This piece was originally published in the April 2016 issue of ei, the magazine of the electroindustry.
By Patrick Hughes, Senior Director, Government Relations and Strategic Initiatives, NEMA
Across the United States, annual electricity growth has flattened—from 9.8 percent in the 1950s to 0.5 percent today—due in part to advances in energy efficiency and distributed renewable energy technologies and accelerated by government policies and demographic trends.
Many utilities are facing a market where consumers are using less electricity, generating their own electricity, storing their own electricity, relying less on grid-supplied power, or even disconnecting entirely from the electric grid. As electricity sales stall or even decline, utilities will be forced to increase prices to recover the cost of fixed infrastructure investments, thus increasing the cost-effectiveness of energy efficiency and distributed generation and further decreasing utility sales—a positive feedback loop referred to as cascading natural deregulation or the “utility death spiral.”
But many in the industry dispute that utilities and utility regulators will let the situation get that dire. Indeed, we are already seeing states planning for a future with increasing levels of energy efficiency, distributed generation, energy storage, and other distributed energy resources (DERs). The New York State Public Service Commission is currently undertaking an ambitious process to rewrite the rules by which New York’s electric utilities will be governed in order to prevent large-scale disruptions to utility business models while allowing utilities to explore new revenue streams that will allow them to remain solvent as they facilitate and operate a more modern electric grid.
Called Reforming the Energy Vision (REV), the New York State Public Service Commission’s regulatory docket has grown to encompass 12 separate proceedings on issues such as net metering, utility energy efficiency programs, and the value of distributed energy resources.
Organized along two tracks—the Track I and Track II frameworks on regulatory and ratemaking reforms, respectively—the details of the REV process are still unfolding, but many of the foundational reforms have been established. These include the creation of a distribution system platform (DSP), a shift to more dynamic rate structures, and opportunities for utilities to diversify their revenues by offering new services to customers.
Distribution System Platform
Track I began as a staff white paper published in 2014 in response to guidance issued by the Public Service Commission and by Governor Andrew Cuomo. The final order, Adopting Regulatory Policy Framework and Implementation Plan, was issued in February 2015, to achieve six objectives:
- Enhanced customer knowledge and tools that will support effective management of the total energy bill
- Market animation and leverage of customer contributions
- System-wide efficiency
- Fuel and resource diversity
- System reliability and resiliency
- Reduction of carbon emissions
The key structural change to achieve these fundamental objectives is the creation of a DSP operated by utilities that will facilitate transactions at the retail level—similar to how wholesale electricity markets operate in many parts of the country. Third-party owners of DERs (e.g., solar photovoltaic systems, energy storage systems, microgrids, energy efficiency, and demand response) will actively participate in retail markets by providing valuable clean-energy generation and dynamic grid-balancing ancillary services, all while increasing the utilization factor of existing equipment and creating a more efficiently run power system.
Acting as the interface between customers, the distribution system, and the wholesale system, utilities operating the DSPs will create and manage markets for services provided by DERs. Many of these services can only be provided or facilitated by modern equipment, including advanced metering infrastructure, smart inverters for solar photovoltaic systems, energy storage systems, microgrids, connected thermostats, connected lighting systems, and connected appliances for use in demand response programs. How rates are determined to appropriately and accurately value the services provided by these advanced technologies will depend on the outcome of Track II.
Ratemaking and Utility Business Models
To govern transactions and align incentives between utilities and customers, New York State Department of Public Service issued the REV Track II “Staff White Paper on Ratemaking and Utility Business Models” in July 2015. It laid out six fundamental ratemaking principles to achieve the six previously listed objectives.
- Align earning opportunities with customer value
- Maintain flexibility
- Provide accurate and appropriate value signals
- Maintain a sound electrical industry
- Shift balance of regulatory incentives to market incentives
- Achieve public policy objectives
The Track II paper proposes a number of reforms, including allowing utilities to earn revenue from shifting capital expenditures to third-party DER providers and retaining part of the avoided cost as revenue (a change to the so-called “clawback” mechanism that would otherwise refund unspent capital to customers), detailing how costs related to setting up and operating the DSP are approved, and introducing market-based earnings and earnings impact mechanisms.
Market-based earnings (MBEs) are new sources of revenue earned by utilities for providing new services, including services provided through the DSP, and for managing their customers’ utility bills through energy efficiency. These MBEs will provide the financial incentive for utilities to actively encourage third-party DER owners to participate in the DSP and will encourage utilities to offer new services. For example, a utility could generate new revenue by offering engineering and design services for a new customer-owned microgrid.
In addition to MBEs, the REV Track II envisions performance-based regulatory requirements called earnings impact mechanisms (EIMs) to provide a financial incentive or penalty for utilities to meet certain predetermined performance benchmarks. Among the potential EIMs in the white paper were peak reduction, energy efficiency, customer engagement, affordability, and interconnection speed.
In addition to EIMs are scorecard metrics that are tracked but do not have associated financial incentives or penalties. Potential metrics include system utilization and efficiency, carbon reduction, conversion of fossil-fueled end uses (e.g., adoption of electric vehicles and conversions from natural gas to electric heating), distributed generation penetration, energy efficiency penetration, and dynamic load management penetration. Eventually, the individual performance targets, rewards, and penalties for EIMs and scorecards will be determined by the Public Service Commission during utility rate cases.
Ratemaking and electricity pricing reforms were also proposed to increase the dynamism of rates. Facilitated by the broad deployment of advanced metering infrastructure (i.e., smart meters), these ratemaking and pricing reforms include
- time-of-use rates;
- peak-coincident demand charges;
- smart home rate with more granular price signals for customers seeking a more active role in their own energy management; and
- creation of a new form of dynamic, geographically specific pricing mechanism called LMP+D: the locational marginal price plus the additional value that DER provides to the system (the specific value of “D” has yet to be determined).
This means that customers with solar systems in a congested section of the distribution grid would receive a higher price for their kilowatt-hours than similar customers in an uncongested area, creating price signals for customers to build more DER on the parts of the distribution grid that need them the most.
Next Step: DSIP
To show how they plan to achieve the REV objectives, each utility must file an initial distribution service implementation plan (DSIP) by June 30, 2016, followed by a supplemental DSIP by September 1, 2016. The DSIPs are frameworks that lay out exactly how each utility intends to encourage DER deployment and coordinate with third-party DER providers, as well as what tools and information utilities will need to successfully operate the distribution service platform.
In the meantime, utilities have proposed pilot projects to better understand the business models behind deploying third-party-owned DER and for new services offered by utilities. For example, National Grid proposed a resiliency demonstration project to test the willingness of customers to pay more for enhanced reliability from a microgrid that would provide essential services (e.g., first responders, banking, gas, and groceries) during severe weather events. This pilot is not studying the technologies that make up a microgrid; rather, it is exploring new ways to pay for microgrids.
As the New York State Public Service Commission continues to work through the REV process and utilities begin to implement pilot projects, specific details will emerge about how the electric industry will prepare for a future of flat or declining electricity growth. New York will no doubt pursue these reforms gradually to protect consumers and investors from unintended consequences. Eventually these efforts will result in a transition to a more reliable, cost-effective, and cleaner electric grid, one that can be used as a model for other states.
Prior to joining government relations, Mr. Hughes was NEMA’s policy director for high-performance buildings and industrial energy efficiency.