Calif. Public Power Leaders Say New Rule Threatens Ability of Utilities to Respond to Emergencies
May 1, 2023
by Paul Ciampoli
APPA News Director
May 1, 2023
A rule recently approved by the California Air Resources Board that is designed to transition all medium- and heavy-duty vehicles in the state to electric or hydrogen-powered vehicles includes “a major flaw that could risk longer water and electric outages during emergencies,” leaders of the California Municipal Utilities Association, the Southern California Public Power Authority and the Northern California Power Agency said.
At issue is the Advanced Clean Fleets rule, which was approved by CARB on April 28. The rule requires most California fleets to begin purchasing zero-emission medium- and heavy-duty vehicles in 2024. Beginning January 1, 2024, 50% of medium- and heavy-duty vehicles purchased by publicly owned electric utilities and public water and wastewater agencies must be zero-emission. Starting January 1, 2027, all medium- and heavy-duty vehicles purchased by public agencies must be zero-emission. The rule stems from an Executive Order issued by Governor Newsom in 2020 that, among other things, also initiated California’s approach to banning the sale of gasoline powered by cars by 2035.
In an Op-Ed completed prior to the rule’s approval, Barry Moline, Executive Director, California Municipal Utilities Association, Michael Webster, Executive Director, Southern California Public Power Authority and Randy Howard, General Manager, Northern California Power Agency, acknowledged that overall the rule is essential to achieve California’s environmental goal of a carbon-neutral economy by 2045.
“But the proposed rule’s major concern is that it may hinder many local utilities’ ability to respond to emergencies, natural disasters, and significant service disruptions. Customers and communities served by local governments that own and operate their own water, wastewater, and electric utilities will be at risk,” wrote Moline, Webster and Howard.
The heavy specialty vehicles that utility crews use daily reach power lines; clear debris; transport, remove, and set utility poles; move and set critical water infrastructure; and provide water purification for communities, they pointed out. “During emergencies, this important work is often done under challenging conditions and in rural, isolated locations.”
But these specialty utility vehicles are not widely available in electric or hydrogen models. “That likely will continue to be the case for the next several years — a period when the ACF rule will require California utilities to purchase and utilize zero-emission vehicles. While these vehicles account for only a small number statewide, they play an outsize role in safely maintaining and restoring the electrical grid and water infrastructure,” Moline, Webster and Howard said.
They emphasized the point that publicly owned utilities do not want an exemption to the rule, noting that generally, public water, wastewater, and electric utilities support purchasing zero-emission vehicles wherever feasible.
“But given the stakes — and risks to public health and safety — the rule must be amended to provide reasonable, practical accommodations when a zero-emission vehicle cannot do the same emergency work as a traditional utility vehicle. This prudent amendment would help protect local communities statewide that serve Californians,” the Op-Ed said.
“We must also recognize the reality that vehicles powered by hydrogen — not electric — are better suited for the work of many utility vehicles. It is paradoxical to rely on an electric vehicle to restore power when there is no electricity to keep the vehicle charged.”
Hydrogen vehicles, on the other hand, “are not dependent on the grid and can be refueled quickly in the field, allowing a utility crew to operate around the clock while repairing damaged infrastructure. The widespread deployment of hydrogen vehicles is, however, on a slower timeline than electric vehicles.”
The federal government “is providing billions of dollars to build hydrogen hubs across the country, which should help expand the hydrogen vehicle industry. Until then, utilities need the flexibility to purchase traditional vehicles when a zero-emission vehicle is unavailable or cannot meet emergency response needs,” Moline, Webster and Howard said.
They said that CARB must take these emergency response concerns seriously and amend the Advanced Clean Fleets rule “to accommodate the essential work of publicly owned electric and water utilities.”
In early April, the three groups submitted a detailed letter requesting specific changes to the regulation. Among other things, the groups asked CARB to open a subsequent Advanced Clean Fleets implementation rulemaking following adoption of the rule, so that concerns detailed in the letter can be addressed.
Meanwhile, there is at least one bill under consideration by California lawmakers that is intended to give utility fleets the flexibility that CMUA believes is needed, noted Matt Williams, Communications Director for CMUA.
Rising Costs for Projects Withdrawn from SPP Interconnection Queue: Report
May 1, 2023
by Peter Maloney
APPA News
May 1, 2023
Average interconnection costs for the Southwest Power Pool are stable for projects that complete all interconnection studies but have escalated sharply for projects that withdraw from the queue, according to a report from Lawrence Berkeley National Laboratory.
The report, Generator Interconnection Cost Analysis in the Southwest Power Pool (SPP) Territory, found that the interconnection costs for projects completed in the 2020-2022 timeframe were largely unchanged at $57 per kilowatt, from completed projects in the 2002-2009 timeframe at $54 per kilowatt.
Projects that withdrew from the interconnection queue, however, saw large cost escalations in the 2010s, from $22 per kilowatt in the 2000s to $247 per kilowatt in the 2010s and $304 per kilowatt in the early 2020s.
Projects still moving through the queue had an average cost of $106 per kilowatt in 2020-2023.
Average costs for withdrawn projects are now five times the costs of completed projects, likely a key driver for those withdrawals, the Berkeley Lab researchers said in the report. They also noted that project-specific interconnection costs in the Southwest Power Pool differ widely due to many factors and do not have the shape of a normal distribution.
The Southwest Power Pool’s queue has ballooned over the past decade, the Berkeley researchers said, noting that the cumulative active queue is now more than five times larger than in 2013, with 2022 additions being nearly three times the size of 2021 requests.
At year-end 2022, the Southwest Power Pool had 109 gigawatts of generation and storage capacity actively seeking grid interconnection, a level of capacity more than twice as large as the power pool’s roughly 51-gigawatt peak load in recent years.
Almost all, more than 96 percent, of the capacity in the Southwest Power Pool’s queue is clean energy, including solar and solar hybrids at 51 gigawatts, wind at 35 gigawatts, and standalone storage at 13 gigawatts.
Broader network upgrade costs are the primary driver of recent cost increases, especially for withdrawn projects, the Berkeley researchers found. No costs for upgrades beyond the interconnecting substation were reported in the 2000s, but they have recently increased on average to $23 per kilowatt in the 2020s. For withdrawn projects, network costs grew sharply in the 2010s to $180 per kilowatt and continued to climb for some projects in the 2020s, to $230 per kilowatt.
The report also found that a very small subset of generators seeking interconnection in the Southwest Power Pool face lower network upgrade costs by choosing interconnection services as an energy instead of a capacity resource. However, those project owners of energy resources forfeit preferential treatment during high load hours, cannot participate in the Southwest Power Pool’s resource adequacy market, and may face increased curtailment, the researchers said.
SPP initiated interconnection process reforms in 2009, transitioning to a clustered, “first-ready, first-served” approach and increasing project deposits and readiness criteria; despite these and other reforms, some of which are ongoing, SPP’s active queue interconnection wait times have increased steadily, with the typical project taking nearly six years to reach commercial operations in 2022, the report found.
Another recent report from Lawrence Berkeley said requests to connect clean energy projects to the grid have soared in recent years, leading to longer wait times and backlogs for project developers.
The Southwest Power Pool report is the fourth in a series analyzing interconnection costs in wholesale electricity markets, with prior studies analyzing the Midcontinent Independent System Operator, the PJM Interconnection, and the New York Independent System Operator.
Berkeley Lab is working on a forthcoming study that will analyze ISO New England’s interconnection queue.
LADWP Crews Prepare for Runoff from Record Snowpack Melt
April 28, 2023
by Paul Ciampoli
APPA News Director
April 28, 2023
The Los Angeles Department of Water and Power on April 25 said it has begun preparing early for this year’s runoff based on lessons learned from the last extreme wet year in 2017.
The historic snowpack levels in the Eastern Sierra of 296 percent of normal translates into runoff that is 233 percent of normal, LADWP said. That translates into one million acre feet, or 326-billion gallons of water that will need to be managed.
The runoff season is expected to last through the summer months, requiring significant preparation work and coordination with partner agencies in the Eastern Sierra to implement public safety measures to mitigate the potential for flooding, the utility reported.
“We have had crews and personnel making the necessary preparations since last December and are ready to respond when the snow begins to melt,” said Anselmo Collins, Senior Assistant General Manager of LADWP’s Water System. “A typical runoff season can last anywhere from May to June. However, with our record snowpack this year and the volume of water that translates into once the snow melts, the season may push through to August.”
“We have already begun managing excess flows by spreading water throughout the aqueduct system to replenish local groundwater aquifers, and maximizing flows in the LA Aqueduct by emptying reservoirs to create more storage space for runoff waters,” said Adam Perez, LADWP’s Aqueduct Manager. “This allows us to supply Los Angeles with aqueduct water in place of purchased and pumped water wherever possible.”
Currently, approximately 130 billion gallons of water is expected to make its way to Los Angeles this spring and summer via the Los Angeles Aqueduct, potentially enough to meet 80 percent of LA’s annual demand, to serve more than 1 million LA households for a year, LADWP said.
The utility said that despite these efforts, a high volume of runoff will still remain in the Eastern Sierra and require management efforts. Additional emergency hires have been put in place to support the increased construction and operational needs. Equipment, such as excavators, backhoes, and in-flow meters, have also been purchased and strategically placed in key locations to expedite response during the runoff season.
Other preparation work includes repairing diversion structures damaged during heavy rainfall earlier this year to ready spreading grounds to receive the runoff; repairing and cleaning ditches that receive the runoff; and shoring up areas of Owens Lake to minimize the expected damage rising water levels may pose to dust mitigation infrastructure.
Wilson Energy’s John Maclaga Details Supply Chain Challenges in Meeting With Lawmakers
April 28, 2023
by Paul Ciampoli
APPA News Director
April 28, 2023
In a recent meeting with House members, John Maclaga, Assistant Director for North Carolina public power utility Wilson Energy, detailed the current supply chain challenges facing the electric power sector and offered potential solutions to alleviate those challenges.
Maclaga participated in an April 19 roundtable in Washington, D.C., convened by the bipartisan Supply Chain Caucus led by Reps. David Rouzer (R-NC), Dusty Johnson (R-SD), Colin Allred (D-TX), and Angie Craig (D-MN).
In an interview with Public Power Current, Maclaga praised the caucus members for “being a truly bipartisan group” of lawmakers who are “taking leadership on this, showing an interest in this” and seeking tangible solutions.
“The reliability and security of the electric grid is at stake if we don’t take action to address the supply chain crisis we’re seeing today,” Maclaga said in a statement related to the roundtable. “Lead times and prices for transformers, utility poles, bucket trucks, and other critical equipment have increased exponentially since the start of the pandemic, with lead times for trucks, for example, jumping from 12 to 60 months and prices increasing four-to-five fold.”
He said that Congress and regulators should make sure the federal government is supporting the development of more robust supply chains and onshoring of manufacturing of critical infrastructure components.
Specifically, Maclaga said that the Department of Energy should be encouraged to halt a proposed rule on transformer efficiency standards. In December, DOE announced it was proposing new energy efficiency standards for distribution transformers.
The proposed rule discourages the remaining U.S. grain-oriented electrical steel (GOES) steel producers and traditional transformer manufacturers from adding any GOES capacity or continuing existing capacity, he argued.
At the meeting, Maclaga noted that DOE has plans to expand electrification, promote electric vehicle use, add additional solar energy and create more energy efficient buildings. “I can’t bring these things online if I can’t connect them,” he said.
He also proposed appropriating $1 billion through the Defense Production Act to increase all forms of distribution and substation transformer manufacturing in the U.S. and directing the Federal Emergency Management Agency to invest in a national stockpile of distribution transformers when/if demand for distribution transformers falls below 2019 levels.
In late 2022, APPA, the Edison Electric Institute, and the National Rural Electric Cooperative Association submitted comments in which they said that DOE should use Defense Production Act authorities to prioritize distribution transformers, large power transformers, and other critical grid components ahead of other technologies, and it should act quickly to alleviate the most acute supply chain challenge with distribution transformers.
Maclaga said in the interview that he urged the lawmakers to “appropriate money in orders of magnitude of billions of dollars to give manufacturers a chance.”
Elaborating on the stockpile idea, he said that “another way to incentivize manufacturers to make more stuff including transformers” would be to start stockpiling equipment. “Don’t buy anything now. Find out what you want to buy, get your specs right, make the announcement. Tell manufacturers we’ve got $20 billion in a FEMA fund to go buy these transformers and when your demand and your production loads gets back to a 2019 lead time again, we’ll start buying them to build the FEMA stockpile. So then if you’re a manufacturer and you’re on the edge of buying a new production facility – maybe you can get a grant to build it – and then go ahead and wear out your three-year backlog as fast as you can and then at the other end of it, FEMA’s going to be there. If you’re first to the trough, knowing that you’ve got your demand levels down, you can be first to the FEMA transformer sale and beat your competitors to the punch.”
What Wilson Energy is Doing to Address Supply Chain Challenges
Maclaga also detailed what Wilson Energy has done to address supply chain challenges.
He said that the utility has been working with ElectriCities of North Carolina to do more joint purchasing.
The utility has been making a push for more standardization when it comes to buying transformers, making the analogy to ordering a pizza.
When a manufacturer asks “what do you want on your transformer? I want it plain with cheese…because I really just want a transformer at this point and I don’t care whether it has taps, or special locks on it or my company’s sticker. I don’t care about that stuff anymore. I just want a transformer.”
Noting that Wilson Energy is an AMI and GIS system, “we have some talented people on staff that have been using those two systems to go look at where do we have transformers that are underused or overused. In other words, transformer right sizing.”
Maclaga said that pre-pandemic, it was not economical to keep old transformers. “In other words, we got them off from some old piece of line we were rebuilding, take those fifty-year-old transformers down, we’ll take them to a scrapper and sell them.” But now, “we’re not scrapping anything unless it can’t be safely turned on.”
House Members Urge DOE to Withdraw Proposed Rule for Distribution Transformers
More than 60 House members on April 3 urged Secretary of Energy Jennifer Granholm to withdraw the proposed rule to increase conservation standards for distribution transformers.
The efficiency standards for distribution transformers proposed by DOE would worsen current distribution transformer supply shortages and, to the extent that they are even feasible, would impose significant costs on consumers, the American Public Power Association said in March.
The electric industry is currently experiencing a critical shortage of distribution transformers, “and the efficiency standards included in the NOPR would likely exacerbate a supply shortfall that has already reached crisis levels, threatening electric reliability, economic development, and the ongoing transition to lower-emitting generating resources,” APPA argued in its March 27 comments to DOE regarding the NOPR.
Department of Energy Laboratories Test Virtual Nuclear-Renewable Hybrid Plant
April 27, 2023
by Peter Maloney
APPA News
April 27, 2023
Two national laboratories have completed a test of a virtual nuclear-renewable hybrid power plant.
The test involved a solar array, battery storage system, hydrogen fuel electrolyzer, and a controllable grid interface at the National Renewable Energy Laboratory in Golden, Colo., connected via a high-speed fiber optic network to simulations of a small modular nuclear reactor and high-temperature electrolysis unit at Idaho National Laboratory in Idaho Falls, Idaho.
Utah Associated Municipal Power Systems and its partners, NuScale Power Fluor Corporation, and the Department of Energy, are developing a small modular reactor project at an Idaho National Laboratory facility.
Utah Associated Municipal Power Systems and NuScale Power, along with Shell Global Solutions, are also assessing a process for producing hydrogen using small modular nuclear reactors.
The Colorado and Idaho operations were connected in real time using the Department of Energy’s Energy Sciences Network that uses fiber optic cable to provide high-speed, low-latency, and low-jitter data connections. The researchers said the connection created a “Super Lab” that allowed them to study energy systems currently not in existence to demonstrate that renewable and nuclear energy, combined within a hybrid system, can complement each other to support the grid.
During the demonstration, the researchers simulated a sudden loss in solar power from a passing cloud, and the nuclear reactor stepped in to support grid demand.
The tested scenarios provide developers a baseline and high-quality operational data for how hybrid renewables-nuclear designs might operate together for a reliable power grid, the researchers said.
For the next SuperLab demonstration, scheduled for late 2023, Department of Energy researchers plan to simulate a national-scale disaster across eight national laboratories to study how a major outage from a hurricane or cyberattack would play out on a distributed energy system. The scale of the experiment would involve 10,000 devices and be much larger than previous demonstrations, they said.
California CCA Group Issues Request for Information on Offshore Wind Projects
April 27, 2023
by Peter Maloney
APPA News
April 27, 2023
California Community Power recently issued a request for information for offshore wind projects in the Humboldt and Morro Bay areas, as well as other possible offshore wind developments.
California Community Power, which represents nine community choice aggregators from Humboldt to Santa Barbara counties, said it plans to use the results of the RFI to inform board recommendations regarding procurement, readiness, and barriers to offshore wind projects.
In 2021, the Department of the Interior with the Department of Defense and the state of California identified Morro Bay off California’s central coast as an area that could support up to 3 gigawatts of offshore wind projects. Together with the Humboldt area off the state’s northern coast Interior the areas could support as much as 4.6 gigawatts of offshore wind energy.
In December 2022, the Bureau of Ocean Energy Management, a division of the Department of the Interior, awarded five leases for offshore wind power development along the California coast.
“Offshore wind energy can provide steady, valuable, and renewable energy to meet California’s clean energy needs, including during heat storms when the grid is taxed,” Matthew Marshall, California Community Power board member and Redwood Coast Energy Authority executive director, said in a statement. “This RFI fits with the goals of CC Power. Gathering information and signaling interest in offshore wind is a prudent step for CC Power to gear up in exploring contracting for new offshore wind resources.”
If contracted for development by California Community Power, the offshore wind projects would be included in each community choice aggregator’s resource plan, and California Community Power said it would administer contracts to drive development and operations of new resources.
California Community Power members represent 2.7 million customers across 112 municipalities.
“This joint-action RFI will focus on California’s opportunity for floating offshore wind turbines, a technology gradually being deployed around the world,” Alex Morris, general manager of California Community Power, said in a statement. “This RFI helps us build formal recommendations on procurement for our Board and will inform strategies to address needs for port infrastructure and expanded electrical grid transmission, known barriers for offshore wind development in California.”
More information regarding the California Community Power Request for Information is available at https://cacommunitypower.org/solicitations/.
N.Y. Legislative Commission Delivers Draft Report on Transitioning LIPA to Owner, Operator of Grid
April 26, 2023
by Paul Ciampoli
APPA News Director
April 26, 2023
The New York State Legislative Commission on the Future of the Long Island Power Authority on April 18 approved a draft report for submission to the New York Legislature detailing its preliminary findings and plan for transitioning LIPA into a public power provider that would both own and operate the electric grid on Long Island and in the Rockaways.
The Commission will now conduct another round of public hearings and consult with its fifteen member advisory committee before delivering a final report to the legislature in time for its recommendations to be acted upon this legislative session.
The draft report lays out the operational, legal, and legislative steps necessary to achieve full public power at the expiration of PSEG Long Island’s contract on December 31, 2025.
The draft report’s key financial finding is that LIPA can save between nearly $50 million and $80 million a year by operating its electric grid itself without hiring an outside, for-profit utility – PSEG Long Island – to operate it for them, after one-time transition costs of between $16 million and $59 million.
In late 2021, LIPA announced a revised management services contract and settlement with PSEG Long Island that included reforms designed to drive performance and accountability, while providing an unprecedented level of oversight of PSEG Long Island’s operations.
North Carolina Planning Collaborative Identifies 38 Major Transmission Projects
April 26, 2023
by Paul Ciampoli
APPA News Director
April 26, 2023
Participants in the North Carolina Transmission Planning Collaborative have identified 38 major transmission projects that will improve the electric transmission infrastructure as part of a 2022-2032 collaborative transmission plan, ElectriCities of North Carolina said on April 13.
The 38 major transmission projects in the 2022 plan represent $1.49 billion in new transmission investments during the next decade. This includes 24 reliability projects representing more than $936 million in investments and 14 additional public policy projects representing more than $554 million in investments that will enable the interconnection of new resources and replace aging infrastructure.
The major transmission projects identified in the 2022 plan are expected to be implemented during the next 10 years by the transmission owners to enhance system reliability and resiliency, support addition of new generation resources, and potentially enable increased economic electricity transfers across the transmission network. Major projects are defined as those requiring transmission investments of more than $10 million each.
The 2022 plan includes nine new Duke Energy Carolinas reliability projects totaling more than $255 million in new transmission investments. The in-service dates and cost estimates for some planned or underway 2022 reliability projects have been revised from the previous year’s plan report.
The 2022 plan includes four new DEC and ten new Duke Energy Progress public policy projects totaling more than $554 million in new transmission investments.
The NCTPC was formed in 2005 by the load-serving entities to ensure DEC and DEP develop a shared plan for electric transmission system enhancements located in the states of North Carolina and South Carolina.
Those LSEs include DEC, DEP, ElectriCities of North Carolina, which serves public power communities across the state, and North Carolina’s Electric Cooperatives’ generation and transmission arm, North Carolina EMC, which serves as the power supplier for most of the state’s electric cooperatives.
Since its inception in 2005, transmission projects totaling more than $2.919 billion have been identified in the NCTPC plans. More than $1.158 billion in projects have been placed in service through the end of 2022, $1.46 billion are still in the planning stage and another $299 million were deferred until after 2032 or cancelled as a result of changing transmission system requirements. The plan is updated annually.
The NCTPC was established to provide participants and other stakeholders an opportunity to participate in the electric transmission planning process and develop a single coordinated transmission plan that includes reliability, resource supply additions, public policy, and local economic study transmission planning considerations. The group’s priority is to appropriately balance costs, benefits and risks associated with the use of transmission and generation resources.
Another goal of the NCTPC is to study the strength of the transmission infrastructure of DEC and DEP. The scope of the 2022 NCTPC study included a base reliability analysis for transmission needs to meet load growth between 2022 and 2032.
For a variety of reasons, such as load growth, generation retirements, or power purchase agreements expiring, LSEs may wish to evaluate other resource supply options to meet future load demand. These resource supply options can be either in the form of transactions or some hypothetical generators added to meet resource adequacy requirements for this study.
In 2022, the NCTPC also examined the impacts of 14 different hypothetical transfers into, out of, and through the DEC and DEP systems under the Local Economic Planning Process. The results of these studies are documented in Section VI of the 2022 Plan report.
“The NCTPC provides a valuable function by allowing stakeholders to better understand the electric transmission planning process,” said Marty Berland of ElectriCities of North Carolina, Chairman of the NCTPC Oversight/Steering Committee. “By offering greater transparency and opportunity to provide input to the process, entities that rely on the transmission system can collaborate to develop plans for future enhancements in a manner that optimizes cost effectiveness and reliability.”
SPP Market Participation Helps Colorado Springs Utilities Save Customers $2.1 million
April 26, 2023
by Paul Ciampoli
APPA News Director
April 26, 2023
From August to December 2022, Colorado Springs Utilities saved its customers approximately $2.1 million through its involvement in the Southwest Power Pool’s Western Energy Imbalance Market, the public power utility recently said.
The cost savings were realized thanks to energy-related purchases through the WEIS market that were below Colorado Springs Utilities’ cost to generate electricity locally and market sales of excess power generation.
Colorado Springs Utilities entered the SPP WEIS market in August 2022 to ensure reliable supplies of power, adequate transmission infrastructure and competitive wholesale electricity prices, it said.
“To realize more than $2 million in cost savings in just five months highlights why we joined SPP WEIS,” said the utility’s CEO Travas Deal. “By participating in shared resource pools like SPP WEIS, we can help maintain system reliability and manage energy costs for our customers – no matter regulatory mandates or market-related pressures.”
SPP’s WEIS helps Colorado Springs Utilities manage current and future energy costs “by having real-time access to the latest market intelligence, enhance the resiliency of its electric grid and help the organization access the lowest cost resources from other member utilities,” the utility said.
FERC Approves Incentive Rate Treatment for Cybersecurity Investments
April 24, 2023
by Paul Ciampoli
APPA News Director
April 24, 2023
The Federal Energy Regulatory Commission on April 21 issued a final rule providing incentive-based rate treatment for utilities making certain voluntary cybersecurity investments.
The final rule follows Congress’ direction under the Infrastructure Investment and Jobs Act of 2021 that the Commission revise its regulations to establish incentive-based rate treatments to encourage utilities to invest in advanced cybersecurity technology and participate in cybersecurity threat information sharing programs for the benefit of consumers.
In response to the notice of proposed rulemaking that preceded the final rule, APPA urged FERC to reconsider several aspects of the NOPR, including a proposal to allow a 200-basis point return on equity adder on eligible investments.
FERC said that the final rule largely tracks the Notice of Proposed Rulemaking issued September 22, 2022.
However, it also includes some important additions, the Commission said.
Specifically, the Commission expanded the definition of eligible cybersecurity investments to include not only a pre-qualified list of cybersecurity investments, but also those investments that are made on a case-by-case basis, allowing utilities to request incentives for a variety of solutions tailored to their specific situations.
The Commission will also allow utilities to seek incentives for early compliance with new cybersecurity reliability standards.
The final rule adopts the NOPR’s proposed requirement that expenditures materially improve a utility’s cybersecurity posture.
It also adopts the proposal to allow deferred cost recovery that would enable the utility to defer expenses and include the unamortized portion in its rate base, but does not adopt the proposed return on equity adder of 200 basis points.
The rule also states that approved incentives, with certain exceptions, will remain in effect for up to five years from the date on which expenses are incurred, provided that the investments remain voluntary.
The final rule takes effect 60 days following publication in the Federal Register.
Commissioner Danly Dissents
FERC Commissioner James Danly dissented from the final rule.
He said the final rule is not in line with the Infrastructure Investment and Jobs Act directive to establish incentive-based rate treatments that encourage investments by utilities in advanced cybersecurity technology and participation by utilities in cybersecurity threat information.