A scoping memo was issued in the proceeding to review the Power Charge Indifference Adjustment (PCIA). The PCIA is a mechanism intended to ensure that when electric customers leave utility service to shop that they remain responsible for costs previously incurred on their behalf by the utility. The most recent revisions to state law regarding the PCIA require that: "1) bundled service IOU customers do not experience any cost increases when other retail customers elect to receive service from other providers, or due to the implementation of a CCA program, and 2) customers who depart for another provider or due to formation of a CCA not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load."

The scoping memo establishes two tracks to the proceeding. Track 1 will examine legal issues regarding exemptions from the PCIA for customers participating in the California Alternative Rates for Energy program or who are served on medical baseline rates. Track 2 will examine the current PCIA methodology and possible alternatives.

The Scoping Memo adopted the following "overall goal" for the proceeding: "The Commission shall ensure that bundled retail customers of an electrical corporation shall not experience any cost increases as a result of either (1) retail customers of an electrical corporation electing to receive service from other providers or (2) the implementation of a community choice aggregator program. The Commission shall also ensure that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load."

The Scoping Memo adopted the following "guiding principles" for the proceeding:
"1. Any PCIA methodology adopted by the Commission to prevent cost increases for either bundled or departing load:
a. should be transparent and verifiable, including the most open and easily accessible treatment of input data, while maintaining confidentiality of information that should remain confidential;
b. should have reasonably predictable outcomes that promote certainty and stability for all customers within a reasonable planning horizon;
c. should be flexible enough to maintain its accuracy and stability if the number of departing customers changes significantly, and to maintain its accuracy and stability if customers return to bundled-customer service;
d. should not create unreasonable obstacles for customers of non-IOU energy providers;
e. should be consistent with California energy policy goals and mandates;
f. should allow alternative providers to be responsible for power procurement activities on behalf of their customers, except as expressly required by law;
g. should allow an alternative provider to elect to pay for its share of above-market costs in a manner that complements the CCA’s particular procurement needs and goals;
h. should only include legitimately unavoidable costs and account for the IOUs’ responsibility to prudently manage their generation portfolio and take all reasonable steps to minimize above-market costs;
i. should reflect the value of the benefits that departing customers impart to remaining bundled service customers;
j. should accurately reflect and seek to preserve all short, medium, and long-term value of the resources procured by the utilities; and
k. should respect the terms of existing power purchase agreements between power suppliers and IOUs (consistent with IEP and ACC proposals)."

The issues to be addressed in Track 2 are as follows:
"1. Does the current PCIA methodology prevent cost increases for bundled customers as a result of either (1) retail customers of an electrical corporation electing to receive service from other providers or (2) the implementation of a CCA program?
2. Does the current PCIA methodology prevent cost increases for CCA customers and direct access customers as a result of an allocation of costs that were not incurred on behalf of the departing load?
3. If the answer to question 1 or 2 is “no,” can the current PCIA methodology be revised to ensure that cost increases are prevented for bundled and departing load?
4. If not, what replacement methodology should the Commission adopt in order to meet the statutory requirement to ensure that bundled retail customers shall not experience any cost increases as a result of either (1) retail customers of an electrical corporation electing to receive service from other providers or (2) the implementation of a CCA program, and that departing load does not experience any cost increases as a result of an allocation of costs that were not incurred on behalf of the departing load.
5. How should the Commission ensure access to necessary data and require transparency of calculations in order to enable interested parties to (1) review the current PCIA methodology and understand its results and (2) contribute to and understand the development of any possible replacement methodology?
6. Should the Commission require and verify optimization of IOU portfolio management (e.g., contract extensions and contract renegotiation) in order to minimize above-market costs?
7. Should the Commission adopt alternatives to the PCIA framework, including but not limited to the following?
a. The Joint Utilities’ Portfolio Allocation Methodology;
b. Portfolio buy-out by CCA/ESP;
c. Assignment of IOUs' contracts to CCA/ESP; or
d. Options for customers to prepay the PCIA on a one-time basis, to be relieved of the PCIA burden going forward.
8. Should the Commission require forecasting of the PCIA or an alternative cost allocation method for a specific future period?
9. Should the Commission “cap” the PCIA or an alternative cost allocation method?
10. Should the Commission adopt a sunset of the obligation to pay the PCIA or an alternative cost allocation method?
11. Additional considerations and statutory changes relevant to review, revision, and consideration of alternatives to the PCIA."

The Scoping Memo also established a procedural schedule including workshops, testimony, and briefing dates, starting with a meet and confer on data issues to be scheduled within the next week. The full text of the Scoping Memo is available on the NEM Website.

Dominion filed a petition with the Commission seeking approval of “six voluntary 100 percent renewable energy tariffs” applicable to commercial and industrial customers with peak loads of over 1,000 kilowatts designated Rate Schedule CRG. Dominion's filing is of particular significance because if the Commission approves the CRG Rate Schedules as meeting the statutory definition of a 100% renewable energy tariff under Virginia Code § 56-577 A 5, then “the CRG Rate Schedules would impact the Company’s obligation to allow retail choice to certain customers seeking to purchase renewable energy.” Dominion's petition follows a recent petition filed by Direct Energy in this regard, wherein the Commission found that under Virginia law Direct is permitted to offer such products, so long as Dominion does not have an applicable green tariff to serve relevant customers.

Echoing concerns submitted by NEM and other parties in previously filed Motions to Dismiss in the proceeding, Staff Testimony on Dominion's proposed Rate Schedule CRG maintains that the Dominion filing lacks actual rates or a defined rate methodology preventing an assessment of whether such rates are just and reasonable. Accordingly, Staff does not recommend approval.

Staff further explains that, "the Company does not currently have any resources in place to serve as the CRG Portfolio and has not identified any specific third-party or Company-owned renewable generation facilities that Dominion will include in its CRG Portfolios in the future. Consequently, the Staff is unable to independently analyze and verify the Company's ability to supply renewable energy to CRG Rate Schedule customers on a continuous hourly basis, 24 hours a day, seven days a week, and 365 days a year as the Company proposes." The full text of Staff's Testimony is available on the NEM Website.

Relatedly, the Commission recently rejected a similar filing made by APCo for approval of a voluntary renewable energy rider, Rider REO. The Commission found that APCo had not demonstrated that the proposed Rider REO rate (equating to $0.08961 per kilowatt hour) was just and reasonable. Multiple parties had objected to the rate as being significantly higher than current market rates for renewable energy. The full text of the APCo Order is available on the NEM Website.