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October 31, 2024

Iterative Changes to Interconnection Queues Discussed at Transmission Summit

ARLINGTON, Va. — Interconnection requests continue to grow, and grid operators have had to adopt waves of changes to try to keep pace with them over the years, experts said at Infocast’s Transmission & Interconnection Summit on Monday.

Lawrence Berkeley National Laboratory’s Joseph Rand opened up the conference going over the latest national queue figures he helped produce, which show 2,000 GW waiting to connect to the country’s grids. (See LBNL: Interconnection Queues Grew 40% in 2022.)

“Interconnection requests are growing across the country, in really every grid operator region that we analyze,” Rand said.

One exception in 2022 was CAISO, where it had to pause taking on new projects after a massive spike in requests in 2021. The ISO is processing its first batch of interconnection requests since then, and Rand said it is “another massive one,” which will turn that regional trend around.

While the queues signal plenty of interest in building out renewables, which are the dominant sources for new generation everywhere, most of the projects will not get built.

“People might say, ‘Well, maybe the queues are working the way they should: We’re encouraging generators to come online where it makes sense, in terms of the transmission system where there’s capacity on the system, and where it’s kind of most economically viable to do so,’” Rand said. “But on the other hand, I think it’s a little bit concerning to see completion rates as low as 20% and, by capacity, only about 14%.”

FERC has a pending Notice of Proposed Rulemaking on interconnection queues that would update its pro forma rules from a serial, first-come, first-served system to a cluster-approach that favors projects that are ready to go, Rand said. (See FERC Proposes Interconnection Process Overhaul.)

Some of the changes proposed by FERC have been in place in different markets for years, and they have had to continually improve their processes as the queues grew, he said.

MISO went to a cluster process 15 years ago, and it instituted a first-ready, first-served system years ago with an additional seven waves of changes since then, said Grid Strategies Vice President Richard Seide.

“So, one clear takeaway that everyone should understand: Queues are a work in progress,” he added.

Queue reform is a complex topic, so it makes sense that grid operators would take their time and tweak rules over years to see what works, said AES Vice President of Strategic Development Alexina Jackson.

“I really commend the last panel for recognizing that what we’re doing should be iterative,” Jackson said. “Queue reform is challenging.”

While FERC’s proposed revisions — and the changes PJM recently instituted that are largely in line with the NOPR — should speed up the process, Jackson said it was important to move some of the work around queues into the planning process. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

The energy transition is in the queues, as the resources there represent the clean energy mix the grid is moving toward, said RMI Manager Katie Siegner. She agreed with Jackson on FERC’s NOPR and PJM’s revisions.

“All of that is a really promising signal that we’re finally mustering the will and the resources to tackle the interconnection backlog that has become one of the thorniest challenges in the transition to a more carbon-free electricity mix in the U.S.,” she added.

PJM’s move to a cluster approach in studying projects in the queue will help move them forward by cutting the costs of network upgrades, but Siegner argued more would be needed if the RTO were going to meet the demand of state renewable portfolio standards, corporate clean energy contracts and federal policies pushing renewables.

Planning Transmission to Clear the Queues

Beyond connecting individual projects, the grid is forecast to have to double or even triple in size by midcentury to meet decarbonization goals in the power industry, while electrifying others, and that is a huge task, said Michael Colvin, the Environmental Defense Fund’s California energy program manager. That transmission expansion should include trunk lines out to renewable, resource-rich regions to bring them to market.

CAISO released a 20-year transmission plan that looked ahead to see how the grid would need to evolve as the state meets its clean energy and climate targets, said the grid operator’s vice president of infrastructure and operations planning, Neil Millar.

The 20-year plan was voluntary, but planners used some of its suggestions, and the extra information helped give the industry a lot more comfort that everything was moving in the right direction, Millar said.

CAISO went to a cluster approach back in 2010, and it has worked on reforming its queue every couple of years since then, said LS Power Senior Vice President Sandeep Arora. But projects entering the queue today probably won’t be built until the end of the decade.

“There’s only so many real estate opportunities, and every developer is after those same opportunities, right?” Arora said. “So, the cost of doing businesses is going up on the real estate side.”

Real estate is a major issue in developing new resources in the Northeast, especially anything along its coasts, with the high land values and the abundance of historic and cultural sites, said POWER Engineers Senior Project Engineer Ken Fortier. Given those realities, it makes sense to plan transmission corridors that can accommodate future generation to minimize the overall permitting process.

“We want to make sure we’re not going back and having to knock on those same landowners’ doors and say, ‘Hey, we built this line five years ago; I guess we’re going to be building it again,’” Fortier said.

The planning process in New England would have to be updated for such lines to be built, because right now it lags behind other regions, such as New York, in terms of planning for public policy, said NextEra Energy’s Michelle Gardner.

Demand is expected to grow in New England by 40% by 2035 and 72% by 2040 because of electrification, all while about 32,000 MW of renewables remains in the queue, said Eversource Energy Vice President of Transmission Policy Vandan Divatia.

“We can’t look at these in silos; we’ve got to try to co-optimize,” he added.

A major issue is who is going to pay for all the new transmission. Divatia argued that it should not be left to renewable energy developers; expanding the grid has societal benefits, so consumers should help pay, which will speed up the transition to cleaner energy. Eversource is doing that on Cape Cod, where its customers have paid for the equivalent of a 115-kV line, but it is building a 345-kV line with the difference footed by an offshore wind farm.

New England’s grid can handle about 5 GW of offshore wind without major upgrades, and the states have contracted for enough wind that now is the time to start thinking about expanding the grid to accommodate more, Gardner said. That could be handled by the states coming together and working with ISO-NE to figure out what upgrades are needed to make their offshore wind procurements feasible, she added.

The transmission planning side is generally more important than the queue in New England, Gardner said. While some projects have been stuck in the queue for years, they include wind farms in Northern Maine that face huge costs to connect.

“There may be some projects in the queue now that have been here for a long time, but it’s not because the queue is broken,” Gardner said. “It’s because they just can’t get down to the load. But projects in Connecticut or Massachusetts generally have processed appropriately through the ISO study.”

MISO-SPP JTIQ

In parts of MISO and SPP, all of the projects are impacted by other “affected systems,” which the two hope to overcome through the Joint Targeted Interconnection Queue (JTIQ) study, said NextEra Energy’s Matt Pawlowski.

“We have a lot of projects in both regions,” Pawlowski said. “We’ve had a lot of issues with affected systems and the timelines for affected-system studies that don’t align with our commercial time frames or the interconnection studies in each of the regions. So, if you have an SPP project, [you’ve] got to be hindered by the fact that there’s affected systems that don’t necessarily align with the study time frames in SPP and vice versa in MISO.”

Those delays can cause power purchase agreements and generation developments to be canceled, he said.

The JTIQ will lead to major, central lines designed to resolve any affected-system issues in northern MISO and SPP, said Sunflower Electric Power’s Clifford Franklin. In the past, the cost of dealing with affected systems has been so high that individual projects have not been able to bear it.

The plan invests close to $1 billion in major transmission upgrades, and while 90% of the cost is expected to be picked up by generation developers, load could be on the hook for cost overruns. That has led to some opposition, Franklin said.

Planning lines to deal with such issues will give project developers the certainty they need to move forward. “This stability of the rate, the entry fee, is what is hoped will reduce backlogs,” Franklin said.

Speculative Projects?

Projects have often pulled out of queues when faced with the need to fund transmission upgrades that erase any chance for them to profit, but some developers on the panel argued that they have reasons other than hunting for the cheapest grid connection to file “speculative projects.”

NextEra had some of those projects looking for a cheap connection back when the costs of doing so were low, but the nation’s largest renewable developer still has plenty of projects — for different reasons, Pawlowski said.

“Those speculative projects needed to be in there,” Pawlowski said. “And the reason why they needed to be in there is because if it’s going to take me five to six years, or even seven years, to go through the interconnection queue, I cannot provide my customers with projects if that study process is that long.”

If a client asks for a contract for a wind farm, they will not want to wait the six or seven years it would take NextEra to move a development through the queue process and then actually build it, so the firm has projects in the queue that it can sell to clients in years’ less time. The way to get around that is to make the process as quick as possible, Pawlowski said.

The Inflation Reduction Act put interconnections on steroids, and while the queues were busy before the law and its bevy of energy subsidies were passed, it has created a new dynamic, Seide said.

“The fact is, all of this money out there — private equity funds — they want interconnects, right?” Seide said. “So, when that process of dollars at risk would cause people to withdraw. That doesn’t happen today.”

In the past, some developers were scrappy, and raising the deposit amounts to weed out speculative projects from the queues would have worked, but that is no longer the case, he added.

Clean Path NY Joins Calls for Inflation Adjustment

Clean Path New York on Wednesday asked state regulators to include it in any inflation adjustments approved for Tier 1 renewable energy certificates (RECs), saying generators would otherwise shun the 174-mile transmission project being planned to deliver power to New York City.

CPNY — a project of the New York Power Authority, Invenergy and EnergyRe — filed its petition with the Public Service Commission in response to a June 7 request by the Alliance for Clean Energy New York (15-E-0302).

ACE NY asked the PSC to authorize the New York State Energy Research and Development Authority to add an inflation-adjustment mechanism for projects awarded through NYSERDA’s 2021 renewable energy certificate solicitation. ACE NY said its solar and onshore wind developer members were facing the same inflationary pressures that have caused offshore wind developers to seek to renegotiate their deals. (See OSW Developers Seeking More Money from New York.)

CPNY said it was seeking relief “due to the unforeseen and severe market disruptions that have occurred” since April 2022, when NYSERDA awarded it a contract to deliver 1,300 MW of renewable energy from upstate to Zone J in New York City. (See NYPSC OKs 2 Huge Clean Energy Projects for New York City.)

CPNY’s contract is based on a single strike price that includes production and delivery of emissions-free power, with a portion of the REC payments going to 23 generation projects and the balance used to fund the transmission line.

Fourteen of the 23 projects in CPNY’s generation portfolio hold Tier 1 contracts with NYSERDA, and the other nine are Tier 1-eligible wind and solar projects “that are experiencing exactly the same cost pressures,” CPNY said.

“To the extent that the commission provides an adjustment mechanism that shifts the price of Tier 1 RECs upward, CPNY will need to increase its payments to Tier 1 generators in order to induce their participation in CPNY,” it said. “If CPNY does not provide the same level of net revenues to [its] resources … those resources would be commercially disadvantaged by participating in the CPNY project and therefore motivated to participate only in Tier 1.”

CPNY, which emphasized it is not seeking to change the transmission component of its contract, asked the PSC to rule by Oct. 12. The transmission project, which has an expected in-service date of 2027, is currently undergoing permitting and interconnection analysis.

“If the commission fails to provide concurrent relief to CPNY, or if it fails to act on this request by its Oct. 12, 2023, session, CPNY will be unable to attract capital for the CPNY project or proceed with binding orders for the hundreds of millions of dollars in materials and equipment needed,” it said.

ERCOT: Prepared for Expected Record Demand

AUSTIN, Texas — ERCOT has wasted no time in putting its new emergency communications system to use, issuing its first weather watch Tuesday ahead of triple-digit temperatures that are expected to smash existing demand records.

The watch, an early public notification of a weather forecast that signals high demand, begins Thursday and extends through June 21. The ISO says grid conditions are normal, but the weather conditions and expected demand will mean lower operating reserves.

The National Weather Service is forecasting triple-digit temperatures across much of the state during the waning days of spring, with highs of 103 F in Austin. Humid conditions Wednesday pushed the heat index to 112 F in Corpus Christi and 115 F in Brownsville.

ERCOT’s new six-day forecast projects demand will reach 81.3 GW on Friday and then hit 83.2 GW on June 20. Both marks would break the record of 80.14 GW set last July. The ISO set 11 peak records last year as it exceeded pre-summer expectations by more than 2.6 GW.

“Ah, it’s the summer crisis season,” cracked one attendee at the Edison Electric Institute’s annual meeting in Austin.

The grid operator’s final seasonal assessment for the summer forecasted a summer peak of 82.7 GW, assuming typical summer grid conditions. (See ERCOT, PUC Repeat Call for Dispatchable Generation.)

ERCOT expects to have about 90 GW of available seasonal capacity during much of the weather watch. Solar capacity has nearly doubled from last year, from 8.66 GW to 16.85 GW. Energy storage capacity has also grown since last summer, from 1.29 GW to 3.29 GW.

CEO Pablo Vegas said staff will closely monitor conditions and “deploy all available tools to manage the grid.”

The weather watch is part of a new communications strategy resulting from reliability concerns following the 2021 winter storm. (See “New Grid Notifications Added,” ERCOT Monitor Recommends New Market Design in Report.)

Meteorologists are predicting an El Niño climate pattern this year. El Niños are marked by warming surface water temperatures in the Pacific Ocean that tend to raise temperatures. They often also bring more rain to the southern U.S.

New Ancillary Service Product

The Texas grid operator last week added a new daily procured ancillary service to its suite of products for the first time in 20 years — the ERCOT contingency reserve service (ECRS).

ERCOT said it has procured an average of 2,073 MW of ECRS per hour at an average price of $25.26 MWh since June 10. It says the product is necessary because load and generation are constantly changing due to daily load patterns, instantaneous load variation, changes in intermittent generation output, and generators tripping offline.

ECRS offers capacity that can be sustained at a specified level for two consecutive hours. It will be deployed to restore frequency within 10 minutes of a significant deviation; to compensate for intra-hour net load forecast uncertainty when large amounts of online thermal ramping capability are not available; or when limited capacity is available for dispatch.

ERCOT began procuring the service on June 10, fulfilling a directive from Texas regulators to improve grid reliability. (See ERCOT Technical Advisory Committee Briefs: May 23, 2023.)

“As summer temperatures begin to rise across Texas and with high demand forecasted, we will continue to use all operational tools available, including implementation of new programs like ECRS,” Vegas said in a statement.

NYISO Management Committee Briefs: June 13, 2023

Vote Set on Rate Schedule 1

BOLTON LANDING, N.Y. — NYISO stakeholders will vote July 26 on whether a new study should be conducted to evaluate the cost allocation between transmission withdrawals and injections.

ISO officials previewed the vote on the Rate Schedule 1 cost-of-service study Tuesday at a joint Board of Directors and Management Committee meeting.

Rate Schedule 1 governs the charges made to market participants using NYISO’s open access transmission system and helps ensure that all participants are charged fairly for their services.

RS1 allocations were last changed in 2011 and are currently set at 72% for withdrawals and 28% for injections. Roughly 67% of the MC at the time supported the allocations, which were scheduled to be effective for a minimum of five years, with a Management Committee vote required in the third quarter of this year.

Recent attempts to adjust RS1 allocations were voted down by stakeholders. (See “Cost of Service Study,” NYISO Management Committee Briefs: July 28, 2021.)

But the ISO told stakeholders Tuesday: “In recent years, discussions with market participants have indicated that a study is necessary in the future due to evolving market changes.”

The most recent RS1 allocation study, performed by Black and Veatch in 2011, cost about $215,000 and took six months to complete. The study included analysis of ISO data, staff interviews, and comparison of practices of other grid operators.

The ISO has steadily increased the allocation for injections since 1999, when withdrawals were allocated 100% of costs.

Should the MC vote to conduct a new study, NYISO anticipates new RS1 allocations would be effective by 2025.

Solicitation for MMU Evaluations

NYISO has opened its annual solicitation of stakeholder feedback on its market monitoring unit, Potomac Economics.

NYISO is asking for comments on the MMU’s performance, suggestions on how the MMU’s duties should change or improve, and opinions whether the ISO should search for a new MMU.

The ISO has worked with Potomac for more than a decade, and some attendees had questions about this ongoing relationship.

One attendee expressed concerns about the ISO’s reliance on Potomac’s proprietary software, asking if there could be issues should either the ISO decide to work with another MMU or the data gets compromised.

Shaun Johnson, director of market mitigation and analysis at NYISO, responded that Potomac has made significant upgrades to their cybersecurity and information technology systems and has an off-site datacenter that backs up their data to give them redundancy capabilities. Should the ISO hire another MMU, any transition would include considerations about how Potomac’s NYISO data would be shared and used, he said.

The same attendee asked whether NYISO’s relationship with the MMU has changed over the years, saying there is a perception that the ISO does not listen to Potomac’s recommendations as much as before.

“We have meetings and conversations with the MMU every day,” Johnson said. “So what you see at stakeholder meetings are maybe just the end results or beginning of those conversations.

“Just like within NYISO and within the stakeholder community, sometimes we agree with each other, sometimes we disagree with each other, but it’s really about collaborating to come up with the best results,” Johnson said.

NYISO requested that comments be sent to either sjohn@nyiso.com or deckels@nyiso.com by July 31. Submitted feedback will be confidential.

FERC Update

FERC staff updated the MC about what the agency has been doing for the past year and what plans NYISO should be aware of.

FERC energy industry analyst Emily Chen said FERC is reviewing NYISO’s third Order 2222 compliance filing to determine whether more revisions are needed (ER21-2460). (See “FERC Compliance Filings,” NYISO Business Issues Committee Briefs: May 24, 2023.)

Leanne Khammal, deputy director of FERC’s Division of Electric Power – East, said the agency continues to work on improving interconnection queue backlogs via Notices of Proposed Rulemaking (RM22-14), develop more effective winter emergency and reliability plans with Northeastern RTOs, and host technical conferences that seek to improve transmission planning processes, such as the upcoming PJM Capacity Market Forum.

Staff also told the MC that FERC is searching for a new NYISO liaison, since the position’s previous holder recently retired. Staff said they are looking at ways to improve the role via stakeholder feedback.

FERC’s Danly, Christie Again Warn Congress of Looming Reliability Crisis

FERC’s two Republican commissioners told members of Congress on Tuesday that the U.S. is heading toward a reliability crisis driven by the rapid retirements of dispatchable fossil fuel-fired generators.

Appearing before the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security, each of the four sitting commissioners painted a different picture of the state of grid reliability in the country. While they gave different critiques of the resource mix, Commissioners James Danly and Mark Christie had ominous outlooks, harshly criticizing FERC-approved market designs in the RTOs and ISOs.

“The United States is heading towards a reliability crisis in our electric markets,” Danly said. He cited two primary factors: “the effect of subsidies” for intermittent renewable resources, “and the commission’s, let’s call it, ‘abandonment’ of its longstanding commitment to the rule of law.”

“I think we’re headed toward potentially very dire, potentially catastrophic consequences in the United States,” Christie said. “The basic reason is we’re facing a shortfall of power supply. … The problem is not the addition of wind and solar. The problem is the subtraction of coal and gas and other dispatchable resources.”

The commissioners’ statements were similar to those they gave to the Senate Energy and Natural Resources Committee last month. (See Senators Praise Phillips, FERC’s Output at Oversight Hearing.)

Republican members of the subcommittee agreed, though they were eager to blame the Biden administration, particularly EPA’s newest proposal to reduce power plant emissions, for the impending doom.

“The commission must do more to resist such regulations that run contrary to its core mission,” proclaimed subcommittee Chair Jeff Duncan (R-S.C.). “Electric reliability has significantly degraded over the past few years. Blackouts and energy rationing are now commonplace in wholesale electricity markets like California and Texas. The nation’s largest grid operator, the PJM Interconnection, issued a dire warning earlier this year that it may face significant capacity shortfalls because of, in large part, rules like the EPA has proposed.”

“It’s essential the commission return to its core mission of facilitating the delivery of abundant, affordable energy resources, like natural gas and electricity, to Americans,” said Cathy McMorris Rodgers (R-Wash.), chair of the full committee. “FERC must resist calls by the radical left to circumvent the commission’s mandated priorities.”

Acting FERC Chair Willie Phillips (D) sought to assure the subcommittee that “reliability is, and always must be, job No. 1.” He listed several actions the commission has taken related to reliability and grid resilience since he took the helm at the beginning of the year, including directing NERC to develop new cybersecurity standards.

Phillips also said his highest priority “in the near term is to finalize a proposed rule that will greatly improve our processes for interconnecting new electric generating resources, reducing the time it takes to bring those resources online.”

Neither side of the aisle of the subcommittee gave that statement much attention. For their part, Democrats used much of their time to question how, if at all, FERC accounts for environmental justice when approving natural gas infrastructure.

Ranking member Diana DeGette (D-Colo.) did ask Phillips whether the recently enacted Fiscal Responsibility Act, which ordered NERC to study interregional transfer capability, would delay FERC’s work on the issue. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)

“NERC is directed to do a study under the debt limit deal; we also have an ongoing proceeding at FERC,” Phillips responded. “It is my belief that those two proceedings can move forward in parallel. … It is not my intention to wait” for NERC to complete the study.

Zero-emission Truck Sales Accelerating, Report Shows

In what’s being called “breakthrough growth,” more than 3,500 zero-emission medium- and heavy-duty trucks were deployed in the U.S. in 2022, more vehicles than in the previous five years combined, according to a new report.

The 3,510 vehicles added in 2022 bring to 5,483 the number of zero-emission trucks (ZETs) purchased and placed into service in the U.S. from January 2017 through the end of 2022. The figures are in a report released by CALSTART, a national nonprofit focused on clean transportation technologies.

Zero-emission trucks are also becoming more widespread. Since mid-2022, seven states — Arkansas, Delaware, Montana, Nebraska, Oklahoma, Rhode Island and Wyoming — have seen their first ZET deployments, the report said.

The zero-emission vehicles tallied in the report include Class 2b to 8 trucks, classifications that are based on weight. The trucks range from larger pickups, cargo vans, and step vans to semis, garbage trucks, and on-road yard tractors.

The trucks include battery-electric and hydrogen fuel cell vehicles. Hybrids aren’t counted.

The 5,483 deployed ZETs are only a minute fraction of the 26.7 million trucks registered in the U.S. in 2022. But continued strong growth in ZET deployment is expected.

“This growth rate is expected to continue its aggressive upward trend as more OEMs enter the market, established OEMs expand their offerings, and fleets become more comfortable with the technology,” CALSTART said in its report.

As of December, more than 136 medium- and heavy-duty ZET models from more than 41 manufacturers were available for purchase.

Shifting Trends

As recently as March 2022, on-road yard tractors were the most-deployed type of zero-emission truck, according to a previous CALSTART report. Vehicles with low range requirements, such as yard tractors, were dominating ZET deployments, the previous report said. (See With Calif. in Lead, Clean Truck Sales Accelerate Nationwide.)

But now, smaller ZETs have taken the lead.

Cargo vans accounted for 2,565 deployments, or almost half of ZETs placed into service from 2017 through 2022. The price of the zero-emission vans compares favorably to that of their gas-fueled counterparts, the report said, and models such as Ford’s E-Transit van and BrightDrop’s Zevo 600 have become popular.

“This market is expected to grow quickly, thanks in part to the new federal Commercial Clean Vehicle Credit, which provides up to $7,500 in tax credits to mitigate the incremental cost,” the report said.

The second-most deployed ZET in the report was yard tractors, with 912 vehicles placed into service.

But pickup trucks scooted into third place, accounting for 831 of ZETs deployed. Zero-emission pickup trucks in the Class 2b weight category became available last year, the report noted.

Deployments by State

Among the 5,483 ZETs placed into service since 2017, CALSTART was able to identify locations for 3,107 of the vehicles.

Among those ZETs, California led the way, with 1,472 deployments. New York followed with 186 ZETs, while Florida and Texas had 137 and 131 deployments, respectively.

Fifty-nine percent of ZET deployments were in states that had adopted California’s Advanced Clean Trucks rule. As of December 2022, those include California, Oregon, Washington, Massachusetts, New York, New Jersey and Vermont. Advanced Clean Trucks requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles each year.

California is also home to the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP) for medium- and heavy-duty trucks. From 2011 to 2022, HVIP issued vouchers for 3,149 ZETs totaling $315 million, or roughly $100,000 per vehicle on average, according to CALSTART, which administers HVIP on behalf of the California Air Resources Board (CARB).

California ZET deployment may also get a boost from the Advanced Clean Fleets regulation that CARB adopted in April. (See CARB Adopts Clean Fleets Rule Despite Broad Skepticism.) The regulation requires truck fleet operators to start transitioning to zero-emission vehicles starting in January 2024, and all new medium- and heavy-duty trucks sold in the state must be zero-emission beginning in 2036.

How Much Energy It Will Take to Electrify Trucking

The Biden administration’s goal to achieve net zero emissions from transportation by 2050 will require an increase in the generation and delivery of an additional 1,800 terawatt-hours per year, estimates the Electric Power Research Institute.

Watson Collins, an engineer and senior technical executive at EPRI, offered the estimate Tuesday during a webinar organized by the North American Council for Freight Efficiency, a trucking industry initiative sponsored in cooperation with the Rocky Mountain Institute, an environmental organization.

“The grid today [carries] about 4,000 terawatt-hours,” Collins said, estimating the additional power needed to electrify transportation as roughly “about a 50% increase in throughput on the grid.”

“This is going to take 20 years,” he said, adding he’s not concerned since utilities made a similar increase in the past few decades to electrify heating, air conditioning and myriad other electrical functions.

In the meantime, Collins said trucking companies considering the cost of running electric trucks instead of diesels must keep in mind that “the slower you charge is better, [and] is cheaper. The infrastructure is less expensive. And it’s better for the batteries.” 

EV Charge Cost Impact (Electric Power Research Institute) Content.jpgWhen an EV is charged is just as much a price determining factor as how much power the charge uses. | Electric Power Research Institute

 

The faster a trucking company must charge its vehicles, the less likely those rigs will be cheaper to operate than traditional diesel vehicles, he explained, at least at today’s fuel and power prices. Slower charging during the night or off-peak hours during the day also will make the electric truck more cost-competitive compared to diesel, he added.

“There’s a huge savings potential if you’re charging the vehicles in the off-peak period. That’s part of why I’m mentioning that off-peak is usually the slow-charging, longer-duration charges, because you can save a lot of money.” Local utility infrastructure also is significant, he said.

An EPRI survey of utilities found that 60% would not have to immediately build costly and time-consuming upgrades to accommodate trucking company depots increasing their demand by no more than 1 MW.

By contrast, 60% of the utilities surveyed said they would need to build upgrades to handle a load increase of 20 MW, he said.

Robert Graff, a senior technical adviser at RMI and adviser to NACFE, said most commercial electric vehicles in use today are limited to 350 kW, “with many operations getting by with 50 kilowatts or less.”

“Charging at this level meets the needs of many fleets, particularly single-shift return-to-base operations.

“As the use of commercial battery electric vehicle expands … there will be use cases that will benefit from higher-power charging, such as adding hundreds of miles of range to heavy-duty trucking during around-the-clock operations,” he added.

Ted Bohn, an engineer with Argonne National Laboratory, said work now is concentrated on standardizing components and voltages. He said the lab has been experimenting with 350-kW units “tied in parallel to come up with 3,000 amps … at 1,000 volts and 300 amps.” That combination figures to 3 MW, he said.

By comparison, most home 240-volt EV chargers draw no more than 7,200 watts — less than 10 kW — according to the Department of Energy.

Emil Youssefzadeh, an engineer and chairman of WattEV, a California firm that leases Class 8 trucks and builds the charging stations to electrify them, said what his company has encountered is “a level of slowness” from utilities building upgrades to supply the company’s growing demand from the expansion of charging depots.

WattEV rents drayage trucks to companies working at the Port of Los Angeles, where diesel exhaust emissions had become a major problem.

But relying solely on a local utility for power may not always be necessary, Youssefzadeh said. “Is there a solution other than grid power? The answer is that we’re looking at different alternatives, putting in microgrids, solar with distributed energy resources, [to offer] higher capabilities, to go to 20 megawatts,” he said.

NACFE Webinar Panel (Electric Power Research Institute) Content.jpg

Ryan Menze, an engineer managing charging hardware and software engineering at Daimler Trucks North America, said the company has analyzed the situation in a process similar to balancing a series of mathematical equations.

“If any of these three things — technology, cost parity or infrastructure — is zero, we will not be successful as an industry. We will not be successful as an organization in pushing zero-emission technologies,” he said.

The company’s Freightliner division has designed a series of heavy-duty trucks marketed under the eCascadia model. 

“From a technology perspective, on the vehicle side [of the equation], we need to ensure that we have the charging capabilities and can meet the range demands of our customers,” Menze said.

“One of the big technology analogies I like to use is [that] it’s kind of a balance. We need to have the right amount of charge speed which enables enough range and the time that our customers have using their 30-minute required breaks that they have to take every day and opportunity charging, when possible, but also having the necessary range on a single charge in order to complete their missions throughout the day,” he said.

The webinar was one of a series planned by NACFE and RMI in preparation for a three-week event in September designed to measure and record the charging, resilience and local distribution grid capacity at eight trucking depots operating fleets of at least 15 electric trucks. Seven of the depots are in California; the eighth is in Queens, N.Y.

The scrutiny of depot operations follows a similar series of real-world testing of trucking fleets by NACFE since 2016. (See DOE Offers $100M for Electrification of Heavy Trucks, US Way Behind China in Deploying Heavy-duty EVs,
Electric Trucking, from Delivery Vans to Big Rigs, are Coming, Report: Electric Heavy-duty Trucks Can Now Replace Some Diesels.)

Moore Picks Energy Attorney Suchman to Round out Maryland PSC

Maryland Gov. Wes Moore (D) submitted his third nomination for the state’s Public Service Commission on Wednesday, naming energy attorney Bonnie Suchman to take the seat currently held by Commissioner Odogwu Obi Linton.

Suchman will join incoming Chair Fred Hoover, an attorney in the Office of People’s Counsel, and Commissioner Kumar Barve, a long-time state delegate from Montgomery County. Hoover will begin his term July 1, following the expiration of current Chair Jason Stanek’s term.

Barve replaced Commissioner Patrice Bubar, attending his first commission meeting on June 7, according to Tori Leonard, PSC communications director. Exactly when Suchman will attend her first commission meeting is uncertain, Leonard said. She will need to be sworn in at a state district court at a time of her choosing.

Suchman’s resume includes stints as special counsel for electric utility restructuring at the U.S. Department of Energy during the Clinton administration and as a senior attorney focusing on transmission issues for the Edison Electric Institute. She also led the energy practice at Troutman Pepper, where she worked on both state and federal energy policy issues. She has continued working on energy issues with her own practice, Suchman LLC.

Barve was first elected to the Maryland House of Delegates in 1991. Before Moore tapped him for the PSC, he had been chair of the House Environment and Transportation Committee since 2015. He was also majority leader in the House from 2003 to 2014.

He is also the CFO for EMSI, a small environmental services company located in Rockville.

Bubar, Linton and Stanek were appointed to the PSC by former Gov. Larry Hogan (R), but Bubar and Linton were not confirmed by the Senate. Moore rescinded their nominations after taking office.

Hoover, Barve and Suchman will also have to be confirmed by the General Assembly when it is back in session in January 2024. They join Commissioners Michael T. Richard and Anthony O’Donnell, both reappointed by Hogan for second terms in 2020 and 2021, respectively.

Kim Coble, executive director of the Maryland League of Conservation Voters, applauded Suchman’s appointment and “the Moore administration for putting forward somebody that has extensive experience in utilities and electricity.”

“The thing that I think is important here is to understand in Maryland … the PSC plays a really significant role, and a unique role in advancing the … electricity agenda,” Coble said. “The Moore administration has made their commitment to climate change very clear … and so to have somebody with [Suchman’s] background helping to advance [this] agenda, I think it’d be a strong asset to the state.”

Moore ran afoul of Coble and other energy advocates earlier this year when he nominated Juan Alvarado, senior director of energy analysis for the American Gas Association, to the commission. As opposition mounted, Alvarado withdrew his nomination. (See Alvarado Withdraws from Md. PSC Nomination.)

Reliability Panel Highlights Benefits of Interregional Transmission

As more clean energy comes online and extreme weather accelerates, states need to work together to unlock the reliability benefits of increased interregional transmission, said a panel of experts convened by the American Council on Renewable Energy to discuss NERC’s Summer Reliability Assessment.

The assessment found that while all regions have adequate supply to cover peak load under normal conditions, most regions face elevated risk of shortfall during extreme weather conditions. NERC said this elevated risk is due largely to retirements of fossil fuel generators and above-average projected summer temperatures across most of North America, consistent with long-term climate trends. (See NERC Warns of Summer Reliability Risks Across North America.)

“My review of the NERC summer assessment is there’s nothing particularly surprising,” said Commissioner Andrew French of the Kansas Corporation Commission. “I think it continues to highlight trends and concerns that we’ve seen crop up over the last several years. I definitely don’t view it as a specific indication that anything will happen, or anything won’t happen.”

French said the loss of dispatchable fossil fuel generators has reduced the state’s safety cushion of excess generating capacity, which is driving reliability risks. He said that in the short term, policymakers should focus on retaining resources that provide reliability benefits, while focusing in the long term on the reliability attributes of expanding demand response programs and interregional transmission.

To put a better value on the reliability benefits of transmission investments, French said planning processes should incorporate a calculation related to the value of lost load, along with potentially valuing “large-scale interregional transmission as a generating capacity resource.”

Simon Mahan, executive director of the Southern Renewable Energy Association, said the summer outlook looks manageable for the Southeast but cautioned against settling into a false sense of security. “There are extreme weather events that could come in and radically change your plans quickly. When that happens, it’s important that we have the regional and the interregional transmission capability available to us so that we can import power if we need it, or we can export power to our neighbors if they need it.”

Danielle Mills, principal of infrastructure policy development at CAISO, said California is in a better position than last year because of improved hydro conditions and the addition of 3,000 MW of battery storage in the state.

“We still do see some risk associated with those periods after 8 p.m. when the solar generation is declining if we have high loads and a lack of availability of imports” Mills said.

Mills said the state is “looking at opportunities to improve transmission planning across the West and look at interregional transmission planning projects, as well as projects that can provide power to California from out of state.”

Nicole Hughes, executive director of Renewable Northwest, said nothing in the report was too concerning, but instead “more of an indication of risk to come.”

Hughes agreed with the assessment that expanding the grid will be essential to mitigating reliability risks in the future. She said the inadequate transmission infrastructure has made it difficult to bring renewable energy generation online to meet the region’s clean energy goals.

With CAISO being the only ISO on the West Coast, Hughes touted the benefits of a potential Northwest RTO.

“Pretty much it’s across-the-board accepted in our region that we need … more of an RTO that can bring us all together and limit the number of balancing areas, and I think the Western Resource Adequacy Program is going to be a good test model for that,” Hughes said.

Led by the Western Power Pool and approved by FERC this year, the Western Resource Adequacy Program will coordinate resource adequacy efforts across 10 Western states and British Columbia. (See FERC Approves Western Resource Adequacy Program.)

Mahan also highlighted potential benefits of an RTO for the Southeast to limit the number of balancing areas and improve reliability. He noted that a Brattle Group report released this year for South Carolina found that the state would generate about $300 million in net benefits by integrating with PJM.

Warren Lasher, former senior director of system planning at ERCOT, said that growing electricity demand poses a significant challenge for Texas. He added that increasing frequency of extreme weather events can make it difficult to project reliability based on historical data.

Hughes said the impacts of climate change on both wildfire risks and the capability of hydroelectric resources in the Northwest will be difficult but essential factors to model in the future.

“We rely significantly on the hydropower system, and there’s a lot of questions about what that’s going to look like going forward,” Hughes said. “What is average seems to be changing, and that’s why diversity of resources across a larger grid is so important.”

NJ OSW Projects Face Public Funding Scrutiny

Public financial support for New Jersey’s offshore wind projects has come under scrutiny from lawmakers as Danish developer Ørsted seeks to obtain access to federal tax credits to help offset rising supply chain and materials costs on its Ocean Wind 1 project.

A think-tank report published June 5 on the state’s rapidly growing OSW sector said the developer has been “locked in negotiations for months” with state officials in an effort to use federal offshore wind tax credits created under the 2020 Stimulus Act and the Inflation Reduction Act (IRA).

“Ørsted’s argument is that material, labor and borrowing costs have soared in the runaway global inflation that followed the COVID-19 pandemic,” pushing up costs to higher levels than when the developer bid on the project, according to the report, which was compiled by the Sweeney Center for Public Policy at Rowan University.

New Jersey law, however, requires tax benefits from offshore wind projects to be returned to ratepayers. That contrasts with other states, among them New York, which allows developers to use the federal tax credits, the report says. It added that the administration of Gov. Phil Murphy and legislators “have been in discussions on a bill to authorize Ørsted to retain the full federal tax credits.”

The New Jersey Board of Public Utilities approved the 1.1 GW Ocean Wind in 2019, in the state’s first solicitation, and in 2021 approved the 1.148 GW Ocean Wind 2, also an Ørsted project, and the 1.51 GW Atlantic Shores. The state in March launched a third solicitation.

Stephanie Francoeur, a spokeswoman for Ørsted, said it and other developers are in discussions with the state and the BPU “to address the macroeconomic challenges facing early stage offshore wind projects, including opportunities made available by federal tax incentives.”

“We continue to assess existing federal tax credits to support our local investments, create jobs,” she said. “We remain committed to Ocean Wind 1 and look forward to continuing our conversations with New Jersey policymakers to help address these unforeseen challenges.”

Atlantic Shores, the developer of the project of the same name, declined to comment.

The prospect of an increase in assistance to offshore wind developers, however, stoked bipartisan resistance at a May 23 hearing of New Jersey’s Senate Budget and Appropriations Committee. Two committee members expressed concern that the state would provide additional financial assistance to developers under pressure from inflation and rising costs, and pressed Joseph L. Fiordaliso, the BPU president, on the agency’s plans.

Sen. Paul Sarlo (D), the committee’s chairman, said it “has been hearing some rumors that there is going to be a request from this body to subsidize the wind projects that are currently under construction,” and asked if that was true. When Fiordaliso responded, “Not that I am aware of,” Sarlo made clear his antipathy to giving extra help to offshore wind developers.

“I’m probably one of the most pro-business, pro-development legislators,” Sarlo said. “I’m going to have a very difficult time supporting any type of future subsidies.”

“These are large players, international players who knew what they were getting into when they built these facilities,” he said. “They’re going to have to step up their game. We don’t bail out every developer in the state of New Jersey who gets himself into a new adventure, a new endeavor.”

Rising Headwinds

The flap was one of several recent gusts of headwind against the offshore wind sector. Last week, the BPU postponed an item from its agenda that would modify the scope — seemingly due to cost increases — of the state’s $1.1 billion offshore transmission project to tie offshore wind projects to the grid. The agency also put back by five weeks the deadline for the state’s third offshore wind solicitation, to Aug. 4, to give developers more time to put together their submissions. (See NJ BPU Pulls Offshore Tx Project Mod from Agenda After Complaint.)

In addition, the county of Cape May, through which a cable for Ocean Wind 1 will pass, on May 26 passed a resolution opposing the Ørsted projects and has filed an appeal against a BPU decision to grant an easement across county land for the cable. The sector also has faced a steady drumbeat of concern over the death of several whales on the Jersey Shore that project opponents say might be due to preliminary work on the wind projects, despite state and federal officials saying they’ve found nothing linking the deaths to the projects, which have yet to start construction.

Fiordaliso, at the BPU’s meeting last Wednesday, expressed frustration at the offshore developers, although it was unclear what triggered the outburst.

“We have had, almost since Day 1, delay after delay after delay,” he said. “All one developer in particular has done is delay this process for one reason or another.”

He did not identify the developer, although Ørsted is the only one involved since Day 1.

Asked about Fiordaliso’s comments, Madeline Urbish, Ørsted’s head of government affairs in New Jersey, said they were “unexpected,” and added that the company is committed to completing Ocean Wind 1.

She said the developer is working closely with the BPU, the New Jersey Department of Environmental Protection and federal agencies, “despite early delays in federal permitting” and cited the “unprecedented macroeconomic challenges [that] have led to significant cost increases for capital-intensive industries across New Jersey and the U.S., including the offshore wind energy industry.”

“The available federal programs, including the Inflation Reduction Act, present an opportunity to address inflationary costs without increasing costs for ratepayers,” she said in an email to NetZero Insider, but added that they won’t “entirely cover the increased costs the project has faced due to inflation, supply chain constraints, and interest rate hikes.

Francoeur, noting that projects in other states can receive the tax credits, said that without these, New Jersey runs the risk of threatening early stage supply chain investments, manufacturing and jobs.

Escalating Costs

At the committee hearing, Tim Sullivan, CEO of the New Jersey Economic Development Authority (EDA), which has provided much of the funding for the state’s OSW projects, sought to distinguish between federal and state subsidies. He said the IRA would provide a “tremendous amount of resources” to support offshore wind projects, but “that is not at the expense of ratepayers.”

But Sen. Steve Oroho (R), echoed Sarlo’s concern, saying that the state’s Office of Legislative Services had calculated that the “amount of taxpayer subsidies already committed to the wind port and related projects alone totals more than $1 billion.” The funds include a $350 million loan program to support offshore wind related businesses and funds to support the construction of the New Jersey Wind Port, which will provide space for marshaling OSW projects and manufacturing turbine parts. (See NJ $1 Billion OSW Port and Marshaling Hub 60% Finished.)

“And despite this $1 billion already in taxpayer subsidies, wind port project costs are rapidly escalating to the point where Ørsted and vendors are threatening the project could stall without massive additional subsidies,” he said. “That is where the concern comes.”

Disappearing Promises

The issue has added to an already-simmering debate over the cost of the state’s clean energy program and efforts to position itself as a regional player that can provide wind port, marshaling and manufacturing services to projects along the East Coast. Republicans and some business groups have expressed concern at the cost of the projects, and the lack of a concrete estimate of how much they will cost ratepayers.

Speaking at a March 6 BPU meeting, then-Commissioner Dianne Solomon — who left the board last month, after Murphy replaced her — said she had been concerned “from the outset” at the cost of the OSW projects. She spoke before voting in support of the BPU’s launch of its third solicitation of OSW projects.

“It appears that with every solicitation, promises are made that somehow disappear or we learn of increases in costs,” said Solomon, who was first nominated to the board by Republican Gov. Chris Christie.

“For instance, with the first [OSW] solicitation, we were assured that any federal funds or investment tax credits would be used to offset the cost of the OREC,” she said. “But we now learn that legislators are poised to give the funds back to the developer.”

Fiordaliso responded, as he did at the budget hearing, by citing the example of the subsidies for the state’s now strong solar sector. “Initially, is it going to cost more money, yes,” he said of the wind sector. “But the prices will continue to come down just as they have in the solar industry.”

Monopile Factory Phase “in doubt”

The Sweeney Center report said the state’s inability to reach an agreement over the use of federal tax credits would put “in doubt” a key element of another part of the state’s OSW plan — a manufacturing plant at the Paulsboro Marine Terminal that makes monopiles, the massive steel poles that support a wind turbine.

The first phase of the project, a joint venture between EEW, a German monopile manufacturer, and Ørsted, is up and running, with the help of a $160 million investment from the Danish developer, the report said. But the second phase of the project is “already more than a year behind schedule,’ the report said.

Both Ocean Wind 1 and Atlantic Shores agreed in their bid solicitation to use monopiles made at the Paulsboro plant. But completing phase two of the plant is dependent on the two plants moving forward, and that is “contingent on legislative action,” the report said.

That in turn is holding up manufacturing and means the factory may not be able to meet its delivery deadlines with the two projects, the report said.

Francoeur said that EEW’s Paulsboro facility has the “potential to be a premier supplier for U.S. offshore wind projects and that continued capital investments made possible by the federal government, along with a steady stream of demand for monopiles, are critical to its long-term success, as they are for all domestic supply chain initiatives.”