In our latest Exploring North Carolina Smart Grid webinar, we learned about the importance of electric rate modernization for supporting grid improvements and a clean energy future. The session featured Cara Goldenberg and Heather House of the Rocky Mountain Institute, Lon Huber with Duke Energy, and Jack Floyd of the North Carolina Utilities Commission Public Staff. The presenters discussed upcoming considerations and challenges around rate design, strategic initiatives and pilots in North Carolina, and how other states are reforming their approach to ratemaking.
Investor-owned utilities have traditionally been compensated through a cost-of-service model. Under this model, certain expenses, including operations and maintenance, are passed through to customers in the form of electricity rates. Capital expenses, such as building out infrastructure and power plants, are added to what’s called a utility’s rate base. Everything that goes into the rate base also receives a rate of return.
Added up, these pieces produce a revenue requirement, which is how much money utilities must collect from customers to cover their expenses, pay their taxes and earn a rate of return for shareholders. This revenue requirement is used in calculating rates. (Note: This overview does not represent the exact equation that states use; it’s a simplified version that captures some of the major components.)
Ultimately, how much revenue utilities obtain depends on how much electricity they sell. This structure, however, offers limited motivation to pursue energy efficiency, customer-focused distributed energy resources and other efforts that might lower electricity sales. Furthermore, it doesn’t provide an incentive to reduce expenses for what goes into the rate base, so utilities gain from building equipment.
As Rocky Mountain Institute’s Cara Goldenberg explained, though, the electricity system is changing. New consumer expectations, new policies, new needs on the grid and new industry targets are here, and these have not been previously considered in utility compensation. Therefore, utilities face barriers to meeting these fresh demands.
Performance-based regulation, or PBR, is one approach to reducing these barriers and providing incentives for utilities to keep up with their changing landscape. Although PBR is just a piece of the puzzle, it has the potential to complement other strategies, such as tariff and rate design, distributed energy resource compensation, and planning and grid modernization initiatives.
One foundational aspect of PBR is decoupling the link between energy delivered and revenue collected. Removing this association can produce greater investment in energy efficiency and provide a more stable inflow of utility revenue, which could promote innovation. To date, over a third of U.S. states and about 50 utilities have implemented decoupling.
Several states also offer multiyear rate plans. Instead of holding annual rate cases, regulators set utility revenues around three to five years in advance, often basing them on forecasted expenditures. The objective here is to drive cost containment by allowing utilities to hold onto the savings they achieve from keeping their costs below the set revenues. Multiyear rate plans additionally reduce the regulatory burden of rate cases.
Implementing multiyear rate plans won’t automatically lead to more clean energy, but it can work alongside other policies and regulations that stimulate investment. It provides more revenue certainty for utilities, which can increase flexibility in grid modernization and related efforts.
Multiyear rate plans can be supported by targeted performance incentive mechanisms (PIMs). PIMs are designed to reward or penalize utility performance in achieving objectives or outcomes that align with public interests.
PIM rewards and penalties can be set up in a variety of ways. For example, in a shared savings mechanism, if a utility reduces expenditures compared to a baseline, it keeps some of its savings as profit. PIMs can be used for energy efficiency as well as other emergent outcomes, such as distributed energy resource utilization and demand management improvements.
The PBR process is already underway in several states. In Hawaii, for example, it was initiated by the public utilities commission, with a goal of exploring how the utility business model and regulatory framework might be realigned to better reflect public interest and policy objectives.
In Minnesota, PBR was started after a utility filed a multiyear rate plan with its commission. The commission then opened a proceeding to examine the use of additional PBR mechanisms. The state is taking a more incremental approach to track performance metrics and see if those evolve into PIMs.
Innovation Through AMI Data and Rate Design
Technology is reducing cost constraints on customer-sided utility solutions, and it’s coming at a great time. With innovations such as advanced metering infrastructure (AMI), utilities can cost-effectively capture data and turn that data into information that can solve challenges and facilitate a clean energy future.
These developments are especially valuable when considering peak demand. Peak demand reflects times when the grid is under the most strain, and utilities must build their entire systems to meet these situations. For Duke Energy, Lon Huber explained, peak demand occurs in the winter and is caused primarily by residential customers, particularly in the morning hours. But what type of customers, specifically?
Harnessing AMI data and demographic information, Huber and his team constructed an analytics dashboard to dive into the details. What they have found is that the type and age of a home appear to be important. Single-family and mobile homes are the primary drivers, as well as homes built between 1975 and 1989, when electric heating was more common than gas heating (which is the inverse of what has been found before and since).
Digging deeper, AMI disaggregation has allowed Duke Energy to pinpoint which individual appliances are influencing peak demand. Space heating, especially heat pumps, appears to be a large contributor, while water heating and other equipment have less of an impact.
With this information, Duke Energy better knows who and what to target with energy efficiency and demand response measures. One idea that stemmed from this effort was to run a bring-your-own-thermostat program. Other developments have included leveraging current programs and creating a long-term strategy and framework for future programs.
Potential modeling revealed that rate design combined with home technologies could lead to sizable peak demand reductions. Recent pilot projects have backed up these patterns. Duke Energy has found that rate structures can produce a 7 to 20 percent improvement on high peak event days, showing that customers understand and respond to rate features. There was an even greater impact when smart thermostats were also present.
How about mixing rate design and rooftop solar? Duke Energy and collaborators put together a next generation of net metering in South Carolina that has four components: proper cost recovery, a static time-of-use rate, dynamic pricing events to target critical days and a connection between solar and dispatchable resources — Duke Energy is starting with smart thermostats and then moving to battery storage and other controllable devices. The goal is to create a more holistic resource that can benefit customers system-wide.
Effectively tackling winter peak, Huber concluded, will require widespread adoption of new rates and products, and customers need options to balance control, risk, price and goals.
As the manager of rates and energy services for the Public Staff, Jack Floyd works to represent the using and consuming public in front of the North Carolina Utilities Commission. When it comes to rate design, his team has been busy. Since 2007, 13 rate cases across North Carolina’s three regulated investor-owned utilities (Duke Energy Progress, Duke Energy Carolinas and Dominion Energy North Carolina) have come before the Utilities Commission.
However, although there have been changes to rate design in particular areas of service, there has been no broader meaningful update in several decades. Most of the designs used today originated in the 1960s, ‘70s and ‘80s.
With the expansion of AMI, though, we are gaining new insights into how the utility system is used. These analytics are helping companies look more granularly at load shapes and identify how cost of service and rate design need to shift.
Other changes that are affecting utility service include the transition to LEDs and introduction of time-of-use pilots, as well as the growth of electric vehicles, battery storage, microgrids and distributed generation. At the same time, there are new cost drivers, a greater awareness of impacts on vulnerable populations and pushes for more customer choice and autonomy over electricity usage.
All this progress is happening in an environment without legislative transformation. In North Carolina, the law has remained the same, and developments such as PBR have not yet materialized. In other words, Floyd said, we’re still looking at a traditional vertically integrated cost-of-service-based rate design approach.
When conducting a comprehensive rate study, Floyd mentioned high-level principles, outlined by the Regulatory Assistance Project, that can guide the Utilities Commission and utilities.
- Be forward-looking and reflect long-run marginal costs
- Be focused on the usage components of service that are most cost- and price-sensitive
- Be simple and understandable
- Recover system costs in proportion to how much electricity consumers use, and when they use it
- Give consumers information and the opportunity to respond to that information by adjusting usage
- Be dynamic where possible
The objectives of such a study are to look at costs incurred to connect customers, ensure payment is proportional to usage and provide fair and just compensation for consumers and users who supply power to the grid.
The comprehensive rate study is stakeholder-driven and explores cost of service (which rate design is predicated on), levels of service (firm to non-firm), unbundling rates into functional parts, dynamic pricing designs and affordability for vulnerable communities. This endeavor does not mean that existing rate structures are inadequate, but they should be examined with these ideas in mind.
North Carolina’s Energy Regulatory Process
As Floyd discussed, the Public Staff in North Carolina operates within the state’s current regulatory system. But that system may change in the future, Rocky Mountain Institute’s Heather House said.
Under Gov. Roy Cooper’s Executive Order 80, the North Carolina Department of Environmental Quality was directed to create a Clean Energy Plan for the state. The plan promotes the utilization and integration of clean energy resources to support a modern and resilient grid. It was developed through a stakeholder process throughout 2019, and over 800 contributors provided input.
Within the broader category of utility incentives and comprehensive system planning, the plan recommends launching a North Carolina Energy Regulatory Process, or NERP. NERP would include representatives from key stakeholder groups to design policies that align regulatory incentives and processes with 21st century public policy goals, customer expectations, utility needs and technology innovation. A second recommendation encourages evaluating components of PBR using pilot programs and other methods.
NERP launched in February 2020. Its purpose is to produce recommendations for policy and regulatory changes that can be delivered to the North Carolina Governor, General Assembly and Utilities Commission. To get there, it seeks to build trust and expertise among North Carolina energy stakeholders, examine alternatives to the traditional utility regulatory model and incentives, and generate policy proposals that participants and stakeholders can work to implement.
The stakeholders met to identify desirable outcomes, which fell into four categories: improving customer value, improving utility regulation, improving environmental quality and conducting a quality stakeholder process. The three top priority outcomes included affordability and bill stability, regulatory incentives aligned with cost control and policy goals, and carbon reduction.
NERP has been an intense, ongoing effort consisting of study groups, workshops and webinars. Some of its planned outputs will include discussions of wholesale market reform, competitive procurement and asset retirement for uneconomic coal. One group is specifically investigating PBR and will provide a guidance document with key findings and options for the Utilities Commission to deliberate. The group is also drafting legislative language for potential amendments, a fact sheet and case studies.
In all, the process is helping North Carolina explore possible ways to modernize its electric utility system.
We hope you enjoyed and learned from this year’s Exploring North Carolina Smart Grid webinar series. If you missed any of our previous sessions, you can view recordings and access additional resources here. We want to thank all the presenters for sharing their time and expertise as well as Duke Energy for collaborating with us to deliver the series.