FERC last week said a MISO transmission owner cannot duck refunds stemming from the commission’s recent decision to implement a 10.02% return on equity (ROE) for the grid operator’s other TOs.
In a Dec. 1 order accepting the TOs’ compliance filing for MISO’s new ROE, the commission said Mississippi’s Cooperative Energy cannot evade its refund obligation by shortening its refund period (ER17-215).
MISO’s ROE has been a carousel of numbers for years. FERC in 2020 enacted a 10.02% ROE for transmission rates effective September 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were intended at different times to replace the 12.38% ROE established in 2002, which FERC deemed excessive years ago. (See FERC Stands by 10.02% ROE.)
The TOs’ compliance filings in question date back to 2016, reflecting the 10.32% ROE. FERC accepted them and ordered them updated to the TO’s current ROE of 10.02%, including incentives not to exceed 12.62%.
But the docket’s bigger point of contention came from Cooperative Energy, which argued that it shouldn’t have to provide refunds for the full refund period FERC prescribed.
FERC ultimately ordered TOs to refund customers for the 12.38% ROE from Nov. 13, 2013-Feb. 11, 2015, and Sept. 28, 2016-Dec. 23, 2020. (See MISO, TOs: More Time Needed for ROE Refunds.)
Cooperative Energy argued that it wasn’t obligated to issue refunds until mid-2015. That’s the date it began receiving a 50-basis point adder for its participation in MISO, despite it having been a non-public utility TO in MISO and using the MISO ROE since December 2013.
Other MISO TOs bristled at Cooperative’s interpretation of refund periods, leading them to register a limited protest of their own compliance filing.
FERC pointed out that Cooperative’s RTO adder was conditioned on its agreement to provide ROE refunds should the commission lower the rate. FERC said the TO should use its 2013 entrance into MISO as its effective refund date.
The commission found Cooperative’s arguments that forcing more refunds would amount to retroactive ratemaking to be baseless.
NYISO on Thursday updated stakeholders on several market changes in the works to accommodate thousands of megawatts of state-solicited renewable resources coming online in New York over the next decade.
The measures range from carbon pricing and buyer-side mitigation to distributed energy resource participation models, including for storage, hybrid and co-located resources, all part of the ISO’s Grid in Transition initiative announced two years ago, NYISO Principal Economist Nicole Bouchez told the Installed Capacity/Market Issues Working Group.
The ISO also posted the final version of its 2022 Master Plan for managing the changes in the energy, ancillary services and capacity markets.
The state’s Climate Leadership and Community Protection Act (CLCPA) and other statutes set ambitious clean energy targets staggered every five years from 2025 to midcentury, with strict emissions limits that regulators recently cited in denying air quality permits to two gas-fired generator proposals in the Hudson Valley and New York City. (See NY Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.)
“This path of Grid in Transition is focused on market enhancements under three different areas, the first one being aligning competitive markets in New York with the state’s clean energy objectives,” Bouchez said. “The second one is valuing reserves for resource flexibility, and the third one is improving capacity market valuation.”
NYISO retained The Brattle Group to forecast future resource mixes and help inform planning for reliability and market design over the next two decades, with the final report presented in June 2020. (See ‘Astonishing’ Buildout Needed for Clean NY Grid.)
Stakeholders expressed concerns about how fast the ISO is able to incorporate new events and regulations into its capacity processes. For example, the gas-fired projects were turned down, but state agencies have approved two separate projects totaling 2,550 MW to bring solar, wind and hydropower south to the city, as well as offshore wind projects totaling 4,300 MW. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)
In addition to the projects proposed, the ISO also presented an update on leading indicator metrics, with the most recent data provided in September, Bouchez said.
Supporting Studies
In looking at what changes to the markets are needed to face a growth in intermittent resource penetration, the ISO relied on several studies it has conducted over the past few years, including the following:
Aside from work on buyer-side mitigation tests and capacity accreditation, the ISO deployed a software-defined wide area network (SD-WAN). Separately, the NYISO is developing a billing and settlement system and billing simulator code. The remaining code for the DER participation model will be developed in 2022, with deployment also scheduled for next year.
The ISO expects to implement its hybrid co-located model in mid-December and will work to integrate the rules and software needed to enable large‐scale weather-dependent and energy storage resources to participate as co‐located resources (CSR) behind a single interconnection point. FERC in March accepted the ISO’s rules allowing an energy storage resource to participate in the wholesale markets with wind or solar as a CSR, and NYISO has since been working on the market software. (See FERC Approves NYISO Co-located Storage Model.)
A regulation service project completed in September last year updated requirements, and the ISO will continue to monitor fleet changes and appropriately update statewide regulation procurement requirements in the future.
New Resource Integration
One critical area is related to new resource integration projects, Bouchez said.
She listed three: the DER participation model, the hybrid aggregation model — which is scheduled for a functional requirements specification in 2022 — and internal controllable lines, “obviously something that we need to work through,” she said.
The ISO anticipates starting to review the real-time market structure to start in 2025, “but we’re thinking that it might not be a bad thing to start those discussions [next year] about the existing structure and different ideas for what changes should be considered and why,” Bouchez said.
Reliability Risks
The ISO on Friday released its Comprehensive Reliability Plan (CRP), the culmination of the 2020-2021 Reliability Planning Process. The report concludes that the state’s bulk power system will meet all applicable reliability criteria from 2021 through 2030 for forecasted system demand in normal weather.
The figure shows typical load profiles with typical generation profiles for wind and solar resources; while there may be enough energy overall to meet demand, it will be necessary to shift the generation from the afternoon to the morning and evening hours. | The Brattle Group
But it also “demonstrates that our reliability margins are thinning to concerning levels beginning in 2023,” Zach Smith, vice president of system and resource planning, said in a statement. “We have to move carefully with the Grid in Transition in order to maintain reliability and avoid the kind of problems we’ve seen in other parts of the U.S.”
The CRP recommends monitoring and tracking transmission projects and other risk factors in order to mitigate risks to BPS reliability. In addition, system margins are expected to narrow to such a level that warrants review of current reliability rules and procedures.
NYISO said it will administer its short-term reliability process to address generator deactivation notices and other system changes on a quarterly basis, and continuously evaluate on a forward-looking, five-year basis.
“The potential risks to reliability identified in the analyses may be resolved by new capacity resources coming into service, construction of additional transmission facilities, and/or increased energy efficiency, integration of distributed energy resources, and growth in demand response participation,” NYISO said.
Reversing course, FERC on Thursday ruled that PJM did not have to pay an Illinois wind farm $10 million under a resettlement of incremental capacity transfer rights (ICTRs) to the Commonwealth Edison locational deliverability area (LDA) (EL18-183).
ICTRs — available to interconnection customers that are required to fund a transmission facility — are awarded based on how much the improvement increases the transmission import capability into an LDA. ICTR holders receive revenues if the LDA in question is constrained in subsequent capacity auctions. The rights are good for up to 30 years.
The commission ordered the resettlement in April 2020 in response to a complaint by Radford’s Run Wind Farm, which said PJM unfairly denied ICTRs for funding an upgrade identified in its system impact study (SIS) to mitigate a thermal overload on the 345-kV Loretto-Wilton Center line.
In a subsequent compliance filing, PJM determined that Radford’s Run was entitled to almost $10 million for the 2019/20 delivery year. Crediting the wind farm required offsetting charges to the load-serving entities in the ComEd LDA associated with their corresponding CTR reductions. (See PJM Announces $10M Resettlement in ComEd LDA.)
In Thursday’s order, however, the commission said it now concludes the wind farm wasn’t entitled to ICTRs at the time of the 2016 Base Residual Auction for 2019/20.
Agreeing with challenges by PJM and Exelon’s Commonwealth Edison (NASDAQ:EXC), FERC said its earlier rebilling directive was “incompatible” with the PJM tariff’s definition of ICTRs because the wind farm did not become “obligated to fund” its upgrades until after the 2016 BRA.
The commission said PJM’s tariff is “ambiguous as it does not expressly state when the obligation to fund must occur.”
It concluded that the tariff requires that the resource either execute an interconnection construction service agreement with collateral or reimburse the transmission provider for the costs of the customer-funded upgrades prior to the BRA to qualify for the ICTRs for the associated delivery year.
The 306-MW wind farm in Macon County, Ill., went into service in December 2017. Neither the wind farm’s owner, RWE Renewables Americas, nor its attorney, Bruce Grabow of Locke Lord, responded to requests for comment.
PJM spokesman Jeff Shields said the RTO will comply with the order. “We don’t have any further details at this time,” he said.
FERC last week approved WECC-levied penalties totaling $156,000 against Black Hills Power (NYSE:BHP) and Southern California Edison (NYSE:EIX) for violations of NERC reliability standards (NP22-3).
NERC submitted the settlements to FERC on Oct. 28 in a spreadsheet Notice of Penalty. The commission indicated last week it would not review the WECC settlements, along with a separate $300,000 penalty against Ohio Valley Electric Corp. (See OVEC Hit with $300K in NERC Penalties.)
BHP Reports Study Shortfalls
Black Hills’ $46,000 penalty resulted from three violations of TPL-001-4 (Transmission system planning performance requirements) and one each of PRC-005-1 (Transmission and generation protection system maintenance and testing) and PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance). All were self-reported.
The utility’s infringement of TPL-001-4 had to do with the 2017 and 2018 Transmission Coordinating Planning Committee (TCPC) studies, which Black Hills discovered in 2020 had not been completed to requirements R2, R3 and R4 of the standard. Specifically, several aspects of the planning assessment were not finished in 2017 because the employees who were assigned to handle those parts left the company before it was done. The following year’s assessment was completed late as well, though WECC did not state whether this was because of the employees’ departure as well.
WECC assessed the risk level of the violation as minimal and acknowledged that it “did not pose a serious or substantial risk to the reliability of the bulk power system.” However, the regional entity also pointed out that the lack of a complete planning assessment could have limited Black Hills’ ability to “identify weaknesses in its system … implement action plans for identified system deficiencies or make needed system improvements.”
The RE regarded the issues with Black Hills’ planning assessments as systemic, warranting a financial penalty, because of the number of requirements violated and the fact that they spanned several years. The utility’s first mitigating action for the infraction was to complete the missing aspects of the affected assessments, which it did in 2020 while working on the 2019 assessment. It also created a TPL-001-4 process checklist to monitor the project’s progress each year, with backup plans for what to do if the needed information is not available in time.
The PRC-005-1 violation originated with Black Hills’ failure to verify the functioning of battery terminal connection resistance and battery interval or unit-to-unit connection resistance in two battery banks at a 230-kV converter substation. Black Hills reported in 2019 that it had not performed the testing — which is required every 15 months, according to the standard — since the standard became effective in 2007 because contractors performing the testing were unable to access the battery’s posts and straps. Black Hills verified the resistance of the batteries and replaced the bolts that kept contractors from accessing the batteries.
Similarly, the utility’s violation of PRC-005-6 was failure to verify that the communications system at a bulk electric system substation was functional every four calendar months. Black Hills found that its internal BES review committee “did not analyze and recategorize the substation as containing BES elements” after a new substation was interconnected on the BHP system in 2016. The utility completed the required maintenance testing, conducted an extent of condition review that found no other instances of noncompliance, and overhauled its BES review committee.
WECC considered these infractions systemic as well because of the overlapping timelines. The RE noted Black Hills’ internal compliance program but did not consider it a mitigating factor because of its failure to detect or prevent these violations, as well as the violations of TPL-001-4.
Testing Failures Net $110K Penalty for SCE
The $110,000 penalty for SCE originated from a violation of regional reliability standards FAC-501-WECC-2 (Transmission maintenance) and FAC-501-WECC-1, the earlier version replaced by FAC-501-WECC-2 in 2018.
SCE reported both infractions in May 2019. The utility discovered the infringement of FAC-501-WECC-2 first: It realized that three series capacitors and three circuit breakers that were elements of major WECC transfer paths had not been maintained and inspected in January 2019 as the standard required. The second violation was discovered during the investigation of the first, when SCE found that it did not have documentation of the 2016 and 2017 reviews of its transmission maintenance and inspection program (TMIP). The utility was also late in completing the 2018 TMIP review.
WECC found that the root cause of the original violation was failure to track the progress of the inspections, coupled with lack of communication between responsible parties. The second was caused by poorly defined management policy guidance and expectations, specifically the lack of a formal process for initiating the annual review of the TMIP, for documenting its completion or for storing the documents.
SCE mitigated the infractions by completing maintenance and testing for the series capacitors and circuit breakers, updating its monthly workload planning checklist to ensure the TMIP is completed, and documenting the scheduling process project plan. It also documented a process for annual review of the TMIP.
Nevada Gov. Steve Sisolak on Thursday announced the membership of a panel that will advise the governor and legislature on potentially bringing the state into an RTO.
Sisolak named Sen. Chris Brooks (D), the bill’s author, as chairman of the task force. Its other 18 members include representatives of utilities, labor, environmental groups, business and government.
The governor’s office expects to add five more task force members in coming weeks.
“This task force will further advance our state’s mission of developing our infrastructure, bolstering our commitment to renewable energy and building out our green energy economy,” Sisolak said in a release.
RTO by 2030
SB 448 includes a requirement for transmission providers to join an RTO by January 2030, unless they can show that they haven’t been able to find a viable RTO or that joining an RTO wouldn’t be in the best interest of the providers or their customers.
The Regional Transmission Coordination Task Force will formulate advice on topics and policies related to regional energy transmission in the West.
Under the provisions of SB 448, the task force will study the potential costs and benefits of forming or joining an RTO, for transmission providers and their customers in Nevada. The task force may bring in an independent third party to help analyze those costs and benefits.
The panel will explore policies to help bring transmission providers in the state into an RTO by 2030, including whether any legislation is needed to allow the providers to join an RTO.
The task force will also look at business the state could attract by having a position in a regional wholesale electricity market. It will look at locations for new transmission facilities that would help achieve the state’s clean energy and economic development goals.
The task force will meet at least twice a year and send a report to the governor and legislature by Nov. 30, 2022, ahead of the state’s 2023 Legislative session.
Cost Savings, Reliability
Western Resource Advocates, which has a representative on the task force, pointed to a market study this year that found Western electricity customers could save more than $2 billion a year if a single market operator managed transmission and coordinated generation planning. Such a move could also support renewable energy development and improve reliability. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
“The state task force’s work on a Western regional transmission organization will help Nevada reap the economic, environmental and reliability benefits of regionalization,” Vijay Satyal, Western Resource Advocates’ regional energy markets manager, said in a release.
Members of the Regional Transmission Coordination Task Force are:
Sen. Chris Brooks (chairman)
David Bobzien, director, Governor’s Office of Energy
Kris Sanchez, deputy director, Governor’s Office of Economic Development
Carolyn Barbash, vice president, transmission development and policy, NV Energy
Carolyn Turner, executive director, Nevada Rural Electric Association
Cameron Dyer, managing senior staff attorney, Western Resource Advocates
Eric Witkoski, executive director, Colorado River Commission of Nevada
Erik Hansen, chief sustainability officer, Wynn Resorts
Jeremy Newman, assistant business manager, IBEW Local Union 396
Leslie Mujica, executive director, IBEW/NECA/LMCC – Las Vegas Power Professionals
Luke Papez, director, project development, LS Power Development
Richard Perkins, president/CEO, The Perkins Co.
Mona Tierney-Lloyd, head, U.S. state public policy and institutional affairs, Enel North America
Samuel Castor, EVP of policy, Switch
John Seeliger, regional energy manager, Nevada Gold Mines
Kostan Lathouris, managing member, Lathouris Law PLLC
From Buffalo to Long Island, New York is trying to reduce transportation-related pollution not only by promoting electric vehicles, but by increasing the availability of public buses and light rail, developing greenways to make bicycling safer and easier.
Betta Broad, NYCP | NYCP
“The regional Transportation and Climate Initiative Program (TCI-P) had some setbacks, but we’re still committed to the program and want people to take action by supporting it and signing our petition to send a message to Gov. [Kathy] Hochul,” Betta Broad, director of New Yorkers for Clean Power (NYCP) and a member of the state’s Climate Action Council, said Wednesday as she hosted a “teach-in” on clean transportation on behalf of NY for TCI.
Connecticut Gov. Ned Lamont, Massachusetts Gov. Charlie Baker and Rhode Island Gov. Dan McKee separately announced last month that their states would back away from the program, which they and D.C. in December 2020 had signed a memorandum of understanding to join. (See Conn. Environmental Advocates Urge Continued Commitment to TCI-P.)
“We hope to see TCI included in the Climate Action Council’s plan that will also be circulating across the state next year, with lots of opportunities for public comment,” Broad said.
EVs vs. Mass Transit?
Meanwhile, passage of the bipartisan infrastructure bill in Washington means many billions of dollars coming to New York for transportation initiatives, she said.
Douglas Funke, president of the city’s Citizens for Regional Transit, said investing in more infrastructure to accommodate individual vehicles is not the ideal solution.
“We really have to fix the car problem, and public transit in our opinion is the way to do that,” Funke said.
He noted that Buffalo had a plan for a 42-mile light rail network but only built 6 miles. The city is building another 6, which is encouraging, he said, but it’s still far from the goal.
Changing all vehicles to electric doesn’t work in urban areas like Buffalo or New York City, Funke said, “because you still have the congestion, still have all the parking, all the roads. Every ton of concrete generates a ton of CO2, so if you have to keep building parking lots and roads and repairing them for all the cars, it just creates more pollution.”
Mariah Okrongly, Bedford 2030 | NYCP
In suburban Westchester County, however, EVs make more sense, said Mariah Okrongly, program manager at Bedford 2030, which is working to get local school districts to buy electric school buses.
Her organization expects at least one of the school districts in the next bond proposition to include an electric school bus, but it has been difficult selling the novel concept of using the buses to feed the grid with the vehicle-to-grid technology, Okrongly said.
“So it definitely is a long a long-haul initiative, but worthwhile, and with the new infrastructure bill and all the funds associated with that, there’s going to be a bigger push to move forward with this, so I think it’s a prime time if you’re considering this to begin the process,” Okrongly said.
Another town, Peekskill, is hosting a pilot on-demand, fully electric transit program that links with Westchester’s Bee-Line bus network, said Nina Orville of Sustainable Westchester.
The on-demand fleet also provides the opportunity to build out the charging infrastructure in Peekskill, where most households have either one car or none, Orville said.
“We still need to do work across the state to address tariffs for charging vehicles, which is particularly important for people who live in multifamily housing and have to use charging infrastructure that might be billed different rates than if they had their own charging equipment,” she said.
On-demand EVs “would be swell” in southeast Queens, where most commuters still have to take a bus to a Long Island Rail Road station and then to the New York City Subway to get to work, said Jean Sassine, a member of New York Community for Change.
“We just need more buses, more electric buses because … most of the pollution is coming from cars,” Sassine said. “Queens is built with the idea of that old sprawl mentality, so we’re either driving or waiting for buses.”
Greenways Connect People
Ibrahim Abdul-Matin, Green Squash | NYCP
The Brooklyn-Queens Greenway is part of a larger effort to develop dedicated biking and walking paths throughout New York City, said Ibrahim Abdul-Matin, of consultancy Green Squash, who also serves on the state’s advisory board of the Trust for Public Land.
A lot of people don’t necessarily feel safe or comfortable on the subway or they live far from where they work, Abdul-Matin said. The old purpose of greenways was to infuse residents with trees and wildlife, but now the idea is to reconnect and create a whole different type of transportation infrastructure, he said.
The Trust for Public Land has put together a slate of projects to help conserve and protect natural areas around the country, and almost every initiative had bipartisan support, he said.
Brigitte Griswold, Groundwork Hudson Valley | NYCP
Community volunteers in Yonkers thought they were doing trash pick-up on a series of vacant lots, but then realized the lots were the former route of an abandoned railroad known as the Putnam that used to run from New York City all the way up to Brewster before it was discontinued in the 1940s, said Brigitte Griswold, executive director of Groundwork Hudson Valley.
“A piece of the old railroad was completely forgotten: a 2.2-mile route that was a spur off the main line that ran from New York City to downtown Yonkers,” she said. “And so we got involved with thinking about how we could convert these series of vacant lots into a green bike and walking pathway.”
The Yonkers Greenway wasn’t originally conceived as a green solution, but as an answer to crime and a way to revitalize economic activity in the neighborhoods where businesses were shuttered, she said. When completed within the next two years, the greenway will be a 15-minute bike ride to Manhattan and will also connect with the 242nd St. subway stop in the Bronx.
For over 12 years Sustainable Westchester has been developing the Yonkers Greenway to transform a disused railway into a green corridor to Manhattan. | NYCP
Meanwhile, the Center for Post Carbon Logistics is developing solar-powered boats to carry freight up and down the Hudson River, said Andy Willner, the center’s executive director.
“The schooner Apollonia is a freight sailing vessel that carries Hudson Valley goods to and from New York City,” Willner said. “Primarily their cargo has been grains and malted barley for beer and distilled spirits, but they also had their first interaction with a cross-oceanic sailing vessel.”
FERC ordered hearing and settlement judge procedures on Wednesday in response to industrial customers’ protest of PJM’s proposed revisions to its administrative rates (ER22-26).
The commission accepted PJM’s proposed tariff revisions for filing and suspended them for a “nominal period” to become effective Jan. 1 while directing the appointment of a settlement judge within 45 days and the issuance of a report on the status of the settlement discussions 60 days after that.
FERC said its initial analysis found PJM’s proposed tariff revisions may be unjust and unreasonable.
PJM’s proposal called for changing its administrative cost recovery from the current practice of initial charges at stated rate levels with a varying quarterly refund to the new practice of monthly rates based on that month’s costs and that month’s billing determinations.
The RTO said the proposal was developed in conjunction with the Finance Committee and is “specific only” to schedule 9 of the tariff, which provides cost recovery for its subsidiary, PJM Settlement, Inc. The company provides billing, settlement, treasury and credit management functions for transactions in the PJM markets. Other schedules recover costs for FERC’s annual charges, the Independent Market Monitor and other entities that benefit the PJM region.
The schedule 9 changes received unanimous support from the Finance Committee in July. PJM said the administrative rate review was initiated to examine “rate equity” across its membership to avoid cross subsidization among the different customer classes and for “overall revenue adequacy.”
The proposal “adjusts with changes in usage patterns” of the services that PJM provides and the costs of providing the services; it was designed to avoid over- and under-collection of funds to finance the RTO.
Stakeholders endorsed the proposal and tariff revisions at the September Members Committee meeting. The proposal was endorsed with a sector-weighted vote of 3.84 (76.8%), and PJM made a filing with the commission on Oct. 1. (See “PJM Administrative Rates,” PJM MRC Briefs: Sept. 29, 2021.)
Disagreements
The PJM Industrial Customer Coalition (ICC) protested PJM’s filing, arguing that the proposal was “not supported by any quantitative analysis or evidentiary support, such as a cost-of-service study.” The ICC said PJM did not provide any explanation for using the number of invoices as the new billing determinant for schedule 9, and that for industrial customers that have multiple accounts for multiple facilities in PJM, the “cost implications of the per invoice weekly charge is substantial.”
The ICC said one of its members will see costs increase by 385%, while PJM “has not demonstrated that the cost to serve industrial customers with multiple accounts/invoices has uniformly increased by that kind of magnitude.”
PJM said the “vast majority” of settlement costs are fixed expenses, “reflecting the resources PJM Settlement must secure to conduct its activities.” The RTO said “more than half” of the ICC members were charged “little or nothing” under the current system.
FERC said it needed fact finding to determine “whether PJM has justified its proposal to show that its per invoice approach comports with cost causation principles.”
FERC Commissioner Allison Clements partially dissented to the order, saying she would have also set a hearing on whether PJM’s cost transparency procedures are sufficient.
“Having previously participated in different RTO stakeholder processes, I appreciate the value of clarity in procedures related to ensuring transparency,” Clements said in her dissent. “I am not convinced based on the record compiled to-date that the procedures outlined by PJM will prove adequate.”
PJM last filed to update its administrative rates five years ago. In December 2016, FERC accepted PJM’s proposal to increase its stated rates over an eight-year period, with a 7.5% increase in 2017 and a 2.5% hike annually between 2019 and 2024.
The RTO said it required the rate increase at that time because its stated-rate revenues had fallen below the level needed to recover its administrative costs.
The Government Accountability Office (GAO) warned on Thursday that the federal government has yet to take “urgently needed” actions to protect the nation’s critical infrastructure, including the electric grid, from cyberattacks.
In written testimony to the U.S. House of Representatives’ Transportation and Infrastructure Committee, Nick Marinos, GAO’s director of information technology and cybersecurity, highlighted incidents such as the ransomware attack against Colonial Pipeline in May, which led the company to shut down its entire network, temporarily halting nearly half the supply of gasoline, diesel and other fuel products to the U.S. East Coast. (See Colonial CEO Welcomes Federal Cyber Assistance.)
While the Colonial attack demonstrated that cyberthreats targeting critical infrastructure are growing rapidly, Marinos said that “GAO’s recommendation to develop and execute a comprehensive national cyber strategy is not yet fully implemented.”
Marinos specifically noted the lack of follow-through on GAO’s March report that spotlighted the vulnerability of electric distribution systems to cyberattacks. (See Distribution a Cyber Weak Point, GAO Warns.) In that report, GAO observed that the Department of Energy had no plans to study the impact of a cyber threat to these systems, much less mitigate it.
Marinos said that although DOE “agreed with our recommendation” the needed actions had not been taken as of November.
He also criticized the federal government for neglecting its role in protecting national critical infrastructure. GAO has made multiple recommendations in this regard as well, which Marinos chided the government for not following. (See GAO Pushes Agencies for Action on Resilience.)
A major focus of Marinos’ 24-page statement was the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), established in 2018 to “[protect] federal civilian agencies’ networks from cyber threats and to enhance the security of the nation’s critical infrastructure in the face of both physical and cyber threats.” The Senate confirmed former Morgan Stanley executive Jen Easterly to head CISA in July. (See Senate Confirms Easterly as CISA Chief.)
GAO issued a report in March calling for organizational changes to CISA to address complaints about the agency from public- and private-sector stakeholders, including “lack of clarity surrounding its organizational changes and the lack of stakeholder involvement in developing guidance.” While these actions have not been implemented, Marinos said that DHS had “concurred” with them and plans to fully implement them by the end of next year.
GAO did win approval of its recommendation for creation of a National Cyber Directorate within the White House. The directorate’s first head, Chris Inglis, was confirmed by the Senate in June. (See Inglis, Easterly Define Roles in Confirmation Hearing.) Marinos called this an “important first step,” saying the cyber director can help coordinate the actions of various groups across government and perform oversight of their activities.
Nevertheless, Marinos warned that the October document — which lays out a vision for the office and high-level lines of effort including planning and incident response, budget review and assessment, and federal cybersecurity goals — falls short of a true national cyber strategy, which he called “more urgent than ever.”
The California Public Utilities Commission on Thursday adopted measures aimed at securing up to 3 GW of additional capacity through supply- and demand-side programs to prevent shortages in extreme heat waves in the summers of 2022 and 2023.
The measures include ordering the state’s three big investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to accelerate procurement of battery storage and to increase production from existing natural gas plants, as well as increasing payments to demand response customers.
The CPUC projected shortfalls of 2 to 3 GW during the next two summers, but PG&E, SCE and SDG&E have already procured 1 GW in response to earlier commission decisions, President Marybel Batjer said.
“While the gap is large, I want to be clear that there is already significant procurement that can be used toward this need,” Batjer said.
Measures approved in three decisions Thursday include:
expanding the use of a central procurement entity to ensure local reliability served by community choice aggregators and other load-serving entities;
doubling the payment to participants in the CPUC’s Emergency Load Reduction Program to $2/kWh and paying residential customers the same rate for reducing use during grid emergencies; and
funding a $22.5 million smart-thermostat incentive program “designed to reduce air conditioning a few degrees during emergencies” and creating pilot programs “to test the effectiveness of dynamic rates that change rapidly in response to grid emergencies.”
Other measures allow PG&E to install additional temporary gas generators and authorize SDG&E to build four new microgrid projects totaling 160 MW. (See CPUC Proposes Summer Reliability Measures.)
Since late 2019, the CPUC has directed the state’s IOUs to collectively procure more than 17 GW of additional capacity, including a June order for 11.5 GW of new resources to come online between 2023 and 2026. The rolling blackouts of August 2020 and energy emergencies the past two summers lent urgency to the efforts.
Thursday’s actions were taken in response to an emergency declaration by Gov. Gavin Newsom in July that said the state could face up to a 5-GW shortage this summer. A subsequent CPUC analysis found the shortage to be 3 GW at most.
The commission cited the potential for continuing high temperatures, wildfires and drought in the West as reasons for boosting the planning reserve margin in CAISO territory to 20-25% in the coming summers.
The state’s increasing reliance on solar power — which ramps down as the sun sets — adds to the challenge, the decision said.
“This perfect storm of reliability challenges requires urgent action now,” it said.
Two recently completed solar projects in rural Vermont demonstrate how one developer overcame higher development costs for brownfield sites to help meet state environmental and clean energy objectives.
Burlington-based Encore Renewable Energy built a 2.2-MW solar project on a closed landfill and a 2.3-MW project on a former gravel pit in Jericho, Vt.
“By using these otherwise underutilized or undevelopable pieces of property, we’re essentially preserving additional greenfield space,” Encore founder and CEO Chad Farrell told NetZero Insider. “In Jericho, that could be conservation to maintain the most carbon sequestration possible or that can be housing or other commercial or agricultural land use.”
Both brownfield projects were challenging, but building a solar array on a landfill has an additional level of complexity from a permitting perspective that also affects project costs, Farrell said.
To build on a capped landfill, a developer must assure regulators that construction will not harm the environmental remediation already approved for the property. That remedy, Farrell said, can be a soil cap, and it might include a geomembrane between the waste and the cap. “We have to demonstrate that we’re not going to cause any additional erosion … or settlement.”
Adjusting construction to accommodate the environmental needs of the landfill affects the project timeline and labor needs, which makes it more expensive to develop than other projects, according to Farrell.
On other sites, construction vehicles can drive onto the property with installation equipment, but that’s not possible with a landfill. “We have to use smaller Bobcat rigs that have lower weight and lower tire or track pressure, and that just takes a lot more time.”
In addition, foundation posts, which typically sit 6 to 8 feet into the ground, cannot penetrate the 3-foot soil cap. And the cap wouldn’t have the stability needed for structures to withstand high wind forces.
For landfills, Encore uses ballasted foundations that Farrell said have enough weight to distribute the downward force of the panels over a wide area. Foundations at the Jericho site, he said, are prefabricated tubs that were filled with cement in the field.
Incentives Needed
With higher overall development costs comes a higher price per kilowatt-hour, which makes developing brownfields a significant market challenge.
In the case of the Jericho landfill, however, the local utility wanted to work with the community and bring the clean generation into one of its higher demand centers.
“Vermont Electric Cooperative was willing to sign on to a slightly higher [power purchase agreement] price for the landfill project in order to meet the town’s objectives of reusing that site, while also addressing their requirements under Vermont’s renewable energy standard.”
By pairing the landfill and gravel pit projects, Encore was able to achieve economies of scale and bring down the overall PPA cost to the utility, according to Farrell.
The dynamics that moved the Jericho arrays forward to completion would not be possible for all the developable landfills in the state.
“If the only projects that are selected in any kind of statewide selection process are all about the lowest per-kilowatt-hour price delivered, landfills can’t compete,” Farrell said.
Brownfields, carports and rooftops are statutorily defined in Vermont as preferred sites.
“That’s where the general public would like to see these generation assets,” Farrell said. “We have to do a better job of incentivizing these types of projects.”
The Vermont Climate Council’s recently adopted Initial Climate Action Plan calls for incentivizing solar development in “already altered locations” and discouraging siting new generation in “intact ecosystems.” It also calls for regulators to design a 100% renewable energy standard by 2030. Farrell is a legislatively appointed council member. (See Vt. Climate Council Adopts ‘Initial Climate Action Plan’.)
Landfills can only be one part of what Farrell sees as “multiple tranches” for solar development to help meet the state’s energy and environmental goals. Some landfills are challenging in terms of scale and topography, he said.
“Older municipal dumps often were only 1 or 2 acres, and they were built like a mound of trash, so they have excessive slope for us to be able to deliver even the ballasted racking projects,” he said.
That means the state needs a “mix and match” approach for the size of sites and projects it authorizes, he said. In addition to residential- and commercial-scale projects, and medium-scale brownfields, Farrells said Vermont needs 5-MW and larger facilities that might require 30 acres of open space, for example.
The large projects are “where we can really deliver solar at the lowest price points possible, which, in consideration of ratepayer impact, has to be part of the discussion,” Farrell said.
