A more than year-long test of 10 hydrogen-fueled semitrucks demonstrated that the vehicles can perform roughly equally with their 5-year-old diesel equivalents.
However, the maker of the trucks is staying mum about future testing and manufacturing plans.
The test runs at the Port of Los Angeles were financed by part of a $41 million Zero and Near-Zero Emissions Freight Facilities grant awarded by the California Air Resources Board, with the port as the prime applicant. The grant is part of California Climate Investments, a state initiative funded by billions of cap-and-trade dollars.
The Port of Los Angeles has set a goal of producing net-zero carbon emissions from its short-haul trucks by 2035.
A Kenworth truck manufacturing plant in the Seattle suburb of Renton made the trucks. Kenworth is owned by PACCAR, which is based in the Bellevue, Wash.
“We clearly showed that hydrogen is a viable clean fuel capable of powering commercial transportation for customers, matching diesel performance in range and power, with quick refueling for minimal downtime and smooth, quiet operation,” Joe Adams, Kenworth chief engineer, said in a Sept. 22 press release. The test runs ended in August
Toyota Motor North America and Kenworth joined forces to design and build the hydrogen-fueled semis. The trucks are Kenworth T680s built with Toyota hydrogen fuel cell electric powertrains, with water being the only emissions. The trucks went through initial tests at a PACCAR facility in Mount Vernon, Wash.
The Kenworth T680 FCEV truck — dubbed an “Ocean” — was supposed to work comparably with a 2017 diesel engine driving about 200-350 miles a day. The T680 FCEV has a range of more than 300 miles when fully loaded to 82,000 pounds.
The 10 test trucks normally worked one-day hauls around the Port of Los Angeles in the greater Los Angeles area. Toyota Logistic Services, UPS Total Transportation Services and Southern Counties Express were other freight carriers using the trucks.
The trucks frequently handled multiple shifts and ran 400 to 500 miles per day. Swapping out the hydrogen fuel cells took 15 to 20 minutes, according to the press release.
“Hydrogen infrastructure is still in its infancy, so hydrogen fuel is more expensive than diesel to fuel the truck,” PACCAR spokesperson Jeff Parietti said in an email. “We would expect the costs to come down as scale of production/distribution increases. Preventative maintenance is primarily a series of fluid replacements and inspections. So there is the opportunity for reduced maintenance costs over diesel.”
In the press release, Andrew Lund, Toyota chief engineer for zero-emission advanced product planning, said: “The potential for this technology as a replacement for higher-emission powertrains is real and supports both regulatory and society initiatives to combat climate change while helping us achieve our own goals of carbon neutrality.”
PACCAR and Kenworth do not have a prospective price tag for an individual T680 FCEV truck.
In a 2021 interview, port officials said the purchase price for a new diesel semi is $110,000 to $120,000, roughly $350,000 for a battery-powered semi and an estimated $1 million for a hydrogen-fueled semi.
In an email to Net Zero Insider, PACCAR declined to discuss its next testing and manufacturing plans.
MISO and SPP stakeholders expressed their consternation Friday over the RTOs’ proposed cost allocation for their interregional transmission planning initiative designed to ease overloaded generator interconnection queues.
The discord arose during a workshop over allocating costs for the grid operators’ Joint Targeted Interconnection Queue (JTIQ) study.
MISO and SPP plan to assign 90% of the $1 billion JTIQ portfolio to interconnection customers and the remaining 10% to an aggregate of their load. The RTOs said they will allocate a fixed, per-megawatt charge to interconnection customers that affect a facility in the neighboring region to pay for the portfolio. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
The RTOs are proposing a 5% distribution factor (DFAX) impact threshold on a neighboring system before interconnection requests are considered in a JTIQ-affected system zone and therefore, subject to transmission-cost sharing.
“We want to ensure the cost related to these JTIQ projects … are certain and reasonable,” Clint Savoy, SPP’s manager of interregional strategy, said during the workshop. He said the RTOs continue to believe that a 5% DFAX results in the most equitable cost allocation among interconnecting generation along their seam.
Stakeholders responded by saying MISO and SPP haven’t provided enough analysis that the 5% criterion is the best route.
The staffs said when they employed a 10% distribution factor, generation eligible to share in transmission costs dropped by nearly 60%. When the factor was increased to 15%, eligible generation plummeted by about 80%, making network upgrade costs untenable for the remaining interconnecting generation.
“If you make the zone too small, you could potentially, I think, incent siting generation outside of the zone,” Savoy said.
Some stakeholders repeated calls for an 80-20% split between generation and load assignment. They said load stands to benefit more than the 10% portion of JTIQ transmission costs.
North Dakota Public Service Commission Chair Julie Fedorchak said the 90-10 generation-load cost-allocation split is almost moot because generators will bake their JTIQ upgrade costs into customer bills.
“Those costs will ultimately be paid by the load,” she said.
MISO and SPP are also proposing another regional study for generation projects that: either have a 10% or greater DFAX impact on the neighboring system or who affect a certain number of the neighboring RTO’s substations, based on voltage rating. The RTOs said the study is necessary to monitor new local constraints caused by the incoming generation not covered by the major JTIQ transmission projects. When that happens, the host RTO plans to coordinate with the other RTO and transmission owners to “formulate a mitigation plan to alleviate the identified localized constraints.”
Clean Grid Alliance’s Natalie McIntire said stakeholders have “discomfort” with the cost-allocation proposal because MISO and SPP cannot provide an understanding of the overall costs that new generation will shoulder.
“It’s hard to know how all of these pieces will fit together and whether the result is going to be workable for interconnection customers and will result in viable projects,” she said.
Savoy said though he knows stakeholders would prefer a predicted range of costs, that’s “impossible” to provide at this point.
“This is an incremental step forward. We can’t give you complete cost certainty,” he said. However, Savoy said the JTIQ allocation should lower interconnection customers’ costs and asked stakeholders to at least give the RTOs a chance to improve the process.
David Kelley, SPP’s director of seams and market design, said interconnection customers splitting the costs of larger, “backbone projects” that allow mass interconnections is preferrable to the grid operators’ current affected system study process, where often high-priced network upgrades are designated to individual generation projects.
“We have to come up with a way to fund the transmission needed in this area,” Kelley said. “Basically today, we have an area that generators cannot develop in.”
“We are in agreement that the status quo sucks,” National Grid Renewable’s Rafik Halim said.
Invenergy’s Arash Ghodsian said he was supportive of the initial design but asked for a better explanation of the assumptions of proposed cost assignments’ mechanics.
Many large emitters of greenhouse gases incentivize their executives insufficiently or not at all to reduce those emissions, a corporate watchdog group says in a new report.
The practice of linking executive compensation to progress on environmental, social and governance metrics is growing, with just over half of all S&P 500 companies reporting such a linkage in 2021, the nonprofit As You Sow said in “Pay for Climate Performance.”
The report focuses on the 47 U.S. companies on the Climate Action 100+ list, an investor initiative pressing for change by the world’s largest greenhouse gas emitters. It assigns the companies letter grades based on their inclusion of a climate metric in their 2021 CEO pay package; inclusion of measurable climate metric and measurable pay; and inclusion of climate metric in the long-term incentive plan.
Twenty-five of the companies had no explicit link of emissions to executive pay and got an F, while 17 got a D. Marathon Petroleum, Valero Energy, Southern Co. and American Electric Power got C’s.
Xcel Energy (NASDAQ:XEL) got the one and only B.
“Xcel Energy received a B for linking CEO pay to emissions-reduction performance in its long-term incentive plan, with a measurable amount of pay related to achievement of reduction goals,” the report’s authors wrote.
To get an A, a company would have to align its goals and incentives to the 1.5-degree Celsius warming target of the Paris Agreement. None of the 47 did this, the report found.
Other findings highlighted by the authors:
At most companies offering climate-based pay incentives, the sum involved was a small fraction of the overall compensation package and thus of negligible value as an incentive.
Company proxy reports were short on transparent disclosure, making it difficult to distinguish effective CEO pay links; transparency would increase by linking quantitative climate metrics to measurable pay.
Discretion is rarely used to alter CEO pay for financial metrics and should be equally rare with climate metrics.
Where climate incentives are dwarfed by financial performance metrics, emissions reductions will not be a priority for the CEO.
Climate incentives should be framed as quantitative metrics such as “reduce GHG emissions by 30% by 2030 over a 2021 baseline” rather than qualitative measures such as “progress efforts in support of the energy transition” or “demonstrate leadership.”
The report’s authors also give advice to investors hoping to drive climate progress at a company: “When considering the quality of the compensation and climate link, investors need to concurrently consider the quality of the company climate transition plan and its alignment with CEO pay. Investors should also pay particular attention to the interaction of compensation design and the rigor of the climate metric. A facile understanding of the nuances of compensation or the company-specific transition plan can result in the addition of a metric intended to appease shareholders that inflates pay and nothing more.”
As You Sow calls itself an organization “dedicated to increasing environmental and social corporate responsibility while increasing company value.” The nonprofit, formed in 1992, “envisions a safe, just and sustainable world in which environmental health and human rights are central to corporate decision-making.”
American Electric Power and Liberty Utilities, a subsidiary of Algonquin Power & Utilities, said Friday they have struck an amended sale agreement that cuts the price of AEP’s Kentucky operations by $200 million and extends the timeline to close the deal.
Liberty will now acquire AEP’s Kentucky operations at a reduced $2.646 billion through a purchase of all Kentucky Power’s and AEP Kentucky Transco’s stock. The original deal had Liberty paying a $2.8 billion sale price. (See PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities.)
AEP expects to net approximately $1.2 billion in cash from the sale. It said the reduced revenue means that it will likely record a pre-tax loss ranging from $180 million to $220 million in the third quarter.
Liberty and AEP said they will close on the sale in January. The transaction was earlier slated to close by mid-2022. FERC must still approve the sale.
“This sale will provide significant benefits to customers in eastern Kentucky to help offset volatile fuel prices and support economic growth,” retiring AEP CEO Nick Akins said in a news release. “It also will support AEP’s ability to invest in projects throughout our regulated businesses that will enable the move to a clean, more reliable and resilient energy system.”
AEP CFO Julie Sloat, who will succeed Akins on Jan. 1, said that the new timeline will not affect AEP’s planned equity needs or its operating earnings guidance.
Montgomery County Public Schools (MCPS), in Maryland, is expanding its partnership with a company electrifying its bus fleet to use the vehicles as a distributed energy resource on the PJM wholesale electricity market, DER software provider Voltus announced on Wednesday.
MCPS and Highland Electric Fleets entered into a contract last year to electrify the county’s 326 diesel school buses. Voltus said its software will allow the buses to provide wholesale synchronized reserves, improving grid stability and increasing the school system’s cost savings.
“By connecting Highland’s customers to electricity markets that value them, Voltus is unlocking the power of electric vehicle fleets,” said Dana Guernsey, Voltus’ chief product officer. “We’re thrilled to demonstrate the value that electric school buses can provide to support grid reliability. … We aim to help Highland accelerate the transition to 100% electric school buses by layering on ancillary services and other value streams, which make adopting electric school buses the profitable choice.”
The company says it has a 2,600-MW portfolio across all nine U.S. and Canadian wholesale power markets. The resources include small-scale residential clients to major manufacturers and data centers.
Under the $1,312,500 four-year contract Highland and MCPS entered last year, Highland will provide the school buses, install charging infrastructure, assist in training drivers and mechanics, and pay for the electricity, maintenance and repair costs. (See Schools’ ‘Budget Neutral’ Bus Deal Could Accelerate BEB Growth.)
“Partnering with Voltus allows us to offer another value stream to school districts, further lowering the cost of upgrading to electric and also supporting increased renewable energy penetration by making the bus batteries available to utilities and wholesale electricity markets when they’re not being used to transport students,” said Ben Schutzman, vice president of fleet operations at Highland.
AUSTIN, Texas — ERCOT staff and state regulatory representatives agreed the electricity and gas industries have learned valuable lessons from the February 2021 winter storm, lessons that are now being put into place to winterize and protect critical facilities in the supply chain.
“One of the big lessons we learned coming out of [Winter Storm] Uri was we can’t be stagnant,” Thomas Gleeson, the Public Utility Commission’s executive director, said during the Texas Reliability Entity’s Extreme Events Resiliency Workshop on Sept. 20-21.
Texas RE staff moderated a series of discussions on grid resilience topics with industry experts during the two-day event.
Gleeson chairs the Electric Supply Chain Security and Mapping Committee, which was created by legislation following last year’s storm to prevent mistakenly shutting down critical gas infrastructure during a load shed. The group completed the map’s first version in April, easily beating its Sept. 1 deadline. It identified 65,000 facilities, 60,000 miles of electric transmission lines and 21,000 miles of gas transmission pipeline.
While the mapping committee met in private because it is dealing with critical infrastructure, it did hold two public meetings.
“The goal [of the open meetings] is to rebuild public trust. We need to be out there talking to folks about what we’re doing, why the map has to stay secure and private,” Gleeson said. “It’s important for us to explain the work that we’re doing to ensure to Texans that we are providing them with the best grid that we can.”
Working on a separate path, PUC staff developed expanded weather preparation rules for generators and transmission utilities to ensure reliability during both summer and winter weather events. The PUC adopted those rules on Thursday.
Natalie Dubiel, an attorney for the Texas Railroad Commission, thanked the mapping committee for its work, which started a six-month clock for the regulatory body to adopt its own weatherization rules. The RRC, which oversees the state’s natural gas and oil industries, had its rule in place Sept. 19, beating its deadline by almost six weeks.
“The rule is fairly dense,” Dubiel said. “We did want to get it in place before that timeline just to give our operators a chance to prepare for this upcoming winter, particularly given that this is a whole new area of jurisdiction that the Railroad Commission did not have.”
Rule 3.66, as it’s known, applies to gas supply chain and pipeline facilities. Their operators must implement “weather emergency preparation measures” by Dec. 1 each year that ensure sustained operations during a weather emergency and correct weather-related forced stoppages that prevented sustained operation because of previous weather emergencies.
Dubiel said the RRC broadened the definition of energy emergency to cover more than just load-shed events.
“There may be times the grid is constrained and demand is high. We want gas flowing,” she said.
“We’re better prepared than we were last year,” said ERCOT’s David Kezell, who joined the grid operator as its first director of weatherization and inspection last October.
ERCOT developed an inspector training program, hired inspectors and sent them out into the field before last winter to check on generators that failed during the 2021 storm. Kezell said market participants demonstrated “high levels of compliance” last winter. Going forward, inspections will occur before both the winter and summer seasons for generation resources and transmission facilities.
“This really is a team effort. … Where the rubber meets the road is in the facilities and the people that are doing the work,” he said. “We’ve got a new structure in terms of state law. The actual technicians have to do a good job of doing their job, so we applaud them for the effort that they’re going through.”
Cold Weather Standard Nears Approval
Mark Henry, Texas RE’s director of reliability services and registration, said he expects the NERC Board of Trustees to approve the EOP-012-1 (extreme cold weather preparedness and operations) standard during its October meeting, with FERC approval then coming before year-end.
The standard passed NERC’s membership on its second attempt earlier in September. The standard, part of NERC’s Project 2021-07 (extreme cold weather grid operations, preparedness and coordination) in response to the mass outages caused by the February 2021 winter storm, was posted for comment in May. (See “Updates on Standards Projects,” NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022.)
“There’s a little bit more bite and specificity to [the standard],” Henry said.
The standard revises some requirements instituted after the 2019 cold weather event involving MISO and SPP. It adds freeze-protection criteria to freeze-protection systems; a five-year review of minimum temperatures, cold-weather plans and freeze-protection measures; and corrective action plans for freezing events.
It will take effect April 1, 2023.
Work continues on a second standards authorization request for the 2023/24 winter, Henry said. This phase of Project 2021-07 would set requirements for identifying cold-weather critical components and systems for each generating unit and implementing freeze-protection measures; determining the generating capacity that can be relied upon during “local forecasted cold weather”; and protecting critical natural gas loads from load shed.
Early Projection for Mild Winter
ERCOT’s in-house meteorologist, Chris Coleman, promised his audience they will eventually see a respite from one of Texas’ hottest summers on record. Winter is coming, he said, but it has a greater potential to trend warmer than colder.
The potential of a third-straight La Niña winter is one reason why. Coleman said that since 1950, there have been 26 La Niña winters in Texas. Fourteen of those have fallen in the warmest third of all winters, but three have fallen in the coldest third.
“There is some correlation between La Niña and the unlikelihood of a cold winter,” he said. “There’s no correlation between La Niña and a winter with an extreme cold event.”
It can happen, though. Since 1894, Dallas has had 14 winters where the temperatures have reached 5 degrees Fahrenheit or lower. Two of those occurred during La Niña.
“When I say it’s going to be a warm winter, there could still be a day or two, or a week or two, that’s extremely cold,” Coleman said. “You can get some pretty dramatic changes in the winter.”
June through July was the second hottest period for Texas, topped only by 2011. Those months were also the 39th driest on record — 2011 is No. 1 there too — and the fifth driest this century. Austin has recorded 68 100-degree days this year, San Antonio 58, Dallas 47 and Houston 22. One more 100-degree day in Austin would move 2022 into second place for days over the century mark, behind only 2011.
“If you’re getting close to records, you might as well just break the record,” Coleman said. “In fact, I get upset when it’s 99 degrees. ‘Just give me that 100. It’s not like it feels that much different.’”
The New Jersey Board of Public Utilities (BPU) on Wednesday approved an easement sought by the state’s first offshore wind project, Ocean Wind 1, to run transmission onshore through Ocean City to a substation, removing a key obstacle to the project.
With little comment, the five-member board unanimously approved an order that said developer Ørsted had demonstrated that the easement for transmission to run underground across land developed with money from the state Green Acres program was “reasonably necessary” to the construction and operation of the wind project. Green Acres funds are awarded to develop parks and open space. The order also granted the project a series of consents needed to obtain environmental and other permits.
The BPU’s approval, in the face of opposition from Ocean City’s governing body and residents, opens the way for Ørsted to seek easement and permit approval from the New Jersey Department of Environmental Protection (DEP), which is needed for the project to get federal backing. Ocean City had asked the BPU to delay the project while an administrative hearing and environmental studies of the cable route are conducted.
However, the project still needs the BPU’s approval in a second case, in which the developer needs permission to run transmission on land owned by Cape May County and that government’s consent on permit approvals.
The Ocean City case was first test of a controversial law enacted in July 2021 that allowed offshore wind developers to site power cables and equipment on public land regardless of local or state government opposition. The outcome of the case could provide a roadmap for other projects facing similar opposition in the future.
The reasonably-necessary standard was set out in the law, which specifically prohibited municipal and county governments, and state agencies, from preventing the placement of offshore wind equipment if the BPU gave its approval. (See NJ Lawmakers Back Offshore Wind Bills.) Several speakers at public hearings into the easement argued that the law effectively disenfranchised local officials and removed their authority to make decisions on issues that would affect their residents.
Ørsted is seeking a 30-foot-wide easement running the length of the island on which the city is located, which is about 8 miles long. A 275-kV line will connect Ocean Wind’s turbines, about 15 miles offshore, to the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.
Without the law in place, and the BPU’s power to override local authorities, the project would have needed Ocean City’s consent for several permit approvals, including Waterfront Development, Wetlands Act of 1970, Coastal Area Facilities Review Act, Flood Hazard Area Control Act and Freshwater Wetlands Protection Act, and a Tidelands License, among other permits, according to the order.
Those permits are required for the DEP to “issue a federal consistency determination, which is a prerequisite for Bureau of Ocean Energy Management’s (BOEM) approval of the project’s construction and operations plan,” according to the order.
The 1,100-MW Ocean Wind project, which was approved in 2019, was the first of three approved offshore wind farms by the state so far. The BPU has also approved the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, and the state expects to hold a third solicitation, for 1,200 MW, in the first quarter of 2023. (See related story, NJ Seeks Stakeholder Input for 3rd OSW Solicitation.)
The BPU’s ruling came the day before it holds two online hearings on another easement for an underground transmission line from the Ocean Wind 1 project across land owned by Cape May County. In that case, Ørsted’s petition says Cape May officials have not responded to its efforts to secure approvals.
Public Opposition
Although the Ocean Wind project is strongly supported by government officials and embraced by environmentalists, Ocean City opposes the project, as do local residents, who say the nearly 100 turbines will tarnish their ocean view. Also opposed are commercial fishermen, who say it will hurt their ability to fish, and tourism interests, who fear fewer visitors will come to enjoy a shoreline with turbines on the horizon. (See Ørsted NJ Wind Project Faces Local Opposition.)
The board’s approval Wednesday in the Ocean City case followed two public hearings into the easement application and an online session in which Ørsted and the city presented oral arguments. Speakers in the two hearings opposed to the easement focused as much on their concerns about the project as a whole, and offshore wind in general, as on the details of the easement and how it would affect the community.
Mike DeVlieger, a former Ocean City councilman, said that “overwhelmingly our community is against this, and it’s not even close.” He added that “this presents medical concerns; it can present environmental concerns.”
But environmentalists argued that the threat of climate change is so serious that radical action was needed, and any potential disruption would not reach an unacceptable level.
Dorothy F. McCrosson, solicitor for the city, argued that Ocean Wind 1 could avoid the conflict with Ocean City if it opted to send the transmission through nearby Egg Harbor instead. In that scenario the beach and wetlands would not be disturbed and the streets would not be excavated.
She said the alternative route would present no disruption to Ocean City, but Ørsted had dismissed it earlier because it would be more expensive.
But attorney Gregory Eisenstark, representing Ocean Wind 1, said that once the construction was complete, there would be minimal disruption because the lines would be underground. He argued that the main reason that the city opposes the project “has to do with Ocean City’s overall objection to offshore wind.”
He argued that under the reasonably-necessary standard set out in the law, the route chosen by Ørsted just had to be a reasonable one. “It doesn’t have to be the best one. It doesn’t have to be the lowest-cost one.”
ISO-NE repeated a familiar refrain on Wednesday while presenting its initial take on FERC’s interconnection Notice of Proposed Rulemaking: give us flexibility and make sure our region’s particular needs can be met.
The rulemaking is intended to help free up what FERC commissioners see as a backlog slowing the development of new generation and in turn threatening reliability. (See FERC Proposes Interconnection Process Overhaul).
But in a presentation to NEPOOL’s Transmission Committee on Wednesday, ISO-NE made clear that it sees its own interconnection challenges as less daunting than what some of the other, larger RTOs are facing.
“New England does not currently suffer interconnection queue backlogs to the same extent as other regions,” said Al McBride, the grid operator’s director of transmission strategy and services.
ISO-NE is still readying its formal comments, but in the preliminary ideas presented to stakeholders, McBride emphasized that the proposed changes to the interconnection process for RTOs are “expansive” and would involve trade-offs about how grid operators spend their time.
In recent years, McBride noted, ISO-NE has integrated its interconnection planning with the Forward Capacity Market, launched the Elective Transmission Upgrades project, and adopted clustering procedures which let projects be evaluated together.
Those changes shouldn’t be overwritten by whatever comes out of the NOPR, the grid operator is arguing.
“It will be important to explain that it will be preferable to retain some aspects of these enhancements under allowances for regional differences, which is consistent with the NOPR,” McBride said in his presentation.
For example, the NOPR calls for a new cluster study process, which in some ways clashes with what ISO-NE is already doing.
Another point of the NOPR, which is likely to be among its most contentious, is that the proposed rule would carry with it new firm deadlines for interconnection studies and penalties for transmission providers if they aren’t met. Those new features would replace the existing “reasonable efforts” standards.
ISO-NE is wary of the proposed new penalties for several reasons: McBride warned that adding a punishment could introduce the potential for litigation or administrative processes that could distract and divert resources away from conducting the actual studies at the heart of the interconnection process.
And he also noted that sometimes delays aren’t the fault of ISO-NE.
The deadline for comments to FERC on the NOPR is Oct. 13, with reply comments due on Nov. 14.
NEPOOL counsel also published draft stakeholder comments on the NOPR last week, with the theme the same: allow for flexibility.
“NEPOOL urges the Commission to allow for variations from the pro forma procedures and agreements in any ISO/RTO compliance with and implementation of the final rule, to the extent justified under the independent entity variation standard,” the comments read.
New York City is on the verge of implementing the nation’s first traffic congestion pricing scheme, titled the Central Business District Tolling Program (CBDTP), which will seek to generate revenue and reduce pollution across the city.
MTA’s Central Business District Tolling Program Area | MTA
The CBDTP would electronically charge motorists up to $35 when entering Manhattan below 60th Street to reduce traffic while raising revenue to fund improvements to the Metropolitan Transportation Authority’s (MTA) subway and bus systems.
Passed by the New York State Legislature in 2019, the plan was originally slated to be implemented in 2021, but lack of federal environmental guidance, the COVID-19 pandemic and a changing governorship because of political scandals delayed the project until at least 2024.
The MTA, which has been slow to recover from the unprecedented drop in ridership during the pandemic, estimates that the CBDTP will generate $1 billion annually.
Despite potential economic benefits and grassroots pressure to act on climate change, there has been fierce opposition to the plan, specifically around the proposed costs and the shifting of pollution to the city’s outer boroughs.
History & Details
A congestion pricing scheme for the city was first proposed in 2007 as a disincentivizing fee that would reduce traffic and generate revenue but was only formally approved in the state’s 2019 budget.
The legislation was initially light on details but created exemptions for emergency vehicles, residents who reside inside the tolled zone but earn less than $60,000, and disabled persons.
One critical detail that was known about that the CBDTP was that it would operate through electronic sensors connected to the E-ZPass system.
Although officials have not settled on a fee scale, authorities have stated that E-ZPass holders entering the CBD at peak times would pay between $9 and $23, while those without one and pay the toll by mail can expect to spend as much as $35 during peak times. Discounts would be enabled during off-peak and overnight periods.
The CBDTP’s biggest gaps are around how different types of vehicles, particularly delivery trucks, private taxi services such as Uber and the famous yellow taxis, would pay these tolls. Critics have also complained about the lack of distinction being made between commercial and noncommercial vehicles.
Some proposals that may allay these concerns, but are still under consideration, include setting fee caps on vehicles that have entered the CBD more than once, creating further exemptions for certain classes of passenger vehicles, or even having the MTA’s own buses pay the toll.
Despite these concerns, supporters are delighted by the prospect that the city may implement a decades-long quest to unclog its jammed streets. They and the MTA have pointed to Stockholm, London and Singapore as examples of how congestion pricing schemes not only reduced traffic but also reduced greenhouse gas emissions.
According to the Federal Highway Administration (FHWA), Stockholm’s congestion program resulted in a 25% reduction in congestion, a nearly 15% reduction in emissions and at least a 6% increase in use of public transport, while London’s program led to a 20% drop in emissions, a 30% increase in average vehicle speed and a 25% drop in traffic.
The momentum behind the CBDTP briefly stalled in anticipation of an environmental review that needed to be conducted by both the federal government and state agencies but was delayed during the Trump administration.
Environmental Assessment
The FHWA’s long-awaited environmental assessment (EA), released Aug. 10, evaluated the effects of the CBDTP across seven different tolling scenarios.
The EA found that all scenarios would reduce traffic into Manhattan by as much as 20% for personal vehicles and up to 80% for trucks, though this could lead to a 2.6% increase in trucks driving outside the borough, including through North Jersey.
Total Number of People Entering Manhattan CBD in 2019 | NYMTC Hub Bound Travel Data Report
The report promisingly found evidence that New Yorkers would ditch their personal vehicles for public transportation and that certain scenarios resulted in reductions of as much as 12% of pollution in the CBD.
The EA was required because tolls would be collected on federally funded roads, and a study needed to examine any impacts that the program would have on disadvantaged communities.
In this regard, the report found that certain environmental justice communities could experience reductions in traffic, though these would be offset by traffic increases in areas where toll-dodgers shifted their driving.
The EA’s findings gave some congestion pricing supporters pause as they feared that localized concerns would narrow the CBDTP, which they believe is critical to reducing the city’s overall pollution, tackling the climate crisis and providing funding to a mass transit system still recovering from the pandemic.
The EA did in fact create considerable public backlash, particularly from those located in the South Bronx, Staten Island, Nassau County and Bergen County, N.J., who would feel the brunt of both the environmental and economic consequences from the CBDTP.
In fact, the backlash was so strong that the EA’s public commenting period was extended until Sept. 23 to allow more time for public input after being initially slated to conclude on Sept. 9.
Detractors & Supporters
The debate rages on, and New Jersey Gov. Phil Murphy (D) was the latest contributor.
Murphy said he was opposed to the CBDTP because the recent EA was too “long and complex.” He also said residents had little time to digest its findings nor had any involvement in the planning process, yet they would suffer from the costs without receiving “any direct benefit from the revenues.”
The governor, however, remains supportive of a congestion pricing scheme intended to reduce traffic and emissions. But he alleged that the CBDTP’s primary goal is “revenue production.”
Similarly, New York Mayor Eric Adams (D) supports congestion pricing, but he recently said that the city had “very little input” on the program, and it required more exemptions for disadvantaged and disabled citizens, who he claims will struggle to afford the tolls.
Opposition has forcefully come from U.S. Rep. Nicole Malliotakis (R), who represents New York’s 11th congressional district covering Staten Island and Southern Brooklyn. She said at one recent public hearing that the CBDTP “is being jammed down the throats of the people.”
These sentiments were echoed by U.S. Rep. Josh Gottheimer (D), who represents New Jersey’s 5th congressional district covering parts of North Jersey, including much of Bergen County. Gottheimer said in a hearing that the plan will “drain our families’ pocketbooks” while doing “nothing to actually help the environment or ease congestion.”
Another House Democrat, Ritchie Torres, who represents New York’s 15th congressional district covering the South Bronx, said in a statement that he is concerned about “any plan that threatens to intensify diesel truck traffic on the Cross Bronx Expressway” because it “would raise serious concerns about public health and racial equity.”
Despite fierce opposition, the CBDTP still has supporters.
Brooklyn Borough President Antonio Reynoso (D) recently said at a hearing that “for our city to continue to function, we must get people out of their cars and back onto reliable public transportation.”
Meanwhile, New York Gov. Kathy Hochul has remained supportive of the CBDTP, having said during the Democratic gubernatorial primaries earlier this year that she “supports congestion pricing 100%” and has shown little sign of working against its implementation.
Additionally, many participants during the public commenting period expressed support for the plan because of the potential reduction in traffic, increased speed of public transport, improved air quality in many parts of the city and reduced pollution.
Supporters also countered their detractors by claiming that the amount of people who will shift to mass transit, as well as the upgrades to these systems, will offset localized concerns.
Outlook
Without significant pushback, however, the CBDTP is poised to be approved in mid-2023 and implemented by early-2024.
With the recent completion of the FHWA’s review and the conclusion of the public commenting period, the next steps will be for MTA to share the public’s feedback with the FHWA, which is then expected make a formal decision on the EA in January 2023.
If the FHWA’s final review finds no significant impact from the CBDTP stemming from the public comments, a six-person Traffic Mobility Review Board (TMRB) will finalize toll rates and detail how a credit system will be implemented.
Should the FHWA find any issues, however, it may require a more thorough environmental impact statement, which is what some critics, such as Murphy, have been requesting. Ultimately, the final arrangement will be voted on by MTA board members.
Software designed to provide computer security had the ironic consequence of rendering an electric utility’s essential systems unusable for over a half-hour, and then for more than an hour the following weekend, according to a new Lessons Learned report published by NERC on Wednesday.
The incident outlined in the Loss of Energy Management System Functionality due to Server Resource Deadlock document began with an antivirus software suite installed on production servers for the utility’s energyy management system (EMS). When exposed to certain malware signatures found in the EMS production environment, the software deadlocked — meaning that a process or thread entered a waiting state that it could not exit because it needed resources in use by another waiting process.
As with all of NERC’s Lessons Learned reports, specific details about the event — including the location, date, utilities and regional entities involved — were not provided in order to keep the focus off individual companies. The goal of the documents is not to identify wrongdoing or deficiencies but to educate entities on potential issues that may not be covered by existing reliability standards. At the same time, NERC emphasizes that “implementation of these lessons learned is not a substitute for compliance with” NERC’s standards.
The “flaw was latent in the engine” of the antivirus software, but the registered entity’s staff did not detect it in testing because the production servers had “extremely high file I/O [input/output]” compared to the test environment, resulting in “more opportunity for the antivirus engine to deadlock.”
After the servers locked they were “effectively … unavailable to operators” and left the entity unable to control bulk electric system elements at affected substations. As a result, operators could not calculate reporting area control error (ACE), control performance standards, or implement automatic generation control. In addition, the entity’s state estimator and real-time contingency analysis (RTCA) were not solving, and the EMS could not perform its real-time monitoring and alarming functions.
The first deadlock lasted 31 minutes. NERC said in the report that the entity was able to implement alternative processes for most, if not all, of the affected functions. For example, personnel at regional dispatch centers were able to monitor BES substations and notify the entity of any unusual conditions, while the reliability coordinator took over solving the RTCA and calculated reporting ACE until the utility could restore the system.
The utility’s incident response team (IRT) resolved the first deadlock by disabling non-critical services on the active EMS servers. By this point the provider of the antivirus software had identified a flawed signature as the likely root cause. The IRT applied a new signature and re-enabled non-critical services.
The second deadlock occurred five days later, and the entity implemented its response measures again. After failing to restart the EMS processes through a soft reboot, the IRT decided “to quarantine the impacted server for forensic analysis and to perform a hard reboot of the servers.” Meanwhile, the team again disabled non-critical services on the active EMS servers, which were not re-enabled until the IRT had tested and verified their safety.
This time the deadlock lasted 81 minutes before EMS functions were fully restored. The IRT’s forensic analysis of the affected server determined that the deadlock occurred when the EMS processes, backup services processes, and anti-malware processes ran simultaneously. In addition, the vendor discovered the flaw in the malware engine that ultimately caused the problem.
NERC identified several lessons from the utility’s experience: first, after the initial deadlock the entity accepted the antivirus vendor’s misdiagnosis of the root cause as a signature flaw at face value rather than performing its own testing. Because the actual underlying issue was not addressed, the system remained vulnerable to the same flaw. NERC suggested that entities implement “a more rigorous testing process … during incident response to verify the root cause.”
Next, the report suggested that having staff present — both in the central control center and in the “war room” where the IRT coordinated its response — provided a major help, with a “shared physical space [that] allowed the team to decompose a complex problem [and] maintain momentum and energy during the long response.” Conversely, the ability to remotely and securely connect to the EMS systems, implemented in 2018, “shaved significant time off the response” compared to having to drive onsite to gain physical access.
NERC also noted that with “modern EMS technology environments [making] incidents more complex to respond to,” multiple teams had to coordinate their actions to restore stability to the system. The organization said responders should be prepared with a central response toolkit and scenario-based training so that they can be prepared to use their tools in the proper way. The ability to quarantine the impacted server was also noted approvingly because it allowed the IRT to perform in-depth analysis without affecting active production equipment.
