondary		$/kW		0.000
6		Primary		$/kW		0.000
7		Transmission		$/kW		0.000
8		Option B				0.000
9		Secondary		$/kW		0.000
10		Primary		$/kW		0.000
11		Transmission		$/kW		0.000
12		Option C				0.000
13		Secondary		$/kW		0.000
14		Primary		$/kW		0.000
15		Transmission		$/kW		0.000
16		Option D				0.000
17		Secondary		$/kW		0.000
18		Primary		$/kW		0.000
19		Transmission		$/kW		0.000
20		Option E				0.000
21		Secondary		$/kW		0.000
22		Primary		$/kW		0.000
23		Transmission		$/kW		0.000
24		Option F				0.000
25		Secondary		$/kW		0.000
26		Primary		$/kW		0.000
27		Transmission		$/kW		0.000
28		Demand: Semi-Peak				0.000
29		Secondary		$/kW		0.000
30		Primary		$/kW		0.000
31		Transmission		$/kW		0.000
32		Energy: On-Peak
33		Secondary		$/kWh		0.00302		0.00251
34		Primary		$/kWh		0.00302		0.00251
35		Transmission		$/kWh		0.00302		0.00251
36		Energy: Semi-Peak
37		Secondary		$/kWh		0.00302		0.00251
38		Primary		$/kWh		0.00302		0.00251
39		Transmission		$/kWh		0.00302		0.00251
40		Energy: Off-Peak
41		Secondary		$/kWh		0.00302		0.00251
42		Primary		$/kWh		0.00302		0.00251
43		Transmission		$/kWh		0.00302		0.00251
						PPP		PPP
						RATE		RATE
LINE		DESCRIPTION		UNITS		(with CARE)		(w/ out CARE)
NO.		(A)		(B)		(C)		(D)
1		SCHEDULE PA
2		Basic Service Fee		$/Month		$0.00000
3		Energy		$/kWh		0.00387		0.00336
4
5		SCHEDULE PA-TOU (CLOSED)
6		Metering Charge		$/Month		0.000
7		Basic Service Fee		$/Month		0.000
8		Energy: On-Peak		$/kWh		0.00387		0.00336
9		Energy: Off-Peak		$/kWh		0.00387		0.00336

¹ All further citations are to sections of the PU Code unless otherwise specified.

² Section 381(d) increased the funding for Renewables to $540 million by extending the period for CTC collection for up to three months into 2002. The allocation for this additional $75 million burden was set by D.97-11-022 as the pro rata share of each utility's contribution during the 1998-2001 period.

³ See Section B and Table 10.

⁴ The rates identified as PGC rates in utility tariffs at the beginning of 2000 are listed in the appendix to this Resolution. Note that the PGC rate was one component of the rates frozen by §368. Thus no incremental monies were generated by this rate component. By D.97-10-057, the PGC memorandum accounts are to be credited to the Transition Revenue Account, and thus all funds received in retail rates in excess of the amounts mandated by §381 were credited to this account.

⁵ These rates are net of the CARE surcharges, which in January, 2000 were .039 cents per kWh for PG&E, .095 cents per kWh for Edison, and .051 cents per kWh for SDG&E.

⁶ The rate of inflation is determined exogenously and is thus beyond the control of any one utility. For this reason, the rate of inflation should be calculated for the entire system rather than for each utility.

⁷ This is an index of the market prices of the country's domestically produced goods and services.

⁸ This is the percentage change in the GDP Deflator Index.

⁹ Statistics published by the Bureau of Economic Analysis, U. S. Department of Commerce regarding the U. S. Gross Domestic Product deflator can be found at http://www.bea.gov/ .

¹⁰ PG&E uses a similar incorrect methodology in its discussion on p. 5 of its Comments.

¹¹ SCE-8, Chap. IV, p. 2.

¹² It appears that the CEC concerns are based primarily on Edison's analysis regarding the rate cap, which we have shown to be incorrect (see above).

¹³ This would reduce Edison's share of funding to 39.5%, while SDG&E's would be 14.0% and PG&E's would be 46.5%.

¹⁴ S.B. 1194 (Sher, Stats. 2000, Chapter 1051).