How utility demand-side management strategies must evolve to address a dynamic resource mix
The path to realizing an efficient and flexible grid capable of supporting new value will require the participation of customer-sided resources and technology to interface with the grid of tomorrow.
The following is a viewpoint by Patty Cook, a senior vice president with ICF's Commercial Energy practice.
By some estimates, behind-the-meter distributed energy resources (DERs) are expected to more than double, from 46.4 GW in 2017 to a total 104 GW of flexible capacity by 2023. While energy efficiency (EE) programs of the past were primarily used to reduce baseload in a central-station paradigm, the demand-side management (DSM) programs of the future will also need to align with distributed energy management and resource flexibility goals.
At the same time, the growing number of connected devices, self-generation and energy management options means that customers have a central role to play in the future of the grid — they will no longer be viewed as passive load, but instead as flexible grid resources.
A more integrated approach to DSM will ensure customer programs play an expanded role in supporting grid services, deferral of capital expenditures, and utility revenue streams. This shift will be enabled by a variety of behind-the-meter technologies, a modern grid and dynamic pricing or time-of-use rates working together to optimize the experience for the customer while supporting efficient grid operations.
Utilities are in an ideal position to take advantage of this shift by understanding the role of technology, customer behavior and the various business models for valuing and sourcing DERs and EE. But how will this evolution occur? And what are the barriers, opportunities and signposts?
It will unfold differently at the state and utility levels — and depend on a number of key factors. Regulatory commissions are trying to keep pace with the change through an unprecedented level of activity centered around initiatives like grid modernization, utility business models, electrification, distribution planning, procurement and evolving energy markets — taken together, these actions have the potential to reinvent the electric industry for the next century.
While policy changes in states like California and New York get most of the attention, over 15 states are working through planning efforts focused on building a more modern, distributed and customer-centric grid. As "flexible" becomes the new frame of reference by which resources are valued, "grid currency" will become the norm, even in states anticipating slower levels of technology adoption and decentralization.
Smart integration of EE, DR and DER
Over the past 20 years, conventional EE and demand response programs were procured and valued based on the avoided average system capacity of a gas-fired power plant, with energy savings and demand reduction serving as an economic proxy for the avoided investment in new capacity. As natural gas prices decline and coal and nuclear baseload units become uneconomical and retire, avoided system capacity becomes a less attractive proxy for valuing energy efficiency savings — resulting in conventionally measured and valued EE becoming increasingly less cost-effective.
At the same time, utilities are exploring alternative ways for valuing distributed resources (including EE) as a means to defer distribution investments and provide grid services. Utilities are also leveraging their automated meter infrastructure (AMI) and grid modernization investments — including customer insights and associated load profiles — along with new technologies to help manage an increasingly dynamic and flexible grid.
As a result of these shifts, EE will be valued less as an avoided system cost and more as a grid (bulk power and distribution) resource alongside other DER based on its ability to provide real, meter-based locational and temporal savings, and optimal grid management when needed.
In other words, as the fundamental characteristics of the system change, the method for valuing EE also needs to change since measuring cost-effectiveness on the basis of avoided central station fossil-fueled capacity fails to capture the overarching shift to renewables (central or otherwise) and DER. In the future, "kWh savings anytime, anyplace" will be become "kWh savings at the right time, in the right place".
Central to this evolution is growing customer awareness and choice relative to energy management and self-generation options.
Customers have an array of choices at their fingertips to explore rooftop solar, smart appliances, EV charging options, HVAC, water heating and solar plus storage — all aspects of a grid-connected home that can accommodate customer preferences and comfort. Because these behind-the-meter changes can be read at the meter in near real-time, they can be used to generate lower or more predictable energy bills for customers. Customer usage insights can also be used to help drive "next best offers" of additional products and services to help improve the customer experience.
Many of these behind-the-meter devices can also benefit the grid when collectively managed, by minimizing, shifting or optimizing energy use within the home. In addition to premise-level optimization technologies, distributed energy resource management systems are being piloted and deployed by utilities and third-party aggregators to control fleets of customer assets that meet a variety of grid needs.
Combined with cost-reflective price signals, such as time-of-use rates and dynamic pricing, these distribution management systems can provide a way for customers and utilities to "sync up" energy usage in ways that reduce the cost of delivering electricity (or mitigate cost increases), which supports a more affordable, reliable and sustainable grid for all customers over time.
Thanks to smart device technology, customers can now understand how premise-level consumption patterns impact their monthly bill, comfort level and security.
Customers can see how energy usage during peak times is more expensive and shift their use — or charge their electric vehicle — during less expensive times of the day.
AMI data from smart meters allows utilities to see consumption patterns and load shapes, which can be used to improve outage management and the overall resiliency of the grid. For example, Con Edison, through its NY REV pilots, seeks to demonstrate that cost-reflective, technology agnostic pricing can serve as a platform for unlocking greater DER value and alignment with greater system efficiency.
Smart meter interval data isn't the only tool utilities have to better manage the grid.
Distribution planning and optimization tools have traditionally been used to identify distribution investments and upgrades to improve the safety and reliability of the grid. Enhanced load forecasting and power flow models are now being used to anticipate the health of the grid, including the capacity of the grid to host additional DER at certain locations, down to the circuit level, potentially as a means to defer or avoid distribution investments and to improve grid operations.
The key to a healthy grid: Your customers
As we move toward a two-way relationship between the utility and customer, the most essential questions become: What tools do utilities have to best manage the grid in a more decentralized future, and how should the value of these resources be realized and shared between utilities, customers and third parties — including aggregators and DER providers?
How should DERs, including EE, best support things like distribution deferral, grid services and eventually market participation?
How much and how fast should utilities invest in building the "grid of the future"?
Should all customers pay for and benefit equally from these efforts, and to whom should the revenue accrue from creating additional grid value?
Different answers will emerge depending on each state's unique regulatory paradigm, the extent to which utilities are allowed to own and earn on DER investments, and whether incentives are used to facilitate market transformation. For example, a combination of pricing (i.e., rates), programs and procurement may provide the means by which DERs, including EE, and generation resources will be sourced, depending on the type, scale and timing of the need.
In general, rates are assumed to cast the widest net for capturing customers, generating revenue and ensuring the broadest impact for the least cost.
Further, customer-facing programs can be used to reach a more targeted customer base to increase savings or demand reduction in the near-term, geo-targeting higher-energy users with the most potential for savings or reduction.
These programs can also leverage dynamic pricing and meter-based savings combined with customer-facing technology to increase their value to the grid. Program administrators can also act as aggregators, where fleets of customer-sided resources are managed to achieve a "value stack" where the utility and aggregator share in the value created.
For example, FERC Order 841 will potentially allow for the elusive "dual participation" of DER in providing distribution as well as wholesale services. Finally, all-source competitive RFOs can solicit system capacity, resource adequacy or ancillary services while distribution services procurements target highly localized grid needs, including distribution deferral and other grid services.
Ultimately, DER sourcing mechanisms will come down to how utilities, policy-makers and DER providers agree to balance risk and reward. But it's clear that utilities need a sustainable business model that goes beyond cost avoidance.
Fortunately, significant progress has been made in defining the opportunities, benefits and revenue associated with a more distributed future.
Utilities like HECO, the NY Joint Utilities and the California IOUs are experimenting with performance-based regulations, earnings adjustment mechanisms and various incentives which will allow utilities to earn a rate of return on DERs.
The jury is still out on which combination of levers makes the most economic sense for each utility and how customers will share in any resulting value created. However, it's also clear that the path to realizing an efficient and flexible grid capable of supporting new value will — by necessity — require the participation of customer-sided resources and technology to effectively interface with the grid of tomorrow.
Utilities that take advantage of their existing customer-facing programs, relationships and infrastructure will increase the value they provide to their customers and be better-positioned for the future.