The ALJ in the ComEd auction proceeding issued a proposed order finding that the vertical tranche auction is an appropriate method of procuring electricity for ComEd customers. The proposed order approved the following program provisions: provision of a full requirements product; use of a multiple round, descending clock auction; establishing a 35% load cap; limiting tranche size to 50MW; and using an independent third party auction manager. The proposed order found that a simultaneous ComEd and Ameren auction should be conducted in September 2006.

Supply for residentials would be obtained under agreements with staggered one, three and five year terms comprising 15%, 60% and 25% of the auction respectively. Supply for customers from 400kw to 3MW of demand would be procured under one year agreements. Customers over 3MW of demand would would receive hourly priced service. Customers with demand less than 3MW would have a forty day enrollment window. Customers with demand greater than 3MW would have a thirty day enrollment window.

The proposed order found that PJM's bid mitigation rules limit the "possible and profitable" exercise of market power. It also found that there was no evidence that the PSEG-Exelon merger would have any deleterious impact on the auction proposal or on competitive implications for the state in general.

The full text of the ALJ's Proposed Decision is available on the NEM Website.

NStar filed a proposal to address alleged "'gaming' practices by retail competitive suppliers." NStar argues there is an increased level of load volatility on default service due to, "retail competitive suppliers moving large C&I customer load onto Default Service when the wholesale market price is higher than the Default Service price. Essentially, retail competitive suppliers avail themselves of a free option to park load on Default Service and then sell the power that would have been used otherwise to service that load at a higher price in the market." In order to address the alleged gaming, NStar proposes to prohibit "customers taking Default Service from returning to the same retail competitive supplier that previously served them for a period of six months from the effective date of change from competitive generation service to Default Service." NStar requests the change be made effective January 11, 2006, for incorporation in the January 31, 2006 default service RFP. DTE will hold a public hearing followed by a technical conference on December 19, 2005, beginning at 10AM to receive comments on the proposal. Written comments may also be filed by December 19, 2005. The full text of the NStar Filing and DTE Notice are available on the NEM Website.

BPU Staff will hold a conference call on gas utility business practices on December 15, 2005, at 10AM. The following issues will be discussed: 1) should there be a confirmation letter from the utilities to commercial customers who switch to a marketer, providing 14 days for the customer to inform the utility that there was an error in switching? If so, does the language of the letter need to be reviewed for clarity? Also, can the switching process proceed the day the enrollment is received from the marketer, while the 14 day period is under way?; 2) should the utilities be allowed to have switching restrictions in place for any customers, especially C & I customers on monthly pricing?; 3) should the utilities be allowed to charge customers for multiple switches to a marketer in an annual period?; and 4) should the utilities provide a price comparison on the bill for customers who have already shopped? The conference call number is 888-296-1938, and the passcode is 661759.

The utilities have filed draft hourly integrated market pricing tariffs for their large use customers as required by Commission Order. Comments on the draft tariffs are due January 21, 2006.

In anticipation of an expedited roll out of utility real time pricing, Staff will be conducting outreach with utilities, consumers and ESCOs. Staff will hold technical conferences on the filings and requests ESCO participation. Staff is also concerned that load and energy management services be available to the effected customers and is interested in exploring the role that ESCOs and/or associated energy management service providers will play. Staff requests that ESCOs contact Steve Starowicz at stephen_starowicz@dps.state.ny.us with contact information of those persons in their companies that can aid in this dialogue.

Parties have filed a settlement on Phase 1 of DEO's application to exit the merchant function. The settlement provides that: 1) DEO will conduct a combined descending clock auction for Standard Service Offer (SSO) and PIPP supply, and each tranche will include a proportional assignment of PIPP supply; 2) the $.0211/Mcf component of the Transportation Migration Rider-Part B will be eliminated, and customer education and other implementation costs will be funded, up to $14 million, from a) amounts collected from the 1% accounts receivable discount from April 1, 2005, through the elimination of the discount, and b) a program cost fee of $.0211/Mcf applied to all suppliers participating in the choice program and all suppliers awarded auction tranches that include PIPP customers; 3) DEO will purchase supplier accounts receivable at 100% of face value when the program cost fee is implemented; 4) DEO will maintain interstate pipeline capacity for the Tennessee/Dominion Transmission delivery points to Ashtabula and for the Texas Eastern delivery points to Woodsfield and Powhatan Point delivery points and allocate that capacity on a pro rata basis to SSO and PIPP suppliers; 5) assigned capacity is transferable among suppliers subject to DEO approval; 6) the auction should commence by February 2006 to permit suppliers to commence storage injections by April 2006 for the 2006-07 heating season; and 7) stakeholder meetings for Phase 2 should commence by May 15, 2006. The full text of the Settlement is available on the NEM Website.