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November 8, 2024

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SERC Stresses Advantages of Design Basis Threat Process

Travis Moran (SERC) Content.jpgTravis 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.”

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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.

Elizabeth Arangio 2022-09-29 (RTO Insider LLC) FI.jpgNational Grid Director of Gas Supply Planning Elizabeth Arangio | © RTO Insider LLC

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.

Eric Soderman 2022-09-29 (RTO Insider LLC) FI.jpgEversource Director of Gas Supply Eric Soderman | © RTO Insider LLC

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.”

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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.

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Duke Energy Estimates Net-zero Push at $145B in Next Decade

Duke Energy this week estimated the cost of its clean energy transition plans at $145 billion over the next decade, $10 billion more than its previous 10-year plan.

The majority of this investment in its seven regulated utilities — $75 billion — is projected to be for grid modernization. The rest would go to battery storage and zero-carbon power generation from solar, wind, hydro, nuclear and small modular nuclear ($40 billion); new natural gas generation and maintenance ($10 billion); natural gas distribution ($10 billion); and other expenses including coal maintenance, coal ash and corporate activities ($10 billion).

Hydrogen-enabled natural gas technology is included in the total, along with smart technology to detect potential problems and self-healing technology that limits the frequency and duration of power outages.

Walton Solar Power Plant (Duke Energy) Alt FI.jpgDuke Energy Kentucky’s Walton Solar Power Plants 1 and 2 in Kentucky came online in 2018. | Duke Energy

 

Duke said the 2023-2032 roadmap will support its efforts to reach more than 50% carbon reduction by 2030, 30 GW of regulated renewable energy by 2035 and net-zero carbon emissions by 2050. Its interim targets are 50% reductions in Scope 2 and Scope 3 upstream/downstream emissions by 2035 and an 80% reduction in Scope 1 emissions by 2040.

Specific 2050 targets include 28 GW of installed energy storage and 40% renewable power generation.

“These critical energy infrastructure investments will also provide substantial economic benefits, including job creation and tax revenue for essential governmental services in our regions,” Duke CEO Lynn Good said in a statement accompanying the economic and climate reports released Tuesday.

The economic report by consulting firm EY placed the direct and indirect benefit of Duke’s plans at 20,000-plus jobs created and $250 billion in output during the 10-year period.

To limit the impact of all this spending on its 8.2 million electric and 1.6 million gas customers, Duke said it is investing to lower the cost and volatility of fuel; leveraging clean energy tax credits; transitioning to renewables that generate without fuel costs; and making changes to cut the cost of storm restoration. The recently passed Inflation Reduction Act will further reduce customer costs, it said.

Factors that will control the pace of investment include scalable supply chains; grid planning; and federal, state and local approvals.

Duette Solar Power Plant (Duke Energy) Alt FI.jpgDuke Energy Florida’s Duette Solar Power Plant came online in 2021. | Duke Energy

 

Potential problem points include shortages of skilled labor or materials; slow evolution of numerous technologies that do not currently exist in scalable form; an insufficient or overly expensive supply of renewable natural gas; and site acquisition. For example, Duke’s proposed Carolinas Carbon Plan calls for 12 GW of new solar installed in the next 13 years, which by a conservative estimate of at least 8 acres/MW would entail a 96,000-acre footprint.

Finally, state regulators must allow Duke to recover the costs of its investments from ratepayers, the company said.

Through 2021, Duke had reduced the carbon emissions of its generating fleet 44% from 2005 levels, in part through what it said is the largest planned coal fleet retirement in the industry. Duke expects coal to account for only 5% of its generation mix by 2030 and be eliminated altogether by 2035.

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Western Markets Exploratory Group Shares Views

TEMPE, Ariz. — The Western Markets Exploratory Group made a rare public presentation of its work assessing the pros and cons of organized markets in the West, including an RTO, at the Sept. 29 meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB).

The group’s members include a loose coalition of some of the West’s largest utilities, but its work has taken place largely in private since it began meeting in summer 2021.

Arizona Corporation Commission Chair Lea Marquez Peterson introduced and moderated the WMEG panel, consisting of Arizona Public Service (NYSE:PNW) CEO Jeff Guldner, NV Energy (NYSE:BRK.A) CEO Doug Cannon and Bonneville Power Administration CEO John Hairston.

“There are many options for pursuing greater collaboration among utilities in the West” to promote reliability and economic benefits, Marquez Peterson said. “One option that’s been highly discussed is the creation of an RTO. I believe the regulators in this room would like to see an RTO, and certainly a great number of stakeholders would like to see that also.”

Questions remain, however, about whether an RTO “will really provide more benefits than less expensive options,” she said. In the meantime, “we should continue to investigate all opportunities for furthering collaboration between utilities and for strengthening our relationships with regulators in other states, like the approach with the Western Markets Exploratory Group.”

WMEG is weighing options that include: CAISO’s proposed extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM); the potential for CAISO to expand beyond California and become an RTO; SPP’s Markets+ program, a bundle of services that stops short of a full RTO; SPP’s plans for an RTO West, an offshoot of its Eastern Interconnection RTO; and the Western Power Pool’s Western Resource Adequacy Program (WRAP), a West-wide effort to ensure utilities have sufficient capacity to meet peak demand. (See CREPC-WIRAB Weighs Western Transmission, Markets.)

Guldner said WMEG members are interested in greater market efficiencies such as through CAISO’s EDAM. Large Colorado and Nevada utilities are under legislative mandates to join an RTO by 2030, he noted. And WMEG has talked with CAISO about the possibility of an RTO, but CAISO’s one-state governance remains a sticking point, he said.

“We began talking with the California Independent System Operator about … if we go to one large market, then we really need to address governance, because everybody was concerned about a California-dominated governance in a West-wide market,” Guldner said.

“There are other options, and I just want to make one point really clear. None of the options would involve the rest of the West not trading with California,” he said. “The question is just how that trading will occur. California has a massive load sink [that’s vital] for our generation to be optimized. It’s just whether that would be done directly as part of the California market or whether it would be done through seams agreements between two RTOs.”

SPP’s planned RTO West is another possibility, Guldner said.

WMEG was established to develop a “roadmap” for the West “up to and including a full RTO formation,” with cost-benefit analyses for various options, he said. It now involves 25 entities, including Idaho Power, the Los Angeles Department of Water and Power, Public Service Company of New Mexico and the Western Area Power Administration. (See Western Utilities to Explore Market Options.)

BPA Viewpoint

BPA joined WMEG this year to get a broader understanding of “what’s happening in [Western] markets,” Hairston said. “We come to this discussion with about three-quarters of the high-voltage transmission in the Northwest, so quite honestly, any discussion about an RTO [or other organized markets in the West] has to involve Bonneville Power.

“We understand that, and we accept that responsibility,” he said. “The thing is that when I come to these conversations, I’m bringing 140 some-odd customers with me, and so if you can imagine trying to pull all those different perspectives together and get us on one path, that’s also challenging.”

BPA began participating in the WEIM earlier this year and is seeing positive results from its first foray into an organized market, he said.

Now it is paying close attention to what’s happening with the WRAP as it gets closer to starting operations, Hairston said. The program has signed up 26 participants, representing much of the Western Interconnection, notably absent CAISO. (See Western Power Pool Board Approves WRAP Tariff.)

“The next step for us really is looking at how we develop a resource adequacy program for the West,” Hairston said. “And I think what’s happening in the Western Power Pool [with WRAP] is exactly what we need. We’re seeing the development of an independent governance structure, which I think could be the template for any other types of governance structures that we need as we entertain other markets. So, I’m really encouraged about what I’m seeing.

“Where else have you seen all of these utilities across the Northwest come together in this transparent nature to set up a program that’s going to benefit all of us?” he said. “I think that in itself is an important step. I’m really glad to see that collaboration, and I think it is going to yield some positive results.”

BPA next will join a day-ahead market, whether it is CAISO’s EDAM or SPP’s Markets+, and that could determine its eventual RTO membership, he said.

“Once you get into that extended day-ahead and you make those additional investments and that structure is developed, it’s going to be really challenging to move after that,” Hairston said. “And so, we have to get this next step right because that next step, I think, is really the foundational piece for an RTO.”

“I think at the end of this thing there will be a Western RTO, [but] how [that looks] still remains to be seen,” he said. “Is it one? Is it two? Those things have to be worked out, and that’s going to have a lot to do with the qualitative piece: governance structures; how comfortable entities are in the development, whether it’s through CAISO or SPP. You have to be comfortable with the governance structure you have and how you participate.”

The other piece is quantitative, he said.

“There’s a lot of discussion about the efficiencies gained under one Western RTO as opposed to maybe having several different [organized markets], but from my perspective, we really have to think about what is gained through some incremental efficiencies if the governance structure isn’t what you want,” Hairston said.

“So those are the types of questions we’re trying to tackle, and I think WMEG allows us to work with a number of important utilities, understanding their perspective on the issues and making sure that we’re factoring in all of the considerations as we make decisions and work transparently with our customers in making that decision,” he said.

NV Energy Comments

Nevada’s largest utility, NV Energy, was an early participant in the Western Energy Imbalance Market and has had a positive experience, CEO Cannon said.

The market has produced more than $2 billion in benefits for its participants since it started in 2014.

“Now, as we step forward into what’s next in the state of Nevada … our thinking on market development [is motivated by] … what option we believe is going to be best for Nevada,” Cannon said.

The state has plenty of solar power, like its neighbor California, as well as similar summer peaks, he said. Partnering with California won’t be enough to deliver the diversity of resources — including hydropower from the Pacific Northwest and wind from Wyoming and Idaho — that Nevada needs to decarbonize its energy supply by 2050, as state law requires, he said.

Keeping ratepayer costs down while building infrastructure is another important consideration and will require market efficiencies to drive down energy prices, he said — a point also made by APS’ Guldner. And NV Energy is working under a state mandate to join an RTO by 2030, he said. All are factors the company has to consider when deciding what markets to be part of going forward, he said.

“That’s really what prompted us to look at an organization like WMEG,” Cannon said. “Now we’re up to 25 participants. We have 95 GW of peak load represented in that organization. We have geographic diversity. We have resource diversity. We have time diversity, so it starts to check a lot of those boxes that I talked about before,” he said. “And so, I think it is a very useful organization to help us do some assessment … to understand what is ultimately the best outcome for investors.”

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MISO, PJM Down to 2 Possible TMEPs

MISO and PJM halved their shortlist of potential smaller interregional transmission projects down to two but warned that even those project benefits might be too small to proceed.

The RTOs staffs presented the two contenders Monday during MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC). The potential targeted market efficiency projects (TMEPs) are line work on the Powerton-Towerline 138-kV flowgate in central Illinois and a potential fix for the congested Chicago-Praxair 138-kV flowgate near the Chicago area. (See MISO, PJM Consider 4 Small Interregional Projects.)

The grid operators studied 23 flowgates accounting for $328 million of congestion costs during 2020-21 in this year’s TMEP process.

PJM’s Nick Dumitriu said analysis is still underway and said the two remaining projects won’t necessarily be eliminated. He said the RTOs are still comparing anticipated project costs against the first four years of estimated project benefits.

“It’s premature to say there won’t be a TMEP,” he said, predicting that “at least” one project could still be recommended to the RTOs’ respective boards of directors by the end of the year.

Stakeholders have asked the grid operators to consider raising the $20 million TMEP cost threshold given continued inflation and supply chain issues.

TMEP projects must cost less than $20 million, completely cover installed capital cost within four years of service, and be in service by the third summer peak after their approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

MISO and PJM have approved three small TMEP portfolios since 2017 and one larger interregional market efficiency project in 2020.

This summer, WEC Energy Group’s Chris Plante asked the grid operators to consider creating a joint targeted interconnection queue study similar to that undertaken by MISO and SPP. That work has resulted in identifying about $1 billion of projects on their seams. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)

“We are very encouraged by the progress with SPP and would like to see a similar initiative with PJM,” Plante said.

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SPP Adds SaskPower as First International Member

SPP has added its first international member in Saskatchewan Power Corporation (SaskPower), seven years after the RTO’s first international transactions with the Canadian utility.

The two organizations said SaskPower’s membership represents their continued efforts to increase reliability through interregional coordination. In August, they announced a 20-year interconnection agreement to expand transmission capacity between Saskatchewan and the U.S. The announcement requires construction of a new line, which will allow for 650 MW of cross-border flows beginning in 2027. (See “RTO, SaskPower Agree to Expand Interconnection’s Capacity,” SPP Briefs: Week of Aug. 8, 2022.)

“SPP is very pleased to welcome SaskPower into our organization The continued success of our organization and the integrity of the bulk power system both rely on strong interregional ties,” SPP CEO Barbara Sugg said in a press release.

SaskPower’s membership became effective Oct. 1. They are now SPP’s 115th member.

“Greater integration with the SPP will help to ensure reliable, clean energy is available to Saskatchewan to support our own generating facilities,” SaskPower CEO Rupen Pandya said in a press release.

SPP and SaskPower have operated as adjacent entities since October 2015, when SPP’s service territory expanded to the North Dakota-Saskatchewan border after the Integrated System’s utilities became members of SPP and placed their facilities under the RTO’s tariff. The organizations have a joint operating agreement that outlines how the organizations coordinate reliability and transmission functions.

The utility and SPP will expand the 150-MW tie line that connects them. SPP has been making international transactions with SaskPower since an emergency situation in late 2015, thanks to Canadian interconnections that came when the Integrated System joined the RTO. (See SPP, SaskPower Make First International Trade.)

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Glick Backs Changes to Federal Infrastructure Permitting

Climate activists who cheered the failure of Sen. Joe Manchin’s proposal to ease the permitting of energy infrastructure projects are ignoring how the current rules are hobbling the expansion of renewable power, FERC Chairman Richard Glick said last week.

Glick told Raab Associates’ New England Electric Restructuring Roundtable in Boston Sept. 30 that he was meeting with a group of environmental justice advocates earlier in the week when it was announced that Manchin had pulled the bill from the Senate floor.

“They were all celebrating,” Glick said. “And I said to them, ‘You know, you can have differences of opinion about different provisions in the bill. But if your goal is to get more renewable energy on the grid, you’ve got to get more transmission built. … I think just to pretend that the status quo is working [is a mistake]. It’s not working.”

Manchin (D-W.V.) withdrew the permitting proposal from inclusion in a must-pass spending bill when it became clear he lacked the 60 votes needed for passage in the Senate — with substantial opposition among his fellow Democrats who saw it as a concession to the oil and gas industry that would undermine decarbonization efforts. Manchin vowed to continue seeking votes for the bill.

Glick said the federal government’s role in siting will likely increase as a result of the Infrastructure Investment and Jobs Act, which allows utilities to ask FERC to overrule state regulators’ rejection of a project.

The Manchin proposal would allow FERC to order construction of transmission designated as in the national interest if asked by a state or utility. It would also set a two-year target for the completion of environmental reviews and reduce the time community members have to file legal challenges. (See Manchin Details Proposal to Streamline Approval of Energy Projects.)

As he had earlier in regard to the siting authority in the IIJA, Glick continued to express skepticism that FERC will play a major role in settling siting disputes. (See Glick Aiming for Final Transmission Rule by End of Year.)

“Even if the federal government is given the authority that Sen. Manchin has proposed — FERC in particular — the states are going to continue to play [a major role], whether that be through siting other transmission lines or general ratemaking authority. Utilities aren’t going to want to cross their states very often. And so I think the states are going to continue to play a very important role no matter what happens with the Manchin bill.”

Matthew Nelson, chair of the Massachusetts Department of Public Utilities, who spoke with Glick in the first discussion of the Roundtable, said he welcomed a stronger federal role in transmission siting.

“I don’t think we’re going to get to our decarbonization goals without a big step forward that allows a big, well-researched project to be built. So I think having something like this — having a backstop authority  — is going to be very, very important.”

State Role in Cost Allocation

Nelson also expressed support for FERC’s proposed requirement in its April Notice of Proposed Rulemaking (NOPR) that transmission providers seek the agreement of relevant state entities on cost allocation, with FERC imposing a solution if no agreement is reached (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)

“I do think that FERC kind of being the referee in the room will allow the conversations not to be, ‘It is either build this or not build this,’ but, ‘This is getting built, and what is the proper way to allocate the costs?’ I think that’s a much more productive conversation,” Nelson said. “… So I think that structure has a very good chance of being successful if properly implemented.”

Nelson-Matthew-2019-12-04-RTO-Insider-FI.jpgMatthew Nelson, chair of the Massachusetts Department of Public Utilities | © RTO Insider LLC

Abe Silverman, general counsel for the New Jersey Board of Public Utilities, said FERC could help force agreements to share costs.

“We almost need the Sword of Damocles from FERC hanging over everyone’s head,” he said during the Roundtable’s second discussion. “We almost need that strong, proactive FERC, standing out there saying, ‘If you do not agree to a cost allocation, then we are going to impose one on you.’”

Roundtable moderator Jonathan Raab, who is also moderator for the Joint Federal-State Task Force on Electric Transmission, said he was surprised at the Task Force’s last meeting in July that “there seemed to be a groundswell of support to consider having FERC require some minimum transfer capacity capability” between regions. (See States Back FERC Interregional Transfer Requirement.)

“I think it’s an eminently reasonable idea,” said Nelson. “I think the more that we’ve looked at the way the grid is evolving, the more we need redundancy and reserves for multiple different reasons.”

Nelson said there are many technical questions regarding how to set such minimums. “But I really think it’s a solid idea … that could bring benefits to a lot of different regions when they don’t know they need it.”

Glick said there was “an enormous consensus” following the Texas outages during Winter Storm Uri that transfer capacity needed to be increased. But he said many issues are standing in the way, “not the least of which is who builds it and who pays for it.”

Future NOPR on Socializing Interconnection Costs?

Raab also noted that the task force discussed ways to change participant funding rules to socialize some interconnection costs, a proposal that was not included in the interconnection NOPR issued in June (RM22-14).

“It’s an issue that I feel very strongly about,” Glick responded. “We still have a lot of future NOPRs to come. So hopefully, we will address it.”

Glick said the current process does not allocate costs roughly commensurate with benefits, as required by court precedents.

“In many cases, you know, you have a bunch of wind generators coming in [and the] first one that comes online has to pay the cost of the network upgrade. Everyone else behind them doesn’t have to pay. That doesn’t seem fair, right?” Glick asked. “Secondly, there are a number of benefits that these upgrades provide, in addition to just allowing the generator or generators to hook up to the grid. And we’re not taking that into account.

“At the Task Force, not everyone was on the same page,” Glick said. “I think we have more work to do on it — maybe develop more of a record on it. But I’m very supportive. And I’m determined to address this issue.”

Nelson also expressed support for a change. “Having one person take the hit for everyone behind it worked in the day when there was one huge generator coming online, and maybe that required an upgrade. But I’m not sure that with a distributed generation market, that makes much sense,” he said.

Offshore Wind Transmission

Glick also said the commission is considering whether tariff changes are needed to allow PJM, NYISO or ISO-NE to develop offshore wind “collector” systems to minimize transmission costs and beach landings. “It would be foolish not to include those [state OSW] goals and mandates in our transmission planning processes,” he said.

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New Jersey Offers Plan to Boost Lagging Storage Capacity

New Jersey’s Board of Public Utilities (BPU) on Thursday outlined a proposal to stimulate the development of standalone storage capacity by offering incentives for grid-scale and consumer-level projects, as the state struggles to reach its goal of putting 2,000 MW of storage in place by 2030.

About 30% of the incentives available under the Storage Incentive Program (SIP) would be paid to storage projects as fixed annual incentives to both utility-scale and distributed projects, with a set value per kilowatt-hour of capacity. The remainder of the SIP incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.

The proposal sets a target of building 1,000 MW of four-hour-plus storage by 2030. The BPU is seeking a steady increase in the annual capacity of storage installed each year, with 40 MW of four-hour storage installed in 2023, rising to 330 MW in 2029.

“Storage is expected to play a key role in maintaining electric system reliability as carbon-intensive resources are displaced by more intermittent renewable generation,” according to the proposal. “Energy storage has the potential to simultaneously improve grid reliability, enable more extensive grid decarbonization through expanded hosting capacity, improve community resilience and reduce electricity costs for all consumers.”

Missed Targets

Storage is widely seen as a paramount element needed to manage electricity supply as intermittent renewables become increasingly dominant without relying on fossil-fired peakers.

Yet even as the state has moved aggressively to develop wind, solar and other clean energy initiatives, it has made little progress in developing storage capacity. The state Energy Master Plan recognized storage as a key element and said the state would need 9 GW of capacity. The state Clean Energy Act, enacted in 2018, said that the BPU should create a process for putting 600 MW of storage in place by 2021 and 2,000 MW in place by 2030.

But the state missed the 2021 goal, and it currently has only 497 MW in place at present, little of which is new technology. The BPU has acknowledged in the past that about 420 MW is contributed by the Yards Creek Pumped Storage Facility in Blairstown, a pumped storage facility developed in 1965. The remainder is mainly lithium-ion batteries. (See NJ Lagging in Energy Storage Progress.)

“Multiple other states are already rapidly deploying large quantities of energy storage capacity,” the proposal states. “And some are even finding energy storage already has the ability to reduce costs to electricity consumers in addition to helping advance the clean energy transition. Yet, despite the demonstrated benefits of energy storage and New Jersey clean energy leadership, the state is currently lagging when it comes to energy storage deployment.”

The proposal adds that “multiple benefit-cost analyses commissioned by other states indicate that energy storage deployment can reduce consumers’ net electricity costs, with total ratepayer benefits more than covering the ratepayer costs of storage incentives.”

Creating Consumer Benefits

The SIP represents the BPU’s effort to help remedy the state’s storage shortfall. So does another BPU proposal under the Competitive Solar Incentive (CSI) program, the final rules for which are expected to be released this year. The CSI, which provides incentives for grid-scale solar projects, will offer incentives for co-located storage.

The SIP proposal said the BPU has shaped the program to look for incentive levels that are big enough to lure finance for successful storage projects while “minimizing the period over which ratepayers will support each energy storage resources.”

One difficulty, the proposal says, is that energy storage developers “generally can only monetize a fraction of the benefits they produce.” Although energy storage brings great benefits in “optimizing the regional power system,” it has proven difficult to make money from that, the report says.

The BPU will solicit public and stakeholder input on the plan in three hearings, on Oct. 21, Nov. 4 and Nov. 14.

The proposal says it is seeking to encourage private ownership of storage so that the commercial and operational risks are borne by investors, with support from ratepayers, and to create a competitive market. That will require “a robust effort by the EDCs [electric distribution companies] to ensure that the grid is capable of connecting storage devices at the distribution and transmission levels,” according to the proposal, which does not allow for utility ownership or operation of storage devices.

The proposal also expects energy storage owners to engage in “value stacking,” or lining up “various sources of customer savings/benefits and grid revenues,” to make the project lucrative and attractive to customers. The anticipated revenue streams include:

  • wholesale market revenues;
  • energy arbitrage in time-of-use differentiated markets;
  • participation in wholesale ancillary services markets;
  • retail bill reductions created by active management, such as management of demand charges, standby charges and distribution costs; and
  • cost-effective investment in distributed energy resources, electric vehicle charging or other technologies supported by energy storage devices.

The two-pronged incentive structure is designed to make projects as attractive as possible to investors. The proposal suggests a “declining block” structure in which the BPU sets the incentive levels so that they decrease as capacity in the state rises, which will give investors a “clear trajectory” of the incentive levels for several years.

The first incentives should be 10 annual payments of $20/kWh of storage capacity for the grid supply program and $40/kWh of storage capacity for the distributed program, according to the proposal. To get the incentive, however, the storage device would have to be online 95% of all hours.

The performance-based incentives are designed to “maximize environmental benefits” while also supporting the grid during times of “operational stress.” Aside from ensuring that the devices help reduce emissions, that strategy also will “incent storage developers to site their units in the places on the grid where they will provide the most significant price and environmental benefits to consumers,” according to the proposal.

It suggests the BPU hire a “program administrator” to track and administer the incentives, which will be based in part on marginal carbon emissions data from PJM. That would enable the program to reward grid-supply storage sources that result in lower marginal carbon emission while reducing incentives for storage that do not, the proposal states.

The proposal does not suggest specific incentive rates, which will be determined in discussions with stakeholders.

For distributed storage devices, the proposal suggests that EDCs consider an incentive that would pay based on the operation of the device during hours identified as high demand, such as summer afternoon hours. The EDC will have to show how the payment structure maximizes environmental benefits, minimizes distribution investment, “minimize[s] the stress on the local distribution system and reduce[s] operating costs,” the proposal says.

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NJ Foresees ‘Horse Trading’ with Other PJM States over Tx Costs

New Jersey officials hope to engage in “horse trading” with other PJM states over the cost allocation of transmission needed to meet their climate goals, a key state regulator said last week.

PJM’s Offshore Wind Transmission Study: Phase I, released last year, concluded that a coordinated transmission plan to integrate 14 GW of offshore wind and all existing state renewable portfolio standards would cost about $600 million through 2027 and $2 billion to $3 billion through 2035. (See Tx Upgrades for PJM OSW, Renewables Could Cost $3.2 Billion.)

Abe Silverman (Raab Associates) Content.jpgAbe Silverman, New Jersey Board of Public Utilities | Raab Associates

The New Jersey Board of Public Utilities has estimated costs would be $5 billion to $34 billion in a “piecemeal” approach, BPU General Counsel Abe Silverman said during the second panel of Raab Associates’ New England Electric Restructuring Roundtable in Boston on Friday.

“The other clean energy states and PJM are looking at billions of dollars of transmission upgrades if we do it the way we’re doing it now, when we can meet all the needs of the entire PJM region at approximately the same price,” he said. “So there’s a lot of room for horse trading, if we can get the parties to the table.”

Silverman said the BPU will announce later this month whether it will select any of the 80 proposed transmission projects PJM received in response to its solicitation for 7,500 MW of offshore wind transmission. The solicitation was conducted under PJM’s State Agreement Approach (SAA), which makes New Jersey responsible for all of the costs.

The SAA leaves New Jersey “almost in a hostage situation at the moment,” Silverman said. “The transmission projects that we are planning benefit many states in PJM; they will see lower production costs as a result of these upgrades. But because of the way the system works, we are solely responsible for the cost. That needs to change.”

MISO Planning Efforts Win Praise

Silverman said the SAA shouldn’t be the only option for states such as New Jersey. “And this is where I think we really need the ISOs to step up and do the kind of long-term proactive planning that MISO, frankly, has been doing now for a decade.

“I’m just in awe of what MISO has done over the past couple of years,” he added, saying the RTO is “probably five to 10 years ahead of the rest of us.”

Following more than two years of planning, MISO identified 18 transmission projects that could add 50 to 60 GW of new resources in the MISO Midwest subregion at a cost of $10.3 billion. The RTO says benefits from its Long-Range Transmission Planning Tranche 1 will be shared among all Midwest subregions and produce a benefit-cost ratio of at least 2.1:1 for all zones.

Overlapping the Tranche 1 study was MISO and SPP’s Joint Targeted Interconnection Queue (JTIQ) study, which resulted in five seams projects that will enable 30 GW of new generation.

Aubrey Johnson (Raab Associates) Content.jpgAubrey Johnson, MISO | Raab Associates

“The LRTP deals with deliverability; the JTIQ deals with injectability,” said Aubrey Johnson, MISO’s vice president of system planning, who appeared at the Roundtable via video.

“One of the things that we talk a lot about is we’re not trying to maximize the transmission; we’re trying to maximize the value of the transmission that we propose,” Johnson said. He said MISO is “extremely conservative” in identifying benefits. In “our state of North Dakota, it’s against state law to consider decarbonization [benefits]. … The No. 1 thing that [the projects solve] is congestion.”

But Johnson said the broad benefits have not eliminated “friction” over cost allocation. “Cost allocation is a full-contact sport,” he said, adding that he has created a team to help identify improvements in its cost allocation methodology.

NYISO’s New Transmission

Doreen Harris (Raab Associates) Content.jpgDoreen Harris, NYSERDA | Raab Associates

Also speaking at the Roundtable was Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA) and co-chair of the state Climate Action Council. Harris discussed the state’s Power Grid Study, which identified distribution and transmission upgrades needed to achieve the state’s climate goals, including meeting 70% of the state’s electric energy demand with renewable sources by 2030.

Achieving its goals will change the state’s grid from peaking in the summer to in the winter by the mid-2030s, Harris said, with peak demand doubling to about 45 GW.

To reduce New York City’s reliance on fossil fuels, NYSERDA is procuring 2,550 MW of new HVDC transmission capacity through the Champlain Hudson Power Express, a 1,250-MW line spanning 339 miles from Quebec and Clean Path NY, a 1,300-MW transmission line that will run 175 miles from Delaware County. Both lines will terminate in Queens.

HVDC transmission capacity Map (NYSERDA) Alt FI.jpgNYSERDA is procuring 2,550 MW of new HVDC transmission capacity through the Champlain Hudson Power Express and Clean Path NY. | NYSERDA

 

“It is not simple to move these projects forward by any stretch,” said Harris. “What we are procuring is actually quite unique. So we’re procuring, in this instance, renewable energy attributes delivered to Zone J [New York City]. And so that was what the RFP was looking for. It was not saying, ‘Here’s the [transmission] project to bring forward.’ It was saying, ‘Here’s the problem; solve the problem.’”

ISO-NE Sees Widespread Tx Overloads

Robert Ethier (Raab Associates) Content.jpgRobert Ethier, ISO-NE | Raab Associates

ISO-NE also expects its electric demand to switch to a winter peak by 2035, said Robert Ethier, vice president of system planning for the RTO.

By 2031, ISO-NE forecasts the region will have 1.1 million air-source heat pumps and 1.5 million electric vehicles. By 2050, the RTO says its modeling shows there would be overloads on 50% of its transmission lines without major upgrades to the system.

“So if you build all the things that are required to meet the state goals, and you run everything off electricity in 2050, what does the transmission system look like?” he asked. “The short answer is, a lot more expensive, which is not really a surprise. So the real question is, where does that money get spent?”

Ethier said it was “humbling” to hear the other grid operators discuss their challenges.

“There’s just so much going on in this space,” he said. “I feel good about what New England is doing. I think we’re doing a lot; I think we as a region are moving forward. But boy, you listen to these other regions, you realize every region is kind of in the same boat.”

Obstacles to State Goals

During the question-and-answer period, Fran Cummings of Peregrine Energy Group asked whether grid planners had contingency plans in case worsening climate impacts forces changes now expected in 2050 to be accelerated to 2040.

“The holdup is not going to be the planning, it’s going to be the building,” responded Ethier. “What we’re seeing now is siting is a problem; permitting is a problem; and the supply chain is a problem. We have large wind farms that are delaying their in-service date because of supply chain issues. And we see a lot of that going on in the queue as well: People want to slow down their interconnection process, because it’s ahead of where their project really is.”

Johnson said MISO planners have discovered that resource changes originally expected by 2040 are likely to occur by 2030.

“Procuring a 345-kV transformer is not trivial. Movement of them in the United States is not trivial. The people actually needed to do the work is not trivial. So my concern is that if you try to force an acceleration of all the work that is being considered, the cost of those is going to increase,” he said.