Staff submitted testimony regarding ComEd, IP, and Ameren's Market Value Index (MVI) proposals. Staff stated that IP's proposal to replace the existing 0.061 cents per kWh capacity charge with a schedule of monthly capacity charges (applied before energy losses to the group's firm monthly demand) will modestly lower transition charges. Staff does not support Ameren's three proposed possible additional capacity charges to its MVI formula since they are significantly greater that the existing capacity charge in Ameren's tariff. Staff is opposed to the Ameren and ComEd proposals to modify the price shaping methodology by replacing zero and negative PJM hourly prices with the average of all the positive off-peak PJM prices in the month. Staff supports using the midpoint of the first prior positive hourly price and the next subsequent positive hourly price, on either side of the negative or zero price. Staff, in its testimony, agrees that ComEd's revisions to its MVI formula would have increased the market values (MVs) for the June 2002 to May 2003 applicable Period A by 9% on average, but states that there is no reason to expect similar increases in future years. Staff testimony states that customer specific CTCs enable customers to benefit from PPO and RES-supplied delivery services, but they also reduce the variability of potential savings for specific customers within a class. Staff supports: (1) ComEd's proposal to provide "would-be" MVECs and class CTCs during January and June and (2) ComEd and IP's proposals to compute multi-year CTCs. Staff has no position on: (1) the use of off-peak forwards as the starting point for constructing the off-peak component of the MVI and (2) the use of multiple years worth of PJM West hourly price data and class-specific load data in the price shaping process.

Staff submitted additional testimony that ComEd's plan to restrict the Period A Power Purchase Option (PPO) sign-up period from February 1 through March 31 would take away options from customers and would primarily benefit ComEd's unregulated generating affiliate. Staff stated that ComEd's proposal to restrict the Period B enrollment period would also benefit ComEd's generating affiliate, without any corresponding customer benefit. The full text of the Staff Testimony is available on the NEM Website.

The Retail Electric Supplier (RES) Coalition submitted initial testimony that ComEd, IP and Ameren's current and proposed market value index (MVI) methodologies fail to properly reflect the cost of serving retail load. The testimony states that the current MVI formula under-prices the market value of energy charge (MVEC) by $0.015/kWh in relation to the observed market value of energy in ComEd's retail service market. Despite the Coalition's proposed modifications to the MVI, there would still be an under-valuation of $0.008/kWh, which the Coalition proposes to adress through the use of an adder to the MVI calculation. The RES Coalition submitted a study that illustrated that MVI values are under-priced. The RES Coalition also presented testimony regarding the following: (1) the inadequate reflection of the cost of generation capacity in the Utilities' MVI formulas; (2) the need to use off-peak forwards and revise the methodology used to calculate the basis adjustment to reflect the illiquidity in the market; (3) the need to allow the MVI formula to be revised pending the Utilities' joining RTOs; (4) that certain ComEd proposals (i.e. average load shaping, the January snapshot and the PPO enrollment limits) restricted customer choice; (5) that additional refinements to ComEd's MVEC were needed; and (6) that IP's MVI formula should be revised to incorporate a floating adder to stimulate competition. Members of the RES Coalition are willing to return to a Neutral Fact Finder process in the event that the Utilities do not agree to the proposed revisions to their formulas. The full text of the RES Coalition Testimony can be found on the NEM Website.

NEM submitted proposals on payment allocation and uncollectibles and telephonic enrollment for inclusion in the gas roundtable report. NEM recommended that the payment allocation order with respect to receivables should be revised so that payments are applied first to the consumable portion of the bill, then to the non-consumable portion, and finally based on the age of the receivable. Alternatively, NEM suggested that the consolidated billing party should purchase the receivables of the non-billing party until the utility billing function is competitively outsourced or unbundled from utility rates based on the utilities' fully allocated embedded costs of providing billing and collection services. NEM also supported: (1) the application of a reasonable discount rate for the purchase of receivables; and (2) the use of an incentive rate for the utilities to perform this function. NEM supported the utilities' recovery of the reasonable implementation costs for compliance with either a change in payment allocation order or purchase of receivables. NEM also requested clarification of telephonic enrollment rules to permit receipt of consumer education materials to satisfy the written material requirement of the state's Telephone Solicitation Act. NEM's Proposals for Inclusion in Gas Roundtable Report is available on the NEM Website.

NJBPU issued its BGS Order approving the use of a simultaneous descending clock auction format for the procurement of Basic Generation Service (BGS). The Board approved an auction process for two-thirds of the electric distribution companies' (EDCs') BGS-FP load for 10 months and for one-third of such load for 34 months. Auction rules provide for financial guarantees from winning bidders to protect ratepayers from bidder default. Switching restrictions for BGS-FP and BGS-Commercial and Industrial Energy Pricing (CIEP) customers are not imposed for Years One, Two, or Three. A retail adder of 5 mils/kwh is appropriate for BGS-CIEP customers for the first 34 months of the post-Transition Period. The Board did not approve a retail adder on BGS-Fixed Price (FP) customers for Transition Period Year One. For Years Two and Three the NJBPU finds that a retail adder of 5 mils per kwh is appropriate and should be included in the rates of BGS-FP customers with an annual load equal to or greater that 750 Kw. The Board will reconsider the issue of utilizing a retail adder for customers with an annual load less than 750 Kw before Year Two. If the Board decides to use a retail adder for customers with an annual load less than 750 Kw in Years Two or Three, the adder will not be greater than 5 mils per kwh. NJBPU will at a later date, determine how the retail adder collected should be returned to customers, including possibly as an offset to deferred balances. The full text of the NJBPU Order is available on the NEM Website.

NEM submitted a reply brief in the New York unbundling case urging the Commission to reject the utilities attempts to revive previously rejected avoided cost arguments and implement unbundled rates based on the utilities fully allocated embedded costs. NEM argued that at a minimum the Commission should accept the cost study modifications recommended by ESCO Coalition Witness Hornby, or in the alternative, implement a cost allocation based solely on the percentage of total revenue generated by delivery services as deemed functionalized to non-contestable delivery services for purposes of the embedded cost of service (ECOS) study. All other costs should be properly allocated to contestable services until a fully allocated ECOS study is performed. Additionally, NEM opposed the suggestion to inject another phase of review into this proceeding. NEM urged the adoption and implementation of its embedded cost study methodology on an expeditious basis so that customers can begin to realize the significant benefits of fully allocated embedded cost-based unbundled rates. The full text of NEM's Reply Brief is available on the NEM Website.

Consistent with the recommendations of NEM, the Legislative Transition Taskforce that examines electric restructing issues in the state has recommended that a determination of the amount of the utilities' stranded costs be made. Despite the fact that a determination of whether or not the utilities in fact had any stranded costs had not previously been made, a wires charge was instituted to permit recovery of those costs. The Taskforce directed the Commission to convene a panel of lawmakers, power suppliers, consumers, and utilities to derive a method to calculate stranded costs by July 1, 2003, and for Commission Staff to complete stranded cost calculations by November 1, 2003.