XI. Issuance of the Proposed Decision
The proposed decision was issued on May 9, 2001. Parties filed and served comments on the proposed decision on May 10 and appeared for final oral argument (FOA) before a quorum of the Commission on May 11. Public Utilities Code Section 311(d) generally requires, in matters that have gone to hearing, a 30-day period between service of an assigned Commissioner's or ALJ's proposed decision and the Commission's issuance of the decision. However, Section 311(d) provides that that period may be reduced or waived by the Commission "in an unforeseen emergency or upon the stipulation of all parties to the proceeding or as otherwise provided by law."
Although not expressly stated in Section 311(d), the 30-day period provides an opportunity for parties to comment on the proposed decision. In this proceeding, we are considering the rate design to apply to the three-cent surcharge adopted in D.01-03-082. One of the stated goals of this rate design is to encourage conservation to help Californians avoid, to the extent possible, rolling blackouts during the summer months. Given the fact that the Independent System Operator (ISO) has identified over 30 days28 in which it predicts rolling blackouts to occur and the State of Emergency called by Governor Davis on January 17, 2001, we believe that this constitutes an unforeseen emergency for these purposes. Such blackouts threaten to severely impair public health and safety. Accordingly, we will reduce the 30-day advance publication period of Section 311(d) to six days, and will allow parties to file and serve written comments on May 10, followed by final oral argument on May 11 and Commission consideration of the decision on May 14.
Findings of Fact
1. To the extent possible, we will design rates to promote our fundamental goals of equity and conservation in this proceeding.
2. The goal of equity is one of fairness, viewed in a broad context and encompasses both social and political questions.
3. We do not have the necessary data to consider cost-based equity at this time, because the wholesale market is dysfunctional and costs are not the basis of prices being charged. In addition, we do not have accurate information regarding the nature and extent of costs relating to power purchases to date by CDWR.
4. We recognize the economic impact our revenue allocation and rate design decision will have on all sectors of California. We intend to design rates that provide price signals to which customers can respond and thereby reduce the amount of the increase they will see on their bills.
5. We do not have sufficient data to pursue reducing the disparity in prices paid for energy among customer classes, but intend to revisit this goal in future proceedings.
6. Conserving electricity means reducing the amount of electric power needed to serve customers. A reduction in total energy consumption will help protect Californians from blackouts and reduce the total financing needed by the state to purchase electricity.
7. We intend to promote the greatest amount of conservation during summer peak hours. Summer peak is the time PG&E and Edison have the largest net short position and are therefore projecting a need for the most purchases from CDWR and the ISO to meet anticipated customer needs.
8. Power purchased in the wholesale market all hours by CDWR and the Independent System Operator (ISO) to serve the customers of PG&E and Edison is prohibitively expensive. Once CDWR provides us with information, broken out by month and time of day, on the amount of power it had under contract, the prices it would be paying, and the amount of power it anticipated buying on the spot market, we should be able to determine the value of conserving energy in specific peak periods. However, at this time, the record demonstrates that all energy purchased this summer will be expensive and power purchased in peak periods will be even more expensive.
9. To maximize the value of conserving energy at peak times, we can strengthen the price signal we send customers for periods when prices are highest. We have some ability to do this now by increasing rates at peak periods for those customers on time-of-use (TOU) schedules.
10. The Governor's 20/20 program is designed to reward customers who reduce their overall electric consumption by 20% this summer. This incentive, along with customer education, energy efficiency programs, and the price signal that higher rates will send customers, are effective tools to promote conservation.
11. We recognize business customers generally place an extremely high value on reliability and expect that these customers will be particularly receptive to peak reduction programs and the interruptible programs adopted in R.00-10-002.
12. The Legislature authorized $35 million in SB 5X for the CEC to install interval meters on all commercial customers of PG&E and Edison with connected loads of 200 MW and above. When CEC completes this installation and the CDWR provides specific projections, the Commission will be better able to specifically target and provide more effective price signals.
13. The incremental revenue requirement created by the surcharge authorized in D.01-03-082 is a function of the sales to which the revenue requirement increase applies.
14. The sales forecasts, while the best evidence available, should only be used for the limited purposes of calculating the revenue requirement to be applied in this proceeding.
15. The Commission adopted the one-cent surcharge on January 4, 2001, which applies to all sales except to customers eligible for the CARE program.
16. AB1X prohibits increases to rates, effective as of January 5, 2001, applicable to residential usage below 130% of baseline usage. Usage below 130% is not exempt from the one-cent surcharge. Usage below 130% of baseline usage is exempt from the three-cent surcharge.
17. The EPS is already reflected in the rates that are used as the starting point for the rate design being considered in this proceeding.
18. The revenue allocation and rate design discussed in this decision applies to the three-cent increase adopted in D.01-03-082.
19. Edison calculates the incremental revenue to be recovered by multiplying 3¢/kWh times its total forecasted system-wide sales for 2001 of 83.78 billion kWh. This results in an annual revenue increase of $2.513 billion.
20. PG&E applies 3¢/kWh increase to all its forecasted sales for 2001, which results in an annual incremental revenue requirement of $ 2.46 billion.
21. There is no way of knowing actual procurement costs at this point in time. CDWR has not yet established its revenue requirements for procuring power.
22. We have clearly stated that CDWR is to receive the full amount the utilities collect from all customers for each kWh of power provided by CDWR.
23. PG&E and Edison are required to pay CDWR for energy purchases on behalf of all retail customers, without providing any exemptions for CARE usage or residential usage below 130% of baseline.
24. The two principal issues concerning revenue allocation are: (1) the method used to apportion the revenue increase among customer classes; and (2) the treatment of the shortfall which results from exempting residential usage up to 130% of baseline consumption from any increase.
25. The allocation and rate design issues addressed in this decision are limited to allocation and design of the revenues to be collected pursuant to the surcharge. The underlying rate structure of the utilities will not change.
26. The fundamental facts underlying traditional cost-based revenue allocation have changed. The dysfunctional wholesale energy market has resulted in unconscionable, unlawful wholesale prices, which have increased by staggering proportions since the summer of 2000. These prices bear no relationship to any actual costs incurred in production. The outrageously priced wholesale energy that causes us to take the extraordinary step of imposing this rate surcharge is being produced at the same plants upon which we based our traditional cost allocation procedures. The price of wholesale energy is no longer a function of cost of production but rather a function of what price that can be extracted from a market subject to manipulation.
27. Absent data from CDWR regarding cost forecasts, we have nothing upon which we might be able to determine a cost-based revenue requirement, or to do revenue allocation guided by cost causation.
28. Recent price experience suggests that all kWhs will be valuable. In this volatile and dysfunctional market, we cannot predict which kWhs at what particular time periods will be more valuable than others.
29. The surcharge is in place to provide the additional funds necessary to provide for customers' energy consumption and we have previously determined that generation costs associated specifically with energy consumption are properly recovered using an equal cents per kilowatt hour methodology.
30. Because we have used total forecast sales to this class, and all other classes, upon which to allocate the revenue requirement associated with the 3¢/kWh surcharge, the share allocated to residential sales that are exempt from paying the surcharge must be re-allocated to other sales.
31. Re-allocating the revenue requirement associated with sales that are exempt from paying the surcharge solely to the narrow range of remaining residential sales is too severe. The cost of this legislatively-mandated exemption should be broadly assessed across all customer groups.
32. The revenue requirement caused by exempting CARE customers should be allocated to all other customer classes, including streetlighting.
33. Funding for the CARE program is not at issue in allocating the CARE surcharge shortfall.
34. Because of the extraordinary size of the rate increase, it is reasonable to exempt customers who have usage above 130% of baseline due to medical conditions. The protection we afford these vulnerable customers has a similar equitable basis to our CARE customer exemption.
35. Direct access customers do not contribute to the net short that the CDWR is procuring on behalf of PG&E's and Edison's customers.
36. It would be inequitable for direct access customers to pay for both their own cost of procurement and the procurement costs of bundled customers.
37. The right to recover the revenues equivalent to the three-cent surcharge was established by D.01-03-082 and affected only electricity delivered from the effective date of that decision forward.
38. A 12-month amortization period for the collection of the revenue associated with applying the three-cent surcharge to all sales from March 27, 2001 to the day utilities begin collecting the surcharge it will have less of an impact on already high rates than a shorter amortization period, and it will not disadvantage summer intensive industries such as agriculture.
39. Shifting customers to time-of-use metered schedules helps us achieve our goal of conservation as it shifts use away from periods of peak demand.
40. We can ensure that customers shifted to TOU schedules do not contribute any additional revenue toward transition cost recovery by requiring the utilities to establish tracking accounts for these customers and if there is any net increase in billings as a result of requiring these customers to shift to TOU schedules, applying these increased revenues only to those purposes to which we have previously dedicated the one-cent and three-cent surcharges.
41. We do not have sufficient information to craft a definition of "agricultural commodity food processors" or to determine that no cost shifting to other classes would occur if these customers were allowed to migrate to the agricultural tariffs, as provided under Pub. Util. Code § 740.11.
42. Bill limiters are an effective short-term means to address the concerns of unique industry groups requesting to migrate to special schedules and to mitigate rate shock on individual customers.
43. We expect the revenue shortfall from implementing bill limiters to be small and it is addressable by the utilities reflecting in their compliance advice letters an allocation of the expected shortfall and then establishing balancing accounts to track the over- or undercollection.
44. Increasing block tiers is most equitable form of revenue allocation because prices for the residential customers who are the heaviest users will be higher than moderate users, which is consistent with our goal to encourage conservation through higher rates above threshold usage.
45. It is reasonable to adopt a 5 tier-rate design with incremental block tiers with the following tiers:
a. Tier 1 Up to the baseline amount
b. Tier 2 From 100 - 130% of baseline
c. Tier 3 From 130 - 200% of baseline
d. Tier 4 From 200 - 300% of baseline
e. Tier 5 In excess of 300% of baseline
46. The components of the rate increase in the tiers 3 through 5 include the residential class allocation, and the residential class' share of the shortfalls due to CARE, medical baseline allowances, and the 130% exemption.
47. Schedule E-8 energy charges do not adequately represent the costs of serving schedule E-8 customers as compared to the costs of serving schedule E-1 customers.
48. Because the residential core electric rates have not been adjusted since 1993, schedule E-1 customers pay higher rates to subsidize schedule those customers on the E-8 tariff. This sends the wrong price signal to residential customers with heavy heating loads by encouraging them to increase their winter peak loads.
49. Schedule E-8 fails to meet the Commission's conservation objectives of equity and conservation.
50. We would prefer to eliminate Schedule E-8; however, we must provide sufficient notice to customers, pursuant to § 729.5. It is reasonable, for now, to adopt TURN's proposal to close this schedule to new customers.
51. Tiering rate classes comprised of customers with substantially dissimilar usage volumes is inequitable and inconsistent with our conservation goal.
52. All nonresidential consumers, without regard of usage volume, must conserve, since all usage contributes to the amount that must be purchased by the CDWR.
53. The record does not support the finding that customers with greater usage volume are necessarily inefficient.
54. Tiering the nonresidential class would impose disproportionate impacts on larger volume usage consumers without regard to their efficiency.
55. A uniformly applied rate increase of 3¢/kWh to the nonresidential class provides the appropriate conservation incentive and discourages unfounded biases based upon usage volume.
56. Rates based on SIC classification do not predict energy efficiency or usage, and neither PG&E nor Edison has the SIC classifications of their consumers.
57. PG&E and Edison should collect SIC classification data from their customers in an effort to understand whether a more detailed system of rate design by SIC classification should be available in future rate design proceedings.
58. Tiering nonresidential rates by the customer's historic usage could lead to gaming of meters, result in punishment for seasonal variation, and such tiering would be difficult to implement for new or expanding businesses.
59. Tiering nonresidential rate schedules by baseline usage would reward inefficient users.
60. Tiering TOU rate schedules should be rejected because time-of-use signals are more precise and encourage conservation at the appropriate times relative to the signals sent by tiering, and neither Edison nor PG&E can implement tiered TOU rates by June 1.
61. ORA's proposal for nonresidential, non-TOU rate design for small and large commercial customers is reasonable and consistent with our goals because it balances the year-round need for conservation, with a stronger conservation signal during the peak summer months. 70% of revenue requirement will be allocated to the summer period and 30% to the winter period.
62. We encourage conservation at all time periods. Without adequate date from CDWR showing which period is more valuable than another, we cannot support limiting price signals to one period only.
63. No rate caps should be allotted to the non-TOU nonresidential customer class, other than the bill limiters of 300% of class usage.
64. Customers with declining block schedules, such as GS-2 and PA-2 for Edison, should be corrected to be an increasing block structure to improve conservation incentives.
65. A simple all-hour rate increase does not sufficiently promote conservation during the hours of peak demand.
66. Placing the vast majority of the revenue requirement burden on summer on-peak consumption may result in too much shifting off-peak.
67. The revenue requirement should be spread over all hours, but more of the increase should fall on summer on-peak usage. Although the differential between on- and off-peak usage is increased, on-peak prices are not excessive.
68. We reject the proposed 3-hour super on-peak period for the food processing industry because it would not be revenue neutral.
69. We reject the County of Los Angeles' proposal to limit the impact the rate of increase on essential government facilities because we oppose preferential treatment for any customer class.
70. Agricultural customers depend heavily on summer on-peak usage and have a limited ability to load shift.
71. Agricultural customers are disproportionately affected by the rate increases in this year due to the unique combination of the energy emergency and drought.
72. To mitigate the effects of the rate increase on agricultural customers, it is reasonable to cap agricultural rate increases at 30% for both time-of-use and non-time-of-use customers, with the resulting revenue shortfall to be spread over all eligible customer classes, including streetlights and residential consumers above 130% of baseline.
73. A bill limiter of 250% on energy charges for agricultural customers will assist individual customers within this class in managing their bills.
74. Master meter customers should revise their billing systems to incorporate this surcharge, and to comply with Water Code § 80110 and Pub. Util. Code § 739.5, by June 1, 2001.
75. It is inequitable to allow the master metered customers to reap the financial benefits of the sub-metering transaction without bearing the responsibility that comes with that transaction, i.e., the payment of the surcharge.
76. The surcharge revenue requirement is allocated to the streetlight, outdoor lighting schedules, and traffic signal schedules on equal cents per kilowatt-hour basis.
77. It is not necessary at this time to adopt TURN's tiering method for streetlights (based on the type of lamp rather than the size of lamp or size of customer) because the rate increase itself will prompt cities and counties who employ streetlights to invest in the more efficient bulbs.
78. Interruptible customers should not be exempted from the surcharge, as CIPA proposes. Interruptible customers already receive a substantial pricing incentive, which cannot be altered until March 31, 2002, pursuant to § 743.1(b).
79. Customers must receive as much information as possible about their usage pattern and pricing information in order to make intelligent decisions about energy consumption.
80. Data collection this summer is essential both for analysis in future rate proceedings and to raise consumer awareness about the challenges California faces in the months ahead.
81. Commission staff will work with the utilities to maximize the potential for information sharing and customer assistance offered by the website.
82. Real time pricing has tremendous potential for reducing the overall costs of supplying energy because such pricing will enable to customers to control their bills by shifting load to lower cost times, and will also reduce peak load.
83. Real time pricing meters are critical to implementing real time pricing.
84. The Legislature has appropriated $35 million dollars for the installation of real time pricing metering systems for all bundled service customers with greater than 200 kW in peak load by a program administered by the CEC.
85. We will closely monitor the CEC's progress in installing the meters, and commit to providing any necessary assistance to ensure timely installation of the meters. Our staff will cooperate and assist the CEC in these efforts.
86. We will limit the 10% RRB-financed reduction to rates in effect prior to implementation of the 1¢/kWh and 3¢/kWh surcharges.
87. The customer bill format must communicate the direct correlation between electricity supply, price, usage, and consumption patterns in order to promote price-responsive behavior.
88. Customers need to be informed about the rate increase and how they will be impacted.
89. Consumers are most likely to respond to price signals when the bill provides sufficient detail allowing consumers to clearly identify and understand the differential pricing structures.
90. The customer bill does not provide sufficient space to accommodate comprehensive information about the rate increase. Electric customers should receive information describing the need for the rate increase and the tiered rate structure adopted by the Commission.
91. We will proceed expeditiously to develop and adopt a voluntary RTP that will be available to customers when their interval meters are installed, and we direct Energy Division to work closely with PG&E and Edison on their billing system constraints and the manual billing procedures that can be done for customers until the system changes are complete.
92. Energy Division will facilitate a workshop on May 21, 2001 on real time pricing issues, and we anticipate adopting a final program later this summer. It is reasonable that this workshop be used to develop a master data request and format for data collection. We intend that the data request be finalized and issued no later than June 8 and to refine our approach to rate design in early July.
93. We intend to comprehensively and rigorously review of PG&E's and Edison's rate schedules and rate design in early 2002.
94. The proposed decision was issued on May 9, 2001. Parties filed and served comments on the proposed decision on May 10 and appeared for final oral argument before a quorum of the Commission on May 11.
95. Although not expressly stated in Section 311(d), the 30-day period provides an opportunity for parties to comment on the proposed decision.
96. One of the stated goals of the rate design options considered in this decision is to encourage conservation to help Californians avoid, to the extent possible, rolling blackouts during the summer months.
97. The ISO has predicted more than 30 days of rolling blackouts of electricity supply over the upcoming summer.
98. Electricity supply blackouts can severely impair public health and safety.
99. On January 17, 2001, Governor Davis declared a State of Emergency due to the energy shortage in California.
1. Water Code § 80110 exempts all residential usage below 130% of baseline from any increase in electricity charges after February 1, 2001.
2. It is reasonable to allocate this extraordinary surcharge on an equal cents per kWh basis, in a manner that protects vulnerable customers and ensures no individual customers experience extreme hardship.
3. It is reasonable to adopt a revenue allocation and rate design that achieve the following objectives: (1) reduce the need for procuring power and therefore reduce the amount of money California is paying wholesale generators for electric power; (2) allocate the unreasonable costs of this generation in a fair and understandable manner to all customers, recognizing the adverse economic impact our decision will have on all sectors of California life; (3) protect the most vulnerable customers; (4) ensure no individual customers experience extreme hardship; and (5) provide customers the necessary tools to manage their energy usage and reduce their energy bills.
4. An equal cents per kilowatt-hour is the most equitable revenue allocation methodology as well as the methodology most appropriate to apportioning energy purchase costs to all future energy consumption. This allocation methodology is also simple, understandable, and consistent with our approach for the one cent surcharge adopted in D.01-01-018.
5. Because we agree that the revenue requirement increase should apply only to the 3¢/kWh adopted in D.01-03-082 and because we agree that we will use the utilities' sales forecasts for our determinations in this decision only, these revenue requirement increases are reasonable.
6. It is reasonable to base the revenue requirement on applying the surcharge to forecast system-wide sales.
7. It is reasonable that the revenue requirement shortfall caused by applying the 3¢/kWh surcharge approved in D.01-03-082 to sales to residential customers below 130% of baseline should be re-allocated to all sales other than residential sales below 130% of baseline.
8. It is reasonable to allocate the revenue requirement shortfall from exempting CARE customers to all other customer classes, including streetlighting. This allocation is not a revenue requirement necessary to fund the low-income discount program, from which street lighting continues to be exempt, but rather a general surcharge covering procurement of electricity. It should be allocated as broadly as possible to achieve our goals of equity and conservation.
9. We should exempt from the surcharge all customers who have usage above 130% due to medical conditions. The utilities should reflect the exemption of medical baseline customers in the tariffs they file pursuant to this order.
10. We should allocate the revenue shortfall from this exemption in the same manner as we allocate the CARE shortfall.
11. The revenue associated with applying the three-cent/kWh surcharge to all non-exempt energy sales from March 27, 2001 to the day utilities begin collecting the surcharge should be added to each utility's revenue requirement and amortized over a 12-month period.
12. The surcharge adopted in D.01-03-082 should not apply to direct access customers because they are not relying on CDWR or the utilities to obtain their power.
13. We should require certain customers to shift to TOU schedules in order to better address the current energy emergency.
14. Requiring customers to shift to TOU schedules is not precluded by the continuing rate freeze because no additional revenues will be applied toward transition cost recovery.
15. Our record is insufficient to conclude that there will be no cost shifting if we expand the definition of the agricultural class to include agricultural commodity processing customers. Therefore, pursuant to Pub. Util. Code § 740.11, we do not expand the definition of the agricultural class.
16. It is reasonable to adopt the use of bill limiters of 300% for all rate classes other than agriculture and 250% for the agricultural class, relative to the class average rate. A lower limiter for the agricultural class is reasonable due to the higher than normal water pumping requirements forecast for this summer.
17. CIPA's proposed alteration of the interruptible customer credit calculation is prohibited by § 743.1(b) because it would alter the level of the pricing incentive for interruptible or curtailable service be altered from the levels in effect on June 10, 1996 prior to March 31, 2002.
18. Pursuant to § 368(a), PG&E's and Edison's residential and certain small commercial customers currently receive a 10% reduction to their electricity rates, financed by rate reduction bonds issued pursuant to § 840-847, and orders of this Commission. The 10% rate reduction applies through the end of the transition period established in § 368(a), i.e., through March 31, 2002.
19. We need not and should not determine any ratemaking ramifications of the expiration of the 10% RRB-financed rate reduction in this decision.
20. Section 311(d) generally requires, in matters that have gone to hearing, a 30-day period between service of an assigned Commissioner's or ALJ's proposed decision and the Commission's issuance of the decision. That section also provides that that period may be reduced or waived by the Commission "in an unforeseen emergency or upon the stipulation of all parties to the proceeding or as otherwise provided by law."
21. Based on the fact that the ISO has identified over 30 days in which it predicts rolling blackouts to occur and the State of Emergency called by Governor Davis on January 17, 2001, we conclude that an unforeseen emergency as provided in § 311(d) exists for purposes of adopting this decision.
22. Consistent with the conclusion that an unforeseen emergency exists, we have the authority to reduce the 30-day advance publication period of § 311(d) to five days, and to allow parties to file and serve written comments on May 10, followed by final oral argument on May 11 and Commission consideration of the decision on May 14.
23. This order should be effective today in order to allow the adopted rate design to be implemented expeditiously.
IT IS ORDERED that:
1. Within seven days of the effective date of this decision, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) shall file compliance advice letters with complete tariffs to implement the rate design changes adopted herein. PG&E's advice letter shall become effective on June 1, 2001 subject to Energy Division determining that it is compliant with this Order. Edison's advice letter shall become effective on June 3, 2001 subject to Energy Division determining that it is compliant with this Order. PG&E and Edison shall include with their advice letters detailed and complete workpapers showing the revenue allocation and rate design calculations underlying the new rates for each rate schedule. On the same day that they file their advice letters, PG&E and Edison shall serve electronic copies of the workpapers on Energy Division and all active parties in this phase of the proceeding. Specifically, PG&E and Edison shall comply with the following:
a) The revenue allocation and rate design applies to the 3 cents/kilowatt-hour (kWh) surcharge adopted in Decision (D.) 01-03-082.
b) The incremental revenue requirement associated with the 3 cent/kWh surcharge adopted in D.01-03-082 shall be based on applying the surcharge to forecast system-wide sales excluding direct access sales. The rates attached to this Order reflect revenue allocation and rate design including direct access sales. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show the level of direct access sales removed from the sales forecast in developing the revenue allocation, rate design, and resulting rates.
c) The incremental revenue requirement associated with the 3¢/kWh surcharge adopted in D.01-03-082 shall be allocated among the customer classes based on the proportional number of bundled service kilowatt-hours (kWhs) each class is forecast to consume during calendar year 2001 (i.e., equal cents per kWh allocation).
d) CARE customers, residential usage below 130% of baseline, and non-CARE medical baseline customers are exempt from any revenue allocation associated with the 3 cent/kWh surcharge authorized by D.01-03-082. The rates attached to this decision do not reflect the exemption of non-CARE medical baseline customers. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show the sales associated with non-CARE medical baseline customers, and how the rates were adjusted to reflect exemption of these customers from the surcharge.
e) The revenue resulting from applying the 3¢/kWh surcharge approved in D.01-03-082 to forecast sales to bundled service residential customers below 130% of baseline, CARE customers, and non-CARE medical baseline customers shall be re-allocated on an equal cents per kWh basis to all bundled service sales other than 1) residential sales below 130% of baseline, 2) sales to CARE customers, and 3) sales to non-CARE medical baseline customers.
f) PG&E and Edison shall reflect in the rates an allocation of shortfalls resulting from the application of the bill limiters adopted herein (bill limiter shortfalls). The rates attached to this decision do not reflect an allocation of bill limiter shortfalls. Thus, in workpapers supporting their advice letters, PG&E and Edison shall show how they developed the amount ($) of the bill limiter shortfalls and how these shortfalls are reflected in the revenue allocation, rate design, and rates within each rate schedule. The bill limiter shortfalls shall be allocated on an equal cents per kWh basis to all bundled service sales other than 1) sales to CARE customers, 2) sales to non-CARE medical baseline customers, and 3) residential sales below 130% of baseline.
g) PG&E and Edison shall each establish a balancing account to track the actual bill limiter revenue shortfall amount compared to the allocation of the bill limiter shortfalls required pursuant to Ordering Paragraph 1f, above. Balances in these accounts will be reviewed in PG&E's and Edison's next respective electric rate design proceedings.
h) Edison and PG&E shall reflect a 5 tier-rate residential rate design with incremental block tiers with the following tiers:
a. Tier 1 Up to the baseline amount
b. Tier 2 From 100 - 130% of baseline
c. Tier 3 From 130 - 200% of baseline
d. Tier 4 From 200 - 300% of baseline
e. Tier 5 In excess of 300% of baseline.
i) For small and large commercial customers with seasonal designation, 70% of revenue requirement shall be allocated to the summer period and 30% to the winter period.
j) Non-TOU nonresidential customer class and the residential class shall have a bill limiter of 300% of class usage.
k) All customers with declining block schedules shall be corrected to be an increasing block structure.
l) Agricultural rate increases shall be limited to 30% for both time-of-use and non-time-of-use customers, with the resulting revenue shortfall to be spread over all eligible customer classes, including streetlights and residential consumers above 130% of baseline.
m) Agriculture rates shall also be subject to a bill limiter of 250% on energy charges.
n) The surcharge revenue requirement shall be allocated to the streetlight and outdoor lighting schedules on equal cents per kilowatt-hour basis.
o) An equal cents per kilowatt-hour design for traffic signals shall be reflected in the tariffs.
p) The 10% RRB-financed reduction to rates shall apply to rates in effect prior to implementation of the 1¢/kWh and 3¢/kWh surcharges.
q) The bill format shall incorporate D.01-03-082's rate increase through the applicable baseline tiers, mid-, off-, or on-peak classifications, or other appropriate usage-based component.
r) The bill format shall label the surcharge as "energy surcharge" or "energy procurement surcharge" and should provide the customer a separate line item of total energy surcharges.
2. PG&E and Edison shall amortize the revenue associated with applying the 3¢/kWh surcharge to all non-exempt energy sales from March 27, 2001, to the day utilities begin collecting the surcharge over a 12-month period beginning with the date the utilities begin collecting the surcharge.
3. PG&E and Edison shall collect SIC classification data from their customers in an effort to understand whether a more detailed system of rate design by SIC classification should be available in future rate design proceedings.
4. Master meter customers shall revise their billing systems to incorporate this surcharge, and to comply with Water Code § 80110 and Pub. Util. Code § 739.5, by June 1, 2001.
5. We direct PG&E and Edison to post on their respective websites: (1) dynamic load profile information for all rate groups for which such information is available, (2) pricing information, as it becomes available, (3) day-ahead ISO price for electricity daily, and (4) such other information as may be useful to customers in controlling their energy usage and bills. We direct our staff to work with the utilities to maximize the potential for information sharing and customer assistance offered by the website.
6. PG&E and Edison shall prepare bill inserts notifying customers of the need for the rate increase, tiered rate structure, usage levels not impacted, customer exemptions, the need for conservation and information about the CARE, medical baseline and California 20/20 Rebate programs. The bill insert will be submitted to the Public Advisor for review and approval by May 18 and when approved posted on each utility's website.
7. We shall proceed expeditiously to develop and adopt a voluntary RTP that will be available to customers when their RTP metering systems are installed, and we direct Energy Division to work closely with PG&E and Edison on their billing system constraints and the manual billing procedures that can be done for customers until the system changes are complete.
8. Energy Division shall facilitate a workshop on May 21, 2001 on real time pricing issues and to develop a master data request.
9. The master data request shall be finalized and issued by June 8, 2001.
This order is effective today.
Dated ____________________, at San Francisco, California.
APPENDIX A
LIST OF APPEARANCES
************ APPEARANCES ************ |
Michael Aguirre |
Barbara R. Barkovich |
Robert Pernell |
Jennifer Chamberlin
|
Howard Choy |
Norman J. Furuta |
Douglas K. Kerner
|
James D. Squeri |
Kelly R. Tilton
|
Kathleen Kiernan-Harrington |
William H. Booth |
David J. Byers |
Scott T. Steffen |
Jose E. Guzman, Jr. |
Don Schoenbeck |
Phillip J. Muller |
Beth A. Fox
|
Chris Witteman |
Bernardo R. Garcia |
Lorenzo Kristov |
Robert Miyashiro |
Julie Halligan |
Donald J. Lafrenz |
Steven C Ross |
Rosalina White |
Robert E. Anderson |
J. A. Savage |
John A. Barthrop |
Gregory T. Blue |
Robert D. Schasel |
Karen Lindh |
Gary Herbert |
Bruce Bowen |
Ron Helgens |
Michael Bazeley |
Frank J. Cooley |
Bill C. Wells |
(END OF APPENDIX A)
APPENDIX B
PACIFIC GAS AND ELECTRIC
PROPOSED RATES
APPENDIX C
SOUTHERN CALIFORNIA EDISON
PROPOSED RATES
