Page 402 – RTO Insider

October 7, 2022June 14, 2023

States Urge More Transparency on Tx Planning, Independent Monitors

State regulators and consumer advocates urged FERC Thursday to order the creation of independent transmission monitors and other measures to increase oversight over transmission owners’ planning and spending.

Multiple speakers at FERC’s daylong technical conference on transmission planning and cost controls said FERC action was needed to address an “information asymmetry” in transmission planning and the TOs’ increasing spending on local transmission projects that face little oversight (AD22-8).

In PJM, for example, transmission owners’ spending on local “supplemental” projects since 2014 has dwarfed that on baseline projects meeting regional needs, which are vetted through the RTO’s Regional Transmission Expansion Plan.

PJM baseline vs supplemental projects (PJM) Content.jpg

PJM transmission owners’ spending on local supplemental projects that face little oversight has dwarfed that on baseline projects meeting regional needs since 2014.

PJM

Independent Transmission Monitor

The commission heard from more than three dozen witnesses, many of whom said they supported the creation of independent transmission monitors to provide expertise enabling RTOs and state regulators to ensure their stakeholders’ transmission dollars are being spent most cost effectively.

Michael Haugh, director of analytical services at the Office of the Ohio Consumers’ Counsel, said consumer advocates don’t have access to enough information to ensure project costs are prudently incurred.

Robert Weishaar, McNees Wallace & Nurick | FERC

“We don’t know what we don’t know, and that’s a big issue. … We’ve found that more independence in these types of situations is better,” he said.

Haugh said an independent monitor would be particularly helpful in PJM for TO-proposed supplemental projects, where PJM’s only review is to make sure they do not harm reliability.

“We feel … an independent monitor would be able to look at these independently and see if there are competitive solutions that are better,” he said.

“Our view is that all transmission facilities over which the commission has jurisdiction should be planned by an independent transmission planner,” said Robert Weishaar, energy lawyer for McNees Wallace & Nurick, who represents industrial customers in MISO and PJM. He said an independent transmission monitor could have a standing set of engineers that could analyze and review projects from an objective standpoint.

Weishaar said for years there’s been a “somewhat artificial regulatory distinction” between local and regional transmission projects in terms of oversight, cost recovery and eligibility for competition.

Rhode Island Public Utilities Commission Chair Ron Gerwatowski | FERC

Rhode Island Public Utilities Commission Chair Ron Gerwatowski said someone “with the authority of the commission” involved at the start of a transmission planning process would create “a cost oversight which I believe does not exist in New England today.”

“It’s not so much the information because there are protocols that are put in place that are actually very helpful [to] anyone that has the expertise to look at it. But the question is, ‘Who’s looking at it?’” Gerwatowski said.

Gerwatowski said a monitor would introduce some degree of risk to today’s essentially no-risk rate system, which he said he believes is not FERC’s intent. “The way you recover transmission rates is: Spend the money; get the money. Spend the money; get the money,” he said.

Kentucky Public Service Commission Chair Kent Chandler said an ITM would provide benefits similar to that of independent market monitors in RTO markets.

Kentucky Public Service Commission Chair Kent Chandler | FERC

“I don’t think there’s anything, for instance, that the IMM in MISO or the IMM in PJM do to usurp state authority in relation to choosing our generation. … They provide us with an incredible amount of information in that regard. I can understand people saying it might be an extra layer of bureaucracy, but for many of these projects, it may be the only set of eyes [that would look at] the need and the planning. … I look at it as being an opportunity to provide any of us [regulators] evidence … an independent set of eyes who actually knows what they’re talking about.”

Henry Tilghman, speaking for the Northwest & Intermountain Power Producers’ Coalition, said regional independent transmission monitors would be more efficient than leaving the responsibility to states.

“The reality in the West is if you’re doing a regional transmission project, you’ve got four, maybe five, states plus probably a federal government agency, Bonneville Power Administration. And is it really more efficient to require each of those individual states to staff up to do that sort of independent analysis of the transmission proposals? Or is it more efficient to have a single entity who has the expertise who can provide each of the states consistent information about a proposed project? And I think it is.”

“We have an opportunity, I think, to manage the cost a lot better and the project activity as it’s being proposed,” said Randy Howard, general manager of the Northern California Power Agency. “Because right now, there’s just not a way for us to do that. … We just don’t get access early enough in the process to influence the prioritization of what’s important for reliability and resiliency. And obviously, through our wildfires and other activities, we’ve seen where some of our projects that we tried to impress upon those utilities that should be done earlier, weren’t done. And then consequences occurred.”

TOs Push Back

Witnesses representing transmission owners strongly opposed the ITM concept.

Carolyn Cowan Barbash, vice president of transmission development and policy for NV Energy, said an independent planner isn’t necessary in the West, where states are larger and regulatory processes are sufficiently transparent.

WIRES Executive Director Larry Gasteiger argued that sub-delegating the authority of FERC to independent transmission monitors would invalidate their independence. He said he was troubled by the expectation that FERC lend out its authority to a third party when the commission itself should have oversight authority over costs.

Charles Marshall, ITC Holdings | FERC

Charles Marshall, vice president of transmission planning for ITC Holdings, said his company offers a high degree of data visibility on its proposed transmission projects, no matter how small the price tag.

Also, he said, ITC cancels plans that internal reviews show are no longer needed.

“That’s not a tariff requirement; that’s something that we’ve committed to our stakeholders to do,” Marshall said. “We’re continuously internally reviewing the merits of projects that we’ve yet to commence construction on.”

Jeff Burleson, a senior vice president at Southern Co. (NYSE:SO), recalled an instance several years ago in which the utility was able to cancel a major transmission line it was planning through virtue of its vertically integrated structure.

Jeff Burleson, Southern Co. | FERC

“Effectively, all of our planners sit around the same planning table — generation planners, transmission planners, fuel supply planners — and we look at the alternatives,” he said. “And one of the alternatives we saw to this 90-mile, 500-KV line was siting generation close to the load.

“I don’t think an independent monitor would be helpful to us,” Burleson said. “I think it would just add an additional layer of bureaucracy.”

Attorney Jon Schneider, a partner in Stinson LLP who spoke on behalf of the Large Public Power Council, also expressed doubts about the ITM’s value in controlling costs.

“We have three institutions on the scene as we speak. We have [FERC], we have state commissions, we have RTOs and ISOs. And if we need a fourth institution, it does strike us that something’s sort of going wrong with respect to the oversight exercised by the folks that are already looking at this,” he said.

“If you improve the transparency of the processes, beef up staffs at the state and [FERC] and on the RTO level, we’re not sure that the ITM is cost beneficial with respect to cost oversight. We’re not unsympathetic to it … but we’re a little bit circumspect.”

Defining ITM’s Role

MISO Director of Expansion Planning Jeanna Furnish said FERC should consider whether it intends for an independent transmission monitor to be a one-stop solution and what its role will be in disseminating information, holding meetings and engaging consumer advocates and state regulators.

Furnish pointed to MISO’s ongoing long-range transmission planning effort, which considers a multitude of reliability needs.

“Is it actually appropriate to put all the eggs in one basket? … Are we talking about 350 projects and there’s capacity for this independent transmission monitor to think about alternatives for every single project? I mean, that’s a huge work effort,” she said.

“And that’s another question about how much would all of that cost,” Commissioner Willie Phillips agreed.

Commissioner Allison Clements said that while the set of responsibilities of independent transmission monitors is “not yet fully baked,” a monitor proposing alternatives to every single project “isn’t really the spirit” of what FERC is considering.

Robert Ethier, ISO-NE’s vice president of system planning, said an ITM could provide needed resources but that the model should not be that of the market monitors.

“There’s a need for more public planning ability, more public technical capability, but I’m not sure that an ITM reporting to [FERC] or … reporting to the ISO makes sense. If we have an ITM that reports to the states, I could understand that, because to me, what the states need are more resources to deal with the future. …

“We, in New England at least, are going to ask a lot more of the states going forward. We are going to look to them for guidance on public policy projects in a way that we never have before. And it frankly makes me nervous, the idea that they’re not going to have additional resources to help fill that role.”

Pallas LeeVanSchaick, vice president of Potomac Economics, the market monitor for MISO, NYISO, ISO-NE and ERCOT, said RTOs can’t be expected to provide independent oversight of transmission owners’ local projects.

“We’ve found that [RTOs are] extremely deferential to the concerns of the local transmission owners, and it’s just hard to see that they’ll be able to scrutinize things or ask questions or get them to look at alternative assumptions in the way that you would need,” he said.

FERC Authority Questioned

Glick asked Ari Peskoe, director of the Harvard Electricity Law Initiative and prolific social media commentator, whether he believes FERC has jurisdiction to require regions to establish independence reference monitors, joking, “[I] normally get great legal advice [from you] on Twitter.”

Peskoe said FERC has authority through Order 890, which was “intended to provide transmission customers and other stakeholders a meaningful opportunity to engage in planning along with their transmission providers.”

“There’s a lot of evidence that we’ve heard today and in the record, and as well as in the RM21-17 [Notice of Proposed Rulemaking on transmission planning] that that just isn’t the case right now. And so, I think an ITM could be a solution to that.”

Commissioner James Danly, who participated by phone and spoke little during the conference, disagreed.

“I’m not entirely sure that our jurisdiction is a complete, obvious case that we have the power to do these things,” he said. “I don’t see a whole lot about meaningful opportunities to engage in the Federal Power Act text. And even granting that we have the jurisdiction to do it, we still have requisite statutory showings where we have to show under [Section 206] that the rates are not [just and reasonable]. And applying universal solutions across every region — despite the actual rates that are the result in the planning processes — I think is probably violative of the statute’s requirements.”

Peskoe also said the commission could order monitors in non-RTO areas as well as organized markets. “The commission’s open-access rules apply to all utilities,” he said. “Assuming the commission believes it can still supplement its open-access policies, I believe they would apply to all utilities [and] transmission providers.”

October 6, 2022October 25, 2023

NYISO Installed Capacity Working Group/Market Issues Working Group Briefs: Sept. 30, 2022

Capacity Accreditation of ‘Performance-based’ Resources

Rensselaer, N.Y. — NYISO presented the Installed Capacity Working Group/Market Issues Working Group Sept. 30 with a proposed new technique for setting resource-specific derating factors for “performance-based” resources such as intermittent generation and limited control run of river. The new technique would be used in conjunction with capacity accreditation factors (CAFs) — a measure of the marginal reliability contribution of “representative” generators for each capacity accreditation resource class (CARC), a differentiation based on technology and operating characteristics.

Comparison of difference, ratio & NYISO’s proposed UCAP methodologies | NYISO

The CAFs, which reflect characteristics such as energy duration limitations and correlated unavailability due to weather or fuel supply limitations, will be used in conjunction with resource-specific derating factors that reflect the difference in a unit’s output from the modeled profile of the CARC.

The new proposal seeks to address problems with other proposed methodologies that the ISO said can result in distorted calculations of performance-based resources’ unforced capacity (UCAP).

This proposal is part of Phase 2 of the buyer side mitigation (BSM) rules that were accepted by FERC in May. (See FERC OKs NYISO Capacity Market Changes Stemming from NY Climate Law.)

NYISO’s proposed average capacity factor ratio approach can result in distorted winter UCAPs for resources that have smaller winter capacity factors than annual CAFs.

An alternative, the difference approach, can result in zero or negative UCAPs for resources with lower annual CAFs than average capacity factors in the winter.

To address the shortcomings of the two methodologies, the ISO proposed first calculating UCAPs for each performance-based resource under each approach and then assigning each resource the UCAP value that results in the closer alignment between the resource’s effective capacity value and its annual CAF.

The ISO said its testing of the proposed methodology using historical data from capability year 2021/22 concluded that the new approach removed the distorted winter UCAP values that would result from the use of either approach alone and provides reasonable values for all examined resources.

The ISO also made a presentation on a consumer impact analysis it is conducting on its capacity accreditation proposal. The analysis, which will focus on the 2030 resource mix, will consider the impacts on reliability, costs, transparency and environment and new technologies.

NYISO’s Tariq Niazi said the analysis will give stakeholders an idea of the “direction [and] magnitude” of the new methodology.

The ISO plans to present the results of the analysis at the Oct. 19 ICAPWG meeting.

Query on Transmission Nodes & TCCs

In response to a stakeholder inquiry, NYISO announced it is open to considering transmission nodes as the points of injection (POI) or points of withdrawal (POW) for future transmission congestion contracts (TCC) used to hedge congestion costs.

Transmission nodes are collections of designated load buses on which individual distributed energy resources (DER) are located, mapped, and may participate together in an aggregation.

The ISO publishes a list of valid POIs/POWs before each centralized TCC auction in Attachment E of the TCC manual. For the currently ongoing auction, the ISO lists more than 300 approved locations. The ISO also prohibits the use of certain POI/POW groupings, as detailed in Attachment F of the TCC Manual.

The ISO said it will not allow transmission nodes to be a part of a TCC in its initial deployment of the DER participation model approved by FERC and that it is not required for compliance with Order 2222. (See NYISO Discusses FERC Order 2222 Compliance.)

But it said it would consider allowing nodes as the point of injection or point of withdrawal for a TCC in the future if “presented with reasonable use cases.”

“The NYISO has not yet been presented with a productive use case for TCCs at transmission nodes,” it said.

Questions and suggestions about the proposal can be directed to Kirk Dixon (kdixon@nyiso.com).

Ramp Rates for Duct-Firing Generators

The ISO proposed to change its application of generator ramp rates (MW/min) to accommodate the 45 combined-cycle gas turbines (CCGTs) equipped with duct-firing burners, which inject additional heat to their steam cycles by burning fuel directly in the exhaust duct.

The change seeks to address a concern that the units may not be able to achieve their registered emergency response rate (ERR) when ramping through the high end of their capacity where duct burners are used. The 45 CCGTs have about 840 MWs in their duct burner regions.

The ERR, which is used for scheduling of operating reserves, is a single value that must be greater than or equal to all normal response rates (NRRs).

The new proposal would create multiple ramp rates for scheduling of 10- and 30-minute spinning reserves, reflecting the lower ramp rates seen during duct firing.

The ISO said this would be consistent with its energy scheduling rules, which use multiple ramp rates.

Testing has been performed to verify that 10- and 30-minute spinning reserves are accurately scheduled across multiple ramp rates and that the concept does not harm scheduling of other energy or regulation units.

The ISO is targeting the end of October to present a market design concept. Prototyping of the 10- and 30-minute spinning reserves participation limit will begin later in the year.

Ramp Limits on ‘Internal Controllable’ Lines

The ISO provided a justification for its proposal to limit ramping on “internal controllable” transmission lines (ICL) such as Clean Path New York (CPNY).

CPNY, a 1,300-MW high-voltage direct current line that will run 175 miles from Delaware County to Queens, is expected to be the first “internal controllable line” in the New York control area.

The NYISO says HVDC lines can ramp up and down quickly with some able to reach ramp rates greater than 1,000MW per second — a far cry from the 10-20MW per minute averaged by a typical 1,000-MW generator.

Such lines can also ramp down very quickly without a change in system generation or load. Without ramping limits, the ISO says, ICL flows can shift to parallel AC lines, potentially causing voltage to drop below operating limits or flows on AC lines to exceed limits.

The ISO said the proposed ICL ramp limits will allow operators time to adjust generator reactive and real output, switch shunt capacitors or implement phase angle regulator tap changes to keep AC lines within limits.

The ISO noted that external AC transaction scheduling interfaces and controllable lines operate under interchange ramp limits to prevent voltage problems.

It said the approach to setting limits would be similar to its implementation of the 15-minute scheduling under its coordinated transaction scheduling (CTS) with PJM, “proposing to start with conservative limits and increase ramp as operators gain experience.”

The ISO plans to discuss draft interconnection manual and deliverability tariff revisions with stakeholders through November and file tariff changes with FERC by January 2023.

October 6, 2022

CREPC Seeks to Become an OPSI for the West

TEMPE, Ariz. — The Committee on Regional Electric Power Cooperation (CREPC) is attempting to play a role in Western market formation like the one performed by the Organization of PJM States Inc. (OPSI) in the East, becoming a clearinghouse of information on organized markets and an adviser and advocate for states, especially those with understaffed utility commissions.

“One of the most pressing issues in the West today is the proliferation of forums in which market participants are developing and evaluating incremental steps towards regional electricity coordination — whether through energy markets, resource adequacy sharing, transmission planning or the leap to a full regional transmission organization,” regulators and representatives from 14 Western states wrote in a letter sent to the U.S. Department of Energy in July, urging funding for the CREPC effort.

Current regional market efforts in the balkanized West include CAISO’s proposed extended day-ahead market (EDAM) for its Western Energy Imbalance Market; SPP’s planned Markets+ program, which also includes a day-ahead market; the Western Power Pool’s Western Resource Adequacy Program (WRAP), a West-side RA initiative; and the Western Market Exploratory Group, a loose coalition of utilities assessing market options.

“Each of these efforts has multiple working groups with its own set of meetings,” the letter said. “State utility regulatory commissions and energy offices often do not have the staffing levels, expertise or organizational ability to meaningfully participate in each of these market conversations — or sometimes even understand what is happening and how state interests may be implicated.

“Individual states have been working — somewhat unevenly across the region — to commit more time to regional matters, but acting now to support a collective effort to improve awareness and coordination among states will improve the outcomes of these dialogues,” it said.

The Western Interstate Energy Board (WIEB), of which CREPC is a member committee, applied for $4.1 million in DOE funding to support the initiative to allow the committee play a greater role in educating and convening Western stakeholders as they weigh market participation.

“With support, WIEB could deliver a consolidated and consistently staffed forum for states to become educated on regional cooperation development considerations, to discuss issues among one another, and to inform or respond to emerging regional designs on an opt-in basis,” the letter said.

A panel at last week’s joint meeting of CREPC and the Western Interconnection Regional Advisory Board (WIRAB) weighed the potential for creating a regional committee for the West, similar to OPSI.

“With funding support from the U.S. Department of Energy, CREPC could deliver a consolidated and consistently staffed forum for states to become educated on regional electricity coordination, to discuss issues among one another, and to inform or respond to emerging regional designs,” the agenda item for the panel said.

CREPC, established in 1982, is a joint committee of WIEB and the Western Conference of Public Service Commissioners, informally composed of state energy office officials and utility commissioners, that works to improve the efficiency of the Western grid.

David Bobzien, director of the Nevada Governor’s Office of Energy, said on the CREPC-WIRAB panel that “I consider this to be the highlight of our proceedings. … It’s been a long time coming for this discussion. There have been various conversations swirling about the West in recent months about how best to position, shape, guide [and] facilitate the conversation around markets in the West. And this is a proposal for how to answer that question.”

Another panelist, Washington Utilities and Transportation Commissioner Ann Rendahl, called the DOE funding request crucial.

“Like many agencies and state commissions and even corporations, the Washington commission has lost some staff this year,” Rendahl said. “We’re trying to replace staff at a time when it’s very difficult to get new staff. We are resource-constrained, and having the ability for this provides CREPC as an organization to more fully support states and answer some of these questions about these key market developments and aspects of markets.”

She cited the comments of FERC Commissioner Mark Christie, who spoke in a prior session and emphasized the importance of a committee like OPSI as states wade into organized markets. Christie, a longtime utility regulator in Virginia, was a founding member of OPSI in the early 2000s as PJM grew into the nation’s first RTO. The current discussion in the West about establishing a similar organization to inform and advocate for states’ interests is a “critically important topic,” Christie said.

October 6, 2022

EPA Doubles IIJA Funding for Electric School Buses

EPA announced last week that it is nearly doubling the funds available from the Infrastructure Investment and Jobs Act for the Clean School Bus Program in 2022 to $965 million.

A first round of $500 million in May drew more than 2,000 applications from across the country. The agency said it “will move swiftly to review applications submitted and expects to issue a robust slate of awards” in the coming weeks.

The IIJA authorized $5 billion for the program over a five-year period, with the money going to provide rebates to school districts buying no- or low-carbon vehicles to replace their diesel buses. Funding for the program in 2023 will be $1 billion, EPA said.

“We’re working across all 50 states to accelerate the transition to a future where clean, zero-emissions school buses are the American standard,” EPA Administrator Michael Regan said. “America’s school districts delivered this message loud and clear: We must replace older, dirty diesel school buses.

“Together, we can reduce climate pollution, improve air quality, and reduce the risk of health impacts like asthma for as many as 25 million children who ride the bus every day,” Regan said, citing figures from the American School Bus Council.

The 2022 program guidelines prioritize applications from school districts in low-income, remote rural and tribal areas, and EPA said that “the vast majority of applicants met the priority definition … resulting in access to more funds for buses and electric vehicle infrastructure for schools in areas that need them the most.”

More than 90% of the applications were for “zero-emission electric buses,” EPA reported. Another 9% were for propane-fueled vehicles, and 1% were for compressed natural gas vehicles.

Districts chosen for awards will have to first order the buses and other infrastructure, and submit the purchase orders, to receive their rebates, EPA said.

According to a report from the World Resources Institute (WRI), 22 models of electric school buses are now available, and their efficiency and technology continue to improve. “Many manufacturers are on their second or third iteration,” all with ranges of more than 100 miles and some more than 200 miles, the report said.

The estimates on how much electric school buses reduce emissions vary. In Virginia, investor-owned utility Dominion Energy has partnered with school districts to begin transitioning their bus fleets, with 50 electric buses on the road in 15 districts. The utility estimates that each diesel bus replaced with an EV cuts emissions by 54,000 pounds per year.

Looking at lifecycle emissions — which take into account the source of electricity used to charge electric bus batteries — WRI found emissions reductions varied depending on location and the generation mix on the grid. Based on the U.S. average, lifecycle emissions for electric buses are about half those of diesel or propane-powered vehicles, but in New England, for example, the emissions for electric buses are about one third of diesel or propane.

Sen. Tom Carper (D-Del.), who chairs the Senate Environment and Public Works Committee, said, “Given the response to the availability of these [IIJA] dollars, it’s clear more funding is needed … to build on this progress so that more communities can realize the clean air and energy saving benefits of these cleaner vehicles.”

October 6, 2022

West Coast Leaders Pledge Closer Cooperation on Climate Measures

Leaders from the three West Coast states and the Canadian province of British Columbia signed an agreement Thursday pledging to cooperate on measures to combat climate change.

Meeting in San Francisco, the signatories included British Columbia Premier John Horgan, along with Gavin Newsom, Kate Brown and Jay Inslee — the governors of California, Oregon and Washington.

The non-binding memorandum of understanding outlines broad thrusts but is light on specific details.

Under the MOU, the four governments agree to invest in regional low-carbon transportation measures, including ensuring the installation of conveniently placed electric vehicle charging stations and hydrogen refueling stations along primary and secondary routes throughout their territories. The agreement stresses the ability for zero-emission vehicles (ZEVs) to travel along the Interstate 5 corridor from Canada to California. It also includes provisions for helping public and private institutions electrify their vehicle fleets and for increasing the use of low-carbon fuels.

The four governments also said they will coordinate how they establish standards for ZEVs and energy efficiency in buildings and work together to help cultivate markets for energy-efficient building materials.

“We know growing our economy and protecting our planet are not mutually exclusive goals,” Brown said.

The four leaders also pledged to improve forest thinning and anti-wildfire measures. “We have watched. We have smelled. We have suffered through the smoke,” Inslee said.

They also agreed to make climate a consideration in land-use planning and measures affecting the Pacific Ocean.

“In California, we punch above our weight when it comes to climate action, but our actions can only do so much without the rest of the world at our side. The Pacific Coast is raising the bar for tackling the climate crisis while also ensuring every community is included in our efforts,” Newsom said.

“Here on the Pacific Coast of North America, we’ve been on the frontlines of the climate crisis — both experiencing its most devastating impacts and leading the world in developing solutions to reduce carbon pollution,” Horgan said.

“We are going to collaborate with any jurisdiction in the world,” Inslee said.

The four Western leaders recently shared a virtual dais at the Cascadia Innovation Corridor conference, where they advocated for increased interstate and international cooperation on climate policy. (See Western Governors Talk Climate Change.)

October 6, 2022

DOE Seeks Public Input on Biden Manufacturing Order

The U.S. Department of Energy is seeking input from the public on how to use the authority that President Biden granted it earlier this year to improve power grid reliability.

In a request for information (RFI) issued Monday, DOE cited the president’s June 6 order invoking the Defense Production Act to “accelerate domestic production of” several “key energy technologies”: solar panel components; transformers and electric grid components; heat pumps; insulation; and electrolyzers, fuel cells and platinum group metals.

In an accompanying press release, DOE said that alongside the White House, it has “engaged with stakeholders on maximizing the impact” of the DPA authorities granted it, and claimed that Biden’s “commitment to growing clean energy that’s made in America” has led to billions of dollars in investments in solar, wind and battery storage facilities, along with electric vehicle factories.

Now DOE says the focus is on the risks to national security and defense, as well as grid reliability, posed by the fact that the production processes for many critical power grid components require materials sourced from overseas. The department cited the ongoing disruptions to global supply chains from the COVID-19 pandemic as evidence of the fragility of foreign supply chains, while the Russo-Ukraine War that has raged since February shows “the dangers of our overreliance on foreign sources for grid components and fossil fuels from adversarial nations.”

These crisis situations have arrived at the same time as the worsening impacts of climate change have led to an increasing incidence of hurricanes and wildfires. As a result, utilities have experienced “wait times [of] upwards of two years for grid transformers” that force stakeholders not only to postpone urgent repairs, but also to delay work on existing projects and getting new construction underway. (See Utilities See Challenges, Opportunities in Supply Chain Issues.)

The RFI covers all of the equipment mentioned in Biden’s June order except for heat pumps. DOE mentioned several possible approaches to improve U.S. supply chains such as direct purchases, purchase commitments and financial assistance. The department’s goal is “to understand further how to increase the manufacturing output and the rate of deployment of key clean energy technologies” by soliciting comment on:

technology supply chain challenges and opportunities;
domestic manufacturing, including small- and medium-scale enterprises;
investment in American manufacturing talent; and
energy equity, community access and economic benefit.

“The Defense Production Act provides us with a vital tool to make targeted investments in key technology areas that are essential to ensuring power grid reliability and achieving our clean energy future,” Energy Secretary Jennifer Granholm said in the statement. “DOE is eager to continue hearing ideas from industry, labor, environmental, energy justice, and state, local and tribal stakeholders about how we can best use this powerful new authority to support the clean energy workforce and technologies needed to combat climate change.”

Responses to the RFI must be submitted by 5 p.m. ET on Nov. 30.

October 6, 2022December 14, 2023

BOEM Report Clears Way for 1st California OSW Auctions

A new finding by the U.S. Bureau of Energy Management (BOEM) means California could see its first offshore wind lease auctions by the end of the year.

The agency on Wednesday issued a finding of no significant impacts (FONSI) on marine and human environments from “offshore wind energy leasing activities” in the Morro Bay Wind Energy Area (WEA), located roughly 20 miles off the coast of San Louis Obispo County, about halfway between Los Angeles and San Francisco.

BOEM’s environmental assessment (EA) of the WEA covers only the potential impact of the initial site “characterization” and “assessment” activities performed by offshore developers that are awarded leases for the three parcels within the area. Such activities could include surveys and extraction of core samples or the placement of meteorological buoys, the agency noted. The EA applies to the three parcels; associated rights of way, rights of use and easements; and the issuance of grants for subsea cable corridors and associated collector/converter platforms.

“The completion of our environmental review is an important step forward to advance clean energy development in a responsible manner while promoting economic vitality and well paying union jobs in Central California,” BOEM Director Amanda Lefton said in a statement. “We will continue to work closely with tribes, state and federal partners, and key stakeholders to ensure any future development avoids or minimizes potential impacts to the ocean and other ocean users in the region.”

But the agency pointed out that the FONSI does not apply to “the siting, construction and operation of any commercial wind power facilities,” which would be subject to a different process.

“If BOEM decides to conduct a lease sale in the Morro Bay WEA, the bureau will develop an environmental impact statement (EIS) before approving the construction of any offshore wind energy facility in the Morro Bay WEA,” the agency said in a press release. “That EIS will analyze the specific environmental consequences associated with the project, in consultation with tribes; appropriate federal, state and local agencies; and stakeholders and the public.”

The agency’s finding on Wednesday means that auctions for the three designated lease parcels within the Morro Bay WEA could proceed by the end of this year, in line with a schedule that BOEM offered in May when it announced a proposed sale notice for five lease areas off California, including two parcels in the Humboldt Bay WEA. (See BOEM Issues Proposed Sale Notice for Calif. Offshore Wind Areas.)

The Morro Bay WEA covers 376 square miles and is expected to accommodate up to 3 GW of wind resources.

October 6, 2022June 14, 2023

SERC Stresses Advantages of Design Basis Threat Process

Travis Moran, SERC | SERC

Travis Moran’s pathway into electric reliability was somewhat unusual, SERC Reliability’s senior reliability and security adviser recalled at the regional entity’s Fall Reliability and Security Seminar on Wednesday.

Unlike many people in the room, Moran began his career not as an engineer but in law enforcement, with stints at Interpol, the U.S. State Department, and the Bureau of Alcohol, Tobacco and Firearms.

His jump into electricity came after the attack on Pacific Gas & Electric’s Metcalf substation in California in 2013, when several gunmen opened fire on the facility, severely damaging 17 transformers. (See Substation Saboteurs ‘No Amateurs’.) Hired as an investigator by Dominion resources in 2014, he and his colleagues rapidly realized how little their years of experience had prepared them for the world they were entering.

“They hired [me], a former homicide detective from a big city, and an assistant chief of police,” Moran said. “We knew a lot about … evidence and security, but we didn’t know anything about electricity. So we found out the hard way: we stumbled into retention ponds; we had substation engineers slap our hands; we touched stuff we shouldn’t touch. … We learned the old-fashioned way, and quite frankly there is no other way to learn this industry.”

But Moran’s previous life in law enforcement proved an asset when the Electricity Information Sharing and Analysis Center tapped him to join the Physical Security Advisory Group, which created the Design Basis Threat (DBT) assessment in 2016. The DBT concept, which originated in the nuclear industry, is a tool to identify the intentions and capabilities of potential adversaries and determine appropriate, cost-effective defensive measures.

In his presentation Wednesday, Moran emphasized the advantages of conducting formalized, documented DBT assessments over the more ad-hoc way that many utilities responded after the Metcalf attacks. While these investments were, for the most part, based on legitimate assessments of security needs, in many cases the entities have not made use of them to the extent they might have hoped.

“Billions of dollars were spent on physical protection systems, and when we go out now, a lot of that stuff hasn’t been maintained, a lot of that stuff was unreasonable, some of that stuff may not have been needed,” Moran said. “Obviously some of it was, but … the reason you go through the DBT process is because … it helps you become knowledgeable about how you’re going to protect [yourself]. Number two, it helps save you money about what you do need to protect, what you don’t need to protect, and how to go about it.”

Threats Continue to Mount

The physical threat to the North American power grid has by no means slackened since the Metcalf attacks. As Moran noted, just this year a group of white supremacists pleaded guilty to plotting to destroy transmission substations in hopes of sparking a race war in the U.S. (See FBI: Conspirators Planned Grid Attack to Start Race War.) In such an environment, utility staff developing awareness of the threat landscape can achieve better results the closer their ties to law enforcement at multiple levels.

“I used to always teach my trainees … the only people that know what’s going on in the community really well are your state and local officers. They know the community, they know the informants, they know who the players are; they’re the people that you need to get in touch with,” Moran said. “So if you’re not talking to your local police department … you need to be talking to them because they can inform you.”

Moran noted that for utilities with facilities subject to NERC’s CIP-014-3 reliability standard, which governs physical security, DBT assessments are already a regular part of doing business because requirement R1 of the standard mandates that transmission owners “identify the transmission stations and … substations that if rendered inoperable or damaged could result in instability, uncontrolled separation or cascading.”

He strongly urged that those not covered by the standard make the practice a regular part of their operations anyway. Following a standard procedure will ensure both that utilities are aware of current and emerging threats, and that they have a strong documentation trail to inform all relevant parties in the case of emergency.

“Document, document, document what you did and how you got there,” Moran said. “Don’t be in the position of saying, ‘Well, we checked it, and we didn’t see any threats, or we didn’t see anything that mattered to us.’ Really? Well, when did you do it? What databases did you check? … Process that intelligence, and then you’ve got to produce it and disseminate it.”

October 6, 2022March 22, 2024

New England’s Gas Industry Frets About Cracks in Electric Side

FOXBOROUGH, Mass. — As New England’s gas and electric providers and regulators prepare for another dicey winter, gas industry representatives threw out solutions ranging from market fixes to upgraded pipeline infrastructure at a day-long gathering last week.

The Northeast Energy and Commerce Association’s Fuels Conference focused heavily on the fuel supply challenges that continue to bedevil the Northeast in winter.

ISO-NE recently said that the Everett LNG facility must be maintained for grid reliability, even past 2024 when its anchor tenant, Mystic Generating Station, is set to retire. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal).

That’s narrow-minded, argued an executive for one of the other LNG import terminals that helps brings gas into New England.

“The solution needs to be a market fix that resolves the mismatch between how LNG is contracted for and how generators are compensated, not another subsidy for a singled-out facility,” said Karen Iampen, vice president at Repsol, which operates the Saint John LNG terminal in New Brunswick, Canada.

She called the previous actions by ISO-NE “Band-Aids” that don’t address the region’s larger issues.

“Removing this obstacle to more long-term contracting is the most economic way to ensure fuel security by bringing in more cargoes that more fully utilize the storage and send-out facilities at the LNG terminals,” Iampen said.

Pipelines Want to Build Out

The other way to get more gas into the region is by land, and pipeline companies think that they’ll have a key role to play in New England even as renewables ramp up.

“Renewable growth requires operational flexibility,” said Jim McCord, account director at Kinder Morgan.

He pointed to California, where natural gas systems have helped back up rapidly growing renewable penetration by increasing or decreasing output when necessary.

“As an industry, natural gas will work hard to play this critical role in ensuring energy reliability,” McCord said.

Nobody is trying to build new pipelines to New England, but the existing ones could use upgrades, said Michael Dirrane, director of marketing for Enbridge.

“I’m advocating for brownfield pipeline projects, where we take out the smaller diameter pipe and replace it with higher diameter pipe, and perhaps add some additional horsepower on the system,” Dirrane said.

Those improvements would have minimal impact on the environment or to landowners, Dirrane said.

“That is the best way to drive down costs in New England.”

Tom Lockett of TransCanada said his company also is eyeing brownfield expansion.

LDCs Worried

Meanwhile, the utilities are increasingly concerned that reliability challenges facing the electric system in New England this winter could threaten the gas side, too.

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Elizabeth Arangio, director of gas supply planning for National Grid, said that the “dots are connected.”

“We don’t want anything to happen on the electric side,” Arangio said. “Certainly it will impact us.”

“It’s an unfortunate situation. It’s not a good situation,” said John Rudiak, senior director of energy supply for Avangrid (UIL).

He called it a “spillover risk” that in particular could affect low-pressure gas customers.

“There’s a risk that if there were rolling blackouts, when those blackouts are restored, the gas lines could [face] reduced pressure” if not managed correctly, Rudiak said.

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Eric Soderman, Eversource’s director of gas supply, echoed that fear.

“While the [local distribution companies] have adequately planned to serve their customers for this winter, as they do each winter, we have concerns that a cascading effect in New England could affect lower pressure areas on the pipeline that are extended laterals or don’t have backfeed areas,” Soderman said.

From the LDCs, the dominant feeling is frustration about how the electric side has been handled.

“The bottom line on this one is I feel comfortable about our companies, in terms of our preparation, in terms of our resources and our infrastructure and our capabilities,” Rudiak said. “But I’m really disappointed in [ISO-NE] not having solved the problems of market design and fuel supply reliability after so long.”

October 5, 2022December 22, 2023

Virginia Gov. Youngkin Releases 2022 Energy Plan

Virginia Gov. Glenn Youngkin (R) on Monday released an energy plan that focuses on developing still-untested carbon-free resources while calling into question the ability of current renewable technology to make up for lost capacity as the state shifts away from fossil fuels.

In a letter announcing the plan, Youngkin wrote that previous plans for the transition to cleaner energy were too rigid and followed an “either/or” mindset, whereas his plan seeks a “both/and” approach of expanding solar and wind while investing in other emerging technologies.

“In fact, the only way to confidently move towards a reliable, affordable and clean energy future in Virginia is to go all-in on innovation in nuclear, carbon capture and new technology like hydrogen generation, along with building on our leadership in offshore wind and solar,” he wrote.

While the plan lacks the power of law, it seeks to provide a framework for future policymaking through an assessment of the current state of the energy environment and a series of recommendations for each of its guiding principles: affordability, reliability, competition, innovation and environmental stewardship.

Some of the plan’s recommendations direct state agencies to complete studies on potential reforms, such as addressing cost overruns in utility infrastructure projects, although most of the proposals would require action from the General Assembly.
Democrats, who control the state Senate, are likely to oppose Youngkin’s efforts to roll back the previous administration’s policies.

The plan takes an especially strong stance on creating a hub of nuclear development in southwest Virginia, drawing on expertise fostered at the Norfolk Naval Base, where the nation’s fleet of nuclear submarines and carriers are maintained. It calls for a collaboration with government, industry and academic partners to work toward the deployment of a commercial small modular nuclear reactor within the next 10 years.

The “all of the above” approach detailed in the plan also promotes investments in developing carbon capture, utilization and storage technologies to lower the emissions of existing fossil fuel generation and industries, while building new industries in battery production and renewable energy, particularly the $9.8 billion Coastal Virginia Offshore Wind project.

Proven Technology

The plan received support from a broad coalition of business associations and energy companies who said it provides for affordable power while working toward a cleaner environment.

“Affordable, reliable, sustainable and secure energy from a diversity of resources is a necessity for Virginia’s economic competitiveness,” Virginia Manufacturers Association CEO Brett Vassey said. “The VMA is thankful that Gov. Youngkin’s energy plan recognizes that affordability and environmental responsibility are not mutually exclusive public priorities.”

The plan takes aim at actions undertaken during the administration of Youngkin’s Democratic predecessor, Ralph Northam, including passage of the Virginia Clean Economy Act (VCEA) of 2020 and the Clean Cars Virginia bill, which ties the state to California’s requirement that only zero-emission vehicles be sold after 2035, as well as participation in the Regional Greenhouse Gas Initiative.

The governor’s plan says that transitioning all new vehicle sales to EVs would eliminate consumer choice and strain the electric grid, particularly if done while the state is transforming the generation environment.

Kim Jemaine, policy director with Advanced Energy Economy, expressed surprise that Youngkin’s plan called for reauthorizing the VCEA every five years, contending that the law shares many of the same goals as his energy plan and a path toward achieving those goals through technological investments while also expanding proven and developable clean energy.

“Gov. Youngkin’s objectives of reliability, affordability, innovation, competition and environmental stewardship are all achievable within the framework of the VCEA. It’s unfortunate that the 2022 Energy Plan spends so much time disparaging the VCEA when that law offers a clear path to achieving the administration’s purported goals,” Jemaine said in a statement.

Requiring the law to be reauthorized regularly would also make it more difficult for businesses to plan for the future, particularly those which have made clean energy pledges, Jemaine said.

By remaining a party to RGGI and holding onto the clean cars standards, Virginia would also provide for an energy sector that is cost-effective, reliable and focused on environmental stewardship in a manner that aligns with Youngkin’s energy goals, she said.

“RGGI is helping Virginia transition towards a clean grid while strengthening our flood resilience and cutting Virginians’ electric bills with energy efficiency. The Clean Cars standards help ensure Virginia is a leading state in transportation electrification, encouraging innovation, cutting tailpipe emissions, and reducing our reliance on costly, imported oil,” she said.

Jemaine told RTO Insider that she sees some bright spots in the plan, including an emphasis on expanded offshore wind, increased competitive bidding by independent power producers and investments in future technology innovation — though she said that cannot come at the cost of also investing in proven clean energy today.

“What the energy plan does is it really emphasizes emerging technology like nuclear and hydrogen, and that’s fine, because those technologies may have a space in the future … in the meantime we have to invest in technologies that we already know to ensure that the grid is more stable, reliable and cost effective,” she said.