3. The Proposals Presented

The ruling in R.02-06-001 directed that the proposed tariffs should be designed to recover the total revenue, including transmission and distribution charges, currently allocated to customers 200 kW and larger and be class revenue neutral, compared to existing rates, based on current class load patterns.³ In addition, the utilities were to include customers currently receiving service under interruptible/non-firm rate schedules on the new tariffs and migrate those customers onto an alternative interruptible program called E-BIP (for Base Interruptible Program) that makes a capacity reservation payment to participating customers rather than offering lower rates like the non-firm rate schedules provide.

Each utility responded to these directives by proposing different structures for their default critical peak pricing tariff. The Office of Ratepayer Advocates (ORA) also made a specific proposal in testimony. Below we provide a brief comparison of the critical features of each utility and ORA's primary proposals.

	PG&E Preferred	SCE	SDG&E	ORA Preferred
Customer Applicability	200 kW - 500kW firm customers exclude DA/ag, optional for interruptible tariffs	>200kW firm customers, exclude direct access (DA)	>300kW with access to kWickview, includes DA	All customers over 200 kW, including non-firm.
Critical Peak Price4	$0.25/kWh adder to tariff rate	$1.00/kWh	11am-3pm: $0.13906 3pm-6pm: $0.28065	Not calculated but based on generation marginal capacity cost. Eliminate current generation summer peak demand charge for firm customers. For non-firm customers, split the current summer on-peak energy charge into CPP and non-CPP charges.
Non-Critical Peak Credits5	$0.42 - 0.066/kWh credit applied to partial and off-peak usage within same day as event call	14-18% credit, per event called, applied to on- peak energy and demand charges within billing cycle	$0.08914/kWh peak $0.06512/kWh semi/off-peak	Not calculated
Hedge Premium	$0.001/kWh for all summer kWh	1.93 - 15.12% increase applied to all summer on-peak charges (varies by rate schedule)	5% premium on commodity portion of current summer rates, $0.10423/kWh on-peak $0.07901/kWh semi/off-peak become new rates	Not calculated
Participation Credit	$0.001/kWh credit	None	None	None
Event Duration	3 hours/event, 3-6 pm	6 hours/event, noon-6 pm	7 hours/event, 11am - 6 pm
Triggering Event	Statewide standard that makes use of "best available day-ahead forecast information"	ISO Alert	ISO Alert; SDG&E system and temperature conditions; SDG&E grid emergencies	Prefer SDG&E's proposed trigger, based on system reserves.
Customer Notification	3pm day before	3pm day before	3 pm day before	Not stated
Event Call Limit	12 days (36 hours)	15 days (90 hours)	12 days (84 hours)	12 days
Range of Bill Impacts6	-3.88% to + 3.17%, assuming no change in load and 12 calls	-40.68% to + 16.11% assuming no change in load and 12 calls	-6.12% to +4.88% assuming no change in load and 12 calls	Not calculated
Opt-Out Deadline	None established	June 5, 2005	May 15, 2005	Not stated
Implementation Costs	$7,167,500	$2,009,700	$1,273,000	Not stated
Outreach	Encourage customer feedback through the regulatory process education and marketing	Education and outreach; "information and tools"	Contact/inform; Market load control tech. incentives	Not stated

As is evident from this table, the proposed rate designs are very different. This means that a customer who has facilities in different utility service territories would need to approach its facility management differently based on who the facility takes service from, complicating the customer's energy management planning process. In addition, each utility took a different approach to whether to exclude certain types of customers from the default tariff. For example, PG&E would exclude customers taking service under agricultural tariffs, but SCE would not. It addition, although the utilities complied with the December Ruling in filing the applications, none supports implementing the proposed rates in Summer 2005.