The Commission is required to periodically review the Standard Offer Service (SOS) program and make changes or adjustments as competitive developments warrant. The Commission initiated such a review in 2013. NEM filed comments in response at that time. Subsequently, in 2014, the Pepco-Exelon merger application was filed with the Commission and the SOS review proceeding was suspended. Now that the merger review has been completed, the Commission is resuming the SOS review matter.

The Commission is requesting that prior commenters refresh their responses to the following questions, as necessary, as well as invites comment from other interested parties that did not previously file:

"* Should Pepco continue to act as the SOS Administrator or should the Commission choose another option such as a retail model for providing SOS?
* Should the Administrative Charge be modified? The Administrative Charge is the mechanism by which the SOS Administrator recovers its incremental costs for procuring and providing SOS. These costs, include, but are not limited to, uncollectibles, the Commission’s Market Monitoring Consultant costs, wholesale bidding expenses, working capital expenses, wholesale supply transaction costs related to wholesale supplier administration and transmission service administration, wholesale payment and invoice processing, incremental billing process expenses, customer education costs, incremental system costs, costs related to the purchase/management of the CREF program, and legal and regulatory filing expenses related to SOS requirements.
* Should the adder be eliminated? Removing the adder would drastically reduce or potentially eliminate the administrative credit that results from overcharging the Administrative Charge. It would, moreover, eliminate additional oversight on the adder. However, removing the adder would also make the Administrative Charge vary more from year to year. Note that the original purpose of the adder is to reflect the retail electricity suppliers’ marketing costs in SOS rates in order to ensure that the suppliers are not placed at a competitive disadvantage.9 Such a purpose may not be achieved just because of using the adder.
* Should the SOS Administrator continue to be compensated for the costs of administrating SOS through a margin that is calculated on a volumetric, per kilowatt hour charge basis or instead be paid on an annual fixed-cost basis? Is a volumetric, per kilowatt hour charge consistent with the goal of energy efficiency? If the provider is paid on a fixed annual basis, how much should they receive and how should this charge be split amongst Pepco’s rate classes? Specifically, how much of a return/profit should the SOS Administrator receive above its costs? Should the margin be fixed at a 3-year historical average? What are the reasonable options?
* Should a peak load ceiling for large commercial SOS customers be established where large commercial users would be eligible only for hourly priced service? If a peak load ceiling is established, what should be the peak load ceiling? For example, this ceiling could be set at a peak load of 600 kilowatts.
* Currently, the SOS Administrator procures one (1) year SOS electricity contracts for the large commercial customer load and three (3) year SOS electricity contracts for the small commercial and residential customer load. Should the length of these contracts be changed? If so, why?
* Currently, the bidding for SOS is scheduled on an annual basis with two bid days, one in December and one in January. Should the bidding be scheduled differently and if so, what schedule should be used for the bidding? For example, there could be a larger spread between bid dates, as in Maryland where they procure most residential SOS in October and April.
* Currently, SOS is procured using a sealed-bid auction format. Should the bidding method be changed? If so, what bidding method should be used and why? For example, a reverse descending clock auction could be an alternative bidding method.
* Is there any other aspect of the SOS program that should be changed in light of competitive developments in the District of Columbia?"

The Commission also requested comment on the following new questions:

"* The SOS Administrator will be revising its bid form spreadsheet to comply with the Commission’s December 2015 Order requiring all low-income and non-low income residential customers (i.e., Electric Company Rate Schedules Residential (“R”) and Residential Aid Discount (“RAD”) as well as All Electric (“AE”) and RAD-AE) to be bid together. Given that the SOS Administrator is already making this one change, should it revise its bid sheets further by merging additional rate classes for bidding purposes? If so, what classes should be merged together? For example, should the R and AE rate class customer loads be combined for bidding purposes? Should some other bid categories be removed, such as the Large Commercial demand charge, which is frequently bid at $0/kW? Alternatively, similar to New Jersey’s Basic General Service auction, should the SOS Administrator ask for a single price offer for the entire SOS contract period and administratively allocate the charge to each class? If so, how?
* Some interested persons have recommended that the SOS rates should be a single fixed price and not feature any time-varying rates or different rates by usage quantity. Should such an adjustment be made and, if so, which rates should be simplified?
* The SOS Administrator currently solicits a full requirements product. This product is for a fixed percentage of the SOS load (either Residential and Small Commercial or Large Commercial). It includes many components (i.e., energy, capacity, renewable energy credits (“RECs”), ancillary services, load shaping, etc.). Should the District of Columbia keep this type of SOS product, or should it revise the product being procured? For example, in the default service program in Illinois, the utilities procure blocks of energy, not percentages of load, buy capacity in the PJM market, MISO market, or through a separate Request for Proposals (“RFP”), and have a separate RFP for RECs. The utilities are the ones in charge of combining these and other components together to provide full requirements service to ratepayers and the Illinois Commission has approved separate RFPs for RECs, energy, and capacity procurement. Is this or some other form a better option for the District of Columbia or should it stay with the current bundled product?
* Should bidders or their guarantors be required to be rated by at least one credit rating agency? If not, what credit protections should these bidders provide to the SOS Administrator to guarantee performance?
* What method should be used for performance assurance? Currently the SOS Administrator requires winning bidders to post 15 percent of the value of the contract. Should this be continued? Is the percent of value adequate? Should some form of mark-to-market calculation be used such as that used in Maryland?
* Currently, the Commission’s SOS rules provide that “[n]inety (90) days following the Commission’s approval of the selection of winning bidders for the final tranche, the Commission will disclose upon request (a) the total number of bidders, and (b) the names of the winning bidders.” In addition, the RFP for SOS states that “[a]ny information about the supply procurement results that does not provide supplier-specific information, or disclose any individual bid prices may be made public by the Commission and OPC, at their discretion after all tranches of bidding for that year of SOS are completed. Examples of such information that can be released include, but are not limited to, the total number of bids submitted, or the range in price between the lowest and the highest bids submitted.” Do these provisions provide the right balance between allowing bidders to protect their competitive advantages in bidding versus providing consumers and other members of the public with a transparent procurement process? Should more information be released to the public and if so, what should be released? Should the information be released earlier than 90 days and if so, when?
* Currently, bidders must turn in complete qualifications documents by the due date specified in the RFP. If there are errors in the documents, the bidders are allowed to cure those errors, but only up until the due date. If documents are submitted early there is sufficient time to cure deficiencies. If not, there is not. Should a cure period be added after the due date to allow for the remedy of any deficiencies and if so, what should be the cure period?
* Are there additional enhancements that the Commission should incorporate into its procedures to assure a level playing field when affiliates of the SOS Administrator are participating in the bidding and if so, what enhancements should be included?"

Finally, in view of the obligations imposed by the Community Renewables Energy Amendment Act of 2013 for the SOS Administrator to obtain some portion of electric supply from Community Renewable Energy Facilities, the Commission also requests comment on:

"*What data, if any, would a wholesale supplier need to know about the CREA Program to better prepare its SOS bid? (e.g. the number and capacity of CREFs, the number of CREF subscribers)
* Will the implementation of CREA cause wholesale suppliers to adjust their bid prices in the SOS procurement process? If so, how?
* Are there any changes that would need to be made to the SOS process once CREA is in effect? If so, identify the changes and when they would need to be made?
* What additional issues, if any, related to the implementation of CREA or the integration of CREA and the SOS procurement process need to be brought to the attention of the Commission?"

Comments are due July 25th, and reply comments are due August 8th. The full text of the Order is available on the NEM Website.

Last week the Governor signed Act 47 (HB57), which eliminates the migration rider that is charged to customers that shop with a competitive natural gas supplier. The migration rider has been one of the significant impediments to presenting a clear cost comparison between utility and supplier pricing.

Act 47 does permit a natural gas utility to impose a nonbypassable charge when its actual natural gas costs exceed the revenues collected by more than 10% in the prior twelve month period due to customers switching from sales to transportation service. The utility must seek Commission approval to impose the charge.

Act 47 also provides that natural gas utilities must be permitted recovery of, "prudent and reasonable costs incurred to implement customer choice from retail natural gas customers or other entities. . . pursuant to a reconcilable automatic adjustment."

Finally, Act 47 aligns the interest rate applied to gas cost over- and under-collections to remedy a potential incentive for gas utilities to undercollect purchased gas costs.

The Act becomes effective sixty days after enactment.

The full text of Act 47 is available on the NEM Website.