Many utility goods are in short supply, such as transformers, which have order timeframes of a year or more. Even before the pandemic, utilities were evaluating how best – or how else – to deliver electricity to customers in our increasingly constrained world. Today’s challenges involve a combination of equipment shortages, grid congestion, rate and regulatory pressures, land constraints, aesthetic considerations, and permitting delays so often involved with major infrastructure projects.
Whether it is for reducing line losses and improving efficiencies, shoring up grid resilience, or reinforcing the role customers can play in shifting energy loads, utilities are working to assess “non-wire alternatives.”
Defining Alternatives
“Non-wire alternatives” are technologies or operating practices intended to reduce grid congestion and manage peak demand to offset a utility’s need to make additional investments in conventional assets like wires, poles, and substations. The technologies can include distributed energy resources, such as microgrids or batteries, and practices and programs focused on load management, demand response or energy efficiency.
Such alternatives may have previously been deemed too costly to pursue or raised unacceptable reliability concerns for public power utilities. Yet the supply chain is expected to continue to be strained as utilities expect to have increased needs for electric grid equipment in the coming years. A recent survey from the American Public Power Association showed that utility leaders were concerned about the availability of transformers, meters, bare wire, and underground residential distribution wire.
Non-wire alternatives may become more feasible and achieve greater cost competitiveness. A recent Wood Mackenzie report finds that front-of-the-meter battery storage has been the non-wires alternative technology of choice to date. Compared with other resources, battery storage accounts for most project capacity currently being implemented, with federal regulations likely strengthening this trend going forward. How technology has evolved in power system planning tells an interesting story.
Exploring “Big Build” Alternatives
Public power has a history of evolving system planning based on local input. Transmission towers, with their long swaths of wires crisscrossing the landscape, may be the most recognizable power system asset. They are also some of the most difficult and controversial projects to permit and build.
Non-wire alternatives that could replace multi-mile infrastructure builds have offered solutions. Especially as the cost of solar plummeted over the last decade and other resources, like battery storage, become more viable. In recent years, demand response programs have taken center stage in areas facing extreme temperatures that threaten to overwhelm the grid (or have overwhelmed it already).
It marks a transformative step in advancing targeted, less obtrusive power system solutions over large, centralized structures that could fall victim to budgetary constraints. Especially as utilities plan to meet load growth driven by substantial electrification efforts, they are looking for how to best control that additional load and the associated costs while limiting the amount of physical infrastructure needing to be built. Such targeted solutions also become relevant for public power utilities constrained by transmission congestion issues.
With big demands outlined in planning processes come big opportunities. Grid congestion problems could increasingly be addressed more economically with localized solutions: microgrids, energy storage, energy efficiency, demand response, virtual power plants, advanced software, congestion relief by updating existing business practices, aggregation techniques, or any combination of such alternatives. They may also offer more flexibility and future scalability – plus be more operationally efficient – to maintain grid reliability.
Evolving with Technology
The Alabama Municipal Electric Authority was established in 1981 as a joint action wholesale power provider for 11 public power utilities in Alabama. Collectively they serve approximately 350,000 people across small towns and mid-sized cities. AMEA provides low-cost electricity through wholesale power contracts, owned generation, and by helping to lower demand through various initiatives.
Arthur Bishop, AMEA’s manager of transmission and distribution technology support, shared how AMEA’s load management program has evolved over 20 years. It began by installing load control receivers on member customers’ air conditioners and water heaters in the 1990s. “These were activated via radio signals during peak periods, with some members also stopping pumps and starting generators at water or wastewater plants,” he said.
Technological advancements and how power contracts were being structured evolved this approach. AMEA’s members next used their joint action agency to install SCADA systems. Each then leveraged a smart grid initiative to help upgrade their distribution systems.
“Upgrading member substations with the latest smart regulator panels and using conservation voltage reduction helped to lower peaks with precision – and with verifiable data,” Bishop explained. AMEA now has 30 megawatts of conservation voltage reduction available, with an additional 20 MW possible within the next two years, once all members have advanced metering infrastructure systems in place. The combined 50 MW would represent about 6% of AMEA’s total peak load. “Further testing shows the percentage capable down to a feeder level with AMI also providing higher reliability and flexibility using bellwether meters that provide near real-time data back to SCADA for monitoring while activated,” Bishop said.
AMEA also has a program for renewable behind-the-meter generation for member customers and has installed community solar parks in each member city to study solar usage during peak periods. That led to a 100 MW utility-scale solar project being built in south Montgomery County, Alabama, that is expected to be in-service in January 2023.
Bishop said future contract changes will allow for even more flexibility in distributed generation. “AMEA is exploring adding storage at both the community solar and utility-scale projects, as well as upgrading member-owned generation to more efficient units and additional units at other member facilities.”
Leveraging Blockchain Technology
The Burlington Electric Department is Vermont’s largest municipal power utility. It serves over 21,000 customers across approximately 15 square miles with a generating mix of owned and purchased power that has been 100% renewably sourced since 2014. Almost all of BED’s energy comes from roughly equal shares of biomass, hydropower, and wind.
Casey Lamont, a resource planning analyst, constantly looks for ways to reduce costs and provide additional customer benefits. One such effort was using funding from the American Public Power Association’s research and development program to pilot a demand response program in 2019 using blockchain technology. Together with Omega Grid, LLC, the utility set out to demonstrate that wholesale electric market costs could be reduced using dynamic blockchain market incentives. The goal was two-fold: 1) to reduce capacity and energy costs for the utility by better managing new distributed energy resources on the grid, and 2) to incentivize more customers and devices to participate by exploring immediate low-cost and faster settlements using tokens on a blockchain. The value of those tokens was “trued up” once Burlington knew if an action had helped reduce the utility’s load during the peak hour.
Most demand response programs focus on enrolling larger customers to maximize demand reduction and cover the overhead of engagement. Increased solar penetration, however, has begun to shift peak demand hours into the early evening, generally away from times when larger traditional demand-response participants experienced their demand peaks.
Burlington and Omega Grid theorized that lower cost and faster settlement of transactions enabled by a blockchain-based system could lower the cost to implement a demand response system and enable a greater diversity of customers and devices to participate. Blockchain transactions, and digital technology generally, could thus result in lower costs, enabling broader participation. They also believed that participants would want more control over how they managed their response to the predicted events by offering a bid reflecting their cost to reduce load. Instead, during implementation, they realized that customers wanted a simpler incentive and were not interested in determining their response thresholds based on bid prices.
The pilot demonstrated that it was possible to run a blockchain-based demand response program that could serve a diversity of participants with low-cost transactions. The pilot also identified some needed refinements to move to a larger scale.
“It was a broad-based program where anyone could join and we were sending messages to customers, but we did not have a direct way of determining their response, beyond meter data,” Lamont said. The pilot also demonstrated to Burlington Electric “the value of targeted programs and automated response.”
The effort also explored how a demand response program could be designed to better predict the value of peak events and, for customers, how the onboarding, communication and engagement with customers could be leveraged. Burlington learned that the system could be further enhanced by streamlining methods to onboard customers, automating communication with building management systems, and adding tools for device owners to test that their system is performing.
According to the final report (accessible to DEED members only), “Any public power system that is subject to transmission or capacity charges and the ability to monetize reductions in those charges, or able to benefit from load shifting could find a similar program to be beneficial. The benefit to a public power system would be proportional to the costs that they would be able to reduce under such a program.” Burlington Electric realized a total savings of $14,579, with 70% of that amount returned as customer incentives. The report added that as the importance of bulk or wholesale sources of electricity is minimized in favor of more load flexibility, local generation, and storage, decentralized technology such as blockchain could be helpful in managing many more potential new grid assets as well.
