The ALJ in the Market Value Index (MVI) proceeding has issued a proposed order approving the following adjustments to the market value index calculation: 1) a capacity backed adjustment to account for the requirement that Retail Electric Suppliers (RESs) procure generation capacity; 2) a placeholder in MVI tariffs for PJM/MISO changes that impact the capacity value in the utilities' MVI filings; 3) an upward adjustment to the MVI of $0.55 per MWh to account for the cost premium borne by RESs to acquire "odd lot" schedules; 4) a uniform adjustment of 0.026 cents per kwh for the allocation of sales and marketing expenses; 5) the substitution of realistic positive hourly price values for zero and negative values in PJM price data used to calculate price shape; and 6) an adjustment of $0.88 per MWh to account for Illinois retail market illiquidity risk. The Proposed Order also approved the floating adder approach for Illinois Power, setting the capacity demand credit at $13 per KW-year, setting the initial floating adder at 3.5 mills per kwh and requiring that the adder never be less than $0/MWh or greater than $10/MWh.

The Proposed Order rejected the proposed 8 mill residual adjustment meant to account for MVI model deficiencies reasoning that, "studies do describe a discrepancy in market value rates, but do not precisely translate into an 8 mill/kwh adder." The Proposed Order also rejected proposed MVI adjustments to account for risk associated with customers exiting their contracts early and to synchronize price shape data from the PJM market with load shape data from the ComEd market. The full text of the Proposed Order is available on the NEM Website.

DTE issued an Order on the effects of congestion costs and locational marginal pricing on default service rates. The Order is in response to the March 1, 2003, implementation of a Congestion Management System (CMS) by ISONE that will divide New England into eight zones and hundreds of nodes. Upon implementation of the CMS, the location of customers will effect the cost of providing generation service. The Department recognized that, "in order to avoid introducing distortions into the competitive market, default service prices in each load zone should include the same level of congestion costs that suppliers serving load in that zone would incur." The Department directed the utilities to procure default service supply on a zone-specific basis and to establish zone-differentiated default service prices for medium and large C&I customers. However, for residential and small C&I customers the utiilties are to establish a territory-wide default service rate that is averaged across load zones. The utilities are to procure default service supply for residential and small C&I customers on a zone-specific basis. The Department noted that it intended to reexamine this treatment of residential and small C&I customers after having gained experience with the CMS. The full text of the Order is available on the NEM Website.

NEM submitted comments on Staff's proposed licensing procedures for alternative gas suppliers (AGSs). NEM supported both: (1) the approach taken in the proposed natural gas rules to mirror the existing rules for the electric market; and (2) Staff's presumption of adequate financial, managerial, and technical capabilities of existing AGSs. NEM urged the Commission to clarify some of the vague or conflicting portions of the licensing proposal to provide clarity and certainty to the application process. NEM also submitted specific suggestions on certain licensing requirements including the following: (1) do not set the bond too high as excessive bonding requirements will increase the costs associated with supplying natural gas; (2) do not require an AGS to maintain a Michigan office; (3) account for human error in penalties for slamming/cramming; (4) do not make proprietary information available to potential competitors; and (5) assure that the paperwork burden in reporting requirements is not too costly or unreasonable. The full text of NEM's Comments is available on the NEM Website.

ConEd proposed to reduce the backout credits for Phase 6 of its electric choice program to $0.00025/kWh for residential customers and $0.00018/kWh for all other customers. NEM filed comments opposing the reduction in the credits. NEM argued that backout credits should, at a minimum, be retained at their current amounts pending a Commission Order in the unbundling proceeding. NEM also argued that ConEd's proposed lost revenue recovery mechanism should be rejected inasmuch as it would impose a single transition charge on all customers, rather than a two-part mechanism that recognizes that retail access customers should not be required to pay the utility for services the utility no longer provides. NEM opposed ConEd's proposal to reduce backout credits to purported levels of avoided costs associated with its electric supply function (which ConEd estimated at $0.00008/kWh for residential customers and $0.00001/kWh for all other retail choice customers) as contrary to multiple Commission Orders requiring utilities to implement embedded cost-based rates. The full text of NEM's Comments are available on the NEM Website.

The NYPSC issued an Order, adopting with modifications Staff's Proposal on customer payment allocation such that customer payments will be allocated first to settle any past due utility charges, second to past due ESCO charges, third to utility current charges, and fourth to ESCO current charges. However, the Order only adopts the changes on a voluntary basis pending adoption of rules to implement the new HEFPA law. Payment allocation can be modified only after the bililng party provides notice to the nonbilling party and customers on or before 15 calendar days prior to such payment allocation. Any excess payments received shall be held for payment on future bills, unless the customer directs otherwise. The full text of the NYPSC Order is available on the NEM Website.

The NYPSC instituted a proceeding to develop and implement a renewable portfolio standard for electric energy retailed in New York State. The matters examined in the proceeding will include new opportunities in renewables technologies as alternatives to fossil-fired generation. A procedural conference will be held on March 4, 2003, at 10:30 AM at the Commission's Albany offices. Interested persons may request active party status by sending an email to laurie_gibbs@dps.state.ny.us or calling Laurie Gibbs at 518-486-2802. The NYPSC requestes initial comments on the following issues: (1) the types of resources that should be considered as “renewable”; (2) whether retail suppliers should be required to sell energy from renewable resources; and (3) the impact on the ability of ESCOs to compete with utilities if they are required to procure renewable resources beyond what their customers request. NEM has intervened in this case, and member comments on the issues should be forwarded to headquarters ASAP. Initial comments are due on March 21, 2003. The NYPSC Order instituting the proceeding, the Notice of Procedural Conference and the Ruling Concerning Procedure and Schedule are available on the NEM Website.

The NYSPC directed the major natural gas utilities to file special delivery rates for non-residential customers who operate their own gas-powered distributed electricity generation (DG) units. The utilities are to tailor the new rates specifically to DG customer gas usage profiles. The rates are intended to be in place for three years. The NYSPC also adopted a process designed to establish such rates for residential customers by January 1, 2004, and voted to approve a DG pilot program proposed by the NFG. The pilot program will provide funding to customers to help defray the cost of installing DG equipment at their facilities served by NFG. The full text of the DG Orders will be posted on the NEM Website when made available electronically.

The electric utilities are required to offer customers a market-based standard service offer at the end of their market development periods. Since DP&L is nearing the end of its market development period, Staff has prepared proposed rules on "Processing Applications for Standard Service Offer and Competitive Bidding Process." By the terms of Staff's proposal, utilities would be required to file an application for standard service offer and competitive bidding process by July 1, 2004, for market development periods ending at the end of 2005. The utility applications are to include a market-based variable rate for the standard service offer unless the utility intends to use a competitive bidding process, in which case it can use a market-based fixed rate. The market-based variable rate is to be based on a, "transparent forward market, daily market, and/or hourly market" and the application must specify, in addition to the market-based cost of energy, all of the other costs for providing the service such as administrative costs and costs of hedging. The market-based fixed rate established through competitive bidding is to be a retail rate for retail electric service, and bid prices should reflect the costs and risks of providing such service. Initial comments on Staff's proposal are due March 7, 2003, and reply comments are due March 21, 2003. The full text of the Order is available on the NEM Website.