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November 27, 2024

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With Final Class Year Approval, NYISO Marks End of an Era

NYISO‘s Operating Committee on Sept. 26 approved the system upgrade facilities (SUF) and system deliverability upgrade (SDU) studies for Class Year 2023 — the last using the ISO’s current interconnection process as it transitions to a new cluster-based approach. 

“Next week marks my 20th year with … NYISO, and in my 20 years, we have worked through all kinds of challenges with the class year interconnection process,” said Zach Smith, vice president of system and resource planning. “The team has been fantastic through all of this, but it really has been tremendous with what we expect to be our final class year as we transition to the new cluster process.” 

The SUF study identifies which interconnection facilities and developer attachment facilities would be required to reliably interconnect a group of projects to the grid under the minimum interconnection standard. The SDU study determines whether each project is deliverable at its requested capacity resource interconnection service level.  

CY23 includes 67 projects. If all are interconnected, the generators would add about 14,000 MW to the grid, while the HVDC projects would inject 1,300 MW. The total cost for developers would be about $2.398 billion. 

Developers have until Oct. 28 to accept their cost allocations. The studies would have to be updated if there are any rejections. 

The first transitional cluster study began Aug. 1. 

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Transportation Companies Turn to Solar, Hybrid Refrigeration

Cargo transportation companies are replacing diesel-powered generators with units fueled by solar, batteries and regenerative brake energy in an effort to cut emissions from refrigerated containers and trucks that carry produce, frozen food, pharmaceuticals and other goods.

Goods moved through the cold supply chain typically are kept at low temperatures by refrigeration systems, known as Transport Refrigeration Units (TRU), that are powered by diesel engines. Although the engines are small, typically 9 to 36 horsepower, their emissions are amplified by the gathering of similar trailers and vehicles at distribution centers, truck stops and other facilities with their cooling systems running.

The shift from diesel to renewable energy is part of the multi-pronged effort by cold goods trucking and logistics companies to cut emissions and reduce the waste of food spoiled in transit, according to speakers at an online Net-Zero Carbon Summit Sept. 18 organized by FreightWaves, a logistics and trucking website. As well as reducing diesel use, the methods include improving supply chain efficiency and reducing energy use through more efficient temperature control systems that can minimize the amount of food that goes bad en route.

The focus on cutting TRU emissions is seen in the industry as a solid — and cheaper — first step toward the far more expensive decision to replace diesel-powered trucks with vehicles powered by electricity or other renewable energy.

“TRUs are generally dirtier than trucks,” said Lynda Lambert, a spokeswoman for the California Air Resources Board (CARB). The agency, which has regulated TRUs since 2004, enacted rules in 2022 that will require all of the 200,000 truck-based TRUs in the state to be emissions free by 2030 and sets tight emissions standards for refrigerated containers.

“TRUs are often clustered at facilities located in some of the state’s most vulnerable, overburdened communities that suffer from poor air quality,” Lambert said, in an email interview with Net Zero Insider. “These communities located near main goods movement hubs like ports, railyards and warehouses bear a disproportionate health burden from the emissions.”

Speaking at the conference, Robert Koelsch, CEO of AEM, of Mesa, Arizona, which manufactures solar-powered TRUs, said powering a TRU with renewable energy instead of diesel could save 27 tons of carbon emissions a year.

“That’s a lot, and much easier to implement than a (truck) tractor,” he said. “So we would advise people to look at your TRU fleet first before you look at tractors.” The company website says its refrigerated containers have saved more than 2,000 tons of carbon emissions on more than 1 million deliveries, and compares the zero emissions from its units to typical units that generate between 16.5 and 33 tons of carbon a year.

Koelsch said he began looking to cut TRU emissions 15 years ago when he first encountered a diesel-fueled refrigerator that “started up and the front of the unit shook and smoke, black smoke came out of the top of it.” His company within six months developed a unit fueled by solar-generated electricity stored in a 5,000-pound forklift battery, he said.

The company then worked to retrofit diesel units to run off solar panels on the roof of the container and created a generator to convert energy from the truck wheels into electricity, he said.

“The idea was to go 100% zero emission, not hybrid; no diesel backup,” he said. “We have a patented wheel generator that gives you a range extension on the road in California.” The company also has focused on increasing the efficiency of the cooling unit so that it runs on less energy, and so uses less battery charge, he said.

Hybrid Solution

Paul Kroes, trailer innovation leader at Thermo King, of Minneapolis, which manufactures refrigerated trailers, trucks and vans, said the sector is shifting from diesel-fueled refrigerators to hybrids of electricity and diesel for the same reason consumers have turned to hybrid EVs.

“Range anxiety is a real thing,” he said, and the consequences are greater for an electric refrigeration unit. “For example: Am I going to make it through the day with my load cold? And that’s arguably a much bigger deal and a much more expensive problem.”

Thermo King manufactures electric TRUs for smaller trucks and vans and electric battery packs, and it is set to launch another hybrid unit that runs on diesel and “shore power,” or plug-in electric when the unit is parked at a warehouse or a dock. The company says it is spending $100 million to introduce all-electric transport refrigeration systems “across the global transport cold-chain” by 2025, and in May said it had partnered with Range Energy, a manufacturer of heavy duty trailers, to develop an electric refrigerated trailer, following pilot tests of hybrid units on trailers.

Hybrid refrigeration solutions are growing more popular, Kroes said, because they allow “fleets to dip their toes or their ankles or up to their knees into the EV space.” Companies that ship temperature-controlled goods can go some way to “decarbonizing their fleet without ultimately risking load losses and operational disruptions that can have big impacts, not just to their bottom line, but to their customers and ultimately to us as consumers.”

Still, Kroes said he expects the use of hybrid models to be a short-term solution.

“After a few years, I would hope that fleets start to notice they’re using that engine less and less as a training wheel and eventually they take the training wheels off and they go to an all-electric,” he said. “So hybridization is definitely an interim step.”

Damaged Food Loss

Emissions reductions also can be achieved by simply cutting the amount of food that is damaged or destroyed en route to its destination, and so eradicating the need to produce and ship it needlessly in the first place, speakers said. That approach was highlighted in a recent study by the University of Michigan that found half the food wasted globally could be eliminated through the use of full refrigerated food supply chains, which in turn would cut greenhouse gas (GHG) emissions by 41%.

“The common thread is that if you optimize the cold chain, you’re going to see a reduction in product loss,” said Ilya Preston, CEO of Paxafe, which helps clients improve the efficiency of their supply chains through data collection and analysis. “You’re going to see, therefore, reductions in greenhouse gas emissions.”

But the scale of the emissions reductions can depend on what products in the cold supply chain are the focus of efficiency efforts, he said.

“Meat, for example, accounts for 10% of global loss, but it accounts, on the flip side, for 50% of total greenhouse gas emissions,” he said. “So yeah, I could invest into reducing the loss rates of meat. I’m not going to get that much of a return on the actual quantity of meat that I save. But I’m going to get a ton (of emissions reductions) environmentally speaking.”

“Whereas fruits and vegetables, they make up 30% of the volume of loss in terms of in terms of food, but they only account for 9% of the emissions gases,” he said.

Evigence, of Hoboken, N.J., makes sensors that monitor in real time the freshness of food under transportation in the cold supply chain, Oria Malka, vice president of sales, said at the conference. The sensors use a chemical process “that basically mimics the degradation of any perishable product,” or the freshness, she said. And the company then uses AI to analyze the data to help customers pursue a “smarter decision-making process, using that data to kind of drive less waste, prevent waste in their supply chain, and also optimize their supply chain.”

“And by doing that, you can optimize that shelf life later on in your supply chain and basically not throw that product” out, she said. That enables customers to “optimize those processes and reduce packaging materials, installation materials, and identify where you can go toward more efficient production lines or routes within your cold chain,” she said. “And by that reduce those carbon footprints, and basically make yourself more of a sustainable company.”

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MISO Dips Toes into Potential New Resource Adequacy Standard; States Demand Key Role

MISO is questioning whether its current loss of load standard remains the best method for establishing resource adequacy and initiated a daylong meeting with industry experts and regulators to probe alternatives.  

“The one-day-in-10 years resource adequacy criterion has a number of limitations, and many industry experts recommend change,” MISO Director of Strategic Initiatives and Assessments Jordan Bakke said in opening the Sept. 26 special teleconference.  

Bakke said MISO is exploring the concept of a more comprehensive resource adequacy benchmark. He said MISO needed a “natural, long-form discussion about what’s needed going forward.”  

The grid operator has hinted in public meetings that it might turn to conditional value at risk, loss of load hours or expected unserved energy as possible new measures of resource adequacy risk.  

Bakke said any potential solution MISO might put forward will be developed in partnership with its regulatory and stakeholder community. He emphasized that MISO doesn’t have a preferred approach, timeline or proposed tariff revisions. He said MISO plans to draft a road map for evaluating new standards.  

“We don’t know when and if something will change,” Bakke said.  

Derek Stenclik, representing Energy Systems Integration Group, said he thought MISO is doing the right thing by raising the possibility for change among its stakeholder community.  

He said as far as “setting the threshold for an acceptable level of risk,” MISO needs to land on something transparent and economic.  

Stenclik said MISO should begin by quantifying the size, frequency and duration of outages. MISO also should incorporate a “suite of reliability metrics,” he said, putting more emphasis on expected unserved energy. He said MISO’s move to an energy-limited system heavy on renewables necessitates multiple metrics.  

He said, for example, MISO could use a combination of its current 0.1 days/year loss of load expectation in addition to a 0.3 hours/year loss of load hours analysis and a 1,000 MWh/year expected unserved energy, as PJM has considered.  

“We don’t have to have just one,” Stenclik said.  

Zach Ming, of energy consultancy E3, pointed out that ERCOT recently announced it will use a three-pronged reliability standard that marries the usual one-day-in-10-years standard with a 12-hour limit on outage duration and a 19-GW limit on the magnitude of outages.  

EPRI’s Aidan Tuohy also recommended reducing reliance on a single measurement.  

“Adequacy exists on a spectrum and should not be a binary choice,” he said.  

Tuohy said while LOLE conveys the expected number of days when loss of load occurs, it doesn’t capture the magnitude of the loss. MISO likely needs a more detailed look, Tuohy said, where it considers outlier events, assessing risk by month or hour of day and describing involuntary load-shedding events.  

“More high-impact, low-probability events” are on the way, Tuohy predicted.  

Meanwhile, the Organization of MISO States is positioning itself to have a voice in MISO resource adequacy criteria. 

OMS Executive Director Tricia DeBleeckere said regulators have a collective awareness that the standards need to shift. She reminded attendees that states have resource adequacy jurisdiction and want a “key seat at the table” when designing new criteria.  

DeBleeckere said the 0.1 days/year standard has been in use so long that changing it will be a “huge initiative.”  

“A big thing for OMS is who is going to be making the call when these changes are made,” she said, adding that OMS’s support of MISO’s road map will hinge on how much MISO includes state regulatory standpoints.  

DeBleeckere said though no one can develop a perfect reliability standard, a replacement should be data-driven and not “overcorrect” acceptable levels of risk.  

OMS President and Iowa regulator Josh Byrnes has said state regulators will work on a guiding principles document on resource adequacy standards. It will focus on ensuring states’ leadership on a new reliability standard and allow enough time to understand what’s expected and to meet whatever threshold is set.  

At a Sept. 12 Organization of MISO States board meeting, North Dakota Public Service Commissioner Julie Fedorchak said states should do more to steer discussions on resource adequacy benchmarks.  

“It feels like OMS should enter this area … and take a more leadership role in this resource adequacy metrics discussion,” Fedorchak told other state regulatory staff.  

Byrnes said MISO “probably needs to do a better job” engaging state regulators if it suggests crafting a new resource adequacy target.  

Michigan Public Service Commission Chair Dan Scripps said states “absolutely” should be at the center of those discussions because the “political reality” is state regulators receive calls from customers and governors when outages occur.  

“No one wants to hear that, ‘Oh, that was our one event in 10 years,’” Scripps said.  

Bill Booth, a consultant to the Mississippi Public Service Commission, said he thought NERC, not MISO or state commissions, should establish a resource adequacy standard.  

“Do you want to have a MISO standard and a PJM standard and an SPP standard?” Booth asked rhetorically.  

MISO again will discuss reliability standards at its Oct. 9 Resource Adequacy Subcommittee meeting. 

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With FERC Inaction, ISO-NE Delays Order 2023 Implementation

ISO-NE has suspended its implementation of Order 2023 compliance and rescinded transitional cluster study agreements because of FERC’s lack of action on its compliance filing, Manager of Resource Qualification Alex Rost told the NEPOOL Transmission Committee on Sept. 25.

The RTO submitted its compliance to the commission in May, requesting an Aug. 12 effective date (ER24-2009). FERC has yet to rule on the proposal, throwing a wrench in ISO-NE’s implementation timeline.

Order 2023 requires grid operators to transition from first-come, first-served serial interconnection process to a first-ready, first-served process using cluster studies to evaluate multiple projects at a time. (See FERC Updates Interconnection Queue Process with Order 2023 and NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance.)

Hoping to stick to its proposed timeline, ISO-NE issued transitional cluster study agreements to eligible interconnection customers on Aug. 12. The RTO planned to start work on the transitional cluster study Nov. 11 and provide a final report on the cluster in August 2025.

ISO-NE wrote in a Sept. 23 memo that it’s rescinding the study agreements because of FERC’s inaction. The RTO announced that it was pausing its work on Order 2023 compliance in early September.

A delay of the transitional cluster also would affect the timing of the first standard cluster study, with the first activities for this subsequent process set to begin immediately after the end of the transitional process.

FERC’s delay also has dealt a blow to ISO-NE’s plan to enable late-stage projects to participate in reconfiguration auctions (RAs). Currently, resources need to gain a capacity supply obligation and associated capacity interconnection rights in a Forward Capacity Auction (FCA) in order to participate in RAs, but ISO-NE has delayed its next FCA by three years to make significant changes to its capacity auction process. (See ISO-NE Outlines ‘Straw Scope’ of Capacity Market Reforms.)

ISO-NE has proposed a “Transitional CNR [Capacity Network Resource] Group Study” to provide a “one-time opportunity for late-stage interconnections to achieve capacity interconnection service through the 2024 interim reconfiguration auction qualification activities.”

However, the RTO wrote in its compliance filing that the Aug. 12 effective date for the order is necessary to “align the Order No. 2023 transition process” with the RA qualification timeline. It noted “a delayed order in this proceeding would result in these interconnection customers needing to wait until a later auction cycle, which would not only be detrimental to those interconnection customers, but would result in a less robust auction.”

ISO-NE determined in early September it no longer would proceed “with the Transitional CNR Group Study proposed in the compliance proposal.”

The RTO plans to proceed with interconnection studies under its existing tariff rules going forward.

“When FERC issues an order addressing the compliance proposal, the ISO will assess how to move forward on implementation based on the timing and content of the order,” ISO-NE spokesperson Mary Cate Colapietro said. “We can’t speculate until we actually receive the order.”

Transmission Planning

Also at the TC, Brent Oberlin of ISO-NE provided a comparison of ISO-NE’s new Longer-Term Transmission Planning (LTTP) process and the requirements of FERC Order 1920. (See FERC Approves New Pathway for New England Transmission Projects.)

In general, the Order 1920 process is broader than the LTTP, requiring long-term planning to consider future interconnection needs and how asset condition projects could be properly sized to reduce overall costs. The LTTP also includes more state discretion around when the planning process is initiated, the assumptions used in studies and which projects are selected.

In future meetings of the TC, Oberlin said ISO-NE plans to break down the order into “manageable pieces for stakeholder review and discussion,” detailing which processes will need to be created, and which existing processes will need to be modified, to comply with the order.

He added that ISO-NE will develop changes to its interregional planning procedures separately from its regional planning procedures. The RTO will begin discussing compliance changes in more detail at the TC’s meeting in October, ultimately aiming for a Participants Committee vote in May 2025. The deadline for regional compliance filings is June 12, 2025, and the deadline for interregional compliance filings is Aug. 12, 2025.

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Updated EDAM Study Shows Doubling of PacifiCorp Benefits

PacifiCorp could earn up to $359 million a year in net benefits from participating in CAISO’s Extended Day-Ahead Market, nearly double the previous estimate, according to a newly updated study prepared for the utility by The Brattle Group. 

The update also more than doubles the estimate of benefits for the entire EDAM footprint compared with the original market study Brattle produced for PacifiCorp in April 2023.  

That study showed the six-state utility reaping $181 million in net benefits from a day-ahead market whose footprint included CAISO, Balancing Authority of Northern California, Idaho Power and Los Angeles Department of Water and Power, with all market participants realizing a total of $437 million in benefits. 

The revised study expands the EDAM footprint to include more recently announced participants NV Energy and Portland General Electric, as well as likely joiner Seattle City Light. It also factors in the effects of SPP’s RTO West and Western Energy Imbalance Service footprints. 

As in the original, the updated study measures PacifiCorp’s EDAM benefits against a “business as usual” (BAU) case that consists of the current Western Energy Imbalance Market footprint. It doesn’t consider the effect of potential Western participation in SPP’s Markets+. 

According to Brattle’s updated modeling, PacifiCorp’s rise in benefits results in part from a $53 million reduction in the utility’s adjusted production costs (APC) under the expanded EDAM footprint. The utility sees an even bigger boost from a $120 million increase in EDAM congestion and transfer revenues, with $88 million of that realized on paths with the three newly included market participants. 

More specifically, the updated study found that PacifiCorp’s benefits in its resource-heavy East (PACE) balancing authority area are driven by increased economic dispatch of gas generation into the rest of the EDAM and rising sales revenues from renewable resources.  

“PACE receives $163 million in increased sales revenues on $82 million in increased generation costs, with average day-ahead sales prices increasing from the BAU case to EDAM from $23/MWh to $29/MWh,” the study says. 

Brattle said PacifiCorp’s extensive transmission network would be “extremely valuable” to the EDAM because it connects to more of the market’s members than any other participant.  

The benefits in PacifiCorp’s West (PACW) BAA and Washington territory would derive largely from reduced generation and energy purchase costs. 

“PACW is both able to reduce its generation 360 GWh in EDAM (saving $16.4 million) and time purchases better to buy 539 GWh more in EDAM, but for $12.2 million less than in the BAU case,” according to the study. 

Compared with the 2023 study, the updated study assumes PacifiCorp will be heavier in annual output from renewable and thermal generation, with a 9 TWh increase in wind — mostly in PACE — and a 6 TWh increase in coal-fired generation because of the carbon capture tax credit for the Jim Bridger plant in Wyoming. Nuclear output declined based on removal of one small modular reactor project. Estimates for hydroelectric generation also were lowered to reflect the utility’s own hydro capacity updates. 

PacifiCorp in April became the first Western utility to fully commit to the EDAM and sign an implementation agreement with CAISO. 

Brattle’s updated study increases the EDAM-wide benefit estimate to $837 million, noting the larger footprint produces larger APC savings and increases market revenues.  

“New footprint members account for more than $200 million of the [$285 million] increase in trading revenues,” the study finds. 

The expanded footprint also reduces the region’s bilateral trading value by an additional $275 million, for a total decline of $531 million, according to the study.  

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Sierra Club Urges Big Customers to Push for Clean Energy to Meet Rising Demand

Sierra Club released a report Sept. 18 arguing that utilities can meet rising demand with clean resources, but to ensure that happens, the big customers driving much of that growth need to stick to their clean energy commitments. 

Forecasts of rapid demand growth driven by data centers, electrification and manufacturing have garnered headlines, with merit, says the report, “Demanding Better: How growing demand for electricity can drive a cleaner grid.” 

“Electric utilities across the country, from Virginia to Arizona, have quickly responded by proposing to expand gas-fired generation and retain existing coal-fired power plants, leaving policymakers deeply concerned that actual and projected progress [toward] ambitious climate targets is now at risk,” the report says. “Ironically, the largest drivers of demand are corporate customers with climate commitments, many of whom want to see a different pathway forward.” 

Dominion Energy is forecasting huge demand growth for its Virginia utility largely because of data centers, and it has argued that it will need new natural gas units to help meet it. (See Dominion CEO Says Virginia Well Poised to Meet Growing Demand.) 

The paper suggests that large customers assess their host utilities’ decarbonization plans and actively engage in utility proceedings to demand a transition to clean energy. It argues that utilities should move past annual volumetric renewable purchases to pursue 24/7 clean energy, while regulators should require that new large customers be transparent about their load projections. Large buyers should consider partnering with utilities to permanently buy down emissions. 

Policymakers should work to create a national system for tracking and verifying hourly emissions to facilitate time-based renewable energy credit markets. 

Dominion is not alone in arguing for new natural gas to meet rising demand, with the paper noting Georgia Power, American Electric Power, Duke Energy, Tennessee Valley Authority, Arizona Public Service and others. 

“Electric utilities, apparently caught off guard at this need to provide reliable electricity to a vastly expanded customer base, have defaulted to familiar but high-emissions choices: building turnkey gas power plants and delaying the retirement and replacement of aging coal plants,” the paper says. 

While the decisions were made quickly in response to demand going up for the first time in decades, they could have long-lasting impacts, as new gas plants will have to operate for decades to recover their costs. 

Part of the increase in demand is to address climate change, as electricity offers a ready alternative for heating buildings, fueling transportation and decarbonizing some industry. That, combined with growth in data centers and utilities’ obligation to serve customers, has led to more natural gas plants being planned and coal retirements being delayed around the country. 

One issue hanging over demand growth is that long-term forecasts vary wildly, from artificial intelligence representing 8 to 9% of overall electric demand by 2030 to plateauing well before then. 

“Individual utilities may only have limited insight into their own future,” the report says. “Some observers have hypothesized that large load customers may be shopping the same demand to multiple utilities, looking for the fastest interconnection process at the lowest cost, a practice which puts utilities at risk of overbuilding for loads that may not materialize.” 

Many data centers are built by companies whose business is to build that infrastructure for third parties in anticipation of future demand that might not materialize. The sector also faces competitive pressure to increase the efficiency of data centers through improved chips, cooling, load management and more efficient algorithms in software. 

Perfect foresight is impossible, but utility planning practices can minimize risk while firms building data centers should be transparent about where they are planning new facilities. 

Many of the firms building demand centers have their own goals to decarbonize, but the report notes that traditional renewable energy procurement might not be enough to decarbonize, as historically they have bought renewables far away from load. 

“At the extreme, if a buyer signs a contract with an existing producer, it may offer little or no price signal to incent new clean energy that displaces the need for emitting fossil plants,” the report says. 

Large buyers can get around that issue by reorienting toward hourly tracking to ensure that their energy requirements are being met by local, time-matched clean energy. 

That opportunity is available in some states, but in those that do not offer any kind of retail markets, the paper suggests engaging in utility regulatory proceedings to ensure the firm serving large customers is as clean as possible. Large buyers should also support mandatory renewable or clean energy standards that drive the entire fleet to net zero, the paper says. 

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MISO Affirms Commitment to $21.8B Long-range Tx Plan in Final Workshops

MISO staff are resolute that a collection of 24 proposed, mostly 765-kV projects totaling $21.8 billion is a “least-regrets” avenue to achieving members’ resource plans, despite misgivings from some members.  

MISO held a two-day workshop Sept. 24-25 to emphasize the importance of building the second long-range transmission plan (LRTP) portfolio in MISO Midwest. Planning Coordination and Strategy Advisor Ashleigh Moore characterized the workshop as a “two-day finale” for the second LRTP portfolio; MISO will present the portfolio to its Board of Directors in December for consideration. 

Director of Cost Allocation and Competitive Transmission Jeremiah Doner said after “fine-tuning” electrical facilities and substation design, the portfolio cost now stands at $21.8 billion, up from last week’s $21 billion estimate. Doner said MISO anticipates the projects would go into service in about 10 years.  

With the increase in cost, MISO has slightly scaled back its benefits-to-cost ratios. The RTO now anticipates a benefit-to-cost ratio of between 1.8:1 and 3.5:1 over the first 20 years of the projects’ lives through reliability improvements, production costs, new capacity that won’t have to be built and environmental benefits. (See MISO Says 2nd Long-range Tx Plan to Cost $21B, Deliver Double in Benefits.)  

Doner said at a minimum, each cost allocation zone would see a 1.2:1 benefit-to-cost ratio under MISO’s most conservative analysis. Cost allocation zones in Lower Michigan, Illinois and Missouri would experience the most modest benefits, MISO said, at 1.2-1.3 in its conservative estimate. Cost Allocation Zone 2 in Wisconsin and Michigan’s Upper Peninsula would see the most benefit, at a minimum of 2.8:1 and a maximum of 5.5:1 over 20 years. 

MISO said the portfolio would free up access to regional resources, reducing the need for almost 28 GW in hypothetical future resource additions and delivering $16.3 billion over 20 years in avoided capacity.  

MISO also estimates LRTP II would support almost 116 GW in new resources across MISO Midwest. Local Resource Zone 1 in Minnesota, the Dakotas and Wisconsin and Local Resource Zone 3 in Iowa would see the most resource expansion because of LRTP II, at about 32 GW and 27 GW, respectively.  

Lingering Disagreement over Benefits

Bill Booth, consultant to the Mississippi Public Service Commission, asked what would happen if the resources MISO anticipates aren’t built, particularly the 29 GW of undefined but flexible resources MISO identified as necessary and assumed in its modeling.  

North Dakota Public Service Commission staffer Adam Renfandt said he wondered if benefits would dim if MISO tried siting resources in its hypothetical future more eastward, nearer load centers where locational marginal prices are higher. He also said he worried MISO might hinder new technologies by assuming a conventional mix of resources 20 years out.  

Doner said the second LRTP’s design is flexible enough to support a multitude of directions in resource planning. He said MISO isn’t building specific routes for any prospective facilities. But he said MISO nevertheless will need a fleet that’s spread across the region to support local clearing requirements of MISO’s resource adequacy zones.  

“We’re trying to have a regional backbone plan to support energy transfers. What resources are built is ultimately up to members,” Director of Economic and Policy Planning Christina Drake said.  

Executive Director of Transmission Planning Laura Rauch said MISO isn’t trying to send signals on where to build resources. She stressed that MISO needs regional transmission expansion, and generation will continue to interconnect to an expanded system via individual network upgrades.  

“Resource adequacy and transmission planning in aggregate are in the same house. … We aren’t building for specific units as much as we are regional needs,” Rauch said. She added that the LRTP is planned intentionally on a long-term horizon and allows for resource planning to “continue to evolve and change.”  

WPPI Energy’s Steve Leovy said he continued to have concerns that MISO’s reliability benefit assumptions are overstated. He said absent the portfolio, MISO members would tender reliability projects incrementally under annual transmission expansion plans to maintain NERC standards.  

Stakeholder doubts over the realistic chances of MISO’s assumed future fleet and MISO’s reliability value projections mirror those made by MISO’s Independent Market Monitor. (See MISO, Monitor at Stalemate over Need for $21B Long-range Tx Plan.) 

“We’re not assuming that these issues would go unaddressed and that we would experience future load shed,” Doner said. However, he said MISO cannot ignore the fact that the LRTP portfolio would resolve “hundreds” of reliability issues and subdue substantial risks.  

“There is a value in proactively planning to mitigate these risks … rather than chasing what’s happening year after year,” MISO planner Joe Reddoch said. “There’s obviously value, or we wouldn’t be doing it.”  

WEC Energy Group’s Chris Plante said MISO shouldn’t measure reliability benefits of the LRTP through expected unserved energy, but through the annual reliability projects MISO would avoid. MISO planners have said it would be extremely difficult to predict the multiple reliability projects that might be avoided.  

“It seems like this metric is destined for a lot of time on the witness stand,” Plante said, hinting that the metric will be contested.

Doner countered that the RTO is using a “very dated” $3,500/MWh value of lost load to gauge reliability impacts, making for a conservative view of reliability benefits.  

Support for LRTP II

American Transmission Co.’s Bob McKee said he “really wanted to push back” on the notion that transmission owners should continue to address reliability risks individually. He said MISO’s purpose is to examine its system and prescribe regional plans.  

“If you step back and look back at [the directives of [FERC’s] Order 1920 and even Order 890 and Order 1000, this is exactly what MISO is doing. We’ve been litigating these benefit metrics for a year now. MISO’s metrics are pretty much in lockstep in what FERC is directing other RTOs to do,” McKee argued.  

ITC’s Brian Drumm also said it’s appropriate for MISO to gauge reliability value, especially considering the “wave” of generation retirements and extreme weather conditions bearing down on the footprint.  

Drumm said the $14.8 billion reliability value MISO has placed on LRTP II is “incredibly conservative.”  

“I mean, that number could be $100 billion, $200 billion. And when you’re talking about human lives, I don’t even want to place a number on that,” he said.   

Great River Energy’s Jared Alholinna said his utility believes MISO has done a “remarkable” job analyzing its portfolio. He added that the portfolio most likely will demonstrate the most value in the times that are the hardest to predict, like punishing winter storms.  

Alholinna said MISO’s overall, minimum 1.8:1 ratio probably is understated because the footprint’s fleet transition is occurring faster than the RTO’s 20-year scenario predicts.  

Xcel Energy’s Madeleine Balchan said while it’s possible for Xcel’s Northern States Power to build to meet needs on its own, that’s not why the utility joined MISO.   

Kavita Maini, a consultant representing MISO industrial customers, said she wasn’t suggesting MISO shouldn’t engage in regional planning; however, she said stakeholders are disturbed by some “problematic” and “overexaggerated” benefits MISO is crediting to the portfolio.  

Rauch said the second LRTP portfolio is a culmination of more than 40,000 hours of labor from MISO staff, expertise from outside consultants, about 300 meetings and numerous discussions with stakeholders.  

Rauch said generally, members reacted to the draft LRTP II map released months ago with, “You all need to go bigger,” which was a “shock” to MISO planners. She said the RTO evaluated 97 stakeholder submissions for additional projects, eventually landing on seven and creating an even “stronger portfolio at the end of the day.” 

Rauch said the final LRTP II is an exceptionally valuable portfolio that creates a reliable, “765-kV transmission backbone to support high system transfers under a new resource plan” that members have charted.  

“We’ve come to the end of a very, very long journey,” Vice President of System Planning Aubrey Johnson summed up. “I think we’re better off because of the dialogue. … We’ve often said, ‘this is hard,’ and this should be hard.”  

Johnson said at the end of the day, MISO has heard stakeholder objections over the value of LRTP II, investigated them and disagreed with them.  

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New Jersey BPU Approves Invenergy Offshore Wind Delay

New Jersey’s Board of Public Utilities has approved a request by offshore wind developer Invenergy to delay until Dec. 20 the enforcement of its contract to give the developer time to find an economically viable turbine.

The board accepted the developer’s Motion for a Stay of Order to delay enforcement of the January 2024 agreement that endorsed the developer’s 2,400 MW Leading Light Wind (LLW) Project in the state’s third solicitation. Because of the stay, Invenergy temporarily will avoid making “significant financial obligations” required by the contract.

The company’s July petition said it initially planned to use turbines from one of three manufacturers — GE Vernova, Siemens Gamesa Renewable Energy (SGRE) or Vestas. But changes in the cost or size of their turbines mean Invenergy’s project no longer would be economically feasible if they were used.

Invenergy said it needs time to find a new turbine supplier. Their petition argued that without the stay, the project would have to move ahead without a clear understanding of costs, putting in jeopardy the “significant environmental and economic benefits” of the project.

The Sept. 25 board order unanimously approving the stay largely agreed.

“The public’s interest, in the context of the requested stay, is in reaping the benefits of the LLW Project, or at least preserving the status quo and the opportunity to do so,” the order said.

“Denial would result in Invenergy and the LLW Project having insufficient time to engage in meaningful negotiations with wind turbine manufacturers and the ability to identify in a timely manner a cost-effective wind turbine option, a necessary element of an OSW project,” the order states. Without the stay, it added, “Invenergy must contemplate whether it is possible to continue development of the LLW Project, given the deterioration of the LLW Project economics.”

‘Critical’ to the State

The BPU decision comes almost a year after Danish developer Ørsted pulled the plug on the state’s most advanced project, Ocean Wind 1, awarded in the state’s first solicitation in 2019, and the sister project Ocean Wind 2, awarded in the second solicitation in 2021. Ørsted at the time said the projects no longer were economically viable. Gov. Phil Murphy (D) since has scrambled to accelerate New Jersey’s offshore wind program to make up the two years lost by abandonment of the projects. (See UPDATED: Ørsted Cancels Ocean Wind, Suspends Skipjack.)

The BPU is evaluating three bids submitted in July for its fourth solicitation, with bid selection expected in December. In May, Murphy accelerated the timeline for the state’s fifth solicitation, with the process expected to begin in the second quarter of 2025 (See 3 OSW Proposals Submitted to NJ.)

BPU President Christine Guhl-Sadovy said after the 4-0 vote the state is “committed …. to our offshore wind goals.”

“It is critical towards our fight, and to mitigate climate change, and I think that this action will allow Invenergy to find a suitable wind turbine supplier,” she said. “We look forward to them delivering on the project.”

Commissioner Zenon Christodoulou said he shared Guhl-Sadovy’s optimism. “I’m fully confident that they’ll be able to work through these little hurdles and make sure that an industry which has taken over in many places in the world will apply here in New Jersey as well,” he said.

Shifting Options

Invenergy said it developed its proposal with a “turbine agnostic” approach and the products of all three manufacturers appeared viable at the time it submitted its project proposal to the BPU in August 2023. But the developer soon deemed the Vestas turbines “unsuitable for the site” due to “cost and technical factors.”

Three weeks after the board approved the project in January, GE announced it would not produce the turbine Invenergy planned to use. An Aug. 8 filing in the case by the New Jersey Division of Rate Counsel said the developer had planned to use GE’s Haliade-X 18 MW turbine, but the manufacturer in February announced in a financial filing that it had refocused its business and instead would manufacture the smaller Haliade-X 15.5 MW-250 turbine.

In June, SGRE “notified Invenergy that it was substantially increasing the cost of its turbine offering,” which meant the developer no longer had a “viable turbine supplier,” Invenergy said in its petition.

“The stay … is in the public interest in that it will permit the company the time needed to address these unforeseen circumstances in a thorough and thoughtful manner,” the developer’s petition said, adding that Invenergy “remains committed to bringing the economic and environmental benefits of offshore wind energy” to New Jersey.

Without the stay, the BPU contract would require Invenergy to pay the agency $120 million in security commitments and “multiple other funding commitments,” the New Jersey Division of Rate Counsel said in its Aug. 8 filing. If the project did not meet those commitments, the BPU could modify the price of Offshore Wind Renewable Energy Certificates, the filing said.

The ratepayer advocate said it was not opposed to Invenergy’s petition but had concerns about the board’s “frequent post-award alterations to the Board’s offshore wind solicitation process.”

“The Board’s competitive solicitation process must ensure all bidders are subject to the same rules,” the filing said. “Changing the bidders’ requirements following the close of bidding undermines the competitive process.”

Financial Reporting

The board’s decision comes three weeks after the board approved a slight change in the contract requirements placed on another developer selected in the third solicitation — Attentive Energy, which is developing a 1,342 MW project.

The BPU on Sept. 4 approved the developer’s request to file unaudited financial statements quarterly, rather than audited statements, and to submit them within 60 days of the end of the quarter. The BPU ruled that annual audited financial reports must be submitted 120 days after the end of the year, and not after 180 days, as the developer suggested.

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Report Calls for $75B in New Tx to Meet Western Needs

The Western Interconnection will need about 15,600 new line miles of high-voltage transmission at a cost of about $75 billion over the next 20 years to meet the anticipated increase in load growth, according to a report commissioned by Gridworks and GridLab published Sept. 23.

Conducted for the two groups by Energy Strategies, the Connected West study found that the Western grid’s reliability is at risk even if $30 billion of planned grid investments are implemented in the next decade. The current planned investments represent approximately 5,900 line miles, which may not be enough to support “an electrified and deeply decarbonized Western grid in 2045,” according to the report.

Instead, the report recommends an additional 15,600 new line miles over 20 years. The study found that approximately 85% of the new transmission capacity across the West can be achieved by upgrading existing corridors. Some 2,400 miles of new greenfield transmission would be needed for the proposed transmission system, the report said.

“The high-voltage investment gap to support reliability and efficiency of the grid, representing the next tranche of regional-scale transmission investments not currently planned for, is on the order of at least $75 billion,” the report said. “This investment, at a minimum, is necessary to address the transmission constraints identified in the Connected West scenario.”

The report added that the investment gap “should be considered a ‘floor’ not a ‘ceiling’ of future transmission need.”

Casey Baker, senior program manager for GridLab, said in an email to RTO Insider that the study provides stakeholders with recommendations on how to complete transmission plans “that can be implemented in the various FERC Order 1920 compliance efforts kicking off in regions around the country.” (See FERC Open Meeting Showcases Order 1920 Rehearing Debate.)

“Transmission stakeholders can take the Connected West study and use it in their efforts to promote best practices as their regions move towards completing their own long range transmission plans,” Baker added.

The study builds on the Nature Conservancy’s 2022 Power of Place: West report, which explored the land use requirements and conservation impacts of achieving net-zero greenhouse gas emissions across the Western U.S.

Connected West leveraged Nature Conservancy’s findings to analyze transmission needs for a high electrification scenario involving various clean energy technologies, according to the report. The study evaluated three transmission expansion portfolios, with each portfolio exploring different pathways to improve grid capacity, reliability and efficiency.

Baker noted that although the costs are significant, “the benefit to cost ratio for all three portfolios was approximately 1.4 and assumed significant (approximately 70%) load growth over the next 20 years which could be leveraged to support this investment.”

Total benefits from the new transmission explored in Connected West would be between $250 billion to $275 billion, including up to $150 billion in avoided investments in power plants, $50 billion in avoided losses from extreme weather and $35 billion in reduced energy costs, among other benefits, according to the report.

“Our analysis shows that this level of expansion is not only achievable but necessary to meet the energy demands of the future,” Matthew Tisdale, executive director of Gridworks, said in a news release. “With proper planning, we can build the infrastructure needed to support a robust economy while minimizing costs. Simply put: it will be better for ratepayers, businesses and communities in the West if we make the right investments now to avoid higher costs and greater disruptions later.”

‘Unprecedented’

The Connected West study appears well-positioned to contribute to Western transmission discussions as two parallel efforts ramp up to spur development of the kind of interregional projects the region has struggled to build.

One of those is the Western Power Pool’s Western Transmission Expansion Coalition (WestTEC), which is being guided by electricity industry participants.

The other is the Western States Transmission Initiative (WSTI), which is being facilitated by Gridworks on behalf of the Committee on Regional Electric Power Cooperation’s membership of state energy agency officials. (See In West, Proposals for Tx Planning Proliferate Faster than New Lines.)

Baker called Connected West an “unprecedented study that provides a template for completing a 20-year, holistic, multi-benefit transmission plan.”

“Many other entities including WECC, CAISO, and the U.S. [Department of Energy] have completed 20-year transmission studies, but this is the first long-range transmission plan to integrate economy-wide decarbonization, multiple benefit streams, transmission technology portfolios and environmental siting considerations across the entire Western grid,” he said.

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With Three Mile Island Restart, Debate Continues on Co-located Load in PJM

Data centers and other concentrated electric consumers are increasingly seeking to purchase their power directly through nuclear generators in PJM, raising concerns among state regulators, consumer advocates and utilities that they may be able to skirt paying their fair share. 

Five years after shuttering, Three Mile Island Unit 1 is being resurrected as the Crane Clean Energy Center (CCEC) to supply Microsoft with energy through a power purchase agreement, while Talen Energy is seeking to amend the interconnection service agreement (ISA) for its Susquehanna Nuclear Plant to reduce its output to PJM and instead supply a co-located data center sold to Amazon Web Services. (See Constellation to Reopen, Rename Three Mile Island Unit 1 and Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)  

The latter has drawn protests from Exelon, American Electric Power and the Pennsylvania Public Utility Commission arguing that more information is needed about how the configuration may affect the grid and whether it will benefit from ancillary services, such as black start and regulation, without being assessed proper transmission fees. 

During a Sept. 24 hearing on co-located load held by the Maryland Public Service Commission, FirstEnergy Chief Risk Officer Abigail Phillips said nuclear generation can help meet a resource adequacy gap identified in 2029, with load forecasts driven by data centers and thermal resource deactivations outpacing development in PJM. 

“Right now it doesn’t seem like the capacity markets are paying for those capital costs of generation, and the price signals that PJM talked about this morning are increasing the prices, but in the past auction, no new dispatchable generation is going to come online,” she said. “So how long is it going to take to make those price signals work, and how long are we willing to wait and depend on that before we need to do something to get new generation on in Maryland and the rest of PJM?” 

Data center developers could be choosing to co-locate with dependable generators out of a concern that the PJM grid may not offer the same security it traditionally has, Phillips said, which underscores the need to determine how to ensure adequate capacity. Additional nuclear generation could hold the promise to meeting resource adequacy needs and climate goals at once, she said. 

“Nuclear is getting back into the conversation as a part of a zero-carbon solution. I know Maryland has clean energy goals, and I think that having nuclear back in the game is going to be helpful with achieving long-term capacity and long-term goals, not only for Maryland, but for PJM and the country,” Phillips said. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, drew a distinction between the CCEC and co-located load requests, saying that most advocates are supportive of bringing new nuclear generation online as the balance between supply and demand grows increasingly tight in PJM. Whereas the CCEC will bring about 835 MW of new generation online to serve existing load, he said co-location may be taking generation out of the markets to serve load not considered part of the grid and exempt from service charges. 

Where Poulos does see common ground between the CCEC PPA and co-located load configurations is the potential for major market impacts caused by the addition of large data centers, whether they are in or out of PJM’s market. 

He stressed that consumer advocates are supportive of the economic development that data centers promise the states they locate within, so long as there are rules to ensure that they pay their fair share for any services they consume or grid impacts they prompt. Co-location could also push transmission costs lower by reducing the need for new lines, he said. 

Advocates are also concerned about market power, Poulos said, with the potential for generation owners with a broad portfolio within a tight zone having the ability to pick a resource to take out of the market and push energy and capacity prices higher. Generators could contract with a data center to provide power well below the regional clearing price, knowing that other resources in their portfolio will clear at a higher price. Co-located configurations have the potential to distort price signals even without market manipulation by removing large volumes of load and generation from a zone, he said. 

“The market is supposed to provide the appropriate price signal, but if you have this other massive load being served in the same area offline, so to speak, it could impact the price signals. It could make them not accurate so the price signals aren’t reasonable in the market and for consumers,” Poulos said. 

PJM stakeholders had considered several proposals to change the market rules for co-located configurations last year, but none of them received majority support, and the topic was dropped. Poulos said it’s unlikely stakeholders will be able to make progress while FERC and state commissions are looking at the topic, and it will likely have to be FERC that makes the first move on the broad legal and jurisdictional questions. (See “Proposed Rules for Generation with Co-located Load Rejected,” PJM MRC Briefs: Oct. 25, 2023.) 

The RTO issued guidance around co-located configurations recommending that parties receive firm transmission service while stating that it does not have the authority to prevent private contracts between generators and load seeking to co-locate off the grid. (See “Additional Guidance on Co-located Load,” PJM MRC Briefs: April 25, 2024.) 

During the PSC hearing, Aftab Khan, PJM’s executive vice president of operations, planning and security, said the RTO has requests to study about 8 GW of co-located load configurations, mostly to serve data centers. When such requests are received, he said PJM conducts the “necessary studies” to ensure there is no adverse impact to the grid. Any required transmission upgrades to support the configuration are identified and must be implemented at the cost of the generator before the co-located load can come online. 

He said PJM considers non-network load co-located with interconnected generators to also be electrically connected to the RTO’s grid and benefiting from ancillary services, but it has no way of assessing fees. 

“Under any configuration, co-located load is electrically connected and synchronized to the PJM system when consuming power and therefore benefits from the use of the transmission system and ancillary services, such as black start and regulation services,” Khan said. “PJM network load accounts for such services, but there are no transmission or ancillary service charges to the off-system load. PJM previously tried to address this with proposed rule changes for ancillary services, but the proposal did not achieve the consensus of the PJM members.” 

Independent Market Monitor Joe Bowring also said the load is part of PJM’s grid and the broad impact should be holistically studied to identify impacts, rather than examined through amendments to generators’ ISAs. 

“All load, including co-located load, is on the grid, affects the grid and benefits from the grid,” Bowring said. “As a result, decisions about co-located load affect all customers.” 

Bowring said the Monitor’s analysis of co-location configurations did not find a substantial difference between cost allocation to consumers regardless of whether the load is considered part of PJM’s network or if the large load additions were made miles away from the generator. Instead, he said the underlying issue is how PJM identifies and studies large consumers. 

“It’s not just a question of co-located load; it’s a question about load in general. … What that illustrates and emphasizes is that the analysis has to be done carefully,” he said. 

Phillips told the PSC that it’s critical that the consequences of allowing generators to take their output off the market to serve non-network load is fully understood, both in terms of costs and reliability. 

“Any reduction in dispatchable, on-demand generation that’s available to serve residential customers should be analyzed before we make any changes to policy or regulation. We have to really understand when you co-locate and what that does to capacity, both short term and long term, how does that trickle down into who’s paying for it, who gets the benefit, and we have to make sure it’s not only cost affordable, but [also] we maintain that reliability,” she said. 

In a white paper published Sept. 23, Tony Clark, former FERC commissioner and senior adviser at Wilkinson Barker Knauer, and Vincent Duane, principal at Copper Monarch and former senior vice president of law, compliance and external relations at PJM, argue that allowing data centers to co-locate with nuclear generators allows them to avoid lengthy waiting periods while transmission upgrades necessary to accommodate their load are planned and built. But it can also alter power flows to require network upgrades before other networked loads can interconnect. They call for a cost allocation methodology that recognizes the benefits co-located load and generators receive from being part of the grid. 

“We would not advocate assigning to the co-locating generator the full cost impact of its withdrawal (as is done under the ‘but for’ test for new interconnections),” they wrote. “Nevertheless, the underlying principle — rooted in cost causation — offers a path to assign to the co-location arrangement its share of these cost impacts, thus restoring them to the position they would be in had they connected in the traditional manner.” 

Clark and Duane raise similar concerns about cost allocation for ancillary services and note that nuclear units receive public benefits, such as tax credits, grants and accelerated depreciation from the federal government and states. They argue that makes it especially questionable to allow units to leave RTO markets to serve private load. 

“From this perspective, nuclear generation is uniquely imbued with the public interest, making it unsettling if not unseemly for units, once the first data center comes knocking, to pull up stakes and desert customers that for decades have had their back,” they wrote.