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2012 RDW Workshop

2012 RDW Workshop. A12.02.020. Analysis and Rates July 12, 2012, CPUC. Agenda . 10:00 Welcome/Introductions Procedural Background and Workshop Goals 10:10 Reduction of baseline quantities (BQ) to 50% PG&E Presentation Discussion and Q&A

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2012 RDW Workshop

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  1. 2012 RDW Workshop A12.02.020 Analysis and Rates July 12, 2012, CPUC

  2. Agenda • 10:00 Welcome/Introductions • Procedural Background and Workshop Goals • 10:10 Reduction of baseline quantities (BQ) to 50% • PG&E Presentation • Discussion and Q&A • 11:30 Analysis of the 4-month summer baseline for the Central Valley • PG&E Presentation – including alternative scenarios requested by TURN • Discussion and Q&A • 12:30 Lunch • 1:30 Continue Analysis of the 4-month summer baseline for the Central Valley • 2:00 Minimum Bill Calculation Methodology • PG&E Presentation • Discussion and Q&A • 2:30 Non-tiered Opt-in Residential Time-of-Use (TOU) Rates • PG&E Presentation of Responses to Energy Division Data Request • Discussion and Q&A • 3:30 Changes to Dynamic Rates: SmartRate and other Peak Day Pricing Rates • PG&E Presentation • Discussion and Q&A • 4:00 Adjourn

  3. Reduction of baseline quantities (BQ) to 50% Business Policy

  4. 2001 vs. 2012 Residential Rates in Real Terms

  5. Historic and Projected Residential Rates Business

  6. CPUC Has Just Limited Ability to Fix Upper-Tier Rate Problem • Legislative constraints largely tie the CPUC’s hands • CARE Tier 1 and 2 rates are essentially frozen (22% of sales) • Non-CARE Tier 1 and 2 rates can go up only a small amount once per year (48% of sales) • Adding a CARE Tier 4 rate is prohibited • CPUC has interpreted SB 695 to prohibit customer charges (except in a way that does nothing to reduce upper-tier rates) • Absent legislative reform, CPUC has just three “rate levers” remaining (and even these have limited effectiveness) • Collapse Tiers 3 and 4 into a single Tier 3 • Increase CARE Tier 3 rate • Reduce baseline quantities (BQs) to low end of statutory range

  7. Reduction of baseline quantities (BQ) to 50% • Utilize BQ reduction to at least partially reduce enormous gap between lower (Tiers 1 and 2) and upper (Tiers 3 and 4) rates • Proposal: Reduce BQs from 55% to 50% of historical usage (and reduce them from 65% to 60% for all-electric households in winter) • Decreasing BQs from 55 percent to 50 percent would reduce T3/T4 rates by 2.7 cents/kWh Business

  8. Comparison of Historic, Current and Proposed BQs (a)Each climate zone’s BQs were weighted based on its share of 2011 basic service households.

  9. Comparison of Current and Proposed Usage by Tier

  10. Comparison of Current and Proposed Rates

  11. Summary of bill impacts (a) Based on 2009 calendar year data. Excludes TOU Schedules E6, E7 and E9. (b) Territories P and S are combined in the summer. (c) Territory Q is a geographical subset of T. It uses T values in the summer but X values in the winter.

  12. Analysis of 4-month summer season • Suggested by TURN in 2011 GRC Phase 2 proceeding as possible means for mitigating summer high-bill problems faced by Central Valley customers • Idea is to re-define current six-month summer definition (May-October) to a four-month definition (June-September), with winter expanding from six to eight months • Since baseline quantities are based upon historical usage, this would likely increase summer baseline quantities and thus might mitigate summer bills • However, rate design is a zero sum game, so rates might be higher, as well as bills in other months • PG&E agreed idea was worth exploring, and D.11-05-047 formalized it by directing PG&E to perform a study and report on it in its 2012 RDW • PG&E performed the study and in late October issued a summary report to parties in advance of a November workshop • On November 15, 2011, PG&E held a workshop at its offices where it described the study and results • Thereafter PG&E made minor modifications to the study and filed it as Attachment A to Chapter 2 of its testimony in this proceeding

  13. Monthly Usage in Selected Climate Zones

  14. Monthly Bills - Average Kern Customer

  15. How Would BQs Change?

  16. How would Sales by Tier Change?

  17. How Would Rates Change?

  18. How Would Average Rates Change?

  19. Bill Impacts

  20. Monthly Bills – 90th Percentile Kern Customer

  21. Conclusions • The study concluded that moving from the current six-month summer season to a four-month summer season was unlikely to be very helpful in mitigating bills in the Central Valley (or anywhere else) • Tier 3 and 4 non-CARE rates actually increased (albeit by a small amount) • Average monthly bills did not change very much over the year even in Kern County • Even for the 90th percentile usage customer in Kern County, the average bill over the course of the year actually increased a small amount • This is because large bill increases (ranging from $55 to $66) in the two “shoulder” months of May and October BQs more than offset the bill decreases in the other months (which were about $19 in the four summer months and about $3 in the other months • PG&E does not believe it would be good policy to drastically increase May and October bills only to more modestly decrease them in June through September • Related issues that would need to be investigated before moving to a four-month summer season: • How would it affect TOU rates? • Would it cause customer confusion and require education? • Would it apply to non-residential customers too and, if so, how would rates and bill impacts change for customers on non-residential rate schedules? • How difficult/costly would it be to make billing system modifications and perform customer education?

  22. Alternative scenarios requested by TURN • SCENARIO #3: • 6 Month Summer – 60% BQs for R, S & W; 50% BQs for All Other Baseline Territories • 6 Month Winter – 50% BQs all Territories (60% for All-Electric) • SCENARIO #8: • 4 Month Summer – 60% BQs for R, S & W; 50% BQs for All Other Baseline Territories • 8 Month Winter – 50% BQs all Territories (60% for All-Electric) • SCENARIO #1: • 6 Month Summer 60% BQs for R, S & W; 55% BQs for All Other Baseline Territories • 6 Month Winter – 55% BQs all Territories (65% for All-Electric) • SCENARIO #4: • 4 Month Summer – 60% BQs for R, S & W; 55% BQs for All Other Baseline Territories • 8 Month Winter – 55% BQs all Territories (65% for All-Electric)

  23. Rate comparisons Based on July 1, 2012 rates

  24. Non-Care bill comparisons: Customers and monthly bill changes

  25. Seasonal non-Care bill comparison- Scenario 3

  26. Minimum Bill Calculation Methodology • Minimum bill is designed to recover a small portion of the fixed distribution costs of providing electric service • These costs include metering reading, billing, and other costs that are independent of the customer’s monthly energy consumption • These costs are incurred even in a month when the customer consumes nothing at all • All of PG&E’s residential rates have a minimum charge except Schedules E-8 and EL-8 (which have customer charges) • PG&E’s current minimum bill methodology is a confusing hybrid of fixed daily charges and per-kWh charges • PG&E is proposing changes to make this easier to understand • Patterned after SCE’s minimum bill methodology • Simpler, easier to explain to customers • Competitively neutral with respect to DA/CCA • Proposed minimum bill would apply to delivery service rate components only (T, D, NBCs) • Bundled customers would also pay generation rate (but DA/CCA customers would not) • Proposed $3.50 minimum bill on delivery rate components designed to collect same revenue as current $4.50 minimum bill on total rate

  27. Residential Minimum Bill Proposal - Example • Assumes customer uses 10 kWh per month • At this low level, the minimum bill would apply • A customer taking bundled service would pay: • Minimum bill (on delivery portion of bill) = $3.50 • Generation ($0.071 per kWh times 10 kWh) = $0.71 • Total bill = $4.21 • A customer taking DA or CCA service would pay: • Minimum bill (on delivery portion of bill) = $3.50 • Whatever its ESP or CCA charges for generation • Customer is better (worse) off vs. PG&E bundled service if ESP/CCA charges less than (more than) $0.071 per kWh • Proposal is competitively neutral since customers can benefit from taking service from an ESP or CCA service only if the ESP or CCA offers a lower price for generation than PG&E’s $0.071 per kWh generation rate

  28. Non-tiered Opt-in Residential Time-of-Use (TOU) Rates

  29. Schedules E-6 and E-7 history BACKGROUND: Schedule E-7 has been in place since 1986. The last cost based allocation to Schedule E-7 was in the 90s. Generally, allocations to E-7 were based on participants on that schedule. Since participants were generally larger residential customers, average rates were lower than for E-1 customers Schedule E-7 design remained substantially the same until restructuring. In 1998, the schedule included a meter charge of $3.90; summer rates (31.5/8.5) and winter rates (11.6/8.9) and a baseline credit of 1.7 cents per kWh Beginning in 1998, all residential schedules began receiving a 10% discount. In 1999, up-front TOU meter installation charges were added ($277) In January 2001, a one cent per kWh surcharge was added. In June 2001, the three cent energy surcharge was added creating tiers 3, 4 and 5. Rates were ‘frozen’ until 2004 Since 2001, tier differentials for all regular residential rate schedules have been set at the same levels. Thus, E-7 Tier 1 and Tier 2 rates are set, and then uniform surcharges are added to all standard non-CARE residential upper tier rates. In 2004, the residential rates were converted to four tiers In 2006, up front TOU meter installation charges were removed. Also, residential rates were returned to 5 tiers

  30. Schedules E-6 and E-7 history (continued) In the 2003 GRC Schedule E-6 was proposed as a revenue neutral rate to replace E-7. E-6 was implemented in 2006 Schedule E-6 is time differentiated and includes the tier differentials common to other residential schedules Schedule E-6 is not as steeply differentiated as E-7 and also includes partial peak period to improve its cost basis Schedule E-7 was popular among solar customer-generators. It was closed to new non-solar customers in 2006, but remained open to new solar customers on a limited basis until 2009. Schedule E-7 is currently closed to new customers In the 2007 GRC, settling parties agreed that the revised Schedules E-6 and EL-6 fulfill the requirements of Senate Bill (SB) 1, Public Utilities Code Section 2851 (a)(4), requiring “a time-variant tariff that creates the maximum incentive for ratepayers to install solar systems…” Current TOU meter charges expire as customers are billed using SmartMeters Beginning in 2010, Tier 1 and Tier 2 rates were adjusted based on the SB 695 index. Rates were returned to a four tier structure in 2010 In the 2011 GRC, residential rate design issues were litigated, not settled. As a result several parties offered testimony on Schedule E-6 design. PG&E’s proposed rates with four tiers were adopted

  31. Energy Division Data Request #2 While PG&E may seek approval of a pilot for a non-tiered TOU rate in the future, it continues to be very concerned about revenue shortfalls resulting from larger customers migrating from a steeply tiered rate to an non-tiered rate Energy Division Request: Demonstrate that Schedule E-7 is not revenue neutral Design a non-tiered TOU rate Demonstrate the revenue shortfall from a non-tiered TOU rate

  32. Demonstrate that Schedule E-7 is not revenue neutral In order to design revenue neutral rates, rates are set such that the TOU rate collects the same revenue as would be collected if all customers were on Schedule E-1 PG&E developed the tier and time of use billing determinants for all customers assuming they took service on E-7 July 1, 2012 rates were multiplied by those determinants to derive the revenue from E-1 and E-7 PG&E prepared the same analysis for tiered Schedule E-6 Billing determinants (as if all customers are served on each rate schedule), are derived from load research data

  33. Demonstrate that Schedule E-7 is not revenue neutral Preliminary Results: Schedule E-6 was about 1 percent lower than Schedule E-1, but Schedule E-7 revenue was about 11 percent lower than revenue from Schedule E-1

  34. Design a non-tiered TOU rate similar to E-6 Preliminary Results: PG&E’s design is based on retaining the current E-6 TOU periods and TOU rate differentials The non-tiered rate is revenue neutral

  35. Preliminary Results: The new rate compared to E-1 collects about 1% less in Revenues Design a non-tiered TOU rate similar to E-6

  36. Demonstrate Revenue Shortfall from a Non-Tiered TOU rate Preliminary Results: Bill Comparison Results By Region (All Customers) Using Load Research Data, Separate Bill Increases and Reductions

  37. Changes to Dynamic Rates: SmartRate and other Peak Day Pricing Rates Revise SmartRate and PDP Designs in accordance with Resource Adequacy Requirements D.11-06-022 required PG&E to file operating hours of 1 – 6 pm for its CPP rates in the 2012 RDW, and granted a waiver for the 2012 operating year in anticipation of implementation in 2013 D.12-06-025 continued the treatment established by D.11-06-022 if a decision in the 2012 RDW is not rendered in time for the 2013 operating year. Revise terms and conditions for consistency between SmartRate and PDP

  38. Revise SR from 15 events and a 2 – 7 pm operating period 15 times per year (75 hours) to a 1 – 6 pm operating period 12 times per year (60 hours) Choices: Either increase the SR event charge or reduce the revenue neutral credit to retain the current level of annual incentive Proposed: Reduce the credit to maintain current daily level of event charge ($3 = 5hr x $0.60) For PDP, increase the operating period from 2 – 6 pm (48 hours) to 1 – 6 pm (60 hours) Choices: Either reduce the PDP event charge or increase the PDP revenue neutral credit. Proposed: Reduce the event charge to maintain the daily level of event charge - retaining the existing event charge over a longer number of hours would have implied too great a capacity value ($4.80 = 5hr x $0.96) Changes to Dynamic Rates: SmartRate and other Peak Day Pricing Rates (continued)

  39. Changes to Dynamic Rates: SmartRate and other Peak Day Pricing Rates (continued)

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