(Notes by Barbara Barkovich)
The tariff subteam of the Unbundling/Ratesetting Working Group met at July 25, 1996, at 9:30 am.
Jeff Nahigian, representing TURN, discussed baseline rates. He said that whatever happens with unbundling, he wants to assure that baseline rates continue. He noted that this could be accomplished through an inverted tier in the distribution rate. SoCalGas does this with the gas rate after subtracting out the commodity rate. Current statute requiring baseline rates was noted as well. Jim Price said that the distribution rate is probably sufficient to accommodate the baseline tier differential. Mr. Nahigian agreed. PG&E said that this could be accomplished through the use of the distribution rate or distribution and CTC rates. Akbar Jazayeri of SCE said that if baseline is expected to persist for a long time, it should be in the distribution charge since CTC recovery will end.
Don Fellows of SCE said that baseline issues were being discussed in the low income working group, which will make a presentation to the unbundling/ratesetting group in August. Jim Price said that the presentation should be made to the full working group, not just the tariff subgroup. Mr. Fellows also noted that the Policy Decision says that baseline rates should continue.
John Flory mentioned recent recommendations of declining block rates with the tailblock set at marginal cost.
Mr. Nahigian then reviewed the status of the line extension rulemaking. Line extensions are based on base annual revenues expected from the customer over 20 years (for residential customers) or 1-2 years (for commercial customers). In 1998, unless the allowances are changed, developers will get credit for avoiding generation that the utility will no longer necessarily provide. This would lead to a higher subsidy for installing line extensions than is justified by avoiding distribution costs. He suggested that the base annual revenue needs to be redefined to achieve a distribution-only allowance. He also said that inclusion of CTC recovery had been previously discussed as part of the revenue expectation supporting line extensions but feared that this would turn CTC into a distribution credit when there is no stranded distribution. The most appropriate forum for addressing this issue is probably the line extension OIR and the November 15 utility filings on unbundling. It would be possible to develop figures in the November 15 filings to feed into the OIR in 1997. This could be recommended to the assigned commissioner.
A discussion of nonfirm rates followed. Jim Price summarized the previous meeting. He said that demand bid and nonspinning reserve applications for continuing nonfirm rates had been discussed, with transfer of operation of the program from the UDC to the ISO or PX. Andrew Bell of PG&E said that he had asked: what happens to the existing contracts? what is needed to integrate with the ISO? and what if a customer doesn't want to meet the operating conditions imposed by the ISO--can the customer or the Commission terminate the customer's participation in the program?
SCE has some preliminary ideas as to how to transfer the interruptible program of SCE to the ISO and will make a summary available. SCE's operating criteria are: 1) when the next to the last combustion turbine is activated and there is insufficient time to look for other resources, and 2) when spinning reserve falls below 5% and the price of power available to SCE exceeds 7 cents per kWh. SCE's operations staff were asked to analyze how the ISO could use the capacity available from nonfirm customers. The nonfirm/interruptible notice period is 30 minutes. Replacement capacity is available to the ISO on 10 minutes notice. The ISO could activate the program when replacement capacity falls below 1 1/2% and the ISO forecasts imminent need to use remaining replacement capacity, and when the real time spot market price of power is expected to exceed 7 cents. This would lead to continued use of the program on an emergency basis.
A discussion followed of demand bidding and comparable treatment of PX and DA nonfirm customers. Jeff Nahigian said that demand bidding works in Alberta but Mr. Chalfant (for California Industrial Users) said that there is no DA in Alberta so there is no comparability issue. Mr. Bell said that if an interruptible customer stays with the UDC, the UDC should tell the PX that there are x MW of interruptible in its forecast of demand. The question was raised: where does the economic benefit from interruptible power go? Concerns were raised and countered about double dipping since it was noted that current nonfirm customers receive an incentive in their rates and should not be paid again for being interrupted. Another issue raised was how to flow benefits to PG&E if its customers are interrupted. Nelson Cyr from Northrop and SCE will draft short issue papers on this issue. Barbara Barkovich will also draft something on comparability. PG&E noted that its tariff has language about using the nonfirm program to address local operating conditions but the utility has never acted on it. It was agreed that WEPEX would be asked to address ISO and PX issues soon regarding use of interruptible rates under the new market structure. A concern was raised that the WEPEX Phase 2 filing is due in February 1997 but the utilities' unbundling filings are due November 15, 1996.
The tariff subteam will meet again on August 13 in the afternoon.
(BB:)
The analysis subteam met at 1 pm on July 25, 1996.
Retail Transmission Rates:
SCE's Akbar Jazayeri discussed previous work undertaken by a WEPEX subteam on transmission pricing issues and jurisdictional issues regarding retail transmission rates for UDC and DA customers. There had been the impression that the FERC wanted to set retail transmission rates. If this occurs, i.e. if there is FERC jurisdiction and ratesetting, how would the UDC set retail rates? Would it use coincident or noncoincident demand as the appropriate allocator?
Order 888 appears to indicate some deference to state regulatory preferences. Since its appearance, SCE's rate department thinks that the FERC may leave design of retail rates to the states, resulting in CPUC jurisdiction and ratesetting. SCE provided a handout on the different options and indicated that it is currently assuming that all rates applicable to retail customers will be comparable and designed by the CPUC. It noted that if the FERC set DA rates and the CPUC set UDC rates there would be comparability issues. There would also be a problem with demand rates for customers without demand meters. The FERC also has no expertise in retail ratemaking.
CLECA's Cathy Yap said that if one assumes the use of the same allocator for DA and UDC rates, the major difference between embedded cost-based rates (which FERC uses) and EPMC rates (which the CPUC uses) would be what goes into the EPMC multiplier. What does EPMC mean in this context? There would be differences if the multiplier included both transmission and distribution marginal costs. Akbar Jazayeri said that marginal transmission would have to be redefined since SCE has "transmission" lines that are not under the ISO's jurisdiction. It would probably allocate distribution based on marginal distribution and customer costs and use this for the EPMC multiplier. There could be EPMC by function or full EPMC. EPMC by function is equivalent to embedded cost, to which DRA is opposed.
SCE will put 67 kV and 115 kV lines in distribution which would be a change from existing practice. Otherwise, it could separate transmission into high and low voltage (like PG&E's bulk and area transmission separation).
(AJ: after presentation on the jurisdiction over retail transmission rates)
For the benefit of some team members who have not previously been involved in the CPUC's proceedings on IOU's rates, current allocation of marginal transmission costs and retail rate design based on this allocation were discussed. The discussions then turned to the separation of transmission rates into Access and Congestion charges in the new market structure and the amount of seasonality in current transmission rate design which may be reflected in the Congestion charges. The consensus was that the degree of seasonality to be reflected in Access charge component can only be determined after FERC-CPUC jurisdictional boundry is decided upon and there is some actual data on the congestion-related transmission prices.
Next, we discussed the differences between CPUC and FERC methodologies for allocation of transmission costs and it was noted that a shift from the current CPUC methodology (for Edison) to a FERC 12CP allocation would result in shifting transmission costs to higher load factor customers. In addition, there are current metering barriers to charging retail customers based on their monthly coincident peak demands with the system. It was decided that the Resolution of such issues requires some coordination between the Ratesetting Working Group and the ISO/WEPEX team.
An important question raised related to the course of action the IOUs need to take in their November 15 filings if FERC has not issued a definite decision on deferring jurisdiction over the retail transmission rates to the state. It appears that to fulfill the requirement of filing unbundled rate components by November 15, the IOUs need to assume one of the regulatory structures discussed in the first part of the meeting and present their proposals on thst basis.
Technical Discussion of the Utilities' filings:
In this section of the meeting there were some discussions of SDG&E's filing related to its proposal to have two options of simple average monthly or RTP structures for charging Exchange prices and why the existing TOU energy rate structures may be phased out. In addition, questions were raised about some relatively high non-time related (facilities-related) charges on SDG&E's Large Power rate schedules.
Edison in its filing on July 15 has stated that it will be allocating the transmission revenue requirement to various rate groups based on marginal transmission cost revenues only. Some participants inquired whether this is the same as an embedded cost allocation. Edison responded that this would be the case if marginal and embedded cost allocators happened to be the same.
At this point the discussions turned to what the role of Analysis subgroup should be. Some participants stated that the role should be the development of costs of various distribution services so that if the Commission decides soon that distribution services should be unbundled the required numbers would be available. Edison disagreed and stated that some threshold policy questions such as whether some services retain monopoly status or which services the utility remain as default provider of need to be answered before number work can proceed in a productive manner. It was agreed that these issues will be raised and discussed in the Next day's meeting of the entire Working Group.