The city of Beverly, Mass., is advancing its fleet-wide electric school bus changeover for the district in July with the addition of its second of 48 buses.
Beverly tested its first electric school bus starting last October after entering into a lease agreement with Highland Electric Transportation. The company helps school districts afford electric school buses by leasing them out annually and using vehicle-to-grid (V2G) incentives.
Highland purchases all the power for the buses and uses V2G technology to sell power back to the grid when demand is high. Payments from utilities go back to the school district to offset the upfront cost of electric buses.
Dana Cruikshank, director of transportation for Beverly Public Schools, told NetZero Insider he could “smell the difference” between the district’s electric bus and its traditional diesel buses. Battery powered electric buses reduce the amount of emissions school kids are exposed to, and they are quieter than traditional combustion engines.
“The elementary school kids call it the ‘magic bus,’” Cruikshank said, because the bus driver and students can have conversations without yelling over the sound of a traditional combustion bus engine.
The Beverly School District in Massachusetts is adding an additional electric school bus to its fleet in July after a successful six-month start with its first electric bus. | Beverly Public Schools
The school bus charges overnight on a smart charging system in Beverly’s bus yard that powers on when the buses are below 100%. It takes the bus three hours to charge completely, and it will run for 125 miles before it needs to charge again.
The lease payment includes the cost of electricity and repairs, which “makes the buses affordable to us,” Cruikshank said. “We’re not a huge district.”
While electric buses are more expensive to purchase than diesel buses, lower maintenance and operations costs make the transition more affordable in the long term for school districts, Cruikshank said.
“Anything new we purchase will be electric,” he added.
The Beverly School District’s electric bus project was Highland’s first as a company. And because it has been successful, the project “put us in a position to do much larger projects,” said Matt Stanberry, managing director of market development at Highland.
Montgomery County’s public schools in Maryland struck a deal with Highland in February to lease 326 buses over four years and eventually replace its entire 1,422 bus fleet, making it largest purchase of electric school buses in the U.S.
“We’re really happy about how the project has unfolded in Beverly,” Stanberry told NetZero Insider. “They are in a good place for electrification for the school district going forward.”
The V2G capability adds a “new, interesting and important value stream for schools,” he added, because it lowers the cost for the electric bus service.
Highland is also installing a 360-kW fast charging station in Beverly that will go live next month. The station will be the first of its kind at that power rating, according to Stanberry.
FERC Order 2222 opened value streams by enabling distributed energy resource (DER) aggregators to participate in wholesale electric markets.
“That’s what we need to see from ISO-NE,” Stanberry said. “But we need a continuous participation model that gives resources credit for their value in reducing load and generating power.”
Highland is working to maximize all the resources school buses can provide to lower the cost of electrification for schools.
There are more than 480,000 school buses in the U.S., which adds up to a lot of battery storage capability.
FERC Order 2222 should allow DER resources to adjust their energy offers closer to real time, so they don’t face penalties, Stanberry said. “Getting those details right is really important to us.”
When Greg Rieker started developing a new technology for continuous detection of methane leaks seven years ago, “there was no market opportunity for quantitative, continuous emissions monitoring in oil and gas. The world was just starting to realize that intermittent, large emissions drive a majority of total emissions from the oil and gas sector, and investors hadn’t yet placed heavy pressure on industry to clean up,” said Rieker, speaking at the closing session of the ARPA-E Energy Innovation Summit on May 27.
Today, Rieker is co-founder and CTO of the company built on his initial research, LongPath Technologies, which is now ready to commercialize its methane monitoring system with the help of a $5 million SCALEUP grant from the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E).
Short for Seeding Critical Advances for Leading Energy technologies with Untapped Potential, SCALEUP is aimed at spurring the development of domestic supply chains for cutting-edge clean energy technologies — a key element of President Biden’s climate agenda. Launched in 2020, the program has awarded more than $75 million to a first cohort of 10 startups, represented at the closing session by Rieker and three other CEOs who received SCALEUP grants.
Jigar Shah, director of the DOE’s Loan Programs Office, led a discussion that provided insight into the current energy innovation landscape and the role federal funding can play in helping companies take new technologies from the lab and pilot demonstrations to full commercialization.
At the closing session of the ARPA-E Energy Innovation Summit (clockwise from left): Jigar Shah, director of the DOE’s Loan Programs Office; Colin Wessells, CEO of Natron Energy; Greg Rieker, CEO of LongPath Technologies; Michael Edelman, CEO of Ionic Materials, and Eli Goldstein, CEO of SkyCool Systems. | ARPA-E
Rieker and Colin Wessells, CEO of storage start-up Natron Energy, said their grants have been a catalyst for attracting private investment.
“There’s a lot of talk about `we need homegrown technologies; we need manufacturing here; we’re going to scale it here in the U.S. and build this economy together,’” Wessells said. With SCALEUP, he said, DOE and ARPA-E are “putting their money where their mouth is.”
LongPath
An early ARPA-E grant in 2015 helped Rieker and a team of researchers at the University of Colorado, Boulder, begin to take “a room-size, Nobel Prize-winning laser that took an army of researchers to operate and [shrink] it to the size of a desktop computer that can run autonomously in the field,” he said.
LongPath was founded in 2017, with Rieker coming on as CEO in 2019, according to the company website. The system now ready for commercialization is “akin to a methane radar that sweeps out a 17-square-mile region with a single instrument and can locate and quantify leaks as small as a quarter of your breathing rate right now,” Rieker said.
The SCALEUP grant has already provided LongPath with a level of validation for potential customers and investors, even before the company has received a cent of the money, Rieker said. “We work in an environment where we’re introducing a completely new technology that is almost hard to believe. We’re catching tiny leaks from three miles away that people in the field say, ‘That’s not possible.’”
Rieker said current regulatory frameworks based on finding and fixing leaks during quarterly inspections must change. “We need to be able to prove to regulators that the idea of going after the largest emissions fast and focusing on total emissions reduction, not leak reduction, is key. You can only do that at scale.” Rieker said.
Natron Energy
Similar to LongPath, Natron was a spin-off from university research, in this case, by scientists and entrepreneurs at Stanford University. The company has developed a battery technology based on Prussian blue — formally iron hexacyanoferrate — and sodium-ion. Historically used as a pigment for paints, inks and textiles, Prussian blue’s cell structure allows very fast charging and discharging cycles with minimal degradation of capacity, as well as lower cost and improved safety, according to the company’s website.
The company, which has also attracted some high-profile investors, including Chevron (NYSE:CVX), is targeting “data centers, telecom networks and EV fast-charging services,” Wessells said. “These are customers with large and volatile electric loads to the grid.”
Wessells said the $19.9 million SCALEUP award will allow the company to set up high-volume production in the next 18 months.
“That means several million battery cells per year,” Wessells said. “That’s a high-enough volume to achieve cost structure, and then cash flow and a sustainable business … Higher-volume cell assembly, that’s the building block we would copy exact into a gigafactory where instead of one line you might have 20.”
Wessells sees federal funding for startups as a supplement to a strong business plan. Asked what advice he might give other startups preparing a SCALEUP application, Wessells said, Natron did not really prepare. “We were running a business plan that turned out to be compatible with the objectives of the agency for a certain program. In essence, our heart was already in it, and this is what we cared most about doing.”
Ionic Materials
Ionic Materials is also pioneering an alternative to lithium-ion batteries, in this case, a solid polymer that can transmit ions at room temperature, improving battery safety and performance, and lowering costs, it says. In addition, the polymers have potential applications in telecommunications, electronics, and food and medicine packaging, according to the company’s website.
CEO Michael Edelman said the company’s $8 million SCALEUP award will “de-risk” product development and bridge the traditional “valley of death” startups often face between early-stage and later investment.
“It’s one thing to develop something really interesting, really cool in the lab,” he said. “But how do you get it to a point where you can manufacture cost effectively, at the right quality consistently, so your customers will buy it?”
Manufacturing at commercial scale can also lead to further innovations, he said. The grant “is helping us validate some of this larger production and validate actually new methods that we wouldn’t normally consider in the lab — production technologies that are really new in our industry.”
SkyCool Systems
Like LongPath, SkyCool’s passive technology for cooling data centers, grocery stores and other buildings with high air-conditioning costs sounds scarcely possible. Based on what CEO Eli Goldstein calls “radiative cooling,” the company has developed an optical film that both reflects light and emits thermal radiation into the upper, cooler layers of the atmosphere.
Installed in rooftop panels that are about the same size as photovoltaic solar panels, the technology can improve the efficiency of air conditioning and refrigeration systems and cut electricity use and costs. One pilot project at a California grocery store reduced electricity use by about 100 kWh per day, resulting in estimated annual savings of $5,800, according to a case study on the company website. In another case study, a pilot project at a convenience store, also in California, trimmed daily energy use about 15%.
For Goldstein, the core value of SkyCool’s $3.5 million SCALEUP grant “is about validation with partners — end customers, channel partners, installation partners, as well as manufacturing partners. It will allow us to do deployments with third-party [measurement and verification] and do them with large entities that can purchase our system in the future,” he said.
The grant will also help with training installers, hopefully by leveraging the existing solar workforce, he said.
Echoing the other CEOs on the panel, Goldstein underlined the critical role SCALEUP grants can have for attracting longer-term private investment for domestic clean energy supply chains.
“Having customers that can be referenceable to investors is likely going to be one of the bigger next steps we’ll need to have for the next round of funding,” he said. “As a developer of a new hardware technology, our goal is to have our product out there for 10 to 15 years. Right now, our customers are taking our word for that; developing that data will be incredibly important.”
Speakers on an ARPA-E Innovation Summit panel Wednesday agreed that the transition to renewable energy will require an interconnected nationwide grid.
This macrogrid would facilitate the transfer of clean energy from high-output regions to lower-output regions depending on the time of day, supporting resilience and decarbonization efforts, they said during a session titled “Transmission System of the Future.”
“The power grid of the future is really going to need to unite the country to bring together all of the various clean energy resources we have in various times and places,” NextEra Analytics’ Aaron Bloom said. “Can you decarbonize with other technologies without transmission? Maybe. Probably you could figure out a way. But the key is to do it at a low cost.”
The biggest hurdles to a mass infrastructure buildout are regulatory restrictions, the panelists said. Interconnecting the grid would be the most efficient and cost-effective path to rapid decarbonization, Bloom said, but long interconnection queues and rights-of-way disputes delay transmission projects significantly.
“Transitioning to a grid that relies on no-carbon resources will really require rethinking of the regulatory frameworks,” Elisabeth Treseder of Equinor said.
The panelists agreed that regulatory entities will need to alter their policies to accelerate transmission projects and facilitate their interconnection to the grid.
“When President Kennedy said, ‘We’re going to the moon,’ he didn’t say, ‘as soon as we get through NASA’s long project queue.’ So if you want more renewables, we as society do need to prioritize transmission,” Direct Connect Development Co. CEO Trey Ward said.
NewGrid President and CTO Pablo Ruiz said, “FERC could have a big role … on the regulatory front [by] setting the right incentives. … I think there’s also a role for Congress to lay out the vision and then FERC can help implement. I wouldn’t discount the significance of an infrastructure bill for that.”
Another big hurdle to a mass infrastructure buildout is the cost. “Who’s going to pay for it?” moderator Trisha Miller, of Breakthrough Energy, asked the panel.
Ward hopes that private capital can be mobilized to cover the cost. Direct Connect is a privately financed HVDC transmission line developer, and he and his team are “very excited” that “President Biden wants to unleash private capital to deploy interregional transmission along existing transportation corridors.”
Ward believes the key to unlocking this capital is an investment tax credit (ITC). He said an ITC is the incentive necessary to kickstart corporate investment in transmission.
“A well funded ITC program would unleash private capital on the largest infrastructure initiative of our generation,” he said.
A reorganization of New Hampshire’s government that would create a new Department of Energy is on the verge of being approved through the state’s budget process.
The proposal, which is included in a budget trailer bill (HB 2), takes the energy functions of the Office of Strategic Initiatives (OSI) and regulatory functions of the Public Utilities Commission and restructures them under the DOE.
“We see this as an opportunity to reach better outcomes, whether it be for ratepayers or even just to give energy policies a singular home in the state of New Hampshire,” State Budget Director Matthew Mailloux told the Science, Technology and Energy Committee in a presentation last week. The DOE would be the state’s “single entity for energy policy decision making.”
The New Hampshire Committee on Science, Technology and Energy heard from the state’s budget director last week on a proposal that would reorganize the Public Utilities Commission and create a Department of Energy. | New Hampshire House of Representatives
In April, the House of Representatives passed the trailer bill that contains the DOE proposal. And while the Senate Finance Committee is still working through the full budget, it approved the proposal in a 6-1 vote in mid-May. The legislature is scheduled to adjourn June 30.
Four divisions would be formed under DOE, to include Administration, Policy and Programs, Enforcement, and Regulatory Support. OSI would be dissolved and reorganized partially under the Policy and Programs division. In addition, the existing electric division and gas and water division of the PUC would align under the Regulatory Support division. The commission itself would be administratively attached to DOE.
Restructuring the PUC, according to Mailloux, addresses a “perceived conflict of interest” in the dual roles of commission staff.
Under the current commission structure, staff can be a party to a docket to help build the evidentiary record and present evidence before the commission, while also advising the commission on how it should rule.
“What we’re hoping to do by creating a new Department of Energy is establish a bright red line,” Mailloux said. “Essentially, you either work as an adviser to the commissioners and help them rule on a given docket … or you work for the department, represent the interests of the state and make your case in the hearing room, but never behind closed doors.”
In addition, the proposal adds accountability, he said, by transitioning all leadership positions that move to the DOE to a formal confirmation process with four-year terms. The commission chair will continue to have a six-year term.
The budget also funds for the first time an Office for Offshore Wind Industry Development, which would be located under the Policy and Programs division.
Sen. David Watters (D) sees the Finance Committee’s approval as a win for the work currently underway by the state’s Commission to Study Offshore Wind and Port Development.
“I’m sure it’s going to take some time to get [the office] set up, [but the proposal] will pass with the budget when the budget passes,” Watters told the offshore commission at its monthly meeting Tuesday.
The Office of Offshore Wind Industry Development would support the state’s membership on the Bureau of Ocean Energy Management’s Intergovernmental Renewable Energy Task Force and the offshore commission as it develops industry strategies.
NYISO should focus on market enhancements to incent investment in flexible generation resources that will help integrate intermittent wind and solar resources and encourage the retirement of inefficient generators, Market Monitoring Unit Potomac Economics told the Management Committee on Wednesday.
“To the extent that retirements occur, they should be resources that provide the least value, particularly in terms of flexibility and reliability,” Potomac’s Pallas LeeVanSchaick said as he reported highlights from the 2020 State of the Market Report. “We think it’s critical to focus in this way because ultimately the market is going to be instrumental in determining whether state policy goals can move forward at the lowest possible cost and that minimizes market disruption.”
Mixed Signals
Last year saw lower energy and capacity prices across the state compared to 2019 because long-term trends, natural gas prices, mild weather and the pandemic-related economic slowdown, but slightly higher capacity prices in New York City reflected a smaller surplus than in upstate.
“The higher prices in New York City are affected a great deal by volatile locational capacity requirements [LCRs] and installed reserve margins [IRMs], and by some departure from the market of peaking units,” LeeVanSchaick said. “We have significant concerns about the volatility of these [capacity] requirements.”
It’s important to look at net revenues and see whether they are providing the market signals needed, according to the report. The capacity market does not provide adequate locational signals. For example, the lack of a Zone A-B capacity region has contributed to a higher IRM and low LCRs in 2021/22, the report said.
“The current framework isn’t sustainable in the long term, and at some point there needs to be a capacity market that provides appropriate locational signals,” LeeVanSchaick said.
The changing resource mix creates major challenges, such as capacity prices not providing adequate locational signals and some resource types being under- or overcompensated, the NYISO MMU said. | Potomac Economics
A “more urgent” issue is that the capacity accreditation of some resources leads them to be under- or overcompensated for their capacity, such as duration-limited resources and intermittent generation, the values of which fall as penetration increases. But the current rules for valuing capacity do not adequately reflect that “these resources complement each other” because, for example, the value of battery storage can be increased by high penetration of solar generation … so there’s a number of factors there that the current rules don’t take into account,” LeeVanSchaick said.
The Monitor is emphasizing four enhancements for the energy and ancillary services market:
Dynamic reserve requirements
NYC locational reserve requirements
Compensate reserves that increase transfer capability
Reserve demand curve increases
“In terms of the first three [recommendations] … we’ve encouraged the NYISO to look at [them] in the context of [its 2021] Reserves for Constrained Areas project; that’s a study at this point, but I think it is looking at these three,” LeeVanSchaick said. “The fourth one is something that the NYISO recently” addressed in part with recent tariff changes. The ISO took “a step in the right direction with changes to the reserve demand curves for the larger regions … that were recently approved.”
Regarding capacity market enhancements, the high-priority recommendations are two-fold, he said.
An evaluation of the 2030 high renewable scenario shows that markets guide clean energy investment. | Potomac Economics
“The first, in the short term, and in an urgent sense, we have a recommendation to revise accreditation rules to compensate resources in accordance with their marginal reliability value. This is important because with all of the new investment happening, we don’t have a sustainable set of efficient rules to help guide that investment” by compensating it in accordance with its marginal reliability value, LeeVanSchaick said. “Anything you do that waters down those incentives is going to hamper [efficient future] investment.”
The capacity accreditation also should address how the limited flexibility and availability of some long lead-time generators diminishes their reliability value. For example, just 30% of the 10.7 GW of fossil steam turbines were online in at least half of New York Control Area and Southeast New York reserve shortages in the last three years, he said.
“In the longer term, we still recommend the C-LMP [capacity locational marginal pricing], which would provide appropriate incentives for investment in each area as transmission bottlenecks shift over time; and finally, better alignment between the [New York State] Reliability Council’s IRM-setting process and other capacity market inputs would be beneficial,” he said.
LeeVanSchaick will address various topics of the report in coming Installed Capacity Working Group meetings: public policy issues June 3, capacity issues June 9, and energy and ancillary services issues June 17.
MISO this week said it will need to pause its long-range transmission modeling effort and correct two errors so that it has the clearest picture of future grid performance.
Staff said the work will delay the release of reliability and economic models by a few weeks as they prepare a long-range transmission package.
“Modeling is the most significant effort, and it takes time to get that right,” Jarred Miland, senior manager of system planning coordination, told stakeholders during a Wednesday Planning Advisory Committee teleconference.
MISO said its power flow modeling contained duplicate generation projects with signed interconnection agreements. Miland said the double counting and resource owners’ self-reporting was “significant enough” to justify another reliability model run.
“It’s an easy fix, but it will cause us to redispatch those models,” he said.
The RTO is also fine-tuning load-level modeling predictions based on transmission owners’ input. The grid operator said it needs to better align its local system load level predictions with its regional projections. Through the modeling, MISO is trying to determine when increasing wind and solar generation will strain its transmission system in future years.
Possible transmission expansion under a long-range plan | MISO
Miland said staff will debut long-range models in early June.
TOs have also asked MISO to update some transmission line ratings and line configurations in the modeling. Miland said unlike the other modeling changes, those amendments are routine.
The longer-than-expected modeling phase is holding up a reliability analysis on the long-range transmission-planning work, Miland said. As a result, MISO cancelled its Friday long-term planning workshop. The next workshop is scheduled for June 25.
WEC Energy Group’s Chris Plante said he was disappointed in the decision to cancel the workshop.
“This is an unprecedented … magnitude of study,” he said. “Given the unprecedented amount of work that needs to be done, I was very disappointed that you cancelled the workshop.”
Plante said MISO planners shouldn’t feel pressured to prepare a formal presentation outlining new developments in order to host a workshop. He said about 50 stakeholders have been meeting informally outside of the stakeholder process and without slides to discuss the long-range plan.
“I also want to support more conversation than less,” agreed the Union of Concerned Scientists’ Sam Gomberg.
Multiple stakeholders also questioned MISO’s use of its 2020 Transmission Expansion Plan (MTEP 20) as the basis for its long-range modeling. MTEP 20 models don’t include the transmission projects approved at the end of 2020.
Miland said waiting on completed MTEP 21 models — which do contain the 2020 crop of projects — would have further held up the long-range transmission plan. He said staff will review the impacts of the MTEP 20’s higher voltage projects and may apply them in modeling, if they’re deemed substantial enough.
“If there are significant additions that are really material, let us know,” Miland told stakeholders.
Earlier in May, MISO executives said the long-range plan was essential because it’s the RTO’s only planning that looks more than 20 years into the future. They said without the planning, the grid will buckle under pressure in likely future fleet mixes. (See MISO Stresses Importance of Long-range Tx Plan.)
MISO has said it may need more than a dozen 345-kV additions, a handful of 500 kV and 765 kV lines, and even a massive footprint-wide network of DC lines as part of the long-term planning package. Staff estimates the long-term transmission package could cost anywhere from $30 billion to $100 billion. (See MISO Reveals Contentious Long-range Tx Project Map.)
The RTO’s executives and planners have stressed that the footprint needs new transmission to maintain reliability through an onslaught of renewable grid interconnections.
During a Tuesday interconnection working group teleconference, MISO’s Jesse Phillips, manager of resource utilization, said early indications show that 2021’s batch of interconnection queue entrants “may be at least as large” as the record-breaking 2020 cycle.
MISO currently has 552 projects and about 83 GW of capacity in its queue, down from 2020’s highs of more than 100 GW. Solar generation accounts for 65% of the megawatts in the current queue.
MISO will open the queue to new project applications just once this year. Hopefuls have until July 22 to submit project proposals and documentation.
Cost Allocation Debates Continue
While MISO planners chart the possible routes new transmission could take, stakeholders are still deliberating over how the buildout’s costs will be divvied up.
Stakeholders attending a teleconference on cost allocation Thursday mulled the long-range plan’s ability to help avoid future emergencies during increasingly extreme weather and how that reliability benefit might be measured and translated into cost-sharing.
Members also considered how they could quantify the added reliability benefits from the system’s expanded ability to move huge volumes of power long distances and ease generation’s unfolding shift to renewables.
Distaste remains for a systemwide postage stamp allocation, though some stakeholders continue to argue that it might be necessary to capture widespread reliability advantages.
Stakeholders are divided on whether MISO should use NERC reliability standards to measure transmission reliability benefits beyond a five-year planning horizon. Multiple stakeholders said NERC standards are no longer an adequate benchmark for system reliability, especially in the long term. Many said the standards have not kept pace with the energy industry’s seismic changes.
“The last time we saw system change like this, the Korean War was going on. … It was well before NERC was thought of. Those [standards] were never designed to contemplate the kind of system change we’re seeing today,” Xcel Energy’s Drew Siebenaler said.
“Our power is freaking going out now. … It’s a crisis the South has right now,” Southern Renewable Energy Association Director Simon Mahan said. “For the people down here, we can’t go on like this. If the NERC standards are ‘good enough,’ and the load-shed standards are ‘good enough,’ I’m sorry, I don’t agree with that.”
Mahan said NERC reliability standards were followed during the arctic event, and the system still came up short.
MISO leadership has repeatedly said the added transfer capability of MISO’s last long-range transmission portfolio, approved a decade ago, helped the footprint dodge a more devastating emergency during mid-February’s arctic event.
LS Power’s Pat Hayes said increasing transfer capability between MISO Midwest and MISO South is vital for future system reliability.
Mississippi Public Service Commission consultant Bill Booth argued that weatherization and resource diversity will do more to help avoid serious winter emergencies.
“I don’t think the solution to everything is long-haul transmission,” Booth said.
“Trying to build a system on what is known today is not going to give us the system of tomorrow,” Sustainable FERC Project counsel Lauren Azar countered.
The D.C. Circuit Court of Appeals on Friday dismissed a petition from the Union of Concerned Scientists (UCS) calling for a review of Department of Energy rules concerning disclosure of critical electric infrastructure information (CEII), saying that UCS lacked standing to bring the complaint.
The petition by UCS concerns DOE’s new administrative procedures for CEII. DOE issued the rule in March 2020 under Section 215A of the Federal Power Act (FPA), which allows both DOE and FERC to designate information as CEII “pursuant to the criteria and procedures established by [FERC].”
FERC’s CEII criteria, established in 2016, defines the term as “specific engineering, vulnerability or detailed design information” about existing or future critical infrastructure, physical or virtual, that could:
provide details about the production, generation, transmission, or distribution of energy;
help in planning an attack on critical infrastructure; and
give strategic information about specific critical infrastructure, beyond its location.
Information designated as CEII is exempt from mandatory disclosure under the Freedom of Information Act (FOIA). FERC and NERC cited this rule last year when they decided to end their previous practice of publicly posting redacted information about violations of the ERO’s Critical Infrastructure Protection (CIP) standards (AD19-18), over widespread opposition from industry stakeholders. (See FERC, NERC to End CIP Violation Disclosures.)
DOE Claims to Need Own Procedures
Following the creation of FERC’s rules, DOE said in 2018 that although the FPA gave both it and FERC the ability to designate information as CEII, FERC’s 2016 rule only established CEII designation procedures for the commission itself. As a result, the department claimed the right to determine its own procedures for designating such information, as well as procedures for non-federal entities to request access to DOE-held CEII.
James Forrestal Building in D.C., headquarters of the U.S. Department of Energy | Tim Evanson, CC BY-SA 20, via Wikimedia Commons
Upon announcing its new rules last March, DOE emphasized that its criteria for CEII follow “the designation criteria FERC has already formulated,” and asserted that despite minor differences with FERC’s procedures for such designation, the department’s own procedures are “consistent with FERC’s rule to the maximum extent possible.”
UCS, however, claimed that DOE exceeded its authority under the FPA and, together with consumer advocacy group Public Citizen, petitioned the department for rehearing of the new rule. When rehearing was denied, UCS turned to the courts.
In addition to accusing DOE of acting without authority in promulgating the new rule, UCS also claimed that the CEII designation procedures:
conflict with the department’s obligations under FOIA and the Federal Records Act;
contain overly broad CEII designation criteria and “excessively restrictive limits on access to CEII by non-federal entities; and
could violate the due process rights of parties in proceedings before DOE.
Specifically, UCS identified two aspects of DOE’s rule that would make obtaining information more difficult: first, that the department did not set procedures for access to CEII by participants in DOE proceedings; second, DOE’s requirement that non-federal entities requesting CEII demonstrate that the information’s release is in the national security interest. FERC’s CEII rule only requires that once a request is made, the commission must balance the need for the information against its “sensitivity,” rather than any specific interest.
DOE asked the court to recognize that “there is no indication that the rule will cause [the department] to withhold information” that would be released under FERC’s rule, which the court denied, noting that it is legally required to give the benefit of the doubt to the plaintiff and that access could be reduced in the way UCS described.
However, the court also observed that the plaintiff’s argument rested on speculation about DOE’s behavior under the new rule. Because no actual harm has been alleged, the legal ground for the case is shaky at best.
“This court has been reluctant to find standing based on predictions of how agencies will exercise discretion in future proceedings,” Circuit Judge Judith Rogers wrote on behalf of the court. “Here the discretion DOE has in making designation and access decisions takes the denial of access to CEII from the decidedly likely to the speculative.”
Because UCS could not “demonstrate it [had] suffered a concrete and particularized injury that is imminent and not conjectural,” the court dismissed the petition for lack of standing, without speaking to the underlying argument.
FERC dealt another rejection to security activist Michael Mabee on Wednesday, denying his request for an investigation into the widespread power outages resulting from February’s cold snap despite intervenors supporting his contentions of lax regulatory oversight on the Texas power grid (EL21-54).
Mabee filed his complaint on Feb. 28, not long after the winter storm that led to record cold temperatures in Texas, causing energy demand to skyrocket while multiple generation units went offline. At one point Texas reported more than 52 GW of generation loss, amounting to 48.6% of the state’s total installed generation capacity, and millions of Texans lost power for hours or even days.
Amid the crisis, Texas citizens and government officials turned their ire on Slow Storm Restoration Sparks Anger in Texas, South.) Mabee’s February filing expanded this viewpoint to cover NERC and the Texas Reliability Entity: He called the crisis “the failure of electric reliability standards” and demanded FERC order both entities to conduct an investigation into whether utilities were negligent in applying NERC’s standards.
A snow-covered sidewalk in Deep Ellum, Texas, during February’s winter storm | Matthew T. Rader, CC BY-SA 4.0, via Wikimedia Commons
In a blog post on his personal website, Mabee, who lives in Texas, admitted his FERC complaint had a personal edge, as his own family lost power for more than 36 hours amid sub-zero temperatures. Writing to FERC, he focused on the Texas cold weather-related blackouts of 1989 and 2011, both of which he said were “followed by many promises” — respectively in the form of a report by the Public Utility Commission of Texas and a joint FERC-NERC inquiry — “but little action.”
“I implore the commission: Stop asking and recommending. It is time to direct NERC and Texas RE to take action,” Mabee wrote, requesting the commission order a “comprehensive investigation” by NERC and Texas RE into “whether reliability standards were followed by all entities” involved in the February outages.
Mabee also reminded FERC of his previous complaints about NERC’s Critical Infrastructure Protection (CIP) standards that the commission rejected last year (EL20-46) and warned that deficiencies in one area could indicate much wider problems. (See FERC Denies Mabee’s CIP Complaint.)
“If we are not adequately prepared for a weather event that is forecast well in advance … are we ready for other threats?” he said. “Are we prepared for a cyberattack … a coordinated physical attack … a major geomagnetic disturbance (GMD) event [or] other extreme weather events?”
Many Critics of 2011 Follow-up
Mabee is far from the only observer to note the apparent lack of follow-on actions in response to the 2011 outages: Several members of the Senate Energy and Natural Resources Committee told NERC CEO Jim Robb during a meeting in March that Texas utilities “probably didn’t follow your recommendations very well.” (See Senators Grill Robb, Asthana over Texas Outages.)
In a supportive filing, the Secure the Grid Coalition — a group of “policy, energy and national security experts, legislators, and industry insiders” — called reliability standards “insufficient and underenforced” and requested that FERC “thoroughly investigate the February 2021 blackout … to determine how FERC could have made a material difference by [promoting] economic incentives for grid resilience.”
FERC itself has indicated some agreement that measures taken after 2011 were insufficient: Chairman Richard Glick reminded colleagues at the commission’s February meeting that after the 2011 events, FERC relied on “voluntary guidance to protect the public,” noting that “we don’t have to guess how effective that was.” (See Glick May Seek New Standards Following Texas Outages.)
But in denying Mabee’s request, the commission noted that he had not provided any evidence either of specific reliability standard violations that contributed to the February outages, or of deficiencies in the standards that could have prevented the disaster if corrected. Moreover, FERC referred to its ongoing joint inquiry with NERC — with which Texas RE is assisting — as evidence that “adequate steps are being taken” to evaluate the problem.
“These efforts will create a record about the causes of the February 2021 cold weather event as well as consider the potential for future extreme weather events that will, in turn, inform any decision on the need for further action, including possible new or modified reliability standards,” the commission said. “Moreover, these efforts appear to address certain relief that was requested by the complaint.”
The Texas Reliability Entity’s director of reliability services said Thursday that wind and solar energy will be crucial if the state is to survive another brutal summer.
Texas RE’s Mark Henry lays out the summer outlook in his “Talk with Texas RE” presentation. | Texas RE
Mark Henry appeared buoyed by ERCOT’s 15.7% reserve margin, nearly double its 8.6% margin just two years ago, as he discussed the interconnection’s summer outlook with a “Talk with Texas RE” virtual audience.
“We look very good this summer, compared to the last two years, on paper. Practice has shown the paper can be realized in what we achieve,” Henry said, before interjecting a note of caution. “We can’t serve the expected peak without wind and solar contributing to that.”
He pointed out that conventional resources will account for almost 72 GW of capacity this summer, with wind, solar and battery resources being instrumental in covering the afternoon peaks. The hour ending at 5 p.m. remains ERCOT’s highest-risk hour for unserved energy, Henry said, with the likelihood of unserved energy being less than 0.2%.
NERC projects an elevated risk for ERCOT this summer. | Texas RE
“That’s always a concern to us: Are we going to have enough generation to meet the peaks we’ll have in July and August? It’s always possible it might be a little hotter than we expect for a couple of days. After the events of the past year, there’s growing awareness we need to be even more prepared for situations that are not in the normal realm.”
ERCOT has projected it will have 86.9 GW of total resource capacity, enough to meet an expected peak demand of 77.1 GW this summer. That would be a new demand record, breaking the mark of 74.8 GW set in August 2019. (See ERCOT Resource Adequacy Hard Sell After Winter Storm.)
Thunderstorms and torrential rains have drenched much of the state this spring, lending hope that temperatures this summer will not be as high as they have been in years past. As Henry said ERCOT’s meteorologist told him, “‘Moisture on the ground tends to keep the temperatures down.’
“We’ve got to have our wind and solar at some level, and hopefully we’ll find they perform exceedingly well this summer. I think this a summer we can get through without too much difficulty,” Henry said.
ERCOT Tests Emergency Notification System
ERCOT’s test of its emergency notification system drew cynical tweets. | Joshua D. Rhodes, via Twitter
ERCOT tested its automated emergency notification system Wednesday evening as part of its “aggressive” pre-summer preparation activities.
Test messages were sent through the grid operator’s various communications channels, including its website and mobile app, Twitter, and email distribution lists. The test began at 7:05 p.m. and concluded at 7:25 p.m.
The grid operator said that during a potential grid event, it uses the automated notification system to send “timely communications” directly from the control room.
ERCOT was criticized for unclear communications in February that didn’t prepare Texans for power outages that lasted for days. Lawmakers are working on legislation that would develop an alert system to be coordinated by the Texas Department of Public Safety. (See Legislative Response to Winter Storm Leaves Some Doubting.)
An Oregon designer of small modular reactors has linked up with a venture to build four small reactors at the Hanford Nuclear Reservation in Washington.
NuScale Power of Portland, Ore., on Wednesday signed a memorandum of understanding with the Grant County Public Utility District to see if its small modular reactor (SMR) design can be used in the potentially first Washington reactor complex to go online since 1984.
Grant County PUD is part of a joint venture with Energy Northwest of Richland, Wash., and X-energy of Greenbelt, Md., to build four 80-MW modular reactors at Hanford by 2027. (See Small Nukes Proposed for Wash. Hanford Site.)
SMRs are prefabricated facilities with parts manufactured in one location, then transported to the reactor site for final assembly. A modular segment would consist of a mini reactor of 50 to 300 MW. The design allows for extra modules to be added as needed. Southeast Washington’s Tri-Cities area, which includes Richland, hopes to become a prefabrication site for small modular reactors.
Under the venture, Energy Northwest, which operates the 1,150-MW nuclear-power Columbia Generating Station, would provide a partially built reactor site abandoned in the early 1980s and assume operations of the facility. X-energy is also a reactor design firm.
Rep. Dan Newhouse (R-Wash.) looks on as Energy Northwest CEO Brad Sawatzke, X-energy CEO Clay Sell and Grant PUD CEO Kevin Nordt sign an agreement April 1 to create a partnership to evaluate development of an advanced nuclear reactor in Washington. | Energy Northwest
NuScale’s SMR design has passed a technical review by the Nuclear Regulatory Commission, making its model the farthest along in the nation in obtaining NRC approval. (See NRC OKs NuScale’s Small Modular Reactor Design.)
Under the new MOU, NuScale and Grant County PUD would work together to perform the PUD’s due diligence in deciding by the end of this year on whether to stick with the venture. The PUD is a potential customer for the reactor complex.
“As interest in our small modular reactors grows, we welcome this opportunity to emphasize how NuScale’s safer and smarter technology can be the reliable and affordable clean energy solution that communities like Grant County and others across America need,” NuScale Power CEO John Hopkins said in a press release.
In the same release, Grant County PUD CEO Kevin Nordt said: “NuScale’s dedication to innovation and safety fit well with Grant PUD’s values. We are excited to work towards making nuclear power a key part of a carbon-free future in the Pacific Northwest.”
NuScale has a project already in place with the Utah Associated Municipal Power Systems, a coalition of more than 30 utilities in Idaho, Utah and New Mexico. Two of those utilities have dropped out of that effort in the past year because project costs have increased from $3 billion to $6 billion. The project calls for 12 60-MW modules to be built by 2030 at the U.S. Department of Energy’s Idaho National Laboratory.
A second project in the works at Hanford might go online in 2027. It would consist of a 350-MW Natrium reactor, a sodium‐cooled fast reactor potentially built on the site of another partially built reactor site owned by Energy Northwest. This would be a joint venture between Energy Northwest and TerraPower, a Bellevue, Wash., reactor design developer founded by Bill Gates. Energy Northwest said it is in talks with the company about the project, but TerraPower said it has not yet settled on a site and is considering several locations.
Both projects are near Energy Northwest’s Columbia Generating Station, the only commercial reactor operating in the Pacific Northwest.
Energy Northwest was once called the Washington Public Power Supply System. WPPSS tried to build five reactors in the 1960s and 1970s — three at Hanford and two in Satsop, Wash. — but only Reactor No. 2 (now the Columbia Generating Station) was finished. The others were never completed because cost overruns and massive delays led to WPPSS in 1982 suffering the biggest bond default in Wall Street history up to that point.
