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September 27, 2024

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Pathways Initiative Releases ‘Step 2’ Proposal for Western ‘RO’

The West-Wide Governance Pathways Initiative on Sept. 26 released its “Step 2” draft proposal for dividing up functions between CAISO and the new “regional organization” (RO) that initiative backers are seeking to create to oversee the ISO’s Western real-time and day-ahead markets.

The draft proposal calls for the RO to launch in the form of the “Option 2.0” structure discussed in Pathways meetings, one in which the RO would serve primarily as a “policy-setting” body around market rules for the Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM).

The plan stops short of adopting “Option 2.5,” which would have the RO take on more of CAISO’s market functions and legal responsibilities — but also the accompanying financial and legal risks.

But Pathways backers — and the proposal itself — are leaving open the potential for transitioning to the second option once the new entity is established.

“This is really the recommendation for creating a new independent entity that can have sole authority over [CAISO] market services,” Kathleen Staks, co-chair of the Pathways Launch Committee, said during a joint meeting of the CAISO Board of Governors and Western Energy Markets (WEM) Governing Body shortly after release of the proposal.

“It was very important to make sure that we were communicating with the West that we intend for this thing to continue to be able to grow as the West wants it, as utilities demand it and stakeholders demand it. We need this new regional organization to be able to add market services,” said Staks, who is executive director of Western Freedom.

A fact sheet accompanying the proposal notes the plan (emphasis Pathways’) “is not a consensus document but a draft proposal with wide-ranging recommendations to solicit additional stakeholder feedback.”

According to the fact sheet, under Option 2.0, the RO “will have full authority over market rules, sole Federal Power Act Section 205 rights and ultimate authority over associated business practice manual provisions.”

Under CAISO’s existing tariff, the ISO’s board and WEM Governing Body share joint authority over the WEIM and EDAM. In August, both bodies voted to implement the Pathways “Step 1” proposal, which grants the WEM body “primary” authority over the markets, a tariff change still pending approval by FERC. (See CAISO, WEM Boards Approve Pathways ‘Step 1’ Plan.)

Option 2.0 would elevate that “primary” authority to “sole” authority and shift the oversight to the RO, which would effectively assume the role of the Governing Body.

“Sole 205 rights in Step 2 means that the CAISO board does not have any lingering unilateral authority, which exists today and persists in Step 1 in some exigent circumstances, to make a 205 filing at FERC that unilaterally imposes the CAISO board’s policy view regardless of the views of the other body,” the proposal says.

The only area for which CAISO’s board would retain sole 205 authority is for rules “applicable specifically” to the ISO’s balancing authority or grid.

But the proposal has the ISO continuing to perform day-to-day market operations “within the scope of its existing corporate authority, with varying levels of input from the RO.” Under the plan, RO and CAISO rules would also reside within a “single integrated tariff,” and the ISO would remain the counterparty for existing market contracts.

“One premise of the Pathways Initiative is that consumers across the West would be better served by drawing on the existing CAISO software, hardware, facilities and expert operators, rather than designing, building and paying for this infrastructure and expertise from scratch,” the proposal says. “This premise goes hand in hand with the notion that the widest possible integrated footprint, inclusive of California, would be better for consumers than the alternative.”

Because Step 2 grants the RO sole authority over CAISO markets, its implementation will require a change to California law, according to legal analysis performed by law firm Perkins Coie, an adviser to Pathways. The campaign to begin lobbying lawmakers was already in evidence this past summer, but Pathways supporters say the effort will begin in earnest with the next legislative session starting in January 2025. (See California Labor Groups Affirm Support for Pathways Proposal and California Energy Officials Pitch Pathways Plan to State Senators.)

Passage of a bill would put the ball back into CAISO’s court.

“The ultimate tariff changes will have a [CAISO] stakeholder process, but that wouldn’t begin until after a bill passes in California,” Staks told RTO Insider in an email.

Structure

At 133 pages, the Step 2 draft proposal goes well beyond governance functions to detail the proposed structure of the RO, which would be incorporated as a 501(c)(3) nonprofit corporation in Delaware and maintain its principal place of business in Folsom, Calif., near CAISO’s headquarters. It would be overseen by a seven-member board of directors selected to meet FERC’s independence requirements.

The proposal’s fact sheet says the RO’s “articles of incorporation, bylaws and other corporate documents will center on public interest protections and transparency,” while a Public Policy Committee of the board “will engage with states, local power authorities and federal power marketing administrations about potential impacts to state, local or federal policies before final board adoption of a tariff change or an initiative through the stakeholder process.”

The proposal additionally calls for the RO to engage with the WEIM’s existing Body of State Regulators and establish a Consumer Advocate Organization and Office of Public Participation. It would also create a joint structure for CAISO’s Department of Market Monitoring to report to both the ISO and RO boards.

The draft plan also outlines formation of the RO’s sector-based Stakeholder Representatives Committee (SRC), “which will serve as the primary body responsible for overseeing and guiding the development of new initiatives.” The proposal describes the SRC’s three-part process, consisting of issue identification and prioritization, discussion and solution development, and RO board approval. (See Comments on Western RO Stakeholder Plan Show Complexity of Effort.)

“By incorporating sector-based representation, the SRC will ensure that a balanced range of perspectives is considered, promoting collaboration and consensus through sector-specific discussions. This structured approach will enable stakeholders to identify and address key issues collectively, thereby influencing policy development outcomes in a meaningful way,” the proposal says.

The exact constitution of the SRC is still a work in progress, and the Launch Committee has scheduled an additional meeting to discuss the subject on Oct. 7.

Planting a Seed

The proposal additionally calls for the RO to consider transitioning — “over a defined period of several years” — to Option 2.5 after performing more analysis and gathering stakeholder input on making such a move. Under that option, the RO would take on more of CAISO’s market functions and legal responsibilities, and potentially reorganize itself under its own tariff while maintaining a vendor contract with ISO as market operator.

“In Option 2.5, deeper division of liability between two corporations, overall higher cost both to the CAISO and RO, and to stakeholders as a whole, plus the extensive negotiations we anticipate will be involved to rework dozens of pro forma regulatory contracts in Option 2.5, prevent us as a committee from strongly (as opposed to tentatively) recommending Option 2.5 at this stage,” the proposal says.

A financial table in the proposal shows the RO’s estimated annual operating costs under Option 2.5 would be nearly $23.9 million, including $17.7 million for in-house staffing, compared with $13.7 million under Option 2.0, which would incur about $10.6 million for labor.

The proposal calls for the RO board to perform “a deeper feasibility analysis, with stakeholder input, to assess the costs, benefits, possible expanded market functions, implementation details of how to achieve the additional corporate independence and responsibility, and to determine whether a departure from Option 2.5 is warranted.”

The analysis should be one of the board’s “initial priority tasks,” to be started within nine months of the RO’s formation, the draft adds.

“The idea here is that we will plant a seed. … We’re working with stakeholders and with you to plant the seed into fertile soil and to help water it and help it grow,” Launch Committee Co-Chair Pam Sporborg, of Portland General Electric, said during the CAISO board meeting. “But we do envision that as this organization takes root, that it will grow into what we call Option 2.5, [which] will have expanded authority and take on the actual responsibility, including a lot of the liability and compliance obligations associated with running the market.”

The Launch Committee will hold a stakeholder meeting to discuss the draft proposal on Oct. 4 and is accepting written comments on the plan until Oct. 25. It expects to release a final recommendation the week of Nov. 15.

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California GETs Bill Gets Newsom’s Signature

California Gov. Gavin Newsom has signed a bill that proponents say will speed the deployment of grid-enhancing technologies — techniques that can rapidly boost grid capacity and increase the use of renewable resources. 

Senate Bill 1006 was signed into law Sept. 25. It will require utilities to study the feasibility of using advanced reconductoring and other grid-enhancing technologies (GETs) and submit reports to CAISO, which will review the findings as part of its annual transmission planning.  

A second bill related to GETs is awaiting the governor’s signature. Assembly Bill 2779, by Assemblymember Cottie Petrie-Norris (D), would require CAISO to report any new use of GETs that it deems reasonable, along with the cost savings and efficiency of that technology, when it approves a transmission plan. 

The report would go to the California Public Utilities Commission (CPUC) and committees in the state Assembly and Senate. 

Newsom’s deadline to sign or veto bills is Sept. 30. If the governor takes no action on a bill passed by the legislature, it becomes law without his signature. 

SB 1006, by Sen. Steve Padilla (D), notes that California must “rapidly and cost-effectively” increase transmission capacity to meet its decarbonization goals. 

While new transmission lines “will absolutely be necessary,” GETs are a way to increase capacity at a fraction of the cost of new lines, Padilla said in a release when he introduced the bill. 

“Grid-enhancing technologies can be installed in months and often pay for themselves within a year based on access to lower-cost generation alone,” Julia Selker, executive director of the WATT Coalition, said in a letter urging Newsom to sign the bill. 

GETs listed in SB 1006 include dynamic line ratings, advanced power flow control and topology optimization, as well as advanced reconductoring. 

Under SB 1006, transmission utilities will have two reports due Jan. 1, 2026. The first will look at the feasibility of using GETs to achieve one or more of the following goals: 

    • Increase transmission capacity. 
    • Reduce transmission system congestion. 
    • Reduce curtailment of renewable and zero-carbon resources. 
    • Increase reliability. 
    • Reduce the risk of igniting wildfire. 
    • Increase capacity to connect new renewable energy and zero-carbon resources. 
    • Increase flexibility to reduce risks surrounding technology and permitting uncertainties in statewide electrical system planning and improve optionality for load-serving entities. 

The second study will evaluate which of a utility’s transmission lines could be reconductored to achieve goals similar to those outlined for the first study, with two additions: reducing line losses and increasing the ability to quickly energize new customers or serve increased customer load. 

Utilities will repeat the first study every two years and the second study every four years. 

Supporters of SB 1006 and AB 2779 include Advanced Energy United. 

The bills “will unlock the potential of these revolutionary grid technologies, enabling us to meet rising power demands while minimizing rate impacts so we can keep the lights on without spending an arm and a leg,” Edson Perez, Advanced Energy United’s California policy lead, said in a statement in August. 

Another bill related to GETs, AB 3246 by Assemblymember Eduardo Garcia (D), died in committee last month. The bill would have streamlined the approval process for advanced reconductoring of existing power lines. 

GETs are also called out in a $10 billion climate-resilience bond measure that California voters will decide next month. (See Calif. Lawmakers Send $10B Climate Bond Measure to Nov. Ballot.) 

SB 867, which sent the bond measure to voters, includes $325 million for clean-energy transmission projects, with preference potentially given to projects that provide multiple benefits, such as reconductoring and other GETs. 

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FERC Reliability Conference to Highlight Resource Adequacy

FERC’s annual Reliability Technical Conference next month will feature discussions of cyber and physical security threats, resource adequacy, extreme weather and other emerging concerns to grid reliability, according to an agenda posted Sept. 24 (AD24-10).

The commission hosts the technical conference each year to “discuss policy issues related to the reliability and security of the” electric grid, with panelists from across the ERO Enterprise and other industry participants. Panelists at this year’s conference include NERC CEO Jim Robb — who will also deliver an opening presentation on the state of reliability — along with NERC Chief Engineer Mark Lauby and representatives from MISO, ISO-NE, CAISO, Duke Energy and Southern Co.

The 2024 technical conference will be held at the commission’s headquarters in D.C. on Oct. 16 at 10 a.m. ET. It will also be viewable online.

In the first panel, attendees will discuss a range of challenges currently facing the electric grid, including the rapid spread of inverter-based resources and distributed energy resources, along with “the increased use and importance of natural gas … for system balancing.” Load growth from severe weather and cyber and physical threats are also on the panel’s agenda.

Robb’s co-panelists include Carrie Zalewski, vice president of transmission and electricity markets for the American Clean Power Association; Todd Ramey, senior vice president of markets and digital strategy for MISO; Nelson Peeler, senior vice president of grid strategy, planning and integration for Duke Energy; and Randy Howard, general manager of the Northern California Power Agency.

The second panel will focus on the challenge of maintaining resource adequacy amid “the retirement of existing generation resources, the addition of significant volumes of variable energy resources and rapid anticipated electric load growth” from sources such as data centers. Topics of discussion by the panelists will include appropriate metrics for capturing resource adequacy risk, the challenges of forecasting the addition of new large loads and whether existing resource adequacy mechanisms can procure enough resources to meet future demand.

Panelists on this session will include Lauby, South Dakota Public Utilities Commission Chair Kristie Fiegen, Data Center Coalition President Josh Levi, Hoosier Energy CEO Donna Walker and CAISO Director of California Regulatory Affairs Cristy Sanada.

At the 2023 event, FERC Chair Willie Phillips and his colleagues focused in on cyber and physical security, extreme weather and the power grid’s changing resource mix, with Robb joined by Electricity Information Sharing and Analysis Center CEO Manny Cancel and SERC Reliability CEO Jason Blake, among others. (See FERC Conference Highlights Challenges of Evolving Grid.)

The conference has also provided stakeholders with an opportunity for airing frustrations with the ERO’s approach to reliability standards development and enforcement. At the 2021 conference, several participants criticized NERC’s standards process for being inherently conservative and giving significant influence to industry members who will be subject to penalties for noncompliance. (See Cybersecurity, Climate Change Lead FERC Conference.)

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State, Industry Reps Debate Future of Gas at NECA Fuels Conference

BOSTON — In a reflection of broader disagreements across the New England energy landscape, speakers at the Northeast Energy and Commerce Association’s 2024 Fuels Conference presented divergent visions of the role of natural gas in coming decades.  

New England states face significant pipeline constraints limiting the amount of gas that can be transported into the region. That has spurred expensive long-term contracts to secure LNG supply to support the reliability of the gas system during period of peak demand. (See Massachusetts DPU Approves Everett LNG Contracts.) 

Gas demand for electricity generation and for residential, commercial and industrial needs has risen in recent years. That has led the gas industry and some large consumers to call for increased pipeline capacity.  

Matthew Piatek of S&P Global said that though annual gas demand in the Northeast is projected to decline slightly by the end of the decade, peak demand will remain high.  

“The price swings that we see moving forward may be more severe than they have been in the past,” Piatek said. Producers likely will be cautious about increasing supply going forward, and he said to “expect some price repercussions before there’s a supply response.” 

New England’s reliance on LNG likely will continue over the medium term to meet peak demand, Piatek said, but a pipeline expansion could reduce LNG reliance.  

While aggressive deployment of demand-side measures and pilot projects for technologies like networked ground-source heat pumps also could help ease peak demand pressures, “more work needs to be done on the actual commercial viability of different options,” Piatek said. 

Doubling down on natural gas likely would run contrary to state climate mandates. Massachusetts has aggressive sector-specific decarbonization requirements, and natural gas is the main source of emissions from the state’s power and building sectors. Methane leaks — which typically are undercounted in emissions inventories — have a far greater short-term warming effect on the climate than carbon dioxide. 

Conflicts over the future of gas have caused notable tensions among top Massachusetts lawmakers. While the Massachusetts Department of Public Utilities (DPU) has ruled that decarbonization of the state’s gas network likely will be based on electrification, the DPU also has indicated legislative changes are needed to initiate decommissioning of parts of the gas network (DPU 20-80). 

Disagreement over potential legislative changes helped derail negotiations on a wide-ranging climate bill this summer. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform.) The debate also has played out in other states across the region; both Maine and Rhode Island have ongoing studies into the future of natural gas. 

Marc Brown of the Consumer Energy Alliance, which represents a wide range of industrial energy consumers including major fossil fuel companies, argued that natural gas “is going to play a very important role in balancing out this energy transition.” 

“I don’t see gas as a transitional fuel, I see it as here for the long term,” Brown added. 

Regarding concerns that new investments in natural gas infrastructure could lead to burdensome stranded costs, Brown said “nobody likes stranded costs, but we should also be concerned about upfront costs” associated with widescale electrification.  

From left: Rich Kassel, AJW; Robin Vercruse, Low Carbon Fuels Coalition; Stephen Dodge, moderator, Clean Fuels Alliance America; Floyd Vergara, Clean Fuels Alliance America | © RTO Insider LLC 

Anastasia Daou, of commercial real estate association NAIOP, echoed Brown’s concerns about upfront costs and said Massachusetts building energy codes finalized in 2023 will increase the cost of new building development.  

“The building sector is feeling a little targeted recently,” Daou said, noting that adding costs to new building projects “is simply going to stop development.” 

Government representatives from Maine and Massachusetts pushed back on the narrative that the states are moving too quickly away from gas.  

“We’re clearly headed toward a future where we are less reliant on natural gas,” said Melissa Lavinson, executive director of Massachusetts’ newly created Office of Energy Transformation. Lavinson emphasized that the state has legislatively mandated emissions limits and that the DPU has directed the state’s electric distribution utilities to pursue “basically an electrification pathway” for decarbonization. 

Maine Public Advocate William Harwood said, “the public expects us to meet those greenhouse gas emission goals,” and it’s the job of lawmakers to cut emissions while keeping energy costs as low as possible, protecting low-income customers and keeping businesses afloat.  

“You don’t have to be paying particularly close attention to understand that there are very serious environmental consequences — along with public health consequences — associated with burning gas within homes,” Harwood said. 

Harwood said states must look ahead when considering new gas investments to minimize stranded costs and must be honest about who will pay for stranded costs when they occur.  

“When we get to that point, there is going to be a huge fight over whether those costs are the responsibility of ratepayers or shareholders,” Harwood said. “I don’t know that there’s a good solution for who pays for stranded costs.” 

Low Carbon Fuel Standards

Also at the conference, several speakers made the case for low carbon fuel standard (LCFS) programs to cut transportation emissions. LCFS policies typically incentivize low-carbon fuels through charges imposed on carbon-intensive fuels.  

LCFS programs targeting transportation emissions have been rolled out in California, Washington and Oregon but have yet to gain significant traction on the East Coast.  

Rich Kassel, a partner at consulting firm AJW, said an LCFS is “the only program in the transportation sector on the large scale that addresses emissions from existing vehicles.” 

LCFS programs in the West have reduced emissions of local pollutants and particulates due to the cleaner-burning properties of renewable diesel and biodiesel, Kassel said.  

Kassel added that the greatest pollution reductions have occurred in environmental justice neighborhoods and that the equity benefits could be even greater if a small percentage of revenue generated by the program were required to be spent in environmental justice communities. 

“It’s the way you get Exxon to buy electric school buses in West Harlem,” Kassel said.  

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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 a 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 Commission 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 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.