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October 30, 2024

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FERC Approves More Extreme Weather Rules

FERC on Thursday approved two new rules intended to strengthen the grid against extreme weather events.

The commission ordered NERC to either update reliability standard TPL-001-5.1 (transmission system planning performance requirements) or create a new rule that would require responsible entities to plan specifically for both extreme heat and cold weather events (RM22-10). Either way, entities will be required to create a corrective action plan to mitigate any occasions where performance requirements for extreme weather have not been met.

FERC also directed transmission providers to submit a one-time report detailing their policies and processes for conducting extreme weather vulnerability assessments and mitigating identified risks (RM22-16, AD21-13).

Based on the staff’s presentation at FERC’s monthly open meeting in Washington, D.C., the commission made only minor alterations from when the rules were first proposed about a year ago. (See FERC Approves Extreme Weather Assessment NOPRs.)

Both rules will take effect 90 days after their publication in the Federal Register, and transmission providers will be required to submit their reports within 120 days of publication. FERC had originally proposed that the reports be due in 90 days. The commission also approved extending the public comment period on the reports to 60 days, from the 30 originally proposed. In doing so, FERC agreed with the Edison Electric Institute and other commenters that the time periods were too short. (See ERO Supports FERC Weather Assessment Proposal.)

According to Alyssa Meyer, an energy industry analyst in FERC’s Office of Energy Policy and Innovation, the final rule also requires transmission providers to include in their reports how they define extreme weather and how RTOs and ISOs account for differences between transmission owner members’ assumptions and results.

“For the first time, reliability standards will require planning for extreme heat and cold weather,” acting FERC Chair Willie Phillips said in a statement. “NERC will develop the standards, and once we approve them, transmission owners and operators will identify the elements of their systems that are vulnerable to extreme heat and cold and develop solutions to address those vulnerabilities.”

Elliott: Different Storm, Same Outages

Before the commission approved the orders, FERC staff presented some preliminary findings of the commission’s joint inquiry with NERC into the December 2022 winter storm, also known as Winter Storm Elliott.

Unplanned generator outages exceeded 70 GW of capacity. The three main causes of the outages, staff said, were mechanical problems, equipment freezing and lack of fuel availability. Natural gas production, processing and shipping was hindered by compressor facility and well outages.

The observations are familiar: They are essentially the same as those in a 2021 technical conference held in the aftermath of a February winter storm (Uri) that nearly led to the collapse of the Texas Interconnection. Thursday’s orders stemmed from that conference.

“We’re seeing the same three causes, so therefore we think that it makes all the sense in the world to continue full steam ahead on implementing prior recommendations” from Uri and other previous severe winter storms, said Heather Polzin, an attorney adviser in FERC’s Office of Enforcement. Those include weatherizing equipment, inspecting facilities before winter and reviewing emergency operations plans.

Phillips said after the presentation, “Let me be clear: I want to join [staff] in encouraging, urging, cajoling all the utilities — every covered entity — to not wait. Implement these recommendations now. Right now. We know, to borrow a phrase, ‘Winter is coming.’”

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NERC, Trade Groups Oppose Call for Quick Fix on CIP Standards

NERC and several electric industry trade groups asked FERC this week to reject a petition to change how assets are classified under the Critical Infrastructure Protection (CIP) standard, saying it duplicates an ongoing initiative (EL23-69).

The Secure-the-Grid Coalition last month asked FERC to order NERC to propose an “enhanced standard” for identifying critical infrastructure using the “most recently updated engineering models used in operations.” The group, which describes itself as “policy, energy and national security experts, legislators and industry insiders who are dedicated to strengthening the resilience” of the grid, said NERC should be required to submit the proposed standard within 90 days.

In its response, NERC noted that it already plans to review reliability standard CIP-014-3 (physical security) in a joint technical conference with FERC on Aug. 10 (RD23-2) and through a separate reliability standards development project. CIP-014 requires transmission owners to identify which of their transmission stations and substations are critical to bulk power system reliability and implement a physical security plan for protecting them. The standard requires similar protection for primary control centers controlling critical assets.

“The petition does not allege any significant new circumstances, nor does it raise factual issues that are not ripe for consideration through the current NERC initiatives addressing the physical security of the BPS. Since appropriate forums for considering the petitioner’s ideas have already been or are in the process of being established, development of a new rulemaking to address similar physical security issues is not necessary at this time,” NERC said.

In a separate filing, the American Public Power Association, Edison Electric Institute, Large Public Power Council, National Rural Electric Cooperative Association and Transmission Access Policy Study Group protested the petition, calling it duplicative, unsupported and procedurally deficient.

The groups said the Secure-the-Grid Coalition failed to make its case that CIP-014 requirements for conducting threat assessments are deficient.

“The petition’s support for this request is the bare assertion that ‘[b]ased on the increasing frequency and sophistication of attacks against electric grid infrastructure, and the growing evidence that there is a persistent intent to conduct such attacks from domestic anarchist and extremist groups and foreign adversaries, a more prudent new metric is now required for these “Risk Assessments.”’”

Citing their comments in docket RD23-2-001, the trade groups said their members “are acutely aware of the physical threats posed to the grid, and of the importance of effective protective measures. Notwithstanding an uptick in physical security events in recent years, however, simply pointing to a number of recent events does not establish the need for the commission to direct changes to the threat assessment requirements of CIP-014.”

The trade associations also said FERC should reject Secure-the-Grid’s petition for failing to follow commission rules requiring petitioners to first ask NERC to initiate a new reliability standard. The groups also said the petition should have been filed as a complaint.

Responding to an increase in reports of physical attacks on substations, FERC in December ordered NERC to evaluate the effectiveness of CIP-014. NERC responded with a report in April concluding that the existing criteria are still appropriate to “focus limited industry resources” on the most critical grid facilities and that expanding the criteria would not identify additional critical substations. (See NERC Says Changes Coming to Physical Security Standards.)

However, NERC agreed to conduct a technical conference with FERC to identify the type of substation configurations that should be studied to determine whether any additional substations should be included in the applicability criteria and to establish data needs for conducting those studies.

NERC also said Requirement R1 of CIP-014 should be refined, acknowledging inconsistencies in how entities perform the risk assessment, with some failing to provide sufficient technical studies or justification for study decisions.

NERC’s report recommended a reliability standards development project to clarify the risk assessment methods for studying instability, uncontrolled separation and cascading.

NERC told FERC this week that the project “will be commencing in the near future.”

“Petitioner has not demonstrated a significant change in circumstances or that there is a sufficient problem to merit a generic solution that would necessitate a rulemaking prior to and without the benefit of the public stakeholder processes,” it said.

In a second FERC filing June 13, Secure-the-Grid said it was acting on behalf of the “American public … whose security interests are grossly underrepresented by NERC.”

The group rejected the position that “the costs are too high to invest in widespread and mandatory physical protection of the electric grid.”

“We think the costs are far too high NOT to invest in this protection, and we believe that the public will be willing to pay more for their electricity to see this protection realized,” it said.

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Panelists Debate PJM Capacity Market at FERC Forum

PJM officials and stakeholders told FERC Thursday they oppose abandoning the RTO’s capacity market but disagree over the degree to which it needs to be changed.

The four FERC commissioners heard from 20 RTO officials, state regulators and other stakeholders during a nearly five-hour “Capacity Market Forum,” which the commission scheduled in response to concerns over the RTO’s ability to maintain resource adequacy as dispatchable coal and gas-fired resources retire and are replaced by renewables (AD23-7).

Chair Willie Phillips at the FERC hearing on PJM Capacity Market

FERC Chair Willie Phillips | FERC

“NERC and PJM and others have warned us, early and often, that current forecasts could lead to a supply gap in certain regions over the next few years caused by early plant retirements and far slower development timelines to bring new resources online,” FERC Chair Willie Phillips said in opening the session.

Commissioner Mark Christie, a former Virginia regulator, questioned whether PJM should consider an alternative to the capacity market.

“The statement that the PJM capacity market is fundamentally sound — it just needs some tweaks — this is now the 19th consecutive year I’ve heard that,” he said. “… As we look out to the future … is the PJM capacity market something we can just keep sticking some bubble gum and some rubber bands [to] keep the thing going?”

Marji Philips, senior vice president of wholesale market policy for LS Power, said the market is “broken” because the introduction of intermittent generation means it no longer comprises “fungible” products.

Consultant James Wilson, who represents state consumer advocates, acknowledged PJM is facing a transition but said the market has “enormous excess capacity” and noted that other regions such as California have integrated far higher proportions of wind and solar power. “The house is not burning,” he said.

Independent Market Monitor Joe Bowring also defended the market but said it needs more than “tweaks,” calling Capacity Performance a “failed experiment.”

During Winter Storm Elliott in December, he said, new combined cycle generators performed worse than old combined cycle plants. “There’s no excuse for that,” he said.

Speakers at the FERC hearing on the PJM Capacity Market

FERC Commissioner Mark Christie (left) listens to Kent Chandler, chair of the Kentucky Public Service Commission | FERC

Kent Chandler, chair of the Kentucky Public Service Commission, said the capacity market is only part of PJM’s challenges.

“Even if you fix the capacity market, even if you fixed [resource] accreditation, you’re still going to have gas-electric coordination issues,” he said.

He cited Philips’ criticism that the Intercontinental Exchange is requiring generators to purchase gas four days in advance before the Independence Day holiday because July 4 falls on a Tuesday.

“You know, I’m happy that the gas market is apparently good to have a very enjoyable long weekend on Fourth of July,” he said. “But if we have system issues, that’s going to be a problem. … People are going to have to go find their old Rolodex and try to get ahold of people.”

Energy Landscape ‘Changing Dramatically’

Speaking during the first of three panels, PJM CEO Manu Asthana said the capacity market has historically achieved its goal of sending the price signals needed to incentivize generation where it’s needed, yielding a grid that’s remained reliable even as NERC reports that large portions of the country are at elevated risk this summer.

“Having said that, the energy landscape is changing, and it’s changing dramatically. Policy choices are resulting in accelerated retirement of the generation we use to manage our grid today, and frankly policy choices are chilling investment in new dispatchable generation,” Asthana said.

Asthana said the capacity market can continue to function alongside renewable incentives, so long as accreditation and risk modeling are done properly to ensure that existing resources are valued correctly.

Asthana was joined on the panel by NERC CEO Jim Robb, former FERC Commissioner Phil Moeller, now executive vice president of the Edison Electric Institute, and Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).

Robb said NERC has found that reliability risk has been increasing across the country over the past five years, referencing a May report warning of an elevated potential for insufficient reserves in many regions. (See NERC Warns of Summer Reliability Risks Across North America.) Although PJM was not identified as being at risk, he said its identification of 40 to 50 GW of capacity that could be retiring by 2030 means it could soon be on the map.

The traditional one-outage-in-10-years reliability metric is becoming outdated and needs to be replaced with a focus on providing energy in every hour, he said. Grid operators also need to improve planning around how extreme weather is modeled, he said.

“We need to make sure investments that are needed to maintain reliability purposes are compensated for and reflected in the design of the markets. Markets have demonstrated an incredible ability to drive out inefficiency, but they really haven’t demonstrated their ability to reward the reliability investments that are going to become increasingly valuable as an insurance policy against extreme weather events and common condition challenges such as wind droughts and solar droughts,” he said.

In NERC’s post event analysis of the December 2022 winter storm, 2014 polar vortex and other major storms, Robb said natural gas availability has been an issue. He said the gas distribution system performs well at its historical role of keeping pilot lights lit, but it was designed in a time when it was a niche fuel for energy production.

“Right now natural gas is the single largest fuel for power generation, and power generation is the single largest customer of the natural gas industry. Every winter event we’ve analyzed has had the supply of natural gas to power generation and the ability of that system to perform to meet the needs of customers as a common theme. … At some point we’ve got to take this problem on, but it’s a bigger problem than any of us can solve individually,” he said.

Moeller said jurisdictional questions make addressing coordination between the electric and gas industries complex. But if the cause of winter deliverability issues is on the transportation side, rather than gas production, there may be solutions such as how force majeure is declared and transparency when outages occur, he said. He expressed hope that work the North American Energy Standards Board is engaged in will yield solutions the commission can act on.

Poulos cautioned against a focus on retaining existing generation, arguing that PJM should incentivize the entry of reliable resources, rather than picking and choosing resource types.

Commissioner Christie said the capacity market’s “constant state of churn” is undermining investment in new resources.

“The big problem PJM faces is because you’re a big multistate RTO and your problem is not economic … it’s political. PJM has 13 states and D.C., and the policies of those states have diverged tremendously since the first time [the Reliability Pricing Model] was approved,” he said. “Wouldn’t an SPP model be better for reconciling the different state policies and let them figure out what to build and what to buy, as opposed to trying to hold this thing together with all these states diverging?”

Asthana said PJM is set up to accommodate fixed resource requirements and bilateral contracts, while retaining the capacity market for load that’s open to retail choice and maintaining reliability across a large geographic area.

Bowring and Poulos agreed, saying that the capacity market has reduced prices for consumers while preserving reliability while other regions experience elevated risk.

Critical Issue Fast Path Process

On a second panel, representatives of power providers, environmental groups and state consumer advocates debated the solutions the RTO is considering through the critical issue fast path (CIFP) stakeholder process.

Adam Keech, PJM’s vice president of market design and economics, said the core of the RTO’s CIFP proposal includes improving risk modeling by moving away from the assumption that the peak load and reliability risk are aligned. PJM also seeks to improve accreditation to better reflect what capacity resources will be available when needed and to rework performance incentives to align them with the market seller offer cap. At the CIFP meeting on Wednesday, PJM also proposed a shift to a seasonal capacity market to account for the identification of higher risk in the winter.

Glen Thomas, president of the PJM Power Providers (P3) Group, said accreditation is important but needs to be accompanied by changes to allow generators to recover costs, reflect risks in their bids and limit the potential of demand side market power.

Todd Snitchler, CEO of the Electric Power Supply Association, said accreditation of all resources, thermal and intermittent, must be improved.

“If load is going to grow, you’re going to need more, not less [generation]. You’re going to need both and, not either-or. But certainly it suggests that you’re going to need certain performance characteristics that will enable your system to operate reliably,” he said.

Michelle Bloodworth, CEO of coal power industry group America’s Power, agreed, saying that generators likely to retire under pending state and federal policies will take valuable contributions to reliability with them.

“Whether that’s coal or another thermal resource, those attributes are being lost that PJM still needs,” she said.

The Sierra Club’s Casey Roberts said accreditation should account for fuel availability, saying that if gas-fired resources cannot procure fuel on short notice, they may not be as flexible as believed.

Susan Bruce, of the PJM Industrial Customer Coalition, said while many consumers support a seasonal market, there has to be a focus on the drivers of winter risk.

“I think there is interest in a seasonal auction from a customer perspective. However, getting that cost allocation piece right is complex and important, and just replicating what we have for summer to winter I don’t think is the solution, because the reason why we have winter risk is because we have performance issues,” she said.

Commissioner Allison Clements questioned what role the interconnection queue is playing in the pace of new resource development.

Abigail Ross Hopper, CEO of the Solar Energy Industries Association, said queue challenges remain significant. There will likely be a significant period of time when few new resources will be constructed because of the amount of time it takes to get approved for interconnection, she said.

LS Power’s Philips said PJM’s market rules do not reflect the realities of demand response and peaker plants, which tend to be rarely called upon and be price capped when they are dispatched.

“This market is not addressing the reality of who needs the money, and it’s not sending the price signals,” she said.

Chair Phillips questioned whether PJM is considering changes that can address some of the issues behind Winter Storm Elliott, including the sharp drop in temperatures.

Keech said PJM is using a longer weather history lookback to capture cyclical patterns and tying reliability risk and generator performance to weather. It also is looking at options outside the capacity market, including notification to gas units, scheduling and modeling uncertainty in the energy and reserve markets and the costs that are recoverable for reserve commitments, such as fuel procurement.

FERC hearing on PJM Capacity Market

Regulators and public advocates from Ohio, New Jersey, Kentucky, D.C., Maryland and Delaware (left) spoke to FERC during the forum’s third panel. | FERC

A third panel featured state regulators and public advocates, including Kentucky’s Chandler; Ohio Commissioner Dan Conway; New Jersey Commissioner Zenon Christodoulou; D.C. Public Service Commission Chair Emile Thompson; William Fields, deputy people’s counsel for Maryland; and Ruth Ann Price, deputy public advocate for Delaware.

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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.

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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.

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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.

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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.

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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.

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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.

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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.)