In preparation for the May 19th retail choice en banc hearing being convened by the California PUC and California Energy Commission, CAPUC Staff has issued a white paper entitled, “Consumer and Retail Choice, the Role of the Utility, and an Evolving Regulatory Framework.”

The white paper notes that between rooftop solar, Community Choice Aggregation and Direct Access providers (ESPs), that 25% of utility retail load will be served a non-IOU source or provider this year (550,000 solar customers, 915,000 CCA customers). That number is estimated to increase to 85% over the coming decade.

The white paper reviews the state’s aggressive GHG reduction goals that require significant infrastructure investments but that traditional utility rate structures rely on volumetric sales of electricity. The white paper explains the integrated planning process, resource adequacy requirements, and demand forecasts involving load serving entities.

Currently, the Power Charge Indifference Adjustment (PCIA) recovers above market energy costs from customers that chose to leave utility bundled service for an ESP or CCA. Non-bypassable charges that recover infrastructure costs have recently been expanded to include net energy metering customers. The development and application of the PCIA and NBCs to ensure fair cost allocation among customers is a contentious issue.

The white paper notes that consideration must be made as to whether a new provider of last resort should be adopted, and whether competitive retail or POLR service becomes the default. Likewise, utility legacy generation contracts and the application of non-bypassable exit fees or wires charges should be examined.

State law permitted the CAPUC to require the utilities to develop default time of use rates for residential customers in 2019, but a corresponding requirement does not apply to ESPs or CCAs. The white paper raises the concern that non-participation in time of use pricing may cause providers to vary prices and rates for commodity based on customer profiling by location.

The white paper notes that consumer protection for ESPs were adopted many years ago but similar safeguards have not been developed for CCAs, rooftop solar installers or community solar marketers. The appropriate regulations to apply to the market for these products should be explored.

The white paper seeks comment on the following questions:
“1. As an increasing number of customers can obtain electric generation service from a variety of sources (including IOUs, ESPs, CCAs, and on-site technologies), how does California ensure that all customers get the benefit of having multiple institutions play an important role in helping finance the infrastructure needed to meet the State of California’s GHG strategies, including electrification of transportation and fuel switching in the natural gas industry, while also ensuring that all customers have access to at least basic electric service?
2. What are the roles of the incumbent electric distribution utilities in the future, and what are the means for them to finance their core functions (e.g., distribution service, transmission service, POLR retail service) where some of these services are provided to all electricity customers and some are provided to only some customers (and in some cases may be provided because no other supplier is willing and/or able to provide them)?
3. Who will be the provider of last resort for customers who don’t seek to make key decisions for themselves, but prefer a simple and reliable bundled service? What agencies are best designed to provide customer protection in this new electric industry structure? What policies and/or authorities are necessary for utility regulators (or others) to assure that all customers - regardless of their supplier of generation and/or delivery service) have access to reliable and efficient electricity supply that also supports California’s economic and environmental goals?
4. How does the State of California ensure that the many different players work together to ensure that the State’s electric supply is not only clean but is also reliable, efficient and resilient? For example in light of the changes underway in the State’s electric system, how should the State provide such products and services as ramping power, voltage support, frequency control and managing over-generation? How should the State’s electric system become more resilient (e.g., capable of fending off attacks from physical and cyber threats, as well as speedy recovery from disasters)? How will California’s consumers pay for the many mandated public goods programs, ranging from energy research to providing energy efficiency upgrades and rate discounts for low income customers, which the California legislature has determined are core elements of the State’s electric system?
5. How will the State of California provide protection for consumers against predatory actions by providers of electric service or energy technologies in these new policy settings?”

A post-hearing report will summarize comments on the questions and insights gained. The CAPUC will open a rulemaking to examine the future role(s), structure(s), fiscal and other functions of the electric IOUs. It will also examine the scope and scale of the current retail competition framework.

The white paper concludes by noting, “it is very difficult to conceive of a scenario where the CPUC and CEC will not find that significant changes to the regulatory model and the utility structure are required.”

An Agenda for the en banc hearing has also been released. The full text of the Staff White Paper is available on the NEM Website.

The Commission issued an Order clarifying that technical conferences will be used to develop mechanisms for utilities, AESs, cooperative and municipally owned utilities to demonstrate compliance with new state law that they own or have contractual rights to sufficient capacity to meet their capacity obligations. The utilities had filed proposals in contested rate proceedings but the Commission decided that technical conferences are preferable to piecemeal adjudication.

The Commission requested that stakeholders in the technical conferences provide comment on the following questions by May 26th:

"1. Should the schedule laid out in Section 6w(8), MCL 460.6w(8) for capacity demonstrations be adhered to, or should any of these deadlines be adjusted as allowed under Section 6w(10), MCL 460.6w(10) to ensure proper alignment with MISO’s procedures and requirements? If a stakeholder recommends that the dates should be adjusted, please describe what revisions should be made.
2. Should there be a uniform methodology for capacity demonstration, both among types of providers (investor-owned utilities, rural electric cooperatives, municipally-owned utilities, and AESs) and among service territories?
3. Should there be a “locational requirement” for resources used to satisfy capacity obligations, and if so, should individual load serving entities (LSEs) be required to demonstrate a share of the overall locational requirement?"

The Commission intends to issue an Order on June 15th providing guidance on the three issues.

Staff will convene technical conferences on June 8th, June 29-30, and July 10, 2017, after which Staff will file a Report and Recommendations on resolved and open issues for stakeholder comment. Additional issues identified for the technical conferences include:

"How should capacity obligations change if customers change suppliers?
What type of proof should be required to verify any changes in load over the 4 year period for AESs? Is that necessary to track?
What level of proof should be required that capacity is owned or under contract and will not be sold in the interim as part of a capacity demonstration? Is a signed affidavit sufficient? If not, what level of proof should be required?
What level of proof should be required in order to count existing or proposed energy efficiency or demand response or demand-side management programs towards meeting capacity obligations?
What level of proof should be required in order to count newly proposed generation resources towards meeting capacity obligations? Signed generator-interconnection agreement before it could be counted? Signed affidavit including schedule to receive permits, approvals and complete construction ahead of the 4-year forward obligation?
If a small portion of the capacity obligation is allowed to be obtained in the MISO PRA to account for fluctuations in capacity obligations, is it possible to determine if those ZRCs purchased in the auction can be traced to generation that is physically located in Zone 7? If not, should ZRCs obtained in the PRA count towards meeting any portion of any potential LCR obligation or strictly PRMR obligation?
How transparent should the capacity demonstration process be?
Should the capacity demonstrations be contestable by other parties?
Would the most recently released LCR and PRMR by MISO for the prompt year be reasonably used for setting capacity obligations that are four years forward? If not, what is an appropriate methodology for determining the capacity obligations pursuant to MCL 460.6w?
In the case where an entity does not meet its capacity obligations, should the entity be required to include any information regarding which customer loads do not have capacity to meet the obligations?
If an AES meets its PRMR but not an LCR obligation, as applicable, is all of that entity’s load to be covered by the SRM with capacity provided by a utility or is another remedy appropriate?
What avenues exist for AES customers in Michigan to meet capacity obligations through demand reductions or demand response?
If an entity does not meet its capacity obligations 4 years forward to the MPSC, at what point in time do the requirements for that AES to participate in the PRA to cover that load end?"

The Commission will make a final determination on the establishment of the capacity demonstration process on September 28, 2017. The full text of the Order is available on the NEM Website.

The Nevada Committee on Energy Choice, that was convened in response to the energy choice ballot initiative, met again this week. The Committee heard presentations from former FERC and Texas PUC Chair Pat Wood, former PAPUC Commissioner John Hanger, and Nicolas Chaset, the Chief of Staff for CAPUC President Picker. Both Pat Wood and John Hanger gave highly informative remarks about the genesis and evolution of retail choice initiatives in their states. Questions from the Committee members ran the gamut from consumer education content and funding; preserving economic development incentives; state-specific versus regional wholesale markets; stranded cost calculations and recovery; and consumer protection regulations and enforcement. Lessons learned cited by Hanger included the availability of supplier consolidated billing, supplier-provided default service and development of the demand side of the market.

Of significance, the representative from NVEnergy noted his company was ready to fully divest its generation and did not have an interest in performing the merchant function under the market construct being considered.

The CAPUC representative stated that his Commission was expected to make big decisions in the next year on the utility's role in retail markets. He cited the "disrupting forces" of net metering and Community Choice Aggregation (CCA), including the recent decision of the County of Los Angeles to form a CCA.

The full texts of the Presentations from Pat Wood, John Hanger and Nicolas Chaset are available on the NEM Website.