On December 18, 2003, the California Public Utilities Commission (CPUC) will vote on three plans involving renewables and energy choice. Two plans proposed by Commissioner Peevey and ALJ Walwyn would allow California electric utilities to sign up their customers for 5 years of power procurement contracts, while disregarding a new state law which requires minimum levels of renewable energy, and also blocks communities that are now seeking competitive electric service suppliers by committing their residents, businesses and public agencies into utility power contracts through 2009.

A 3rd plan by Commissioner Lynch would limit the December 18 utility procurement authorization to one year (2004), and calls for the CPUC to prepare an integrated approach to utility procurement that allows for Community Choice Aggregation and ensures compliance with the Renewables Portfolio Standard law after 2004. Both Community Choice (AB117) and the Renewables Portfolio Standard (SB 1078) laws were approved by the legislature and signed by the governor in September 2002 alongside the utility procurement law (AB57) that made it legal for the CPUC to commit ratepayers to long-term contracts again.

The Michigan Public Service Commission will hold a public hearing to consider the March 4, 2003, application of Consumers Energy Company for approval to recover net stranded costs of about $103,265,369 through a recovery charge of $0.025821/kWh for the period of January 1, 2004 through December 31, 2004. NEM will request intervenor status on Monday. Any member wishing to participate should contact Headquarters.

The first public hearing in this matter will be held, January 6, 2004 at 9AM at the Commission's offices. This hearing will be a prehearing conference to set future hearing dates and decide other procedural matters. The full text of Consumers' Application for Determination of 2002 Net Stranded Costs is available on the NEM Website.

The BPU approved and modified the utilities Joint Proposal for procuring BGS for Year Two of the post Transition Period (starting on June 1, 2004) and beyond. The utilities proposed two simultaneous, multi-round, descending clock auctions for the procurement of services to meet the full electricity requirements of retail customers that have not chosen a Third Party Supplier (TPS). One auction will procure service for larger C&I customers through an auction to provide hourly-priced service (BGS CIEP Auction). The second auction will procure service for all other utility customers through a fixed price auction (BGS-FP).

The Board also held that all CIEP customers should continue to pay the Default Supply Service Availability Charge (DSSAC) and that the DSSAC should remain at its current level of $0.00015/kwh. The Board stated that it expects to address the issue of expanding the CIEP class at its next agenda meeting. The Board also held that a retail margin of 5mils/kwh is appropriate for BGS-FP customers with a load of 750 Kw or greater and a retail margin of 5 mils/kwh continues to be appropriate for BGS-CIEP customers. The full text of the NJBPU Order is available on the NJBPU Website. A NEM Analysis of the Order is available.

The NYPSC issued an Order in the HEFPA proceeding. The NYPSC affirmed its mandatory pro-ration policy. The Order also clarified multiple issues on pro-ration, suspension, and customer information. The Commission declined to require utilities to offer to purchase ESCO receivables reasoning that ESCOs and distribution utilities are in the best position to take responsibility for negotiating the business arrangements required for the latter to purchase ESCOs’ accounts receivable. The Commission did recognize however that, "the purchase of accounts receivable, when coupled with other aspects of an aggressive retail access program, may help foster the development of residential retail markets."

HEFPA implementation and pro-ration will be instituted before changes to the UBP and the EDI protocols are finalized. A collaborative process will be formed to develop any required changes to the UBPs and EDI protocols. The full text of the Order is available on the NEM Website. An additional copy of a NEM Analysis is available upon request.

The NYPSC issued an Order on standby rates for Central Hudson (CH). The Order takes effect on July 1, 2004. It allocates costs between as-used demand charges and contract demand charges; the charges for demand exceeding contract levels; and procedures and criteria for revising contract demand levels. Customers will be offered the option of hourly load integrated energy service pricing. Under certain conditions, the utility and a customer may negotiate an individual agreement governing a customer's election to disconnect itself from the grid, or an individual agreement establishing standby rates for a customer that sells most of its energy output to third parties.

In contrast to the previous standby rate orders, this Order has provisions for net energy metering--i.e., the company's purchase of a customer's energy output--for customers with photovoltaic or wind-powered on-site generation installations, up to a company–wide total of 0.8 MW of OSG capacity.

Depending on their load patterns, some pre-existing standby customers are expected to pay higher electric bills under the new rates than at present. To mitigate any such adverse impact, pre-existing customers that prefer to avoid an abrupt transition will be offered a phase-in of standby rates over eight years starting July 1, 2004.

Customers whose that use an "eligible designated technology" and enter service after September 19, 2003, will have the option of a five-year phase-in (starting July 1, 2004) or a permanent exemption from the standby rates. "Eligible designated technology" includes "fuel cell; wind; solar thermal; photovoltaics; sustainably-managed biomass; tidal; geothermal; methane waste; or combined heat and power systems of less than 1 MW." The phase-ins for pre-existing or designated technology customers, and the exemption for the latter, are conditioned on entering service by May 31, 2006. The full text of the Order is available on the NEM Website.

In May 2002, the NYPSC instituted a proceeding to consider gas rates for distributed generation (DG) technologies. The NYPSC's April 24, 2003 Order directed the local gas distribution companies (LDCs) to file tariffs instituting firm delivery service for C&I DG customers by July 23, 2003. Staff reviewed the tariff filings and has identified areas where the utilities’ filings were not in compliance with the April 24 Order. Staff recommended and the NYPSC approved that the DG tariff amendments be allowed to become effective, provided that the LDCs comply with Staff's recommendations: (1) KeySpan should revise its tariff to eliminate minimum annual bill provisions; (2) NiMo should amend its tariff to: (a) revise its proposed DG rates so that they are based on existing rates for C&I customers rather than on an ECOS Study that has not, as yet, been adopted by the Commission; and (b) eliminate its proposed demand charge for customers with DG equipment rated at less than 5 Mw; and (3) Con Ed/O&R should amend its tariff to: (a) revise their rates to define load factor on the basis of the customers’ winter peak demand, and (b) eliminate the 50% minimum load factor in the minimum monthly bills and remove the sunset provision from their DG tariffs. LDCs must file the tariff amendments listed above to become effective on a temporary basis on not less than one day’s notice on January 1, 2004. The full text of the Order is available on the NEM Website.

New York regulators decided to create offices of Retail Market Development (ORMD) and Economic Development & Policy Coordination (OEDPC). The new agencies will replace the offices of Consumer Education & Advocacy (OCEA) and Competition Transition. The agencies will be involved in policy development, competitive metering and competition-related outreach along with coordinating the design and implementation of retail access programs. The agencies will be involved in overseeing EDI, performance based incentives for increasing customer choice, monitoring and updating retail access procedures, encouraging suppliers to enter the market and resolving complaints.

PUCO established a procedural schedule for Cincinnati Gas and Electric's (CG&E) application to modify its market-based standard service pricing for non-residential electric customers and establish an alternative competitive-bid service rate option. The Commission also requested that the company file a proposed rate stabilization plan. On January 10, 2003, CG&E filed an application detailing its proposal to offer a market-based generation rate to non-residential customers that do not switch to a competitive electric service provider by the end of the market development period. In its application, CG&E also proposed to establish a competitive bidding process that would provide non-residential customers with another rate option through an offer from a competitive retail electric service provider. The Commission requested that the company submit a proposed rate stabilization plan. On January 26, 2004 CG&E will a file a proposed rate stabilization plan, on February 24, 2004 a technical and procedural conference will be held. Members wishing to participate in this case should contact Headquarters before March 2, 2004, the deadline for filing motions to intervene and objections to CG&E's proposed rate stabilization plan.