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December 22, 2025

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Knowledge Gaps Seen as Barrier to Vehicle Electrification

In the race to decarbonize the transportation sector, focusing on fleet vehicles, which account for only 3% of registered vehicles in the country, might seem insignificant. But a report by the Rocky Mountain Institute (RMI) says that a successful transition of fleets will influence the rest of the transportation sector.

“Large fleets drive scale, which results in reduced costs of vehicle technology and infrastructure,” RMI said. “And fleets have the market influence to help drive costly inefficiencies out of the system, resulting, for example, in streamlined permitting processes and prioritized utility interconnect processes.”

The think tank says more than 20% of all U.S. vehicles need to be electric by 2030 to limit climate change to 1.5 degrees Celsius, the threshold set in the Paris Agreement on climate change.

Progress in greening U.S. fleet cars is currently hindered by two significant knowledge gaps, according to the report, “Steep Climb Ahead: How fleet managers can prepare for the coming wave of electrified vehicles.”

While fleet managers know how to procure and maintain vehicles, they have little experience in building and maintaining the charging infrastructure for electric vehicles, RMI said. In addition, the organizations running fleets are not versed in utility rate structures.

Driving Without a Map

The report, which is based on a survey of managers responsible for large fleets, found that 81% of organizations have begun electrifying vehicles but that only about half of those have set explicit goals for transitioning their fleets. The report also said many organizations have not been planning for the charging infrastructure required to support their growing green fleets. In fact, investment by organizations has been upside down, going first to vehicles and then to charging infrastructure, where investment in infrastructure should be the priority. A lack of charging stations could act as a cap on EV adoption, the report said.

“Although many fleets have already implemented pilot programs — usually consisting of a few EVs and low-powered chargers, acquired at modest expense — electrifying a fleet at scale involves much more than just adding more EVs and chargers incrementally,” RMI said. “For many organizations, it will mean restructuring their internal business processes, including procurement, accounting, long-term capital project planning, fiscal budgeting, operations and more” to understand their return on investment and total cost of ownership.

The report says the charging infrastructure necessary to serve truck stops and fleet yards with medium- and heavy-duty trucks can take years to plan and build. It says some fleet managers may be surprised to learn that use of public chargers or Level 2 chargers (7.2 kW) will not suffice and that they will have to install more expensive direct current fast charge (DCFC) units (150 kW).

Of the total number of charge stations in the U.S., DCFC accounts for about 15%, according to the consulting firm EVAdoption. The RMI report said fleet managers planning to expand EV procurement need to begin talks with their utility “at least three years before they expect to actually need the power.”

“We strongly suspect that many fleet managers are in for some unpleasant shocks when they receive the first utility bills for their first set of DCFC,” the report added.

As a result, fleet operators will need “a much more extensive relationship with their local utilities,” RMI said. “And it will mean much more proactive involvement with city and county officials, including local building and planning authorities.”

The report recommends fleets consider “charging as a service” to navigate the complexity of managing vehicle charging around their duty cycles.

Wall Street Takes Notice

The growing infrastructure needs of EVs are attracting attention on Wall Street. Among those offering charging as a service is ChargePoint, which plans to go public next month. EVgo, which has more than 800 fast charging locations in 34 states, also is planning a public offering. And Royal Dutch Shell announced Monday that it is acquiring Ubitricity, the U.K.’s largest EV charging network, in a bid to diversify from fossil fuels.

Jonathan Levy, chief commercial officer for fast EV charger provider EVgo, told RTO Insider that the company is working with fleet managers “to inform their best path to convert their vehicles to EVs.”

Charging solutions will vary “depending on the particular use case,” Levy said.

A Solution Set

RMI’s findings of a knowledge gap among fleet managers are also echoed in a report prepared by the Center for Transportation and the Environment (CTE), released this month by the Federal Transit Administration (FTA).

The report summarizes the discussions of FTA’s Transit Vehicle Innovation Deployment Centers (TVIDC) Advisory Panel on the challenges of electrifying municipal bus fleets. Prior to the adoption of battery-electric buses (BEB), few transit authorities had experience working with utilities as suppliers of bus fuel, the report says. Similarly, utilities are still early in the learning curve of BEB technology and its infrastructure and power requirements.

“Both industries still lack answers for how best to affordably and effectively deploy large-scale electric charging infrastructure at existing transit facilities,” the report said. The learning curve issues were also the subject of discussions at CTE’s Zero Emission Bus Conference last fall. (See Takeaways from the Zero Emission Bus Conference.)

To alleviate costly surprises for fleet managers, the TVIDC panel suggested that an FTA-sponsored, cross-industry working group develop frameworks that help fleet owners and utilities with common issues, such as infrastructure scaling and installation; liability and equipment testing; and certification.

The panel also suggested that making a planning guidebook available to fleet managers could ensure they understand utility operations, power planning and rate-setting issues.

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NERC Opens Comments on CIP Changes

The standards drafting team (SDT) for NERC’s Project 2016-02 is accepting comments through 8 p.m. March 22 on proposed changes to the ERO’s Critical Infrastructure Protection (CIP) reliability standards that are intended to “incorporate virtualization and future technologies.”

Ballot pools are being formed through Feb. 19, and initial ballots and nonbinding polls will be conducted March 12 to 22. NERC is conducting a separate ballot and poll for each of the affected standards, so entities must join the pools for all of the standards on which they wish to comment.

Broad Scope for Proposed Updates

NERC’s Standards Committee approved the posting at its meeting last week. (See NERC Seeks Faster Pace for Standards Postings.) The standard 45-day comment period was extended to 60 days because of the project’s scope, with proposed revisions to 11 standards:

      • CIP-002-7 — Bulk electric system cyber system categorization
      • CIP-003-9 — Security management controls
      • CIP-004-7 — Personnel and training
      • CIP-005-8 — BES cyber system logical isolation
      • CIP-006-7 — Physical security of BES cyber systems
      • CIP-007-7 — Systems security management
      • CIP-008-7 — Incident reporting and response planning
      • CIP-009-7 — Recovery plans for BES cyber systems
      • CIP-010-5 — Configuration change management and vulnerability assessments
      • CIP-011-3 — Information protection
      • CIP-013-3 — Supply chain risk management

At last week’s meeting, NERC Manager of Standards Development Soo Jin Kim explained that the project had been “lying in wait for a little while” because of active comment periods involving some of the same standards; as a result of this delay, the SDT had more time than most teams to add more proposed changes to the inquiry.

“What we have before you today is work that has culminated after many months; the team has waited, and now they will put forth all of their modifications in this package before you today,” Kim said.

In addition to general commentary on proposed standards, the SDT posed 18 questions for industry respondents relating to specific changes. Significant updates include:

      • modifications to CIP-002 and CIP-005 expanding their scope to encompass virtual machines;
      • requirements regarding the types of software to be used when conducting vulnerability assessments before connecting physical or virtual cyber assets;
      • mandatory confidentiality and integrity protections for data passing between multiple physical security perimeters;
      • allowing cryptographic erasure in scenarios where BES cyber information “cannot be mapped to particular disks in virtualized storage”; and
      • applying CIP exceptional circumstances, which allow utilities to temporarily waive certain CIP obligations, to additional requirements in CIP-004, CIP-006 and CIP-010.

The team also put forward for industry comment a number of new, modified or retired definitions for terms in NERC’s glossary, along with the implementation plan for the revised CIP standards and definitions. Under that plan, the standards and definitions will take effect on the first day of the first calendar quarter that is 24 months after their approval by FERC, unless an entity elects to implement them earlier. The SDT asked respondents to suggest an alternate effective date if preferred, along with an explanation of the work and time requirements to justify the change.

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Biden Suspends Trump’s Bulk Power System Supply Chain Order

President Joe Biden has suspended a Trump administration rule that restricts the purchase of bulk power system equipment from foreign adversaries, putting in doubt the future of the measure even as the industry mobilizes to carry it out.

Biden ordered a 90-day review of executive order 13920 as part of a raft of executive actions carried out on his first day in office last week. (See Biden Begins Undoing Trump’s Legacy.) His orders included rejoining the Paris agreement on climate change, revoking the permit for the Keystone XL oil pipeline granted by the previous administration, and putting a temporary moratorium on oil and gas drilling in the Arctic National Wildlife Refuge.

During the 90-day suspension the secretary of energy and the director of the Office of Management and Budget are directed to “jointly consider” whether a replacement order should be issued. Biden has nominated former Michigan Gov. Jennifer Granholm and former Obama administration staffer Neera Tanden, respectively, to fill those roles. (See Dems’ Senate Gains Raise Hopes for Biden Agenda.) Granholm’s confirmation hearing in the Senate Energy and Natural Resources Committee is scheduled for Jan. 27.

Trump Order Cited Security Threats

Trump issued order 13920 last May, declaring a national emergency regarding foreign adversaries — a term defined as any foreign government or nongovernment person engaged in long-term or serious instances of conduct threatening the security of the U.S., its allies or its citizens. (See NERC Issues Level 2 Supply Chain Alert.)

The order banned federal agencies, citizens and companies from transactions involving BPS equipment developed or manufactured by an entity connected with a foreign adversary that:

      • poses a danger to the U.S. electric grid;
      • creates a risk of catastrophic effects to U.S. critical infrastructure; or
      • otherwise threatens the national security of the U.S. or the safety of its citizens.

The Department of Energy followed up Trump’s declaration with a prohibition order late last year barring utilities that supply critical defense facilities — defined by Congress as facilities that are “critical to the defense of the United States” and “vulnerable to a disruption of the supply of electric energy” from external providers — from buying certain equipment made by companies based in China. (See DOE Issues China BPS Equipment Ban.) That order took effect Jan. 16; affected entities are required to certify with DOE by March 17 that they have not entered such transactions and have processes to ensure future compliance.

NERC and the DOE both issued information requests in July in response to order 13920: NERC via a Level 2 alert seeking data on the exposure of the grid to foreign adversaries, and the DOE with a request for information on the industry’s practices for identifying and mitigating supply chain vulnerabilities for BPS components.

FERC Opens Supply Chain Cyber Risk Inquiry.)

Responses to the NOI indicated support from industry participants in general for the government’s efforts to limit the risks posed by foreign-manufactured hardware, but many expressed concern over the difficulty of rooting such equipment out of existing systems. (See NOI Responses Describe Supply Chain Challenges.) Utilities have also warned that overly broad supplier bans could hobble their ability to operate effectively.

“If we’re being told [we’re] only allowed to use one or two [suppliers] … [we] may not be able to fully support this industry,” said Mike Kormos, senior vice president of transmission and compliance at Exelon, during the National Association of Regulatory Utility Commissioners’ Summer Policy Summit last year. (See Industry Seeks Clarity on Supply Chain Orders.)

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UPDATED: Stakeholders Approve WEIS Market Launch

Stakeholders in SPP’s Western Imbalance Service (WEIS) market on Monday unanimously approved its Feb. 1 launch, the last major milestone in a project that began in 2019.

Bruce Rew, SPP’s senior vice president of operations, broke the news during the RTO’s joint quarterly stakeholder briefing, saying the grid operator is “excited” to be operating a power market in the Western Interconnection.

The WEIS Project leadership team, comprising the eight-member Western Markets Executive Committee (WMEC) and representatives from the Western Area Power Administration’s (WAPA) Colorado Missouri and Upper Great Plains West balancing authority areas, met with staff Monday to determine whether to transition from final system testing to a live marketplace.

Following the vote, WAPA tweeted its thanks to customers, stakeholders, SPP, fellow participants and employees “for supporting this monumental effort.”

SPP now joins CAISO in offering a power market in the Western Interconnection.

The vote on the launch had been delayed from Friday after some participants wanted more time to test the WEIS systems’ functions and interfaces.

David Kelley, SPP’s director of seams and tariff services, said last week that staff and stakeholders were trying to “button up some final loose ends.”

“Giving the weekend for some of that to occur would allow for greater confidence in the decision and the vote to take place,” Kelley said on Friday.

Market participants had asked for additional time to see bid-to-bill data with modeling changes they requested, an SPP spokesperson said. That led staff to extend parallel operations, with the WEIS market system running alongside the participants’ current systems, to Jan. 26. Parallel operations had originally been scheduled to end Jan. 14.

Staff has also identified seven “enhancements” that are in yellow status but deemed ready to be addressed after the WEIS market launches.

“We do have plans for those. They’re not problematic,” Customer Relations Manager Don Martin told WEIS stakeholders Friday.

SPP is managing the WEIS market on a contract basis for eight utilities. However, seven of those — Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, and WAPA’s Upper Great Plains West, Rocky Mountain Region and Colorado River Storage Project utilities — have said they are interested in becoming SPP RTO members. (See Western Utilities Eye RTO Membership in SPP.)

SPP also serves as an RC for about 12% of the Western Interconnection. It will add about 3.45 GW of generating capacity to its RC footprint — eight generating resources that are part of Gridforce Energy Management’s BA in Washington, Oregon, Arizona and New Mexico — effective April 1. (See SPP Expands its Western RC Footprint.)

MMU: No Frequent Constraints

SPP’s Market Monitoring Unit told a joint meeting of the WMEC and the Western Markets Working Group (WMWG) Friday that the WEIS market will begin operations without frequently constrained areas (FCAs).

The Monitor analyzed real-time data from Nov. 1, 2019, through Oct. 31, 2020, looking at Western Interconnection constraints monitored by the SPP RC. It found four areas, all in Colorado, with scenarios resulting in at least 100 binding hours.

It defines FCAs as the market footprint areas that both experience high levels of congestion and are associated with one or more pivotal suppliers. It says a supplier is pivotal when some or all of its output is necessary for reliable operations within a defined area.

The Monitor said it will re-evaluate the FCA “designations at least annually.”

Last 3 Open WRRs Approved

The WMWG and WMEC both unanimously approved the final three open revision requests to the WEIS protocols:

      • WRR17: adds documentation to outline how dynamic schedules used to transfer imbalance energy between the market’s balancing authorities will be handled in settlements.
      • WRR18: corrects the real-time loss adjustment factor’s description to accurately reflect its true calculation (“total BA state estimated load without losses/total BA state estimated load with losses”).
      • WRR19: corrects the settlement sign conventions to state that supply imbalance energy is positive and obligation imbalance energy is negative.
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Sierra Club Pans Utility Climate Efforts

Despite pledges to reduce emissions, many of the nation’s largest utilities plan to continue using coal and natural gas-fired generation through 2030, threatening efforts to mitigate climate change, the Sierra Club said in a report Monday.

The environmental group said U.S. utilities must eliminate coal and reduce greenhouse gas emissions by at least 80% by 2030 to limit global warming to 1.5 degrees Celsius (2.7 degrees Fahrenheit), the threshold many climate scientists say is crucial to avoiding the worst impacts of climate change.

“There are three key things utilities must do to enable us to avoid catastrophic warming: They must retire existing coal plants by 2030, terminate plans to build new gas plants and build clean energy much faster,” it said.

The study was based on a review of integrated resource plans and public announcements by the 50 utilities that hold the biggest fossil fuel generating fleets. The 50 companies, which include 79 operating companies, own half of all remaining coal and gas generation in the U.S.

“We find there is a stark difference between utilities’ existing coal and gas generation (1,310 million MWh) and how much clean energy they plan to add this decade (only 250 million MWh),” the group said. “In other words, despite 33 of these companies having a public climate goal, there is an enormous gap between utilities’ current practices and what they need to do to protect people and the planet.”

The companies in the study own 68% of remaining coal generation but have committed to retire only one-quarter of that capacity by 2030, the organization said.

The club noted that Duke Energy, Dominion Energy and Southern Co., which are responsible for more than 12% of the nation’s power sector carbon emissions, each have set corporate climate goals pledging to reach net-zero emissions by 2050. “Yet these companies’ investment plans include large amounts of new gas and lack adequate build-outs of clean energy. Duke and Southern Co. both score an ‘F’ in our analysis, and Dominion scores a ‘D.’ All three will miss their own decarbonization targets unless they change their plans.”

Southern Seeks ‘Orderly Transition’

Southern, which has promised to reduce its carbon emissions 50% by 2030 from a 2007 baseline, told RTO Insider that it was “embracing an orderly transition” of its coal fleet in a process that considers affordability, reliability, safety, environmental impacts and resilience. It said it expects 2020 to be the first time in modern history that the company obtained less than 20% of its generation from coal.

“In employing this robust and analytical approach, GHG emissions have dropped by 44% since 2007, and electricity remains affordable and reliable in our service territories,” it said. “We now expect to achieve our intermediate 50% reduction goal well in advance of 2030.”

Duke: ‘Critical Point’

Duke said the report “fails to recognize all the great progress we’re making.”

The company has pledged at least a 50% reduction in emissions from 2005 levels by 2030. As of 2019, the company says its reductions totaled 39%, putting it “well ahead of the industry average.”

“Our country is at a critical point in addressing the important issue of climate change,” Duke CEO Lynn Good said in a statement Jan. 19 supporting President Biden’s decision to rejoin the Paris Agreement on climate change. “At Duke Energy, we’re taking aggressive action to address this challenge while delivering affordable, reliable and increasingly clean energy. This is what our customers, communities and stakeholders expect from us and what we expect from ourselves.”

Dominion did not immediately respond to requests for comment on the Sierra Club’s critique.

The Future of Gas

The Sierra Club said affordability is not an obstacle to the energy transition, citing a study by Energy Innovation Policy and Technology and Vibrant Clean Energy that concluded local wind and solar could replace about two‑thirds of the U.S. coal fleet at a lower cost to ratepayers. It also noted a report by the University of California, Berkeley and GridLab that found zero-carbon sources could supply 90% of the nation’s electricity by 2035 while reducing costs.

While utilities have reached a consensus on phasing out coal — barring a breakthrough in carbon sequestration technology — the future of natural gas remains a subject of intense debate. (See Gas Going Way of Coal? Not So Fast, Panelists Say.)

Some utilities say gas-fired generation will be necessary for the foreseeable future to support intermittent wind and solar resources. Some 32 of the operating companies included in the study plan to build more than 36 GW of new gas capacity through 2030.

The Sierra Club acknowledged that gas plants’ direct carbon emissions are only half as carbon-intensive as coal-fired plants. But when upstream methane emissions from extraction, processing and transportation are included, “the climate impact of a gas plant is doubled,” the group said. “Overall, the replacement of coal generation by gas generation is not good news for the climate.”

“The scenario of building no new natural gas sounds simple, but it’s the most expensive option for our customers and actually requires coal units to operate longer,” Duke spokeswoman Erin Cuthbert said. “It also relies heavily on emerging technologies and could present challenges in reliability for the families, businesses and industries who rely on us.”

Duke last year said it would seek to reach net-zero methane emissions for its natural gas distribution companies by 2030 by eliminating cast iron and bare steel main piping; deploying technologies to increase its measurement and monitoring of methane emissions; and increasing leak surveys from every five years to every three years.

It said it is also directing its gas procurement for distribution and power generation “toward suppliers with low methane emissions, striking a balance between responsible procurement and maintaining affordability for our customers.”

Duke is a member of ONE Future, a coalition of 37 natural gas production, gathering, processing, transmission, storage and distribution companies working to reduce methane emissions to 1% of total production or less by 2025.

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California Energy Commission Updates Long-Term Forecast

The California Energy Commission updated its 2020-2030 forecast Monday to account for the slowdown caused by the coronavirus pandemic, increased electric-vehicle charging and a projected doubling of battery storage, among other factors.

Commissioners and staff members also paid tribute to Vice Chair Janea Scott, who is leaving for a post in the Biden administration.

In the annual energy forecast update, the anticipated amount of battery storage will double from the previous forecast of 1,300 MW to 2,600 MW by 2030, said Nick Fugate of the CEC’s Energy Assessments Division.

“Battery storage adoption is occurring rapidly,” Fugate said. “We see this just in examining the interconnection data.”

EVs are expected to proliferate and contribute to load growth over the next decade, he said. However, the economic impacts of COVID 19 have been “disrupting sales across all vehicle classes, EVs included,” he said.

The forecast assumes a recovery from those effects over time. It projects there will be 3.3 million zero-emission vehicles (ZEVs) on the road by 2030, mostly battery-powered.

The updated forecast did not account for Gov. Gavin Newsom’s order in September that all new passenger cars and trucks sold in California must be ZEVs by 2035, but the next forecast will include it, Fugate said. (See Can California Meet Its EV Mandates?)

EV charging will produce 14,000 GWh of new demand by 2030 under the current forecast, he said.

Lower growth in population, household formation, employment and income will reduce demand over the next three years, as will decreased commercial and industrial use of electricity, he said.

Forecasting is one of the CEC’s core responsibilities and lays the groundwork for procurement and planning at the California Public Utilities Commission and CAISO. The rolling blackouts in mid-August and close calls over Labor Day weekend caused the CEC to re-examine its forecasts as part of a root-cause analysis of the blackouts requested by Newsom.

Commissioner Andrew McAllister said the forecast would not have changed significantly because of the severe heat waves that partly caused the summer shortfalls.

“It really held up well,” McAllister said. The CEC, CPUC and CAISO remain focused on ensuring reliability this summer and beyond, he noted. (See New CAISO CEO Vows Urgency on Resource Adequacy.)

Scott Leaving

Commissioners and staff spent nearly 90 minutes at the beginning of Monday’s business meeting praising Scott, who is set to become counselor to President Biden’s nominee for Interior Secretary, Rep. Deb Haaland (D-N.M.). Monday’s meeting was Scott’s last.

Scott and most of her fellow commissioners have served together for the last eight years, working as a team to pursue the state’s clean energy goals, Chair David Hochschild said.

“It’s a bittersweet day for us because it’s really hard to lose you,” Hochschild told Scott. “You have been at the core of the commission and all that we’ve done together,” including allocating billions of dollars for cutting-edge energy research and development projects, he said. Scott led the CEC’s research and development portfolio, which includes the Electric Program Investment Charge (EPIC). “Everything you’ve touched, you’ve made better,” he said.

Scott, a well known figure in energy circles, served as deputy counselor for renewable energy at the Interior Department from 2009 to 2013 under the Obama administration.

“Her leadership was noticed … and she was recruited by Gov. Jerry Brown and his team to come to California,” Natural Resources Secretary Wade Crowfoot said. Few people have been “as consequential to the state’s energy vision over the last decade” as Scott, he said.

Her departure means Newsom now has vacancies to fill on the CAISO Board of Governors, the CPUC and the CEC — the three entities largely responsible for energy in California. (See CPUC’s Randolph Named CARB Chair.)

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ISO-NE Planning Advisory Committee Briefs: Jan. 21, 2021

Eversource last week presented the ISO-NE Planning Advisory Committee with plans for two projects that would replace copper conductor and shield wire and 345-kV structures at a cost of nearly $500 million.

The copper conductor and shield wire project would cover 673 structures in Connecticut, Massachusetts and New Hampshire at an estimated $311.1 million. The in-service dates on the project range from the second quarter of this year through the fourth quarter of 2023.

The 345-kV replacements include 567 structures in the same states at about $181 million, according to Eversource’s Chris Soderman, who put forward both projects to the PAC. The work is expected to take place this year and next.

Soderman said Eversource periodically tests samples of copper conductor and shield wire obtained from existing lines during repairs and maintenance. Both materials are susceptible to thermal degradation as well as deterioration because of environmental factors.

Recent test results indicate that outer copper conductor strands have visible verdigris and black oxide in addition to excessive elongation in some strands, potentially caused by overheating. There was also severe corrosion of shield wire, and copper conductors are no longer an industry standard, making spare parts difficult to obtain. Failure of copper conductor or shield wire presents a safety hazard and creates risks to the transmission system’s reliable operation.

Soderman added that Eversource transmission lines with copper conductor or shield wire tend to be old. Copper conductor has not been installed since 1960 and shield wire since 1990. Most of the company’s transmission lines containing these materials also suffer from other age-related deficiencies and deterioration such as wood pole asset condition issues, steel lattice tower deterioration and lack of secure, high-speed telecommunications infrastructure. Soderman said many of those issues could be addressed when performing the replacements. Ultimately, Eversource will replace 80.1 miles of copper conductor and 157.6 miles of shield wire.

One stakeholder questioned Soderman about Eversource spending hundreds of millions of dollars replacing 115-kV lines with lines of the same ratings as part of the project and asked if the utility is considering an upgrade to 345-kV lines for future grid needs. Soderman said the company is reviewing possible upgrades but is seeking to strike a balance between current and future grid needs. The utility is also awaiting results of the Future Grid Initiative reliability study to better understand projected grid needs. (See ISO-NE Provides Initial Feedback on ‘Future Grid’ Study.)

Eversource manages approximately 1,250 miles of 345-kV overhead lines and over 9,000 345-kV structures. The majority of the New England 345-kV system was constructed in the 1960s and 1970s, and the structures targeted by these projects are typically wood, single-circuit structures in an H-frame configuration. Eversource will replace 6.3% of its wooden structures with light-duty tubular steel poles. The new installations must comply with current clearance and strength code requirements.

Soderman said the use of drones in inspections has resulted in a significant increase in identified defects, which indicate substantial decay and decreased load-carrying capacity of aging 345-kV wood structures. High-definition cameras on drones allow inspectors to see possible damage from all angles and take better photos of insect and woodpecker damage, pole top rot, severe fracturing, and hardware and insulator damage.

Most of the work for both projects will take place in Connecticut, where replacement of 30.1 miles of copper conductor and 70.7 miles of shield wire will cost $151 million and cover 322 structures. The 345-kV replacements in that state will include 414 structures at the cost of $135.4 million.

New Chair

Peter Bernard, PAC chair since October 2016, will step down after February’s meeting to spend more time on other duties in the RTO’s system planning department, where he is the manager of transmission planning. Bernard joined ISO-NE in 2009, following more than 15 years with National Grid, and has been directly involved in implementing FERC Order 1000 practices and procedures for the RTO during his tenure.

ISO-NE is proposing Jody Truswell to fill the role of PAC chair, according to a  memo announcing Bernard’s departure. Truswell is a senior project coordinator for transmission service at ISO-NE and the project manager for all offshore wind interconnection requests. She would become chair for the PAC’s meeting in March.

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SPP Adds Decarbonization Future to 20-year Study

Acknowledging environmental and political realities, SPP staff and stakeholders have added an accelerated decarbonization future to the RTO’s 20-year long-term assessment.

Developed by the Economic Studies Working Group, the future is designed to reflect the change of administrations in D.C. and aggressive energy and environmental policy changes. It retires all coal and oil generation, driven by a 93 to 95% emission reductions target in 2042 from 2017 levels. Environmental regulation assumptions are based on changes in federal policy, mandated carbon cuts and a carbon tax.

The future, one of four in the 2022 20-year assessment, also assumes higher solar, wind and energy storage resource additions than SPP’s normal Futures 1 and 2 because of changes in environmental policy and technology that lower capital costs and increase energy conversion efficiency.

“It makes good sense for us to study these things, given the political implications and voluntary reduction measures in the footprint,” ITC Holdings’ Alan Myers, the ESWG chair, told the Markets and Operations Policy Committee during its virtual meeting Jan. 12.

“It’s extremely important to consider how fast and aggressive environmental policy changes will affect SPP,” said Casey Cathey, the RTO’s director of system planning. “We have companies that desire this; the political climate … all these variables are pushing the envelope of renewable energy more than we’ve seen the last few years.”

The accelerated decarbonization future assumes that by 2042 SPP will have 65 GW of wind capacity and 48 GW of solar capacity, with almost 17 GW of energy storage. The grid operator already has 26 GW of installed wind capacity on its system and another 39.9 GW of proposed projects are under some form of study in its generation interconnection queue.

Other Futures

The future was one of two added to the two futures developed as part of the 2022 Integrated Transmission Plan (ITP): a business-as-usual reference case (Future 1) that reflects continued industry trends and environmental regulations, and an emerging technologies case (Future 2) driven primarily by the assumption that electric vehicles and distributed generation will affect energy growth rates. Future 1 predicts 41 GW of wind capacity and 19 GW of solar, and Future 2 foresees 50 GW of wind and 27 GW of solar.

“These are good futures to extend out. We’re saving additional work on the overworked engineering staff,” Myers said.

The fourth future, the SPP-MISO zero hurdle rate (Future 4) focuses on the potential benefit of greater market efficiency between SPP and MISO. Future 4 sets hurdle rates between the two RTOs to zero, with all other input modeling assumptions the same as Future 3.

Both Future 3 and Future 4 assume a moderate increase in SPP’s load because of increased electric transportation and electric home heating, resulting in the grid operator become a winter-peaking RTO.

Asked how SPP could ensure a quality study when the overall peak load is just over 51 GW, Cathey said the model will adjust solar and wind around conventional resources, filling in the valleys when renewable energy drops.

“It’s not just a matter of looking at 51 GW as the overall peak load. It’s a process of doing the right siting,” he said. “What we’re ultimately trying to do is determine what actually will be built … and try to simulate that. We’re trying to get ahead of the game and not wind up with congestion costs.”

The ESWG developed the futures with input from the MOPC and the Strategic Planning Committee. They will be used to create the year 2042 market economic models that will be analyzed in the assessment.

Additional sensitivities will be performed and eventually scoped out by altering some of the futures assumptions, Cathey and Myers said. Some of the potential sensitivities include load, hurdle rates for exports, gas prices and retirements.

The MOPC unanimously approved the scopes of both the long-term assessment and the 2022 ITP, which adjusts the futures with several assumptions about fossil retirements, storage and renewable capacity. Futures 1 and 2 are weighted 50/50 in the 2022 scope.

Cathey promised a more robust report on the 2022 plan during the governance meetings in April.

STEP Down

The committee also approved the 2021 SPP Transmission Expansion Plan (STEP) report that lists the grid operator’s endorsed and approved transmission projects for a 20-year planning horizon. The current plan includes all ongoing network upgrades or those where construction has been completed, but not all closeout requirements fulfilled.

The current STEP’s value has been reduced to $3.2 billion from $5.2 billion in 2019 and $4.6 billion last year.

“That represents a lot of projects that have closed out,” Cathey said.

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California Lawmakers Focus on Building Decarbonization

Legislators in Sacramento introduced a spate of bills this session to ban natural gas from new construction, promote hydrogen as an alternative fuel source and increase demand response to head off future blackouts.

A number of bills deal with building decarbonization, including measures by Sen. Dave Cortese, a Democrat who represents much of Silicon Valley. Cortese introduced a package of measures to electrify public and private structures.

“California must commit to the rapid decarbonization of our buildings to remain a global leader in the face of our climate crisis,” Cortese said in a statement.

The bills he put forth would mandate that state buildings become carbon neutral by 2035 (Senate Bill 30), instruct state agencies to develop new building decarbonization standards (SB 31), and require all cities and counties to update their general plans with the aim to decarbonize buildings (SB 32).

Other decarbonization measures include Assembly Bill 33, which would ban new gas connections in public buildings after Jan. 1, 2022 and prohibit utilities from extending gas lines to new customers. The measure by Assemblyman Phil Ting, a San Francisco Democrat, was sent to the Assembly Committee on Utilities and Energy for consideration.

The move toward building decarbonization in California and other Western states is gaining momentum as state and local governments seek to reduce carbon emissions from natural gas furnaces, water heaters and stoves. (See Cap-and-trade Bill Emerges in Wash. Senate.)

Utilities such as the Sacramento Municipal Utility District are partnering with developers to build all-electric homes and communities.

More Calif. Measures

Additional 2021-22 bills deal with grid reliability after last summer’s rolling blackouts and the continued use of public safety power shutoffs to prevent electrical equipment from sparking wildfires.

Sen. Bill Dodd, a Democrat who represents Napa Valley and serves on the Senate Energy, Utilities and Communications Committee, introduced SB 99, the Community Energy Resilience Act of 2021, to require the state to implement a grant program for local governments to develop community energy resilience plans and ensure that a reliable electricity supply is maintained at critical facilities and in areas most likely to experience a loss of electrical service.

Another Dodd bill, SB 204, seeks to bolster demand response by large industrial users during times of tight supply, including by increasing incentives for curtailing energy use.

“The bottom line is that blackouts due to imbalanced supply and demand are completely unacceptable,” Dodd said. “We need to be proactive to prevent the risk of future blackouts.”

Sen. Nancy Skinner, D-Oakland, introduced SB 18 to boost adoption of hydrogen produced using renewable power sources such as solar energy.

“Green hydrogen offers many climate and energy co-benefits, including better utilizing curtailed power and better integrating renewable resources into the electrical grid to achieve greater than 100 percent zero-carbon energy and put renewable electricity to use to decarbonize many other sectors of the economy,” the bill says.

Skinner’s bill seeks a state “strategic plan for accelerating the production and use of green hydrogen” and recommendations on “how to overcome market barriers and accelerate progress in green hydrogen production and use.”

The fuel source is a potential competitor to battery-powered electric vehicles and could supplement natural gas in existing pipelines, advocates say.

Bills introduced in the 2021-22 session may fare better than energy-related measures in the previous session. In 2020, the start of the pandemic meant many bills died in committee as lawmakers stayed home or focused on measures to fight the coronavirus outbreak when they were in session.

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MISO Reevaluating Value of Loss Load as Monitor Pushes $10,000/MWh

MISO on Friday said it will soon present proposals for reformulating its value of lost load (VoLL) while its Independent Market Monitor once again urged the RTO to nearly triple the current value during a scarcity pricing workshop teleconference.

Monitor David Patton said MISO should bump its VoLL to $10,000/MWh from the current $3,500/MWh, an increase the Monitor has been recommending for more than three years.

Patton said different areas of the footprint place different importance on avoiding interruption of service. Referring to a Lawrence Berkeley Labs model with 2018 data, Patton said MISO residential outage costs range from $3,600 to $3,900/MWh depending on customer income, only “escalating modestly” from the current VoLL. However, commercial and industrial customers place a much higher value on interruptions, ranging anywhere from $32,000/MWh for a non-manufacturing customer to $73,000/MWh for manufacturers. He said commercial and industrial VoLL can go even higher, but those customers would probably have installed backup generation.

Patton said he weighted those amounts based on MISO load data to identify an average value of $23,000/MWh. However, he said the RTO should use a “more reasonable” and more economic $10,000/MWh.

“Very few shortages will occur in that range,” Patton explained of the upper bounds of the operating reserve demand curve (ORDC).

MISO’s ORDC based on VoLL, begins at $3,300/MWh, dropping to $2,100/MWh for much of the curve when the RTO clears 8% of its requirement level. At 89%, the level falls to MISO’s original $1,100/MWh, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200/MWh.

The Monitor is calling for a curve that eliminates step-based pricing in favor of a gently sloped descent from $10,000/MWh.

Patton said shortage pricing is important because MISO’s capacity market doesn’t provide sufficient performance incentives. He said the growth of intermittent resources, which lead to “more output uncertainty and more frequent shortages,” means economic reserve pricing will become more critical. Higher scarcity prices will provide a “natural buffer” for non-intermittent resources to stave off retirement, he said.

He added that a higher VoLL will better ensure that MISO can cover its load in shortage conditions, competing with PJM’s more attractive pricing.

“When both MISO and PJM are in a shortage, there’s no question that generators will sell to PJM, whether the generators are in PJM or MISO,” Patton said. “Certainly, it’s not completely solved. I think [this] will go a long way in ensuring our prices are more in line.”

Patton said even with the increase, PJM will still produce higher shortage prices more of the time.

FERC Filing on the Horizon

MISO Principal Adviser of Market Design Mike Robinson said the RTO is using the Monitor’s analysis as a “starting point” for updating pricing but must also account for the footprint’s geographic diversity.

The RTO has not updated VoLL pricing since 2009. Robinson acknowledged MISO’s reliability-based vertical demand and supply curve “do not meet” in a way that signals new, appropriate price ranges.

Director of Market Design Kevin Vannoy said MISO hopes to file an updated VoLL with FERC in June. He said staff will appear before the Market Subcommittee during spring meetings to discuss alterations and ORDC changes.

Some stakeholders said MISO was on an ambitious timeline considering it hadn’t yet decided if VoLL should apply to force majeure events or used to price dead buses. (See MISO Questions VOLL Pricing During Abnormal Events.)

“It just seems like MISO is going about reestablishing VoLL without first discussing where VoLL can applied,” Xcel Energy’s Kari Hassler said.

Great Plains Institute’s Matt Prorok asked MISO to consider the increasing electrification of essential services when valuing lost load.

“You’re right, those will affect the values,” Robinson said.

Akshay Korad, research and development engineer at MISO, said the RTO would have to update its LMP cap when it pursues a VoLL change because LMPs are capped at VoLL. Korad said the cap was a “design decision made at the beginning of the market that was never revisited afterwards.” He said MISO and stakeholders should decide whether to continue capping LMPs at the new VoLL or another value or stop capping LMPs altogether.