The Commission issued an Order rejecting Pepco's proposed dynamic pricing plan. While noting the value of dynamic pricing, the Commission said it rejected the proposal because: "(1) we are concerned about the potential financial burden that would be placed on residential distribution ratepayers, particularly in the early years of the Dynamic Pricing Plan, as a result of Pepco’s proposed true-up mechanism; (2) we are concerned about the proposed funding mechanism contained in Pepco’s Plan in light of the recent FERC order approving PJM’s proposal to limited demand resources; (3) we have questions about the omission of small commercial customers from Pepco's proposal; and (4) Pepco’s Dynamic Pricing Plan and the parties’ comments raise a number of other economic and technical issues and questions about the implementation of dynamic pricing in the District that warrant further investigation by the Commission."

The Commission decided to convene an informal hearing to address the policy, economic, legal and technical issues and questions related to establishing dynamic pricing on April 23, 2014. Requests to participate in the hearing are due March 14, 2014. Included amongst these are NEM's recommendations that dynamic pricing is a competitive product that should be provided by the marketplace, and the Commission should avoid installing the utility in a new role as the monopoly demand response provider. The Commission issued the following issues for comment at the informal hearing:

1) Should dynamic pricing programs be “opt-in” or “opt-out” and should an opt-in program offer critical-peak pricing or hourly-pricing or both?
2) Should dynamic pricing programs be restricted to residential customers or should non-residential customers who do not have access to dynamic pricing programs offered by competitive suppliers also be included?
3) What type or types of dynamic pricing programs should be offered in the District and why?
4) In a restructured market, which of these companies should provide dynamic pricing programs and why: the distribution company only, the standard offer service provider only, third party suppliers only, or some combination of the listed companies?
5) How should dynamic pricing be determined? If a rebate program is used, how should the appropriate level of rebate be determined?
6) To what extent should distribution customers pay the cost of dynamic pricing programs?
7) Should a dynamic pricing program include additional hardware, such as an in home display device?
8) Should a dynamic pricing program include “shadow billing component”?

Acknowledging the concerns filed by NEM in the docket regarding supplier timely access to AMI data from Pepco, the Commission noted, "Based on the third party suppliers’ comments, it is clear that they are not satisfied by Pepco’s claim that it provides the access they seek nor are we. The Commission believes that the energy usage data produced by AMI should be used for the benefit of all customers in the District of Columbia, including those served by third party suppliers. The Commission seeks to ensure that customers have access to the innovative energy services products that third party suppliers say they want to provide. At the same time, the Commission wants to ensure that it is fully addressing privacy and data security concerns that arise when customer-related data is being shared." The Commission simultaneously issued an Order in a companion AMI Data Access Case regarding these concerns and requesting Pepco and suppliers update the record in that case. The questions raised for additional comment are as follows:

Questions for PEPCO

1) Please provide a sequential, step-by-step description of Pepco’s current business process for transferring interval meter data to authorized Third Party Suppliers (“TPS”), including the meter read, Validation, Editing, and Estimation (“VEE”), PJM settlement, and EDI data transfer to authorized TPS. Please explain how the business process used in the District differs from the business process used in PHI’s Maryland and Delaware territories.
2) Can the business process that Pepco currently uses to provide authorized TPS data via the website be used to deliver interval meter data for use in PJM settlement by TPS? If not,what further refinement to the business process needs to be made to allow for the delivery of interval meter data?
3) Do authorized TPS need EDI 867 IU before they can enable dynamic pricing?
4) What changes to Pepco’s current business process for transferring meter data are needed to enable EDI 867 IU data transfer to authorized TPS?
5) Pepco has indicated an intention to implement a new billing system called Solution One. Please explain how Solution One would modify the business process described in questions 1 and 2 above.
6) The National Institute for Standards and Technology (“NIST”) and the Smart Grip Interoperability Panel (“SGIP”) have reviewed the NAESB REQ.21 Energy Service Provider Interface (“ESPI”). Has Pepco evaluated the ESPI to determine whether it provides better security protection for customers’ data than existing processes based on EDI? If so,
a. What is Pepco’s opinion regarding ESPI?
b. What steps would be involved if a transition from EDI to ESPI for smart meter data transactions with TPS was directed?
c. How long would a transition take and at what cost?

Questions for Third-Party Suppliers

1) Please provide a sequential step-by step description of how your company currently obtains interval meter data for settlement with PJM from Pepco on behalf of your District of Columbia customers, including:
a. Does Pepco submit meter data to PJM on your behalf or do you submit meter data to PJM for your own settlement?
b. Does PJM currently make any modifications to the data provided to you by Pepco during the settlement process? If so, what modifications does PJM make?
c. What is the current timeframe in which your company currently receives smart meter interval data from Pepco to utilize it for PJM settlement? Is the timeframe adequate? If not, why not?
d. Does your company currently use the AMI data available to you via website to refine your near term load forecasts and related market transactions with PJM?
2) Please explain how your company’s current business process differs from the business process used in PHI’s Maryland and Delaware territories.
3) Please explain how your company’s current business process differs from the business process used in any other PJM-served jurisdictions where you operate.
4) How does your company currently make use of AMI current interval usage data?
5) How does your company currently make use of AMI historical interval usage data?
6) How would your company like to make use of AMI interval usage data and what specific Pepco actions or inactions prevent your company from doing so?
7) Does your company need EDI 867 IU before you can enable dynamic pricing?
8) Does your company currently provide residential dynamic pricing plans in PHI’s Maryland and Delaware territories and/or any other PJM-served jurisdictions where you operate? For each jurisdiction where your company provides residential dynamic pricing plans, please provide a detailed description of the program, the name of the utility company providing your company with interval meter data and the type of data that is being provided.
9) Does your company currently provide small commercial dynamic pricing plans in PHI’s Maryland and Delaware territories and/or any other PJM-served jurisdictions where you operate? For each jurisdiction where your company provides small commercial dynamic pricing plans, please provide a detailed description of the program, the name of the utility company providing your company with interval meter data and the type of data that is being provided.
10) Does your company have a written cybersecurity policy? If so, please provide a copy. If not, please describe how your company addresses cybersecurity concerns.
11) Does your company have a written privacy policy for the use of residential consumer data? If so, please provide a copy. If not, please describe how your company addresses the privacy of consumer data.
12) Has your company evaluated the NAESB REQ.21 Energy Service Provider Interface (“ESPI”) which was reviewed by NIST and the SGIP? If so,
a. What is your company’s opinion regarding ESPI?
b. What steps would be involved if a transition from EDI to ESPI for smart meter data transactions with TPS was directed?
c. How long would a transition take and at what cost?

The full texts of the Order Rejecting Pepco's Dynamic Pricing Plan and Order on Supplier Access to Smart Meter Data are available on the NEM Website.

In furtherance of the one of the issues identified in the electric Retail Market Investigation, the Commission has issued a Tentative Order on the creation of a supplier-oriented utility consolidated electric bill. The Commission requests comment on the following proposed changes to the UCB:
1) inclusion of the electric generation supplier (EGS) logo on the bill, in black and white or color;
2) expansion of bill messaging space allotted to EGSs from the current 2 lines to 4 lines; and
3) the inclusion of a Shopping Information Box.

The Commission was not recommending the inclusion of an EGS bill insert but requested additional comment on the costs, benefits and complexities of requiring an EGS insert.

"The Commission believes that these three proposals will aid the customer in not only developing a stronger recognition of, and relationship with, his or her EGS, but will also increase customer awareness when participating in the competitive retail electric market."

The Commission additional requested comment on the implementation costs associated with these changes. It proposed It proposed the new changes be implemented by June 1, 2015, to coincide with new EDC Default Service Plans. Comments are due March 10, and reply comments are due March 24. The full text of the Order is available on the NEM Website.