By William Opalka and Rich Heidorn Jr.

New York regulators last week began to sketch out the details of their ambitious Reforming the Energy Vision (REV) initiative with a white paper on rate design that seeks to upend business models that have been in place for more than a century and establish the state as a leader in the shift to distributed energy resources (DER).

The New York Public Service Commission staff straw proposal is intended to address the “discontinuity” between traditional cost-of-service regulation and the “multi-sided” market envisioned in Reforming the Energy Vision, with customers that are also producers and utilities that also serve as “platforms” for vendors offering services that help consumers reduce or time-shift their energy use.

That means utilities will see less of their earnings from centralized generation and returns on capital investments and more on service revenue and incentives tied to energy reductions, reducing transaction costs and increasing the volumes of DER, such as rooftop solar, microgrids and storage.

“The ratemaking paradigm must create alternatives to the current financial and institutional incentives and provide opportunities for utilities to earn from activities that achieve their service obligations in a manner that supports reductions in the total customer bill,” the paper says.

“The intent of REV is to harness markets to achieve innovative and cost-effective solutions, with utilities facilitating those markets both in their system planning and in day-to-day operations. Financial incentives and economic signals must be in alignment with this goal.”

In February, the PSC issued its “Track 1” order that created a framework for the shift from centralized generation to a customer-centric market that encourages adoption of clean distributed energy resources. The commission said that business as usual is no longer a viable option for utilities in meeting their statutory responsibilities to New Yorkers. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)

Last week’s white paper will be the foundation for an anticipated “Track 2” order on ratemaking changes. “Track 2 looks closely at how we’re going to align the utility investment earning capacity with customer value,” Anthony Belsito, a policy advisor for the PSC, told the Infocast New York Reforming the Energy Vision Summit last week. (See related story, Public Helping Drive New York REV Agenda.)

Gradualism

The paper said that changes to rate design formulas must not cause large, sudden increases in customer bills. And this “gradualism” should also apply to industries such as solar and energy efficiency providers, it said. “Any changes affecting these industries should provide ample time for businesses to adapt and plan for new forms of opportunity.

“For the same reason, rate design changes should be oriented toward investments going forward, versus investments already made. To the extent possible, customer investments already made under assumptions of a program such as [net energy metering (NEM)] should not be disrupted.”

The report says concerns about the impact of NEM on utility earnings are “inconsequential” at current penetration levels.

“Input from the DER industry makes clear that the simplicity and predictability of NEM is very important in engaging customers and providing certainty to investors. Staff does not believe that there is any value in changing NEM for mass-market customers with on-site [distributed generation] at this time.”

Granularity vs. Simplicity

One of the challenges observed by the PSC is the conflict between increasing granularity in cost allocation and maintaining simplicity in billing, particularly for residential customers. That, the staff said, is where aggregators can play an important role. “Customers themselves may not need to see complex rates if a service provider or aggregator sees and manages complexity for them,” it said.

LMP+D

The paper proposes a new method for calculating the value of DER: adding a distribution component (“D”) to the wholesale LMP pricing (location-based marginal price of energy, as New York refers to it).

“The current convention of crediting at the average retail rate may be either too little or too much based on the nature of the resource and its location,” the paper says.

The value of D can include load reduction, frequency regulation, reactive power, line-loss avoidance and resilience.

The PSC plans to develop ways to calculate LMP+D in proceedings involving utilities and DER providers. Staff called for the state’s utilities to adopt software to determine distribution-level marginal costs.

LMP+D can incent net-metered facilities to install smart inverters that can increase the amount of solar generation that can safely be interconnected to a circuit. Staff said the commission should consider requiring smart inverters on future net-metered projects.

While the valuation of DER should vary by location, the paper says, customer charges should remain indifferent to location.

Customers participating in a utility demand response program or exporting power to the grid should receive compensation based on LMP+D, staff said.

Customers who supply only a portion of their electricity and do not participate in a utility program would receive no significant credits from their utilities. “In this circumstance, even when the ‘value of D’ as a service to the grid can be calculated, the reduction of the customer’s bill should continue to be based on the average cost of service. That is, NEM as it is currently constructed should remain applicable.”

Reforming the Energy Vision Rate Design

The paper proposes several additional changes:

• Demand Charges — The paper proposes “for comment and further development” the concept of replacing part of the kilowatt-hour and fixed customer charges with a peak-coincident demand charge. “Because long-run distribution marginal costs are driven by coincident peak on a circuit-by-circuit basis, customers’ usage at system peak provides the most accurate measure of system costs. And, unlike fixed customer charges, peak demand can be managed by customers via DR, energy efficiency and/or DG,” staff said. Fixed customer charges should reflect only the costs of distribution that do not vary with customer demand.

“This change is not proposed as a mere reallocation of costs among customers,” the paper said. “It is proposed as part of a broader strategy to reduce long-term system infrastructure needs, encourage the optimal development of DER, discourage uneconomic bypass of the distribution system and maintain affordable rates for all customers.”

• Time-of-Use Rates — The paper says utilities should develop time-of-use rate demonstration projects and offer technologies that have been shown to increase peak reduction savings, such as in-home displays, “energy orbs” and programmable and communicating thermostats. The paper cites studies showing TOU rates resulting in peak reductions as high as 47%. “Peak load reduction impacts are seen to increase as the peak to off-peak price ratio in TOU rates increases,” it added.
• Smart Home Rate — The PSC said early-adopter consumers should be able to opt in to new rate structures. “A gradual approach to changes in mass-market rates should not prevent customers who are willing and able to begin participating in energy markets as active consumers from doing so.”
• C&I Rate Design — While rates for commercial and industrial customers are more advanced than for mass-market customers, the report calls for additional improvements, saying demand rates should be more precise and reflect the time of energy use. “Current non-coincident demand rates can have the effect of inhibiting a customer from shifting load to off-peak times,” it says. “For example, a customer investing in storage to purchase off-peak power and utilize it at peak times might face an increased demand charge due to the shift in usage to the off-peak time.”

It called for utilities to examine their C/I rates and propose improvements in their next rate filing.

• Standby Service Tariffs — Standby rates, which apply to large customers that generate much of their power on-site and use the distribution grid as a backup, can be another barrier to DER. The PSC recently expanded an exemption from standby rates for four years while it studies rate design changes. Standby rates are related to net metering and to the general rate design issue of fixed versus variable rates, the report notes. “In each case, the responsibility of a customer for the cost of the customer’s reliance on the distribution grid is at issue,” the staff said. “The cost of remaining connected to the grid should generally be lower than the cost of building redundancy and independence into a self-generation system.”