Two renewable energy industry groups are asking federal regulators to address what they say are unfair preferences given to gas-powered generators in ISO-NE.
In a Section 206 complaint filed with FERC this week, RENEW Northeast and the American Clean Power Association wrote that ISO-NE’s rules and practices around capacity accreditation and operating reserve designation don’t adequately take into account the uncertainty of natural gas supply in the region, particularly in winter.
The undue preference, they say, harms almost every other type of generation resource in the region.
The complaint says that ISO-NE’s capacity accreditation for gas-only resources is an “outlier,” in that the grid operator treats them as equivalent to resources with dedicated, on-site fuel supplies despite “known uncertainties with fuel availability for gas-only resources in winter peak conditions” — the well-established pipeline constraints that have been in play in New England for years.
ISO-NE’s qualified capacity rating for a gas generator is based on a test that only confirms the physical ability of the resource to convert fuel into energy, and not its access to that fuel.
“Gas-only resources receive an undue preference by being treated the same way for capacity accreditation as generators with known, dedicated fuel supplies, in spite of uncertainties about the ability of gas-only generators to obtain gas supply in peak winter conditions,” the complaint says.
The groups also contend that the grid operator’s operating reserve designation involves similar undue preferences, because gas-only resources are again unique in that they’re not required to prove the availability of fuel.
“A gas-only resource that cannot find gas is the same as a wind resource without wind or a solar resource without sun,” said RENEW executive director Francis Pullaro. “There is no justification to treat gas-only resources in a different manner.”
ISO-NE spokesperson Matt Kakley said the grid operator is reviewing the filing, noting that the RTO has already started a stakeholder process to improve its capacity accreditation. In its 2022 work plan, the RTO says it is aiming to find methodologies to “appropriately accredit resource contributions to resource adequacy as the resource mix transforms,” with a tentative plan to have a filing to FERC by the end of the year.
The primary method under discussion for doing so is effective load carrying capability (ELCC).
“A commitment by ISO-NE to timely take steps through ELCC implementation to set winter capacity ratings for gas-only resources consistent with the level that could be fueled on a cold winter day would be a positive step,” the renewable groups wrote in their complaint.
By 2035, zero-emission medium- and heavy-duty vehicles (MHDVs) — from delivery vans to 18-wheelers — should be no more expensive to buy and operate than those that run on diesel, according to a new study from the National Renewable Energy Laboratory (NREL).
With that kind of price parity on the horizon, electric trucks could make up 42% of new MHDV sales by 2030 and close to 100% by 2045, the report says.
Those timelines map out “a clear pathway for trucking companies to make the switch from diesel to electric that will help them cut costs and pollution for their customers, while combating climate change,” Energy Secretary Jennifer Granholm said in the March 7 press release announcing the study.
Based on 2019 figures, MHDVs produce about 445 million metric tons of carbon dioxide per year, 21% of the U.S. transportation sector’s total emissions, the report says. While California and other states are attempting to reduce those emissions with rules requiring that increasing percentages of new truck sales be electric, the NREL report builds on the assumption that adoption of these zero-emission vehicles (ZEVs) will be driven by economics by comparing total cost of ownership (TCO).
By 2050, zero-emission vehicles will make up 80% of all trucks on the road, but the 20% of older ICE trucks will use 50% of the energy needed to power the U.S. fleet.
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NREL
A key metric for fleet owners and drivers, TCO includes not only the upfront costs to buy a vehicle, but also its fuel, maintenance and resale value. The report plots the time frames for when battery electric or fuel cell electric vehicles (FCEVs) will reach price parity with comparable diesel vehicles.
The upfront purchase price for an electric MHDV is generally higher than a traditional diesel-powered vehicle with an internal combustion engine (ICE) at present, while fuel and maintenance costs are lower. A 2021 study from the Lawrence Berkeley National Laboratory estimated maintenance for a heavy-duty diesel truck at $12,000 to $13,000 per year versus $6,500 per year for a comparable electric truck.
The NREL report projects that battery and fuel cell prices will trend down between 2035 and 2050, which will lower the overall costs for electric MHDVs.
Electric trucks may be two to three times more expensive than ICE vehicles, according to Fred Ligouri, a spokesperson for Daimler Trucks North America. The company’s Freightliner division has been working with customers to test out a small, preproduction fleet of electric MHDVs and will begin production on its heavy-duty model in late 2022, he said.
Drive More, Save More
The timelines for when ZEVs ― both battery electric vehicles and FCEVs ― will reach price parity with ICE vehicles depends on the vehicle type — medium or heavy duty — and the distances they travel.
For example, the study finds that a heavy-duty battery electric truck with a range of 300 miles and traveling 100 to 500 miles per trip will reach price parity with a similar diesel vehicle around 2033. But if the truck is used for shorter trips, the break-even point is pushed back to 2041.
The correlation between these short distances and later break-even points holds true across different classes. “It’s not a technical problem; it’s mostly a matter of cost,” said Matteo Muratori, team leader for integrated transportation and energy systems analysis at NREL.
With EVs, “you spend more money when you buy the vehicle, but the more you drive it, the more money you save,” Muratori said in an interview with NetZero Insider. “Vehicles that are driven more save more and reduce emissions more; vehicles driven less save less. It takes longer to recover the initial capital cost.”
At the same time, he said, range matters; an electric truck with a range of 150 miles could reach price parity sooner than one with a range of 300 to 500 miles. “Shorter-range vehicles make more economic sense in the near term, and the longer-range vehicles start making economic sense when you get closer to 2030 or 2035,” he said.
Price parity for FCEVs also varies. For medium-duty vehicles, price parity with diesel is expected in 2031, while for heavy-duty FCEVs, the break-even point comes in 2033 or 2034.
Based on these projections, the report estimates that by 2045, 80% of all medium- and heavy-duty trucks on the road could be ZEVs, cutting emissions 69% from 2019 levels.
The report also notes that electric buses have become the leading edge in this transition, as they are already cost-competitive with diesel vehicles “in certain contexts … depending on vehicle and fuel prices and driving requirements.” The TCO for battery electric buses is anticipated to be “well below” that of diesel buses by 2032, the report says.
The Caveats
The NREL report comes with caveats, the most significant of which is the volatile nature of diesel prices. With the war in Ukraine and ban on Russian oil imports driving record spikes in prices, ZEVs could attract a wider range of buyers.
“Diesel is never the cheapest solution anymore because it is priced higher,” Muratori said.
Megawatt chargers will also be needed to keep EVs competitive, he said, and in some instances, FCEVs may be more time- and cost-efficient than battery electric vehicles because fuel cells run on hydrogen, which allows quicker refueling.
“If hydrogen is really cheap and electricity is really expensive, fuel cell vehicles make a lot more sense and vice versa,” Muratori said.
The report’s focus on bottom-line economics also leaves out key variables that may affect the speed and scope of electric truck adoption, such as the time and cost of building out the charging and refueling networks and the supply chains that will be needed to transition the U.S. MHDV fleet. The potential impact of increasingly rigorous federal and state emission reduction and fuel efficiency standards are also not discussed.
For example, California’s clean truck rules have been adopted by five other states: Massachusetts, New Jersey, New York, Oregon and Washington. The rules require that 55% of light-duty truck sales be ZEVs by 2035; for MHD trucks, the requirement is 75% by 2035, goals that will likely affect adoption rates and market growth in those states.
Muratori said the impacts of infrastructure, supply chain and regulatory issues will be important to track as the market evolves. But echoing the report, he argues that economics will drive ZEV adoption in the commercial truck and freight sectors, and demand could rise quickly once cost parity is reached.
More IIJA Funds
Underlining to the feasibility of widespread adoption of electric MHDVs, the NREL report was released alongside a series of White House announcements intended “to advance clean heavy-duty vehicles, as part of our electric, zero-emissions transportation future,” according to a March 7 fact sheet.
While not directly related to price parity, EPA’s new proposed regulations to cut tailpipe emissions of nitrogen oxides from heavy-duty trucks were framed as a stimulus to “jump-start the transition to zero-emission vehicles in the heavy-duty fleet,” the fact sheet said. The target for 2045 is a 60% emissions reduction.
The proposed regulations would also set stricter standards for greenhouse gas emissions for trucking sectors that are already seeing faster adoption of EVs, such as school and public transit buses and commercial delivery trucks.
Other funding announcements rolled out with the NREL report include $17 million from EPA for electric buses to replace diesel vehicles in underserved communities, and $450 million from the Infrastructure Investment and Jobs Act (IIJA) for projects that will cut greenhouse gas emissions at U.S. ports.
The White House continued to push forward on heavy-duty vehicle electrification with Monday’s announcement of another round of grants for 70 projects to improve and electrify public transportation in 39 states. The $409.3 million in funding from the IIJA will be used to “modernize and electrify America’s buses, make bus systems and routes more reliable, and improve their safety,” according to a Department of Transportation press release.
“These grants will help people in communities large and small get to work, get to school, and access the services they need,” Transportation Secretary Pete Buttigieg said in the release. “Everyone deserves access to safe, reliable, clean public transportation.”
Among the grantees, the Connecticut Department of Transportation is getting $11.4 million to buy electric buses, while the Regional Transportation Commission of Southern Nevada will receive close to $5 million for new hydrogen fuel cell buses, according to the release. Still more projects will be funded over the next five years with $5.1 billion in IIJA dollars, the release said.
The New York Public Service Commission on Wednesday heard updates on how the state’s utilities are responding to the PSC chair’s pleas to improve billing practices and customer outreach in the light of this winter’s electric and gas bill surges on higher natural gas prices.
NYPSC Chair Rory Christian | NYDPS
“It bears pointing out that the price spikes we’ve recently seen are not something limited just to New Yorkers. This is a global issue, a national issue, and it’s affecting everyone from Maine to California,” PSC Chair Rory Christian said. “Customers already struggling with a global pandemic are now faced with rising inflation, rising energy costs, and concerns that the war in Ukraine could have far greater impacts in the near term and long term.”
Christian said the PSC has instructed utilities to increase their outreach on the issue, adding that he’s “optimistic” about the results of outreach efforts.
Christian wrote to Consolidated Edison (NYSE: ED) on Feb. 11, directing the state’s largest utility to increase communications and improve its billing mechanisms to reduce dramatic changes in commodity prices from month to month, an issue that exacerbated price volatility for their customers, some of whom saw their monthly bills go up by as much as 67% this winter (Case No. 22-00346).
Revenue Strategies
The other major utilities — Con Ed subsidiary Orange and Rockland; National Grid; Avangrid subsidiaries NYSEG and RG&E; National Fuel; PSEG Long Island; and Central Hudson Gas and Electric — are reviewing their power purchasing to mitigate the risk of severe price volatility, retooling their consumer communications regarding anticipated bill increases, payment assistance plans and programs to reduce energy usage.
Aric Rider and Tammy Mitchell, NYDPS | NYDPS
Con Edison filed an emergency tariff to fix its billing by the summer and said that its hedging practices include reconciling benefits in a future bill, which resulted in a bill credit for its customers beginning with Feb 11 bills and continuing through March 14, said Tammy Mitchell, director of the Department of Public Service’s Office of Electric, Gas and Water.
“While Con Edison customers experienced commodity price and bill volatility, the hedges that Con Edison entered into saved full-service mass market customers over $120 million this winter through the end of February compared to if they were simply subject to market prices,” Mitchell said.
Due to the increases, the supply portion of a Con Ed customer bill jumped from 24% of the total bill in January to about 45% of the total bill in February, she said.
Additional state directives on better outreach are not really the solution to price volatility, Commissioner Diane X. Burman said.
“We need to call out some other state officials who may not fully understand we can’t just say that we have to educate consumers,” Burman said. “I can tell you if I was a consumer who had my checking account or savings account getting an auto withdrawal, and I have overdraft, and then all of a sudden money was coming out that I didn’t expect, I would be devastated. … We have to do better as a commission in understanding that in real time and responding to that.”
Nearly 25% of a Con Ed customer’s bill goes to the city of New York as general revenue, said Commissioner John B. Howard. He said that no one at the state or city level is addressing the issue.
NYPSC Commissioner John B. Howard | NYDPS
“The state of New York today and the city council could do things immediately to provide immediate rate relief to customers,” Howard said. “I believe they could even provide retroactive relief to customers if they take their own revenue requirements and deal with them appropriately.”
Addressing advocates for converting Con Ed to a publicly owned company, Howard said such a change would not alter the fact that $0.25 on every dollar it collects goes to taxes, not to providing service.
“It’s not just Con Ed, although it’s the most gross example across our state,” Howard said. “There are a variety of taxing jurisdictions — school districts, counties, cities — that put on extra taxes to their utility customers. They could take immediate action on their level to reduce bills.”
New Billing System Woes
The PSC also approved a third-party independent consulting company to audit the management and operations of Central Hudson’s electric and gas operations and grid modernization efforts (Case No. 21-M-0541).
For large electric and natural gas utilities such as Central Hudson, the law requires such audits at least once every five years.
In addition, state officials are reviewing the utility’s response to a February storm that left more than 67,000 homes and businesses without power, and are investigating billing problems related to the company’s recent upgrade to a new IT system that resulted in many customers not receiving timely monthly bills (Case No. 22-00497)
Poughkeepsie-based Central Hudson serves about 309,000 electric customers and 84,000 natural gas customers in the mid-Hudson region.
The utility tripled its complaint resolution staffing relative to normal operations, stated it has identified the problems within its new customer information system and is working with its implementation vendor and software engineers to resolve the problems by early next month, said Aric Rider, deputy director of the Office of Consumer Services.
“Central Hudson acknowledges that approximately 7% of its customers, or 21,000 customers, mostly customers that are specially billed, are still facing billing difficulties,” Rider said.
PJM is officially going ahead with its plan for in-person stakeholder meetings at the Valley Forge, Pa. campus beginning with the April Liaison Committee after more than two years of virtual meetings resulting from the COVID-19 pandemic.
Asim Haque, PJM’s vice president of state and member services, said the RTO is following a “phased approach” from April through July with most stakeholder meetings going in-person by June. All PJM meetings will continue to feature a remote attendance option for members.
“As pandemic restrictions nationally and in Pennsylvania are relaxed, PJM is proceeding with our previously announced campus reopening plans,” Haque said in an email sent Thursday to stakeholders.
The first in-person meetings take place April 19 with the Liaison Committee meeting held on the PJM campus as part of the PJM Board of Managers meeting. The Liaison Committee runs from 3 to 5 p.m.
Haque said PJM is requesting members to register as soon as possible for the Liaison Committee meeting to have a clear count ahead of time for the number of stakeholders who will be at the campus.
The PJM Annual Meeting, which includes the board election and General Session, will take place May 17 at the campus. Meetings of the board with the Transmission Owners Agreement-Administrative Committee and the Public Interest & Environmental Organizations User Group are scheduled for May 18.
An in-person meeting of the Markets and Reliability Committee is scheduled for May 25.
Beginning in June, meetings for all standing committees and senior task forces will be held on campus. The meetings include the MRC, and Members, Planning, Market Implementation, Operating and Risk Management committees, along with the Capacity Capability, Electric Gas Coordination, Energy Price Formation, Modeling Generation, Resource Adequacy and the Regulation Market Design senior task forces.
PJM will hold the second part of the Annual Meeting’s MC and General Session at a remote location that will include a “reception and leisure activities” from Oct. 24 to 26. Haque said the location for the remote Annual Meeting is still being decided.
In-person state and member training events started earlier this month in Baltimore for the 2022 PJM Operator Seminar. Two other upcoming member training events are scheduled, including March 28 to April 22, in Columbus, Ohio, and April 25 to May 13, on the PJM campus.
Masks and Vaccinations
Haque said PJM will follow the masking guidance from the U.S. Centers for Disease Control and Prevention and the Montgomery County Office of Public Health, which is currently at a low risk level for cases of COVID-19. Masking is optional and not required indoors at the low risk level.
PJM is maintaining its vaccination policy set in November, Haque said, mandating COVID-19 vaccines for its employees, contractors, vendors and stakeholders working at or attending meetings at campus or to attend RTO events on and off campus. (See PJM to Mandate COVID-19 Vaccines.)
Haque said visitors will be required to be fully vaccinated “without exception” at the time of the event start date they are attending. He said booster shots are not required per CDC guidance.
Visitors are required to show proof of vaccination along with a valid government-issued ID upon arrival at the PJM event.
“I am looking forward to seeing each of you back at the PJM campus, and I want to again thank you for your patience, participation, goodwill and flexibility as we meet the challenges of these changing times,” Haque said.
Multiple “paradigm shifts” in the way New England produces and consumes energy could lead to thousands of miles of overloaded transmission lines, according to the preliminary results of ISO-NE’s 2050 Transmission Study.
The study, initiated by the grid operator in response to a request from the New England States Committee on Electricity for longer-term transmission planning, was designed to examine the next few decades as the region continues to ramp up its decarbonization efforts.
It found that as the region moves from a summer-peaking area to winter-peaking, increases its use of renewables and doubles peak power consumption, about half of its 9,000 miles of lines could be overloaded.
“Significant new transmission will be needed to reliably serve load under the assumptions analyzed in this study,” ISO-NE said in its presentation to the Planning Advisory Committee on Wednesday.
The most challenging scenario is the 2050 winter peak, in which overloads are caused primarily by high heating load and a shortfall in supply requires new resources.
Regional discrepancies also pop up in the study. “The paths between north and south would need significant upgrades to transfer surplus generation in Northern NE to generation-deficient Southern NE,” ISO-NE said. Other possible solutions include relocating large amounts of generation from north to south or putting more offshore wind in the southern part of the region.
The RTO is planning to perform further analysis to determine if summer-only overloads can be solved by different solar resource distributions, and to develop possible transmission solutions.
The Vermont House of Representatives passed a bill (H.715) Thursday that would direct the Public Utility Commission to create a clean heat standard for reducing greenhouse gas emissions in the state’s thermal sector.
A CHS is part of a suite of recommendations issued in December by the Vermont Climate Council in its initial Climate Action Plan to meet the GHG reduction mandates of the 2020 Global Warming Solutions Act (GWSA). In Vermont, about 70% of the thermal sector uses natural gas, fuel oil and propane, which subjects Vermonters to “fuel price volatility,” said Rep. Timothy Briglin (D), chair of the House Energy and Technology Committee. (See Vt. Lawmakers Working on Clean Heat Standard Bill.)
Fuel oil prices in the state have increased 96% since last winter, Briglin said during a debate on the bill in the House on Wednesday.
Opponents of the bill, however, are concerned that the standard will further increase fuel costs and have no clear climate benefits.
“This bill is designed to impose a hidden carbon tax on heating oil … and supposedly meet the arbitrary carbon dioxide emission reduction requirements” of the GWSA, Rep. Terri Williams (R) said.
The standard could increase fuel costs by an estimated 1.5 to 2%, based on comparable standards, such as Vermont’s Renewable Energy Standard, according to Briglin.
“That’s a modest increase relative to … the extraordinary increase in prices that we’ve seen Vermonters pay in just the last two or three weeks,” he said.
Rep. Arthur Peterson (R) expressed doubt during Wednesday’s session that Vermont’s efforts to reduce thermal emissions will have a positive effect.
“We’re 50th in the nation in the production of carbon, and the change we make [with a clean heat standard], in my opinion, won’t affect the world’s climate at all,” he said.
The bill would direct the PUC to create a system of tradeable clean heat credits that natural gas utilities and fossil-based heating fuel wholesalers can buy or earn by reducing GHG emissions through the delivery of clean heat measures. Those measures could include advanced wood heating, cold-climate heat pumps, biofuels, renewable natural gas or weatherization.
Switching from fuel oil to natural gas would not qualify as a clean heat measure.
Each credit created under the standard would be based on the lifecycle CO2e emission reductions associated with the provision of a clean heat measure. Vermont’s current GHG inventory tracks emissions by sector within the state only. A lifecycle accounting would provide a complete picture of the energy and environmental effects of any applicable heating technologies under the standard.
If the bill is enacted, the PUC would establish a docket in August for CHS development, resulting in an order in mid-2024 that implements the standard in January 2025. Clean heat measures implemented this year would earn credits under the standard, according to Briglin.
“Early action credits are important not only because we want as many emissions-reducing actions as early as possible, but because it will allow for a buildup of credits in the market in the early years of the program and lower the cost of compliance for obligated parties,” he said Wednesday on the House floor.
LANSING, Mich. — The state is behind many others in developing electric storage systems and should start taking steps to develop 4 GW by 2040 to both “ensure grid reliability and avoid curtailment of renewable energy generation,” a report released this week said.
The report, prepared for the state’s Department of Energy, Great Lakes and Environment (EGLE), also called for Michigan to reach both a short-term goal of 1 GW of storage by 2025 and a midterm goal of 2.5 GW by 2030. Storage is needed both behind the meter, in home and commercial building renewable energy setups, as well as in front, it said.
To meet the goals, the report outlines a series of 56 different policy actions that should be taken by state officials between now and 2040.
The report was developed by a project team including EGLE, the Institute for Energy Innovation, the Michigan Energy Innovation Business Council and 5 Lakes Energy, and overseen by Michigan State University professor of civil and environmental engineering professor Annick Anctil. It said that the state is taking major steps to decarbonize, with a goal of carbon neutrality by 2050, but it is not keeping pace with other states in developing new storage.
Storage will also help Michigan’s economy, the report said. “As the increasingly electrified automotive manufacturing capital of the country, Michigan’s economy stands to benefit from increased demand for energy storage technologies, including for those energy storage technologies that can be used for both mobile and stationary applications,” the report said. “There are currently 11,400 jobs in Michigan in transportation electrification, representing the largest transportation electrification workforce outside of California. Putting policies in place to support energy storage deployment will serve to grow Michigan’s supply chains in energy storage and transportation electrification — both of which promise to be large global markets.”
The state was one of the first to develop a major storage center in the Ludington Pumped Power Storage Plant along the shores of Lake Michigan in 1973.
Public Service Commissioner Katherine Peretick, whose professional background is in the storage industry, agreed that the state began ahead of others in terms of overall storage efforts, “but in terms of newer technologies, we are lagging behind other” locations.
The PSC, helped by the U.S. Department of Energy, has begun a study to evaluate where and how large-scale energy storage systems should be developed across the state, Peretick said. The researchers conducting the study will look at how the facilities “fit with our grid, with our load profile, with our generation mix [and] our utilities,” as well as give guidance on where such facilities should be built.
Despite its critical need as energy generation moves more toward renewable sources, Peretick said there hasn’t been much discussion overall on storage issues, but that is now changing. Last month, Peretick testified to the Michigan House Energy Committee on storage issues, and she said legislators asked a series of “excellent” questions on a wide array of topics, including safety.
Along with technical issues, the report goes into issues such as monetizing storage at both the wholesale and retail levels; changing legal and regulatory policies that currently focus on fossil fuel-based generation; how to properly value storage; how it fits into the state’s renewable energy standards; and incentives to develop storage systems. In each of these areas, the report looks into how other states are acting on them.
“In some cases, energy storage is simply not contemplated in Michigan policy and regulatory frameworks, while in other cases, regulations and policies place actual limitations on how energy storage can best participate in the market for electricity,” the report said.
“Michigan needs to prepare for and support the deployment and use of energy storage at the level that will be necessary to support and balance our state’s future electricity grid. This will require leadership, business innovation, appropriate incentive programs, regulatory changes and new state laws.”
In its first Lessons Learned report of the year, NERC said the winter storms of February 2021 and resulting mass outages in Texas illustrate the benefits of allowing transmission operators (TOPs) greater flexibility to manage firm load shed operations.
The document builds on a FERC and NERC joint report on the February storms, a section of which discussed the difficulties experienced by TOPs managing the load shed ordered by ERCOT on Feb. 15 in order to keep the power grid stable. Particularly challenging were the situations — which became more frequent as the day wore on — when ERCOT began to order TOPs to “implement controlled outages of electric circuits normally reserved for” underfrequency load shed (UFLS) operations.
Grid planners “typically exclude load connected to UFLS relays from manual load shed plans whenever possible,” the Lessons Learned report said, because these circuits are critical to bringing the grid back under control during an underfrequency event. Underfrequency programs are normally designed to “shed a predetermined percent of load at specific frequency setpoints.” If this load has already been taken offline manually, the system cannot function as intended and a frequency excursion becomes more likely.
ERCOT requires at least 25% of load — not including critical loads such as hospitals, military facilities and police stations — to be reserved for automatic load shedding schemes, including UFLS. However, at times on Feb. 15 and 16, load shedding in the region progressed to the point where UFLS resources represented more than 60% of the remaining load left online, and the grid was already dangerously close to a complete breakdown. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)
This situation was a significant risk because it was far outside the bounds of any scenario envisioned by grid planners. UFLS relays were designed to take no more than 25% of load offline, but here they had control over more than half of the grid at some points. As the report said, “an actual UFLS operation while the system is in this state could lead to an overshoot in frequency and further system instability.”
In response to these conditions, TOPs requested and received approval from their reliability coordinators (RC) to use UFLS circuits to meet ERCOT’s load shed orders; ERCOT’s protocols and operating guides have since been revised to “specifically allow entities to shed UFLS load as long as they continue to meet their UFLS obligations.” NERC’s report said this strategy might be useful on a wider basis, and that RCs and planning coordinators should consider revising their own UFLS programs to allow the practice.
“Having this operational flexibility would increase the amount of load available for rotation, spread the burden of outages to a larger pool of load, and reduce customer outage times,” NERC said. In addition, “taking this approach of including UFLS circuits during load shed lowers the risk of an overshoot in frequency if UFLS operates when actual UFLS loads substantially exceed the required obligations.”
The organization also mentioned that rather than giving the same treatment to all loads designed as critical, TOPs can consider adapting their strategies to the specific requirements of each situation. If a particular load can “withstand outages of several hours without having negative impacts,” it might be considered for load shed of a shorter duration.
While the Biden administration has touted the infrastructure bill approved last year as a way to address climate change, state and local discretion over highway spending could actually cause increased emissions, an analyst told the Maryland Greenhouse Gas Mitigation Working Group Tuesday.
James Bradbury, mitigation program director for the Georgetown Climate Center, told the working group that the Infrastructure Investment and Jobs Act will provide about $599 billion in funding for surface transportation for 2022-26, giving state and local governments discretion to spend as much as 27% of it — or as little as 4% — on new highway construction.
According to the Climate Center’s analysis, spending on new highways could increase emissions beginning in 2026, resulting in a 1.6% increase relative to the baseline by 2032.
“That’s because building more roads consistently results in more traffic — an ‘if you build it, they will come’ effect known as ‘induced demand,’” the center said. “In short, traffic expands to fill the new lanes within a few short years, bringing with it more pollution.”
In contrast, limiting new highway spending to 4% of the total would reduce emissions by 1.3% from the baseline.
“This may not sound like much, but it’s substantial for nationwide transportation emissions in just five years,” Bradbury said.
The Infrastructure Investment and Jobs Act, which provides about $599 billion in funding for surface transportation, gives state and local governments discretion to spend as much as 27% of it — or as little as 4% — on new highway construction. | Georgetown Climate Center
Between 2010 and 2020, an average of 15% of obligated federal funds administered by the Federal Highway Administration was used for highway expansion projects, including new construction, relocation, reconstruction (added capacity), new bridges and major bridge rehabilitation.
“We think the real-world outcome will end up somewhere in between” the high-emission and low-emission scenario, Bradbury said. “Certainly it’s too soon to say where things are headed; It’s a five-year spending bill. But projects are already being funded.”
Although formula funding programs have long provided flexibility for highway dollars to be used for emission-reducing investments like transit and electric vehicle charging, it’s not required by law.
“So those decisions are really largely left up to the states to make,” Bradbury said. “To ensure that investments result in meaningful [emission] reductions, concerted efforts are going to be needed across all levels of government, the state [departments of transportation] will obviously play a crucial leadership role, but governors, legislators, local governments, municipal planning organizations will also be a part of these decisions,” he added.
Telecommuting ‘A Wash’ on Emissions
Bradbury said the increase in telecommuting because of the pandemic has not had a significant impact on emissions because of “rebound effects.”
“While you have some people working from home, oftentimes, those people … might hop in their car at lunchtime and drive to the mall and do some shopping, and the net effect are they tend to have more trips near home,” he said. “You know, those commutes to work oftentimes would be multi-purpose: They pick up kids on the way home and stuff at the grocery store on the way home, as opposed to doing lots of local individual trips. … The net effect of telecommuting, working from home, on VMT [vehicle miles traveled] tends to be somewhat of a wash.”
Angst over EV Costs
Michael Powell, co-chair of the working group, questioned whether funding supporting EV charging would be better spent on subsidizing the vehicles.
“I just spent a lot of time in meetings with building owners and developers who are complaining that they’re putting in electric charging stations and nobody plugs in there,” he said. “I’m beginning to believe that it’s not an infrastructure issue in the short term: it’s the cost of the cars. … I’m beginning to think that we’re getting the cart before the horse here — that if we could lower the cost of the vehicles, people would solve a lot of the charging problems by putting just level one chargers in homes and workstations.”
The Rocky Mountain chapter of the Energy Bar Association this month hosted a panel to discuss the intricacies of creating an organized market in the West.
Erin Overturf, Western Resource Advocates | Energy Bar Association
Each panelist at the March 3 “Winter Energizer” gave a short presentation on their organization and its part in the energy transition. And each made it clear that an organized market would be crucial to reaching the region’s decarbonization targets.
“The aim of this conversation is to decarbonize … the power system as quickly as possible, as reliably and as cost effectively as we can,” Erin Overturf, director of clean energy programs for Western Resource Advocates, said. “We see regional markets as … a key tool to be able to achieve those aims.”
But the panelists acknowledged that the political diversity of the West means designing this market will not be a simple undertaking. Being flexible enough to accommodate states and their varied interests is key to creating a system that benefits states, utilities and ratepayers alike.
Carrie Simpson, Xcel Energy Colorado | Energy Bar Association
“Letting states speak for themselves about what it is that they need to be able to get out of a regional market in order for it to work, I think is absolutely critical,” Overturf said.
But designing a market that is mutually beneficial for all participants would only be the first step to widely decarbonizing the West. To curb greenhouse gas emissions more rapidly, interregional transmission will need to be constructed throughout the entire footprint. And as seen with MISO and SPP, an organized market does not inherently lead to the construction of interregional transmission, said Carrie Simpson, director of western markets for Xcel Energy Colorado.
“I don’t know that an RTO automatically just opens the door for transmission because I think it’s all about what the rules are and what the policies are and what the cost allocation rules are,” Simpson said.
Rachel Bryant, PA Consulting | Energy Bar Association
Though membership in an RTO may improve a utility’s situational awareness and allow it to better assess what kind of interregional transmission projects may be most beneficial, it does not necessarily ease the process of constructing these projects.
The main drawback states and utilities face when considering an organized market is the fear of a lack of autonomy. Rachel Bryant, a principal consultant with PA Consulting, said states have seen how some markets in the East have been rigid and were designed without diverse state policies and adaptability in mind.
“Breaking through that sort of stigma that you’re going to lose all your rights and be forced to do things you don’t want to do — I think is a huge part,” she said. “I feel like markets almost need a marketing manager to make this seem appealing to the people who are most resistant.”
