Senator Dunn's Bill (SB 888) to repeal California's electric industry restructuring law was heavily amended in recent days. The bill now allows customers to keep and even renew power supply contracts signed with energy merchants other than their local utility. Under the amended bill, DA customers are prohibited from switching energy service providers (ESPs) or going back and forth between DA and bundled utility service. However, at a hearing on July 2, 2003, Dunn indicated that he would further amend SB 888 to allow switching between ESPs. Without a specific date and no longer as a requirement, the bill language now says that the California PUC can "develop and submit to the legislature...a detailed proposal for implementation of a 'core/non-core' model for retail electric service..." Direct access can be -- but is not a required -- part of this submission. Additionally, SB 888 as amended now requires non-core customers to pay for energy cost obligations "on a schedule comparable" to the recovery of such costs from core customers, thus eliminating the existing cap on the DA Cost Responsibility Surcharge (CRS).

The Assembly's Committee on Utilities and Commerce, which held hearings on July 2, 2003, will vote on SB 888 on Monday, July 7, 2003. If the bill passes the Assembly committee it will move to the Assembly's Committee on Appropriations after which it could be voted on by the entire Assembly. SB 888 would then have to return to the state Senate for concurrence with Assembly amendments. The full text of SB 888 as Amended is available on the NEM Website.

The General Assembly passed a bill that would extend a cap on rates, but raise prices ten percent. The Connecticut law that allowed business and residential consumers to choose a competitive electric supplier froze standard offer service prices at 10 percent below the rates set in December 1996. If the bill is signed into law it will set the standard offer at the 1996 price and hold it there until 2007.

The Commission will hold a public hearing to increase public awareness of significant natural gas price increases that are expected next winter, to solicit comments and to discuss potential solutions. The meeting will be held 9AM on July 22, 2003, at MPSC Lansing offices. Comments are due July 29, 2003.

Pursuant to NEM's request, Staff has scheduled a meeting on July 23, 2003, from 10AM to 12:30PM to discuss electric enrollment, billing, metering, EDI and other issues. Staff's intent is to use the meeting as a forum to explain the rationale when the original electric rules were developed, let parties' voice their concerns, and Staff will subsequently let the industry know what, if anything, will follow. The meeting will be held at PSE&G in Newark. Contact Fran Sundheim at PSE&G at: frances.sundheim@pseg.com if you plan to attend. Staff has also provided a call-in number for the meeting as follows: dial-in 877-287-0283 and code 404552. An agenda for the meeting is forthcoming.

The EDCs submitted a proposal for the competitive bidding of BGS for the Post Transition Year 2 BGS competitive bid process. The proposal is as follows: (1) BGS procurement offers will be conducted through a statewide Auction Process that simultaneously seeks offers for all BGS Load in the State; (2) The Auction will seek offers for the supply of full requirements tranches of each EDC’s BGS-FP Load. Tranches will be identical and uniform within each EDC and will represent a fixed percentage of the EDC’s total BGS-FP Load. As one-third of the EDC load has already been procured for 24 months beyond the start of Post Transition Year 2, two-thirds of EDC load will be procured for terms starting June 1, 2004, the start of Post Transition Year 2. The majority of the EDCs propose that one-half of that requirement, or one-third of each EDC’s total BGS-FP Load, will be procured for a one year term. The remaining one-half of the requirement will be procured for a period of three years. The end result of this Auction will be that beginning June 1, 2005, and each June 1 thereafter, the EDCs will have under contract one-third of their total BGS Load with a remaining contract term of one year, one-third of their total BGS Load with a remaining contract term of two years, and will need to procure one-third of their total BGS Load for a term of three years; (3) The EDCs will use a Clock Auction to procure BGS-FP supply. In a round, bidders will state how many tranches they wish to serve of a product (an EDC’s BGS-FP Load for a given term) at the price in that round. The Auction ends when the amount supplied is equal to the amount the EDCs wish to procure. There will be a single clearing price for the BGS-FP Load of each EDC for a given term that will apply to all tranches for that EDC for that term. Payments to bidders for July through September will be shaped to reflect higher summer costs. Payments to bidders for the remainder of the bid period will be shaped to reflect lower winter costs; (4) A Clock Auction will also be used to procure supply for BGS-CIEP Load. Beginning August 1, 2003, the larger customers will begin to receive BGS-CIEP service; (5) For BGS-CIEP tranches, rate schedules will specify a 0.03¢/kWh payment for the Default Supply Service Availability Charge (DSSAC), a per kW or per kWh rate for the transmission obligation, a per kWh rate for ancillary services, and a provision to pass through the hourly PJM real-time energy price. The capacity charge will be determined through the Auction clearing price. The term of the BGS-CIEP procurement will be for one year beginning June 1, 2004. The entire position will be open as of that date; (6) BGS Suppliers will be physically and/or financially responsible for the day-to-day provision of electricity to BGS customers. This full-requirements service includes the provision of capacity, energy, transmission, ancillary services and any other services as may be required by PJM. All BGS customers are free to come and go from the BGS service upon notice requirements that generally require prior notice of 20 days; (7) The terms and conditions under which the BGS Supplier will operate will be set forth in the BGS Supplier Master Agreements. Under the Agreement, the EDCs will provide billing, bill calculation and metering for all BGS customers in their service territory and Suppliers will be responsible for meeting Renewable Portfolio Standards, both those currently in force and any new ones that may be implemented during the supply period. The full text of the Joint Proposal and Proposed Auction Rules and Master Agreements are available on the NEM Website.

Staff has requested comments on the initial capital costs and annual costs of complying with HEFPA for small businesses (defined by state regulation as, "any business which is resident in this state, independently owned and operated, and employs less than 100 individuals"). Staff also requests comments on the economic and technical feasability of HEFPA compliance for small businesses. Comments on the job impacts of the legislation should also be submitted. Comments are due July 14, 2003.

The NYPSC granted RG&E's April 1, 2003, petition to extend its full requirements option through October 31, 2003, and directed RG&E to file tariffs implementing a month by month calculation of the base energy and capacity backout credits. The Commission also directed RG&E to hold conferences with interested parties to develop a revised Market-Based Backout Credit (MBBC) calculation methodology to ensure transition to a fully functioning MBBC by October 31, 2003. Additionally, at these conferences, RG&E will discuss the development of its class-specific load shapes, which the Commission stated should be completed by November 1, 2003. The full text of the Order is available on the NEM Website.

As urged by NEM, the Commission seeks comments and proposals for revisions to the rules on GCR that would make the GCR more reflective of recent events in the natural gas industry relating to price volatility and the growth of customer choice. This proceeding will be one of the subjects of NEM's retail issues conference call on July 15, 2003, at 11AM EST. The call-in number is 703-788-0600, and the passcode is 209353. The specific issues for which the Commission seeks comment includes: (1) Should the rules permit or require the use of weather normalized, historical sales volumes for calculation of the Expected Gas Cost (EGC), Actual Adjustment (AA), Balance Adjustment (BA) and/or Refund and Reconciliation Adjustment (RA)? (2) Currently, GCR rates are required to be filed 30 days in advance of their effective date. Should the EGC rate be allowed to be updated at or near the end of that 30-day period in order to reflect the most current market prices? (3) Should the rules allow flexibility to adjust the EGC rate and/or the adjustments other than quarterly? If so, what time periods should be permitted? (4) Should the rules by modified to require the BA to be recovered through the AA and thus recovered over a 12-month rather than 3-month period? (5) Currently, customers that switch to a marketer are responsible for the AA, BA and RA adjustments for a period of 12 months only. Choice customers that subsequently return voluntarily to GCR service resume paying those adjustments immediately upon their return. This leaves open the potential for large credits in these adjustments to artificially lower the GCR rate and induce choice customers to return to the GCR. To prevent such temporary price anomalies from distorting the market in this way, should there be a 12-month moratorium until the adjustments would apply to customers that have returned to the GCR after being with a choice supplier for at least 12 months? Comments are due August 1, 2003, and Reply Comments should be filed by August 15, 2003. The full text of the Request for Comments is available on the NEM Website.

FirstEnergy Services, on behalf of Ohio Edison Company, The Cleveland Electric Illuminating Company, and the Toledo Edison Company seeks to reduce the shopping credit incentive for each rate class commencing in 2004. Under FirstEnergy's proposal the shopping credit levels currently in place would remain intact throughout the remainder of 2003. Starting with bills reflecting 2004 usage, shopping credit levels would be reduced. The reduced shopping credits would remain in place until the end of 2005 or the end of the market development period, whichever occurs first. The full text of FirstEnergy's Application will be on the NEM Website as soon as it is available in electronic form.

As required by the legislature, Staff has submitted a report on stranded costs summarizing the activities of a working group formed to study the issue. Staff reports that no consensus was reached on a calculation methodology. Staff offered its own recommended definitions of "stranded costs" and "just and reasonable net stranded costs." Staff defines "stranded costs" as, "a utility's net loss in economic value arising from electric generation-related costs that become unrecoverable due to restructuring and retail competition." Staff defines "just and reasonable net stranded costs" as, "a utility's net loss in economic value arising from prudently incurred, verifiable and non-mitigable electric generation-related costs that become unrecoverable due to restructuring and retail competition." Staff also said that to monitor the over- or underrecovery of just and reasonable net stranded costs you must calculate total just and reasonable net stranded costs and recoveries of stranded costs from capped rates and wires charges. Staff requested the legislaure to provide guidance as to whether the Commission should formulate a calculation methodology or whether the legislature would provide one. The full text of Staff's Report can be viewed at http://www.state.va.us/scc/division/eaf/comments_strandedcosts.htm.

Dominion Virginia Power filed an application to join PJM. A state law requires Virginia utilities to file an application to join a RTO with the State Corporation Commission by July 1, 2003, but prohibits utilities from joining an RTO until July 1, 2004. Dominion said a consulting firm found that the company could save its customers $477 million over ten years by joining PJM. Dominion will operate in a separate transmission-control zone called PJM South. AEP already filed an application with the SCC and federal regulators to join PJM.