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November 2, 2024

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FERC OKs Transmission Swap Between Idaho Power, PacifiCorp

FERC on Thursday approved a transmission asset swap between Idaho Power and PacificCorp as part of the companies’ plans to develop a 300-mile-long, 500-kV line that will deliver Wyoming wind to the Pacific Northwest and hydropower to the Intermountain West (EC23-111).

In August, Idaho Power said it expected to begin construction work on the Boardman to Hemingway Transmission Project (B2H) this fall. The line between northeastern Oregon and southwestern Idaho is expected in service by June 2026.

The two companies said they sought the transfer to improve the alignment of their transmission assets with their load service areas after the Bonneville Power Administration dropped out as a partner in the B2H project.

Although Bonneville initially had proposed to participate in the project to facilitate service to wholesale customers in southeastern Idaho, it withdrew, choosing to take long-term firm transmission service from Idaho Power.

The transaction will give PacifiCorp 300 MW of west-to-east transmission capacity and 600 MW of east-to-west transmission capacity over the transferred facilities. Idaho Power will gain 200 MW of bi-directional transmission capacity over facilities through Idaho and more than 600 MW of capacity in the Goshen, Idaho, area to support network service from Idaho Power to BPA’s southeastern Idaho wholesale customers.

The commission concluded the transaction would not harm horizontal competition because it does not involve any generation assets and vertical competition would be unaffected because the transmission facilities involved will provide service under FERC-approved Open Access Transmission Tariffs. It also said the deal would not impact wholesale rates because the assets will be transferred at net book value with no acquisition premiums.

The commission conditioned its approval of the deal on the parties’ completion of a memorandum of understanding to address Utah Associated Municipal Power Systems’ (UAMPS) concern that the transaction could impact transmission service to UAMPS’ members in southeastern Idaho.

“We find that applicants have sufficiently addressed UAMPS’ concerns, provided that they follow through on their commitment to enter into the memorandum of understanding,” FERC said, ruling UAMPS’ request to be held harmless “moot.”

In a separate order, the commission also approved revisions to add the B2H project to Idaho Power and PacifiCorp’s joint ownership and operating agreement over transmission facilities in Idaho, Oregon, Washington and Wyoming (ER23-2463).

The B2H project will run between a new switching station near Boardman, Ore., and the existing Hemingway substation near Melba, Idaho. Idaho Power says the project, which it identified in its 2006 integrated resource plan, is the least-cost alternative for serving its customers in fast-growing southern Idaho and eastern Oregon. PacifiCorp said the line will aid its service into northeastern Oregon and provide a second connection between the PacifiCorp-East and PacifiCorp-West balancing authority areas, currently connected only by the Midpoint-to-Summer Lake 500-kV line.

Idaho Power said the project will connect two regions whose peak production of clean power is mismatched with their peak demand. The Pacific Northwest sees energy demand peak in the winter, driven by heating loads, while its peak hydropower production is in the spring and summer. In contrast, electricity demand in the Intermountain West peaks in the summer from irrigation and air conditioning loads, while its wind energy peaks in the winter.

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FERC Directs Arizona Utility to Allow Solar Project to Interconnect

FERC is moving to grant a solar developer’s request to force the Arizona Electric Power Cooperative to allow interconnection.

The proposed order FERC issued Thursday gives AEPCO and developer THSI 30 days to negotiate the terms. If FERC finds the terms acceptable, it will issue a final order reflecting them. If the two sides are unable to reach agreement, FERC will prescribe the terms, consider the two sides’ positions, then issue a final order.

Docket TX23-5-000 centers on the Three Sisters Solar Project, a 300-MW solar array with 300 MW/1,200 MWh of battery storage proposed in southeast Arizona by BrightNight and its subsidiary, THSI.

THSI formally submitted the interconnection request to AEPCO in November 2019. After multiple studies, the dispute arose. In May 2023, AEPCO notified THSI it had removed Three Sisters from the interconnection queue.

In June 2023, THSI asked FERC to direct AEPCO to provide interconnection, finalize the large generator interconnection agreement and restore Three Sisters to its position in the queue.

From early July to early September, AEPCO protested; three industry associations (American Public Power Association, Large Public Power Council and National Rural Electric Cooperative Association) sought to intervene, then also jointly protested; and THSI, AEPCO and the power authorities then filed successive arguments, protests and responses to each other’s filings.

FERC’s proposed order includes the following points and counterpoints by the two sides:

THSI said it originally proposed an Aug. 2, 2022, commercial operation date, then early this year proposed Dec. 15, 2025. It said AEPCO initially raised no concerns but on May 16, 2023, said the new date was a material modification that would necessitate a new interconnection study, and that Three Sisters had been removed from the queue.

Informal dispute resolution attempts were unsuccessful, THSI said.

THSI said all necessary interconnection studies had been performed and found no potential reliability issues and no significant need for network system upgrades. Further, the parties had already negotiated a large generator interconnection agreement.

So, there is little else to discuss, THSI said.

But AEPCO countered there are genuine issues of material fact because there is no certainty whether or how much Three Sisters would serve the wholesale market.

AEPCO said THSI’s initial interconnection request made no mention of something that later came up in a state environmental review: a co-located green hydrogen production facility that would be an off-taker for the solar power generated there. This makes Three Sisters’ grid output uncertain, it said.

But THSI has not secured the right to serve a retail load such as the hydrogen plant, AEPCO said, adding that an AEPCO member has state approval to provide power to the plant.

(THSI counters that there is no binding agreement with the hydrogen facility potentially to be built on site.)

AEPCO says there is no controversy over its willingness to interconnect with THSI, only over whether it must maintain THSI’s position in the queue.

AEPCO questioned whether the public interest is served by allowing a developer to hold an interconnection queue position for more than five years, potentially to the detriment of other developers, for a project that might provide only behind-the-meter power to an industrial end-use off-taker.

AEPCO also laid out multiple reasons it believes FERC lacks jurisdiction to consider the matter. (The power associations made similar arguments. THSI offered counterarguments.)

AEPCO asked FERC to dismiss THSI’s request with prejudice, preserve its right to update the studies and allow it to participate in evidentiary hearings if the matter is not dismissed.

In its proposed order, FERC explains why it does have authority to consider THSI’s request, then explains why it is granting the request.

FERC said it finds the public interest would be served by directing AEPCO to provide interconnection service to THSI because precedent holds that transmission availability enhances competition in power markets, which should result in lower prices for consumers.

A potential future hydrogen facility does not necessitate new interconnection studies, FERC said, because THSI has made no changes to its 300-MW interconnection request.

Nor is there any genuine issue of material fact that would call for an evidentiary hearing, FERC wrote.

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Market Monitors Endorse Call for Gas Reliability Organization

Market monitors from all of FERC’s six jurisdictional grid operators have endorsed calls for a NERC-like gas reliability organization.

The monitors sent the commission a letter Oct. 10 endorsing the recommendations from the North American Energy Standards Board’s (NAESB) Gas Electric Harmonization Forum, issued in July. (See NAESB Forum Chairs Push for Gas Reliability Organization.)

“In a time of unprecedented transformation, the reliability of the bulk electric system (BES) is increasingly dependent on the reliability of natural gas-fired generators,” the monitors wrote. “As noted in multiple forums, recent winter storm and summer heat events have highlighted that the electric and natural gas systems do not function in an integrated manner when needed most, resulting in the loss of hundreds of lives and over $100 billion in economic damage from the 2021 and 2022 winter storms alone.”

The letter was signed by PJM Independent Market Monitor Joe Bowring, SPP Market Monitoring Unit Vice President Keith Collins, CAISO Department of Market Monitoring Executive Director Eric Hildebrandt, ISO-NE Market Monitoring Executive Director David Naughton and Potomac Economics President David Patton, the market monitor for MISO and NYISO.

“We recognize that the report’s primary recommendation is that an optimal solution likely requires federal legislation that creates a NERC-like organization for the natural gas industry,” they said. “However, that outcome is uncertain. Given that uncertainty, we strongly support FERC’s past, current and future efforts to improve the reliability of natural gas-fired generators within the North American BES.”

FERC Chairman Willie Phillips highlighted the letter and its endorsement of the recommendations at the commission’s regular meeting Thursday.

“The primary recommendation of the NAESB report is the establishment of a NERC-like organization for the natural gas industry,” Phillips said. “And I welcome the support of all six independent market monitors, not only for NAESB’s recommendations, but their encouragement that FERC, quote, ‘take actions to use recommendations in this report.’ I could not agree more.”

The market monitors think gas-electric harmonization is a key issue that needs to be addressed, Bowring said in an interview.

“It’s essential to maintaining the reliability of electric power markets as we … transition to more renewables,” Bowring said. “We believe that gas is going to continue to be necessary. And it’s essential that to the extent possible, we get better information, more transparency and more coordination between the two industries.”

While the recommendations are national, Bowring said that they leave enough room for the different regional markets to adapt them to their specific needs.

“There needs to be somewhat different solutions, depending on the market, for sure,” Bowring said.

For instance, PJM currently has a lower level of renewables than most of the ISO/RTOs, but it is facing a very high level of expected coal retirements and that means even more gas will be needed, he said.

Bowring said the most important recommendations from NAESB center on transparency. In PJM, it would benefit to know when pipelines invoke their tariffs to require generators to take the same amount of gas at all hours — which impacts power plant’s ability to ramp up and down — and when they require strict adherence to their nomination schedules, because the gas trading day and power days do not align.

“One of the things that happened during Elliot was that PJM was not aware of these long nomination periods, and therefore they called on resources that couldn’t get gas because they hadn’t nominated it,” Bowring said.

Electric-natural gas harmonization has been a concern for years. Winter Storm Elliot last December was just one of five winter reliability events over the past decade that would have benefited from improved coordination. (See Déjà Vu as FERC, NERC Issue Recommendations over Holiday Outages.)

Although the years of talk have not produced enough changes, Bowring said he was hopeful the momentum around the issue would lead to substantive reforms this time. Dealing with the issue will involve both industries coming together to develop rules that are consistent with their relative incentives.

“The business models are somewhat inconsistent. But there have to be ways to coordinate,” Bowring said. “The idea is not to force anything on the pipelines, or force anything on the generators. But I think it’s in both sides’ interest to coordinate. For whatever reason, it hasn’t happened, and I’m hoping this is a wake-up call to both sides.”

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California Localities Work to Expedite Rooftop Solar Permitting

At least 44 California cities now have automated, real-time permitting systems for residential rooftop solar projects, following passage of a state law last year requiring them to adopt a permitting platform such as SolarAPP+.

Senate Bill 379, also known as the Solar Access Act, was passed to reduce approval times and permitting costs for residential solar and solar-plus-storage projects.

Turnaround times for residential solar permits have averaged two to three weeks and can often be longer than 60 days, Lucio Hernandez, energy specialist at the California Energy Commission, said during a CEC business meeting last month.

“That’s a long time to wait,” said Hernandez, who noted that the delays can cause homeowners to cancel their rooftop solar plans.

But with SolarAPP+, which was developed by the National Renewable Energy Laboratory (NREL), permitting for rooftop solar occurs in an instant.

Under SB 379, California cities with a population of more than 50,000 and counties with a population of more than 150,000 were required to adopt an online, automated permitting platform for residential solar projects by Sept. 30, 2023. Cities with a population of between 5,000 and 50,000 have until Sept. 30, 2024, to comply. Cities with a population of fewer than 5,000 and counties of fewer than 150,000 are exempt.

Implementing SolarAPP+ is one way to comply; permitting software from Symbium or custom in-house software platforms are other potential options.

SB 379 tasked the CEC with collecting solar-permitting data during the transition.

The larger jurisdictions with a Sept. 30, 2023, compliance date include 179 cities and 32 counties, according to a list the CEC provided to NetZero Insider.

As of Sept. 30, 44 cities and nine counties on that list had reported being in compliance with SB 379.

But more local governments may be complying than are shown on the list, CEC spokesperson Michael Ward said. That’s because annual reporting for many of the jurisdictions will start next year, at which time they’ll indicate whether they’ve implemented an automated permitting system and provide data on the number of permits issued. Jurisdictions aren’t required to report their compliance before submitting their annual reports, Ward said.

Varied Reasons for Non-compliance

Dave Rosenfeld, executive director of the Solar Rights Alliance, said reasons vary as to why many California cities with a Sept. 30, 2023, deadline are not yet in compliance. The nonprofit has been tracking California cities’ progress in adopting an automated, instant rooftop solar permitting process.

“Some are close and just dealing with some technical issues,” Rosenfeld told NetZero Insider. “[For] others, it is not clear what the holdup is.”

But more cities and counties are reaching full compliance each week, “so we’re hopeful that’s the trend,” Rosenfeld said.

Rosenfeld encouraged NREL and the CEC to provide as much technical support to local governments as needed, and urged elected officials to check with their building departments to see if they need help overcoming hurdles to streamlined solar permitting.

The transition to automated solar permitting got a boost from the CEC’s California Automated Permit Processing (CalAPP) grant program, launched in 2022. Cities and counties can apply for grants ranging from $40,000 to $100,000 depending on their population. As of last month, 315 grants totaling $17.5 million had been awarded, with $1.5 million remaining.

CEC Chair David Hochschild said that in contrast to the technology innovation the commission typically funds, the CalAPP money was going toward “administrative innovation.”

“But it’s more significant in many ways,” Hochschild said during the CEC’s business meeting last month. “A lot of projects do fall out because of these kind of delays.”

Data presented during the meeting showed the impact of SolarAPP+.

For example, median review time was about 15 days in San Luis Obispo, Calif., and more than 30 days in Tucson, Ariz. After deploying SolarAPP+, permit turnaround became instant in both cities. (See NREL’s SolarAPP+ Slashes Rooftop Solar Permitting Times.)

‘Extra Prodding’ Needed?

The CEC is aware that many cities are working toward compliance with SB 379, such as through participation in the CalAPP grant program.

But for some jurisdictions, the CEC is “not aware of activity” toward compliance. Those local governments “might need some extra prodding to get on board with SB 379,” according to Ward.

A list of those jurisdictions includes the city of Newport Beach, which had a Sept. 30, 2023, compliance deadline.

Newport Beach spokesperson John Pope said the city went live with SolarAPP+ this month and is now fully compliant with SB 379. A few permits have already been processed.

The CEC was also not aware of compliance activity by San Diego County. County spokeswoman Donna Durckel didn’t answer directly when asked whether the county is in compliance with SB 379.

Durckel said the county has an online process called Accela Citizen Access, in which applicants upload plans for new roof-top solar and battery storage projects. Applicants receive same-day or next-day review, comment or approval in 90 to 95% of cases. For the remaining projects, additional information is needed.

“Each year, on average, we’ve approved over 9,000 rooftop solar permits, offering online submittals and fee waivers, which makes the county of San Diego a leader in this area,” Durckel said.

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ICC Staff: More to Consider in Possible Ameren Illinois Exit from MISO

Staff from the Illinois Commerce Commission last week put their own spin on an analysis showing how much Ameren’s switch to PJM could cost MISO.

ICC staff said a previous study from Charles Rivers Associates (CRA) concluding it would cost Illinois more than $3.3 billion from 2025 to 2034 if Ameren were to leave MISO and join PJM needs more context for the commission to consider. They qualified CRA’s cost analysis with potential benefits that the consulting firm didn’t ponder.

The perspective was part of the ICC’s initial comments under the notice of inquiry it opened this summer over the potential benefits of Ameren Illinois quitting MISO to join PJM. (See Illinois Regulators Open NOI on Ameren MISO Membership.)

Ameren commissioned CRA to complete the analysis at the direction of the ICC last year.

ICC staff said as a state with a retail access setup, Illinois may be a “better fit” with PJM’s true capacity market than under MISO’s residual capacity auction with “serious design flaws” and “wildly” fluctuating clearing prices. They said MISO’s balancing market design only allows load-serving entities to purchase relatively small quantities of capacity and is best suited to vertically integrated states that “exert more control over generation and explicitly plan to meet their reliability needs,” not for Illinois’ reliance on competitive markets to determine resource expansion.

“Such an auction design is not complementary to Illinois polices and is a detriment to Illinois ratepayers. Staff acknowledges that MISO is taking steps to address issues with its capacity market. However, such efforts are still in the discussion phase and will likely not be implemented for some time,” ICC staff wrote, noting the importance of MISO adopting a sloped demand curve in its auction.

Staff said unless MISO corrects its Planning Resource Auction, it could lead to continued price separation in Southern Illinois’ Zone 4.

ICC staff also said benefits in the CRA study could have been contemplated on a longer-term horizon than 10 years since MISO itself uses 20-year future scenarios to plan transmission.

“Staff now believes that, while reasonable to assess initial impacts, this time frame may not capture all the benefits of new transmission over time and undervalues transmission assets,” staffers wrote. “… If the benefits of transmission are considered over a longer and more realistic time frame, costs that are prohibitively high in the Ameren study could potentially be mitigated.”

ICC staff said the CRA study discounts the reliability risks of Ameren remaining in MISO. They said MISO is set to experience significantly more solar and storage in its generation fleet than PJM. With that portfolio mix, MISO could more easily exhaust reserves during high demand sunrises and sunset periods, they said.

“Overall, the results point toward PJM having a more resilient system as compared to MISO, which would be a benefit in the join PJM case. This is a significant result and the inability of the MISO market to prevent unserved demand may be one of the primary reasons for considering a change in RTO participation,” staff said.

Staff said CRA might be overestimating the impact of increased capacity costs under the PJM market. They said although the PJM market’s sloped demand curve would cause Zone 4 to procure more capacity — at more expensive prices because of PJM’s annual capacity product — the higher capacity prices could incentivize developers to build new generation or owners to delay retirements and ultimately lower capacity prices.

Finally, ICC staff said the study also assumed that because of their interdependence on Ameren, all utilities in MISO’s Zone 4 will either stay in MISO or join PJM. However, staff said it’s not a given that City Water Light and Power and the Southern Illinois Power Cooperative will follow Ameren’s lead.

MISO declined to comment on the ICC staff’s opinion of market shortcomings. The grid operator similarly had no comment when the ICC opened the notice of inquiry.

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DOE Announces $3.46B for Grid Resilience, Improvement Projects

The five transmission lines in MISO and SPP’s joint targeted interconnection queue (JTIQ) portfolio are among the 58 grid resilience and improvement projects designated to receive a total of $3.46 billion in funding from the Infrastructure Investment and Jobs Act.

Announcing the awards during a Wednesday press call, Energy Secretary Jennifer Granholm hailed the funding as the “largest-ever investment in the American grid,” which would help to deploy 35 GW of new renewable energy projects — providing a 10% increase in renewable capacity — as well as 400 microgrids. Matching funds to the IIJA awards will bring the total investment to $8 billion, she said.

“Right now, the U.S. electric grid is the largest connected machine in the world. It’s 5.7 million miles of transmission and distribution, and about 55,000 substations; and it needs upgrading, clearly,” Granholm said. With the IIJA and the Inflation Reduction Act unleashing a “tidal wave of clean energy investment, the grid as it currently sits is not equipped to handle all the new demand. We need it to be bigger; we need it to be stronger. We need it to be smarter to bring all of these new projects online and to meet the president’s goal of 100% clean energy by 2035.”

Aimed at improving interregional connections and transfers along the MISO-SPP seams, the JTIQ projects are designated to receive $464 million — the largest single award made — which will put a major dent in the latest revised costs for the portfolio of $1.86 billion. Adjusted for inflation and other rising costs from the original project estimate of $1.1 billion, the revised price tag had raised concerns among stakeholders in the seven states involved: Minnesota, the Dakotas, Iowa, Nebraska, Kansas and Missouri. (See JTIQ Portfolio Cost Estimate Nearly Doubles to $1.9B.)

MISO and SPP have been collaborating with the Minnesota Department of Commerce and the Great Plains Institute on the project. MISO has estimated the projects will help to interconnect 28 GW of new, mostly renewable resources.

Maria Robinson, director of DOE’s Grid Deployment Office, praised the portfolio as a model. “My hope is that by this particular project showing what excellent planning and amazing cooperation and coordination across RTO lines can do that we will see more of those types of projects in future iterations.”

In a joint press release, Minnesota Commerce Commissioner Grace Arnold called the award “a historic opportunity to leverage federal clean energy funds to deliver reliable, affordable and safe energy that is increasingly generated by carbon-free and renewable energy resources.” The JTIQ will “expand our electric grid with new transmission lines and to reduce the burden of costs to utility ratepayers for adding those needed transmission lines,” she said.

Echoing Robinson, David Kelley, SPP vice president of engineering, said, “It’s tremendously exciting to think about what these funds will mean for the SPP and MISO regions, and for our industry. As our organizations worked together with our partners and with the DOE, it’s been our goal not only to create value for people living in our service territories, but also to model effective collaboration that spans the borders of states, utilities and grid operators.”

Real-life Effects

Wednesday’s awards are being funded under the Grid Resilience and Innovation Partnerships (GRIP) program, which received a total of $10.5 billion in the IIJA.

The program is aimed at enhancing grid reliability and resilience in the face of the increasingly extreme weather caused by climate change, while also funding innovative, “transformative” grid projects.

The $3.5 billion going to the 58 projects represent the first round of the funding, which drew about 700 initial applications, according to a senior administration official. About 300 of those applicants then were invited to submit full proposals.

The funding also will create good-paying jobs, DOE said in a press release, with about three-quarters of the projects partnering with the International Brotherhood of Electrical Workers. All projects also were required to have community benefit plans, a senior administration official added in a Wednesday press teleconference.

A second round of funding should begin accepting new applications before the end of the year, Granholm said. As with other DOE funding announcements, the projects selected still have to go through contract negotiations with the department before the awards are finalized.

The amounts range from $1.1 million to the municipal utility in Naperville, Ill., to install a distributed energy resource management system to $250 million for new transmission lines to connect renewable energy resources on tribal lands east of Oregon’s Cascade Mountains to Portland General Electric’s urban demand centers.

According to DOE, the Oregon project could bring 1,800 MW of clean energy from the Confederated Tribes of Warm Springs Reservation to PGE. The utility will also “deploy an artificial intelligence-enabled, grid-edge computing platform to improve the connection of distributed energy resources, such as solar, as well as informed modeling that can predict pre-outage conditions and assist real-time decisions,” the release said.

Clean energy advocates stressed the effect the funding would have on grid resilience and renewable energy deployment.

“As we learned this summer, a larger grid is a resilient grid, and the funding for planning and coordination from today’s grants will go a long way toward accelerating these efforts,” said John Moore, director of the Sustainable FERC Project at the National Resources Defense Council. The funding is “a critical step in [DOE’s] efforts to expand the capacity of the nation’s transmission system, increase connectivity between regions and add more clean energy.”

“This announcement shows how important building new transmission is to making the transition to a 100% clean energy grid across the country,” said Harrison Godfrey, managing director of Advanced Energy United. “The best use of public funds is to leverage [them] to unlock private sector investment and create new, good jobs across America.”

The Permitting Question

Besides being the largest, the JTIQ award also is the only one for interregional transmission lines, which are widely seen as critical for grid operators to begin interconnecting the 2,000 GW of renewable and storage projects sitting in their queues at present.

Other projects will provide intrastate HVDC lines, such as the Railbelt Innovative Resiliency project in Alaska, which will receive $206.5 million to bolster grid reliability in the state with the addition of an underwater HVDC line and battery energy storage.

Several projects also will deploy grid-enhancing technologies to increase power flows on existing lines. For example, the Electric Power Research Institute is partnering with the Vermont Electric Power Co. on a project that will use a technology called advanced power flow control, which can pull power from congested lines and redirect it to lines with excess capacity. The project grant is $18 million.

Electric cooperatives were well represented in the funding, with a range of projects focused on improving grid resilience in rural areas. In New Mexico, the Kit Carson Electric Cooperative is vulnerable to power outages from wildfire threats, drought and high winds. The co-op will receive $15.4 million to add battery storage and microgrids in key locations so it can, if needed, shut down its grid for public safety power outages to prevent wildfires while still keeping the power on for critical services in remote communities.

During the press call, a reporter asked about obstacles these projects might face with permitting, as any efforts at permitting legislation have ground to a halt with the House of Representatives still without a speaker.

A senior administration official said that, in general, the projects were developed with strong support from their state or local governments and other stakeholders. Many of them also will provide benefits to low-income, disadvantaged communities. A priority for DOE, the official said, was to choose projects that would be able to move forward quickly.

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ISO-NE Provides More Detail on Order 2023 Compliance

ISO-NE is pursuing an alternative compliance pathway on FERC Order 2023 regarding storage resource interconnection, hoping to sidestep the need for “control technology,” the RTO told the NEPOOL Transmission Committee on Tuesday.

The all-day meeting ran nearly two hours longer than scheduled because stakeholders had so many questions on the proposed “independent entity variation” the RTO said is allowed by the order, which FERC issued in July to revise its pro forma generator interconnection rules. (See FERC Updates Interconnection Queue Process with Order 2023.)

The proposed alternate approach would not require battery storage interconnection customers to install some kind of hardware or software preventing the battery from charging at times of elevated load. Instead, the RTO is proposing to “rely on security-constrained economic dispatch to govern the charging behavior in operations,” Al McBride of ISO-NE told the TC.

Order 2023 allows storage interconnection customers to indicate the conditions in which they plan to charge their resource, while requiring control technology to ensure that a resource sticks to its studied behavior, McBride said.

“ISO believes that this approach is inconsistent with ISO-NE markets and would introduce significant operating inefficiencies compared with a more straightforward approach that is available to the region,” McBride said, adding that FERC’s approach fails to account for the addition of other storage resources at the same location and may limit charging more than is needed.

McBride also responded to stakeholder feedback on ISO-NE’s proposed cluster study interconnection process. He said transmission owners should be required to attend the scoping meetings with the interconnection customers, clarifying the RTO’s position on the issue. Order 2023 does not require TOs to attend these meetings, but several stakeholders have pressed ISO-NE to make this a requirement, saying it would save time and money and reduce the need for restudies.

Liz Delaney, of renewable energy developer New Leaf Energy, presented the TC with some compliance proposals aimed at minimizing the negative effects on projects currently in the late stages of the interconnection process.

Delaney said late-stage interconnection studies that have a “reasonable chance” of concluding prior to the start of the transitional cluster study should be able to proceed until 15 days prior to the start, likely April 30. If the late-stage studies fail to meet the 15-day-prior deadline, the projects should be given the option to enter the transitional cluster, Delaney said.

“These are mature projects whose development timelines will be delayed if they are pulled backwards into the transitional cluster study, impeding the region’s ability to meet its clean energy goals on time,” Delaney said, estimating this would impact about 15 projects totaling 2,700 MW of capacity.

Delaney added that ISO-NE should increase transparency around cluster study and cost allocation methodologies; tailor study deposits to project size; and calculate withdrawal penalties for projects in the transitional cluster study based solely on its costs, instead of those incurred in previous interconnection studies.

ISO-NE’s compliance filing is due with FERC by Dec. 5, if it is not granted extra time. NEPOOL has requested a 45-day extension, which would push the deadline to Jan. 19.

Acting on Transmission Studies

Brent Oberlin of ISO-NE gave the TC a high-level outline of the second phase of the RTO’s Longer-Term Transmission Planning project.

The first phase of the study led to the 2050 Transmission Study, which looks to identify the transmission upgrades needed to meet the region’s anticipated 2050 peak load. (See related story, ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.)

ISO-NE is trying to streamline the process for the states to act on transmission needs identified in the long-term studies. Oberlin said the second phase of the process will establish “the rules that enable the states to achieve their policies through the development of transmission to address anticipated system concerns and the associated cost allocation method.”

Under the RTO’s proposal, the New England States Committee on Electricity would identify the transmission issues they want to address based on the findings of the studies. ISO-NE would then issue a request for proposals based on NESCOE’s requests and select the preferred solution. If needed, NESCOE would have the ability to terminate ISO-NE’s selected solution or submit alternate cost allocation methods.

Oberlin said ISO-NE is still considering whether some transmission projects should be assigned to the incumbent TO in the area, as opposed to going through an open RFP process.

ISO-NE hopes to file the necessary tariff changes with FERC in the second quarter of 2024.

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Robb Says Collaboration Key to Maintaining Cyber Vigilance

QUEBEC CITY — Speaking at the first panel of the Electricity Information Sharing and Analysis Center’s annual GridSecCon security conference in Quebec City, NERC CEO Jim Robb said that the Cybersecurity and Infrastructure Security Agency’s (CISA) Shields Up initiative, implemented prior to Russia’s invasion of Ukraine in 2022, has done a lot “to make cybersecurity accessible” to workers in the electric industry.

However, he added that the initiative also had “created a real problem,” raising the question: How long can the industry be expected to maintain the vigilance that the name implies?

“This industry typically keeps its shields up at all times. And at some point you’ve got to ask yourself, ‘When can we lower them?’ Well, we’ve never lowered them, right?” Robb said. “So I think one of the real challenges here is, how do you sustain the intensity, dealing with the very real fatigue that results from that intensity, and keep your cyber defenses fresh?”

The challenge is exacerbated by the fact that the cyber struggle is “just not a fair fight,” with owners and operators of electric infrastructure — predominately private companies — having to stand against adversaries that include actors backed by nation-states like Russia and China, along with financially motivated criminals. For the industry to resist such opponents, Robb said, its members must be able to rely on “extraordinary collaboration” with their peers and the government.

Robb’s fellow panelists, representing the public and private sector in both the U.S. and Canada, agreed that mutual support is key to building cyber resilience. This also is true outside the power industry. Nitin Natarajan, CISA’s deputy director, described a symposium the agency recently held with emergency responders in the Northeast U.S. to educate them about introducing cybersecurity into their communications.

Adding to Robb’s point about the evolving cyber threat landscape, Natarajan pointed out that ransomware attacks have become easier than ever because of the rise of the ransomware-as-a-service model, in which a core group develops and operates a ransomware package while recruiting affiliates to hack into networks and deploy the app. Groups using this model include DarkSide, which federal officials believe was behind the attack on Colonial Pipeline in 2021. (See Colonial CEO Welcomes Federal Cyber Assistance.)

“You no longer need to start up your own cyber terrorist organization to attack somebody; you can hire somebody to do it for you,” Natarajan said. “If you have Bitcoin and you have an enemy, you can attack somebody today.”

Panelists agreed that because the Canadian and U.S. electric grids are fully integrated, collaboration also must extend across international borders. Rajiv Gupta, associate head of the Canadian Centre for Cyber Security, said Canada’s government is working hard to establish a tough regulatory regime around cybersecurity.

The Critical Cyber Systems Protection Act (CCSPA), part of a major bill making its way through Parliament, is an important step toward ensuring cybersecurity within critical industries, Gupta said. The bill would create a “comprehensive regulatory framework” governing cyber systems in Canada’s critical infrastructure, giving the government the power to review and intervene in cyber compliance and operational situations.

While Gupta and the other panelists applauded CCSPA, they also said it is only “a step in the [right] direction,” acknowledging that more effort will be needed to ensure smaller utilities as well as larger ones can respond to the new requirements.

“The organizations with more money have very different cybersecurity postures than the smaller ones,” Gupta said. “And we have to make sure to close that gap between large and small, because … getting that harmonization, not just across standards and countries and organizations, but also addressing disparities between well-funded organizations and lesser-funded [ones] is super important as well.”

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Analysis Favors Wash. Linkage with Calif. Cap-and-trade Program

A decision by Washington to link its cap-and-trade program to one shared by California and Quebec should benefit participants in both systems, according to a preliminary analysis the Washington Department of Ecology released last week.

“Linkage would likely improve the [Washington] cap-and-invest program’s economic durability, longevity and efficacy,” the analysis found. “In a larger, more liquid market with a greater number of participants, allowance prices would likely be lower and change more predictably. Predictable prices can foster greater investments in decarbonization.”

Participants in Washington’s program would be able to more effectively perform long-range planning, increasing their readiness to pursue expensive investments in decarbonization, the report said.

Washington’s carbon allowance market now is slightly bigger than Quebec’s alone, but only 18% the size of the combined California-Quebec program.

The preliminary analysis estimates Washington’s market by 2025 — the first possible year the two programs could combine — would be just 16% the size of the California-Quebec system.

In its analysis, Ecology set out to compare the difference in outcomes between Washington maintaining a standalone program or entering the combined market — referred to as “linkage” in the report.

“The cap-and-invest program is designed to address the current climate crisis on three critical fronts: by reducing GHG emissions economy-wide, by creating a growing market for cleaner technologies and energy sources, and by funding environmental justice and climate resilience efforts in our state. These goals would not change in a linked market,” the report said.

To assess the effects of linkage, Ecology reviewed the relative size of the carbon allowance budgets for 2023-2026 for the two programs. Because of the significant difference in size, prices of the newly linked market should track those in the California-Quebec market at the time of linkage.

“Because Washington’s allowance prices are higher than those in the California-Quebec linked market at the time of writing, it is likely that Washington’s allowance prices in a linked program will be lower than if Washington’s program remains separate. However, the extent of any allowance price decrease, and the level at which prices may stabilize, are difficult to predict,” the report said.

Washington carbon allowances (WCAs) cleared at $63.03 per metric ton in a quarterly auction in August, compared with $36.14 in California. Critics — particularly Republicans — have blamed Washington’s cap-and-trade program for the state having among the highest gasoline prices in the U.S. this past summer. Gov. Jay Inslee (D) and other state Democratic politicians have accused oil companies of exploiting cap-and-trade to take excessive profits above the cost of complying with the programs. (See Inslee Challenges Cap-and-trade Role in High Wash. Gas Prices.)

‘Linkage-ready’

Ecology acknowledges the price impact of the program in making its case for joining the bigger allowance market.

“We have seen that businesses may elect to pass through their regulatory compliance costs to consumers by increasing prices — on gas and diesel, energy bills and other daily necessities — so the positive impact of lower, more stable allowance prices on Washington residents is extremely important,” the report said.

Economic modeling done last year indicated the price for WCAs could rise to $100 by 2030 before leveling off and declining in subsequent years as the state reduces emissions through decarbonization investments. The “pass-through” costs from such high prices could strain household budgets, the report notes. Linkage with the larger market would mitigate the rise in WCA prices, according to the analysis.

“Reducing this impact between 2023 and 2030 on consumers benefits all Washingtonians, and particularly helps lower-income residents, who spend a larger percentage of their income on necessities like food, transportation and home heating. Linkage, therefore, may not only help mitigate overall consumer cost impacts, it may especially lessen the impact upon vulnerable populations,” the report said.

Washington officials expect to decide late this month or early next whether to join the joint market. Joel Creswell, Ecology’s climate pollution reduction program manager, recently briefed the state’s House Environment and Energy Committee about the upcoming decision. (See Wash. Weighs Joining California-Quebec Cap-and-trade Program.)

If Washington decides to join the joint cap-and-trade market, the governments of California and Quebec will need to approve its membership. Although the Washington law authorizing the state’s cap-and-trade program required it to be “linkage-ready,” meaning key aspects of the two programs already are aligned, the linkage process still could necessitate regulatory changes in each area, the Ecology analysis said.

“If all three jurisdictions decide to link, California and Quebec would need to add amendments to their respective regulations to implement any potential linkage agreement. All three programs would need to complete their processes to adopt policy changes before our carbon markets could actually be linked,” the report said.

If the three jurisdictions agree to linkage, a final agreement likely would be signed in 2025, Creswell told legislators.

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ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B

Transmission upgrades that are needed to avoid overloads in a fully electrified New England by 2050 could cumulatively cost between $22 billion and $26 billion, ISO-NE told its Planning Advisory Committee on Wednesday.

The RTO emphasized that limiting the 2050 winter peak from the anticipated 57 GW to 51 GW would save the region about $8 billion in avoided transmission costs.

The projections were part of the results of ISO-NE’s 2050 Transmission Study, which was requested by the New England States Committee on Electricity in 2020. ISO-NE is now developing a process to better facilitate transmission infrastructure projects based on the findings.

The study focused strictly on thermal overloads on the system during peak load and did not include costs associated with interconnection, distribution, transient stability and other system needs. “The total transmission and distribution costs are anticipated to be much higher,” it said.

“Reducing the peak load can significantly reduce the transmission costs,” Reid Collins of ISO-NE told the PAC. The region could reduce this peak by either investing heavily in demand response, building insulation and heat pump efficiency, or by reducing the levels of electrification during the times of peak load, he said.

As a part of the study, ISO-NE identified a set of “high-likelihood concerns” that will need transmission investment. These include the need to increase transfer capability from Maine and New Hampshire into the Boston area, and to boost import capability into the regions of Burlington, Vt., and southwestern Connecticut.

ISO-NE outlined a set of potential solutions for each of these concerns, including the potential of an offshore grid to address Boston imports. The study also found that the region will likely need many new transformers no matter where the new loads appear.

“It may be worth looking into ordering some of these up front, not knowing exactly where they’re going,” Collins said, noting the long lead times associated with acquiring new transformers.

Some stakeholders expressed concern about the study’s assumptions about the amount of energy storage on the grid in 2050. The study projected that the region would have just over 5,000 MW of nameplate capacity by then, which Collins acknowledged seems to be a low-end estimate. He added that most of the new storage assessed was of four-hour duration.

“There is already more battery storage expected to be online by 2033 than the 2050 Transmission Study’s input assumption for 2040,” Collins said.

While the study assumed that all oil, coal, diesel and municipal solid waste resources would be retired by 2035, it also assumed a significant remaining role for natural gas, with almost 17,000 MW of nameplate capacity expected for 2050.

Economic Planning for the Clean Energy Transition

Also at the PAC, ISO-NE’s Patrick Boughan and Benjamin Wilson presented additional “sensitivity results” of the RTO’s Economic Planning for the Clean Energy Transition pilot study, modeling different scenarios following requests from stakeholders.

The scenarios included running the study without the electrification of heating and transportation, with nuclear retirements, and with biodiesel as a carbon-neutral stored fuel. (See ISO-NE Projects Decrease in Gas, Increase in Coal and Oil for 2032.)

ISO-NE found that added demand from transportation and heating would increase the cost to load by 114% compared to the no-electrification base model.

“Because the additional heating and electrification load peaks in colder conditions, the additional load likely requires more stored fuel generation,” Wilson said, noting these additional loads would greatly increase the expected need for oil generation, from 11 GWh to 834 GWh.

While ISO-NE anticipates that heating and transportation electrification would drive a 67% increase in electricity-sector emissions compared to the no-electrification scenario, Wilson noted that these emissions “are expected to be offset by emission reductions in other sectors.”

In the scenario modeling nuclear retirements, ISO-NE found they would drive increased solar and wind generation but also increase emitting generation, especially during the interim years of 2030 and 2040. During these years, the model showed that nuclear retirements would lead to “a significant increase in gas generation and emissions.”

In the biodiesel scenario, the RTO found that biodiesel — along with synthetic natural gas — would be a useful but expensive fuel for generation.

“Higher carbon prices or [renewable energy certificates] would be needed to allow carbon-neutral fuels to be utilized if they had to compete with existing emitting fuels,” Wilson said.

Asset Condition Projects

Kyra Lagunilla of Rhode Island Energy presented to the PAC on three proposed asset condition projects totaling about $88 million. Lagunilla said the projects are necessary because of deteriorating and out-of-date transmission infrastructure that has led to poor performance on the lines.

The proposed line rebuilds are:

    • the Rhode Island portions of the 115-kV M13 Pottersville-Jepson and L14 Bell Rock-Jepson lines, with a projected cost of $56.5 million and an in-service date of Q4 2025;
    • the 115-kV S-171N Woonsocket-Hartford Ave and T-172N Woonsocket-Hartford Ave lines, with a projected cost of $22.3 million and an in-service date of Q3 2026; and
    • the 115-kV E-183W Franklin Sq-Wampanoag line, with a projected cost of $10.6 million and an in-service date of Q4 2025.