Non-wires alternatives — projects that seek to use distributed energy resources to delay or replace traditional grid investments — are very much a state-by-state, project-by-project affair. In the past five years or so, we’ve seen the handful of legacy non-wires alternatives projects across the country start to be supplanted by a new breed of projects, led by New York and California, along with a handful of New England states.
But as our analysts at Wood Mackenzie Power & Renewables have noted, it’s hard to compare and contrast the benefits or drawbacks of each state’s approach to non-wires alternatives (NWAs), or to measure their cost-effectiveness against alternative approaches. That’s largely because the field is so young, and because each state has adopted different metrics and methodologies, as well as different standards of data sharing and project transparency, which makes apples-to-apples comparisons difficult.
Back in April, nonprofit E4TheFuture hired the Smart Electric Power Alliance (SEPA) and Peak Load Management Alliance (PLMA) trade groups to go out and create a nationwide survey of NWA projects, as a first step in solving this problem. The result is a report released last week, comparing and contrasting 10 representative NWA projects from seven states: New York, California, Arizona, Maine, Michigan, Rhode Island and Washington state.
The projects cover a wide range of technologies, from the old standbys of energy efficiency and demand response, to on-site rooftop solar, combined heat and power, battery and thermal energy storage, and utility-side generation redispatch and conservation voltage optimization. In terms of scale, the projects covered in the report range from the Bonneville Power Administration’s proposed 100-megawatt transmission relief project, to distribution-level NWAs from 330 kilowatts to 85 megawatts.
New York, being the leader in NWA deployments to date, had the most projects on the list, including Consolidated Edison’s Brooklyn-Queens Demand Management (BQDM) initiative, Central Hudson Gas & Electric’s Peak Perks targeted demand management program, and National Grid’s Old Forge NWA pilot. From California, the report picked two projects that aren’t called NWAs, but which nonetheless are aimed at using DERs to mitigate grid impacts — Southern California Edison’s Distribution Energy Storage Integration pilot project and its 85-megawatt flexible capacity contract with Stem.
But the report also highlights some less well-known NWA projects, such as the Swartz Creek Energy Savers Club launched by Michigan utility Consumers Energy and the Natural Resources Defense Council, National Grid’s Tiverton NWA pilot in Rhode Island, Central Maine Power (CMP)’s project with GridSolar, and Arizona Public Service and AES Energy Storage’s Punkin Center battery project.
These projects represent just the tip of the iceberg for NWAs, given that three-quarters of the country’s NWA capacity today is still in the planning stages. That’s why SEPA and PLMA have tried to boil down the very different experiences of the 10 projects they selected into a “handful of key commonalities” that could be useful for utilities, regulators, and would-be NWA project partners looking at their own plans.
The common thread — NWAs (mostly) work, but only after meeting unique challenges
The report’s first finding is also its sunniest. For the most part, these NWA projects have succeeded in their task of “helping to delay or permanently defer infrastructure upgrades,” it states. In New York, both Con Edison and Central Hudson’s programs have reported successes, with the massive Brooklyn-Queens Demand Management program showing the greatest potential benefits thus far, spending a fraction of the $1.2 billion it would have needed to rebuild a major substation in the region on efficiency, demand response, energy storage, fuel cells and combined-heat-and-power systems both in front of and behind the meter.
(The third New York project, National Grid’s Old Forge NWA, is still in the planning stages.)
Southern California Edison’s projects also merit a successful grade, with the Distribution Energy Storage Integration pilot showing the utility could use batteries to avoid a substation upgrade in Orange County, and its 85-megawatt “virtual power plant” with Stem providing the required capacity to help it manage the long-term effects of losing the San Onofre nuclear power plant, as well as ocean-cooled natural gas power plants set to close under state water regulations.
Several other projects appear to offer significant cost savings potential, such as the Bonneville Power Administration’s South of Allston NWA project. Meant to test the use of efficiency, demand response and other dispatchable DERs to defer a $1 billion transmission grid project, the South of Allston project managed to run for two years on a day-ahead basis to provide about 200 megawatts of relief during the months of July, August and September, at a cost of only $5 million. Those are findings the Bonneville Power Administration is eager to use to “inform future longer-term, non-wires program plans,” the report states.
But the list also includes projects that did not, or haven’t yet, met their goals. Consumers Energy’s project is a chief example, with the utility and partner Natural Resources Defense Council unable to recruit enough residential, commercial and industrial customers to meet its 2018 goals to reduce load requirements below 80 percent of its maximum summer capacity. While the project has helped increase efficiency and reduce load, it’s unclear if it can get enough participation to meet that threshold for actually being able to forestall the necessary upgrades.
One of the big challenges with NWAs is the fact that they’re based on future expectations of load growth that may not materialize. “For at least two projects, NWA opportunities originally emerged as a result of high load growth forecasts; however, load growth did not materialize,” the report says. One of those was the GridSolar-Central Maine Power project, which was meant to forestall a $1.5 billion transmission upgrade to serve customers for only a limited number of peak-time hours.
After winning its NWA bid, GridSolar installed 1.85 megawatts of batteries, solar, backup generators and efficient lighting improvements, only to find its contract canceled in 2018 because the anticipated load growth never ended up happening — an eventuality that would have likely ended the $1.5 billion project the NWA was meant to replace. Even so, compared to a more limited transmission upgrade, the project still saved Maine ratepayers about $12 million, the report states.
In fact, the failure of load growth to materialize is a point in favor of, not in opposition to, NWAs in lieu of grid investments, the report notes. That’s because NWAs can be deployed in a modular fashion, “incrementally and in phases as load grows. This allows opportunities to approach load growth uncertainty flexibly and help avoid large upfront costs.”
But to be successful, each project had to overcome a set of challenges that were both unique to its circumstances and shared with other projects, the report notes. The most common shared challenges were bidding and procurement processes that took longer than expected (which is not unusual for first-of-a-kind projects) and the use of some form of “benefit to cost assessment” to measure the value of NWAs against the traditional upgrades they’re meant to defer.
Proper cost comparisons between states, or even between projects, are harder to come by, the report notes. “While Con Edison’s Brooklyn-Queens Demand Management and Bonneville Power Administration’s South of Allston [projects] demonstrated significant cost savings in implementing their NWAs in comparison to the originally proposed infrastructure investment,” the report notes, “many of the case studies were unable to report cost data and analysis.”
The report also highlighted the key problem for NWAs at the intersection of economics and state energy policy — the fact that, for most utilities, spending billions of dollars on capital expenses like grid infrastructure is a surefire way to lock in guaranteed rates of return for years to come. Any project that promises to reduce that capex for a lower-cost alternative is likely to meet with opposition from utilities, unless it’s accompanied by incentives, or alternative revenue streams, or some form of replacement for traditional rate-based cost recovery.
The revenue stream piece is important, because most of the NWA projects listed in the report were built under state regulatory mandate of one form or another. New York’s Reforming the Energy Vision (REV) initiative has driven the bulk of the country’s NWA development, as well as helped to cement the acronym in common usage. As of May 2018, New York utilities had 41 current and upcoming NWA procurements listed on the REV Connect site.
California has driven the NWA process through different channels, such as its mandate for investor-owned utilities to develop distribution resources plans that “identify optimal locations for the deployment of distributed resources,” and approving a pilot regulatory incentive mechanism that awards a 3 to 4 percent pre-tax incentive to utilities deploying cost-effective DERs that defer or displace traditional distribution investments. In September, California’s investor-owned utilities filed their distribution deferral opportunity reports identifying the first set of specifically defined NWA projects at the distribution grid level.
NWAs have also been a part of the New England energy policy mix for some time. Rhode Island has required NWA consideration as part of annual System Reliability Procurement reports since 2006, and allows its major distribution utility to recover costs of investments in system reliability. The Vermont Public Utility Commission enacted legislation in 2015 requiring the Vermont System Planning Committee to identify deferral projects when considering new transmission. And in Maine, the Smart Grid Policy Act Directive requires regulators to consider NWAs before approving T&D projects, and has created a regulatory post of independent investigator to identify cost-effective projects.
There's growing acceptance around the use of nontraditional solutions for utility system planning, the SEPA/PLMA report concludes. Going forward, "[n]ew incentives, regulations, and changes in traditional utility business models will be needed to expand NWAs," it states. The key to success will be a robust stakeholder process that's capable of facilitating these deeper regulatory discussions.