With MISO still years away from allowing distributed energy resource (DER) aggregators to fully participate in its markets, the RTO hosted experts this week to discuss best practices in registering DERs and data sharing.
Voltus’ Emily Orvis said she thought it was valuable to talk about MISO’s current DER registration process even if the grid operator may be six years away from final compliance with FERC Order 2222.
The RTO has requested that the commission allow it to wait until nearly 2030 to introduce a wholesale participation model for DER aggregation. It said it first needs to replace its market platform before staff have the technological capability to comply with the order. (See MISO Stakeholders Protest RTO’s Order 2222 Implementation Timeline.)
Orvis said MISO should standardize its enrollment processes for demand response, emergency demand response, load-modifying resources and dual-enrolled resources.
“The fact that there are disparate registration processes has a cascading effect,” she told stakeholders during a MISO DER Task Force conference call Tuesday. Orvis said that market participants must sometimes email sensitive customer data for LMR and emergency demand response registrations; she recommended staff adopt a single web portal for DER enrollments.
“The future is in some ways already here. We cannot wait until 2029 or whenever 2222 compliance is to figure out a more secure and streamlined registration process,” Orvis said.
She said MISO should modify its registration process so it doesn’t reject entire aggregation enrollments if a single site’s data is incorrect or changes. “For example, if one small site of 100 in an aggregation changes [its load-serving entity], the entire aggregation loses eligibility,” Orvis said.
Creation Energy founder and CEO Chris Hickman said DERs will be more useful to the grid if better data sharing is in place. He said he has always assumed an entity would step up to create and manage a collaborative tool for DER data sharing. Eventually, he said, he realized it was up to his team to establish the nonprofit registry they debuted earlier this year.
When DERs trigger grid issues, it’s because they’re incorporated with little to no operational visibility and control, Hickman said. He said DERs integrated with utility or RTO visibility and control can solve issues like poor power factor and phase balance.
“Regions like Australia, Germany, Ireland, California and Texas that have high penetrations of DERs have experienced cascading outages … and have identified a registry as the key component to help resolve issues,” Hickman said.
He said the industry has an opportunity to collaborate on a data exchange source, his organization’s Collaborative Utility Solutions, that could save billions of dollars. The nonprofit is funded by utilities’ memberships based on their size and competitive aggregators who pay for the data services. DER owners or operators are responsible for registering their assets’ information.
RTOs, state regulatory commissions, equipment vendors and other industry members are eligible for free subscriptions. Hickman said he plans to keep the subscriptions free, saying that if charged, the entities would recover their costs through utilities or consumers, effectively charging the consumer twice for the registry.
Hickman said membership costs will drop as the enrollment grows and administrative costs are dispersed.
“The more members we attract, the lower the costs go,” Hickman said. He said the system aims to replicate the Electric Power Research Institute’s (EPRI) Common Information Model.
EPRI’s Tanguy Hubert said the MISO region could house a program similar to the United Kingdom’s Flexible Power Initiative, where some DERs provide grid services by adjusting their power imports or exports.
Hubert said most of the U.K.’s DER-provided flexibility services are contracted without an advance capacity reservation for unplanned conditions. Only a fraction of capacity is contracted for planned situations under firm reservations, he said.
EPA on Tuesday announced it will propose new emission standards for cars and trucks that could lead to two-thirds of the total light-duty vehicles and 46% of medium-duty vehicles sold in 2032 being electric.
A second set of standards focuses on heavy-duty vehicles such as buses, construction equipment and utility bucket trucks. Both standards would go into place starting in model year 2027 and are built on standards already in place through 2026 that limit the amount of carbon dioxide vehicles can emit.
During a press conference Tuesday, EPA officials were tight-lipped about what exactly those amounts would be, but one official mentioned that light-duty vehicles would be limited to 82 g/mile by 2032. The standards would not mandate any specific technologies, and other carbon-cutting technologies outside of batteries will likely benefit from them, but experts outside the agency said that electric vehicles are the cheapest now.
Since President Biden took office, the number of EV sales has tripled, while the number of available models has doubled, White House Climate Adviser Ali Zaidi said at the press conference. EPA officials said the standards would improve air quality for communities around the country and avoid nearly 10 billion tons of carbon emissions, more than twice the entire country emitted last year.
They also said that they will cut fuel and maintenance costs, saving customers $12,000 over the lifetime of a light-duty vehicle as compared to a vehicle not subject to the new standards. Oil imports would be cut by about $20 billion, and the agency estimates the total benefits of the standards would exceed costs by at least $1 trillion.
The proposal aligns with commitments made by car manufacturers and U.S. states as they plan to accelerate clean technologies to include EVs as a growing part of future product lines, EPA said.
Legal and Supply Chain Challenges
The standards were developed using a process that EPA has used before when it sought to improve the mileage standards of internal combustion engines, which led experts on a call earlier in the day hosted by Environmental Defense Fund to say they should withstand any legal challenges.
“These regulations will reflect, in my view, the single most important regulatory initiative by the Biden administration to combat climate change to really reduce the worst outcomes of climate change,” Margo Oge, a fellow with ClimateWorks Foundation, said on the call.
Getting to nearly 70% EVs in the next decade is going to be challenge, but the industry was already heading this way, and the Inflation Reduction Act has funding that encourages more of the supply chain needed to build all those cars to move to domestic sources, said Oge, who worked at EPA for several decades until the Obama administration.
“We’re going to see massive, massive effort in the U.S. … to invest in all these elements,” she added. “The critical minerals are important. Battery components are important. Manufacturing facilities are important.”
There are already about 75 facilities across 24 states that are involved in the battery and critical materials supply chain, Oge said.
Advanced Energy United Director of Transportation Ryan Gallentine agreed that it was important for the U.S. to ensure its supply chains are increasingly domestic, or at least in friendly nations.
“I think ultimately, at least in the short term, it needs to be an all-of-the-above strategy for sourcing these materials,” Gallentine said in an interview.
The standards are being put in place in service of the overarching goal of limiting the worst impacts of climate change, and global politics should be put aside in furtherance of that overall goal as much as possible, he added.
Can the Grid Handle the New Demand?
Also on Tuesday, NERC, WECC and the California Mobility Center released an analysis of supplying EVs power, which did not take into account the new standards (projecting only as much as 30% of new light-duty vehicles being plug-ins by 2050) but discussed some of the power sectors challenges and opportunities. (See related story, NERC, WECC Outline EV Charging Reliability Impacts.)
The analysis laid out a number of issues with the distribution system’s capability of handling the new loads and other potential problems, but it noted that with enough planning, plug-in vehicles actually could benefit the grid by providing key services such as frequency response.
AEU’s Gallentine agreed with that assessment. Some changes to permitting laws to help expand the bulk power system on the federal side would help, but much of the work is going to be left to the states as they oversee the distribution system, he said.
“At the state level, we’ve been advocating for utility business model reform that would basically allow utilities to build in anticipation of that,” said Gallentine.
Utilities should be able to plan their systems to meet the needs of electrifying fleets and areas such as highway rest stops, where many EVs would charge at once, before that load shows up, he said.
“We need a lot of careful planning and coordination from folks at the state level to tackle the power-supply question,” Gallentine said. “And my concern is that states that aren’t doing that are going to end up with a much more expensive and less efficient deployment of this. I would say whether or not your state is supportive of EV policy, they owe it to all ratepayers to do this in a way that isn’t going to be expensive.”
ALBANY, N.Y. — Amid all the talk of electrons and dollars thrown around at the New York Energy Summit, the old chicken and egg metaphor popped up several times during the three-day event on April 4-6.
The state’s lofty climate goals are balanced by the need for the electricity fossil fuel produces, and there are multiple obstacles to replacing fossil fuel with new clean energy.
Chris Stolicky, chief of gas system planning and reliability at the New York Department of Public Service, said rapidly approaching statutory emissions reduction requirements are running into the realistic need to maintain “peaking assets to offset reduced capacity.”
A chicken and egg proposition, in other words.
Panelists applauded New York for modernizing its grid but worried that attempts to decarbonize too quickly without boosting clean energy generation threaten the state’s ability to both reliably keep the lights on and achieve its goals.
Goals vs. Needs
New York’s conundrum is how to ensure grid reliability and resilience as it calls for fossil fuel resources to be replaced by intermittent resources.
The state must “fill in the gaps for when the sun goes down or the wind breaks,” said Dr. Ingo Stuckman, founder of the Zero Emission think tank, who moderated the summit’s Alignment of Wholesale Markets with Decarbonization Goal panel.
“We have to make sure we have a market that covers the needed resources to maintain a significant amount of supply to meet extreme conditions,” said Mike DeSocio, director of market design at NYISO. But he added that the “outlook is delicate.”
“There are plenty of projects in the pipeline; the issue is we need some projects to be commercial, and that we have not seen yet,” DeSocio said, referring to the ongoing backlog of projects in NYISO’s interconnection queue. (See NYISO Previews Plan to Expedite Interconnection Queue.)
Rachel Goldwasser, general counsel and vice president at Key Capture Energy, contended that energy storage resources could solve many of these problems, but “making sure [storage resources] can be interconnected and that the market signals work … has taken longer than expected.”
DeSocio agreed that storage resources potentially present an elegant solution, but “the jury is still out.”
“We need to make sure that all the pieces are moving together on the chess board,” he said, referring to how one project’s delay in the interconnection queue can impact the timing or viability of another.
NYISO “would love to add storage” he added, but “we want to be careful not to add it too quickly because we don’t have the renewable resources yet to charge storage en masse.”
He also flagged the short duration of most current storage technology: “We haven’t seen storage in the queue that can be expected to run for 10, 12 or 14 hours,” which is the current level of support needed during a grid emergency.
In response to DeSocio’s comments, Goldwasser said, “There’s going to be a transition period where we’re going to be uncomfortable,” and if stakeholders do not address these problems, then “we’ll be in a position where we’re contracting with fossil plants to stay online.”
Cue the Queue
New York’s ability to rapidly integrate emissions-free resources has been hampered by ongoing problems with NYISO’s interconnection queue, which has been pushed to the limit since the state’s Climate Leadership and Community Protection Act (CLCPA) passed in 2019.
“We’ve grabbed the low-hanging fruit,” said Andrew Bernstein, managing partner at Kearsarge Energy, referring to residential solar projects requiring little permitting or study. “Now the question is how to get commercial and industrial projects interconnected.”
There are “tons [of projects] in queue right now. … The question is how do we reduce costs,” he said.
Daniela Pangallo, director at Nautilus Solar (NYSE: NLS), said interconnection costs are multiplied first by inflation and then by the amount of time the process takes to complete, causing some projects to exit the queue entirely.
Joe White, distributed generation ombudsman with Consolidated Edison Company of New York (NYSE: ED), said in response to these growing challenges state agencies and utilities have increasingly integrated stakeholders into these studies to identify “things that are great about the interconnection process … and what items need improvement.”
“We take that feedback and look at any software enhancements, training and opportunities to reinvent the interconnection process, and we put those into motion,” he added.
But more needs to be done to prepare for the future.
Referring to New York’s transformer shortage, Ryan G. Hawthorne, vice president with Central Hudson Gas & Electric (NYSE: CHG), said the state has a “chicken and egg problem.” Do developers push new projects through NYISO’s queue, which risks costs rising, or invest in aging assets to make them more resilient, which may not necessarily be the best long-term solution but offers a more predictable outcome?
What is a certain, he said, is that to ensure future reliability and resilience “we need [investments] in our system to be able to address more frequent and impactful [extreme weather events].”
“We’re entering a period of a lot of uncertainty related to project development,” said Kyle Collins, director of business development at Hydro-Quebec US, where interconnection concerns and questions about renewables’ ability to meet future peak loads has forced generators to “leverage as much as [they] can out of the existing system.”
In the building discussion, moderated by RTO Insider Editor Rich Heidorn Jr., panelists identified how legal mandates and policies, such as the Local Law 97 or the CLCPA, have pressured developers to decarbonize a sector of society that accounts for 30% of New York’s emissions without impacting consumers. (See NYC Proposes Rules to Implement Building Emissions Law.)
Modernizing New York City’s building stock to these new net-zero requirements will be particularly difficult.
These laws “created some challenges” and forced developers “to think very carefully about anything [they] deliver,” said Michael Daschle, senior vice president of sustainability at Brookfield Properties.
Namely, should developers and building owners invest now to upgrade their buildings to comply with new net-zero energy requirements or suffer financial penalties for not decarbonizing that might be less economically painful in the near-term?
Daschle explained that developers are increasingly concerned about whether all-electric homes will “actually be marketable” because they will “require more equipment … and are significantly more expensive.”
Additionally, much of the state’s building stock is old, noted Samantha Pearce, vice president and director of sustainability at New York State Homes and Community Renewal, the state’s affordable housing agency. Electrifying them with new technologies, such as heat pumps, is not only expensive but requires a lot of space, she said.
“We now have to accommodate larger mechanical room spaces,” and in some residential buildings this has created economic “domino effects” that place new “limitations and considerations” into affordable housing decisions, Pearce said.
Similarly, Dawn Fenton, vice president at Volvo Group North America, said the transportation sector is undergoing a “paradigm shift” and needs to move “beyond the pronouncements and lofty goals. … Yet there’s not been a realization of what are the challenges behind [a net-zero future] and that it is not as easy as mandating it as so and it will be so.”
She added, “I think people are starting to recognize the challenges of charging infrastructure or the challenges of permitting reform and all the work that needs to be done to actually realize [the state’s] goals.”
Kara Podkaminer, senior adviser for sustainable transportation at the U.S. Department of Energy, said “there is a misalignment in planning timelines, where in six months you can get an electric vehicle, … but the timeline to get the charging infrastructure or upgrades can be more like a decade.”
Fenton and Podkaminer agreed that consumer education and awareness is the biggest “nut left to crack,” as many people remain skeptical about how decarbonization will impact them, either from an economic, social or environmental perspective.
They also agreed that informed consumers help guide decision-makers to where the needs are greatest.
We need to “come up with a plan together that meets all of our needs in a way that is more streamlined … and produces less uncertainty” Podkaminer said.
“This is a difficult transition for everybody,” Fenton said, but if New York does not address these unresolved issues and “make it as easy as possible for everybody to take part of this transition” then the state will struggle to reach net-zero.
Hawthorne summarized New York’s chicken and egg problem using an example drawn from the transportation sector, but which could be applied to every sector needing to be decarbonized: Do you “want electric vehicles first or their charging stations?”
New Mexico Gov. Michelle Lujan Grisham vetoed large portions of a tax package on Friday, cutting out income tax credits for electric vehicles, energy storage systems and geothermal electricity production.
The tax credits fell victim to budgetary caution on the part of the governor, who said items she vetoed within House Bill 547 would have reduced the state’s annual revenue by $1.1 billion.
“These large reductions would risk significant funding cuts in future years for critical services,” the governor said in a statement.
Friday was the deadline for Lujan Grisham to sign bills from the 2023 legislative session. Bills on which the governor took no action were “pocket vetoed.”
Among this year’s pocket vetoes was HB 365, which would have established a geothermal center of excellence at the New Mexico Institute of Mining and Technology along with grant funding for developing geothermal projects. The House passed the bill on a 63-3 vote; the Senate vote was 37-0.
Camilla Feibelman, director of the Sierra Club Rio Grande Chapter, said the tax credits for EVs, energy storage and geothermal development would have been “a drop in the bucket” of New Mexico’s budget. And the credits would have boosted emerging industries, Fiebelman said in a statement on Friday.
“We are facing a climate emergency that requires emergency action, not vetoes,” Fiebelman said.
Friday’s vetoes were just the latest disappointment for environmental groups regarding the state’s 2023 legislative session, which saw few climate-related bills make it to the governor’s desk.
Senate Bill 520, which set targets for reducing greenhouse gas emissions, failed to make it out of its first committee. (See Emissions Bill Stalls in New Mexico Senate.) A similar bill failed in the legislature’s 2022 session, but advocates had hoped it would fare better during this year’s longer, 60-day session. Sessions in even-numbered years are 30 days and are focused on budget issues.
“It felt like we had really good momentum, but it fell apart early in the session,” Ben Shelton, political and policy director with Conservation Voters New Mexico, told NetZero Insider. “There just was not the appetite to fight with the oil and gas industry and hold them accountable.”
Shelton said another disappointment was an effort to establish a “transition division” in the Economic Development Department to pursue funding for communities transitioning away from an oil and gas economy. Language establishing the division got rolled into HB 12, the Advanced Energy Technology Act, Shelton said, and the bill never made it out of committee.
Another failed bill was HB 426, a proposal for a low-carbon fuel standard. It was at least the third try for the state legislature to pass an LCFS bill, and Lujan Grisham’s administration had backed the proposal. (See LCFS Bill Emerges in NM House as Session Nears Close.)
The bill cleared two committees and was sent to the House floor, where it was never voted on.
In remarks on Friday, Lujan Grisham said New Mexico would continue to be a leader on environmental issues, the Santa Fe New Mexican reported. She said the Sierra Club should be celebrating the creation of the Land of Enchantment Legacy Fund, which was established by SB 9.
The $100 million conservation fund will support water stewardship, forest health, outdoor recreation and wildlife species protection. Lujan Grisham signed the bill last month along with SB 72, which creates a fund to carry out a wildlife corridor plan, aimed at reducing vehicle collisions with wildlife.
Another bill signed into law was SB 53, which prohibits storage of high-level radioactive waste in New Mexico without the state’s consent. The bill was reportedly intended to block Holtec International’s proposed nuclear waste storage project in southeast New Mexico.
Michael Daschle of Brookfield Properties said his company is preparing two designs for a new building: one all-electric, and one that will incorporate natural gas. The all-electric version would be 40 feet taller to accommodate additional equipment and significantly more expensive to build, but it would carry the cachet of being emissions-free, which means a lot to some prospective tenants. “You have to go back to your investors … and say, ‘Look, this is not necessarily going to achieve the same returns as a traditional gas building, but there are all those other considerations to think about.’”
Mike DeSocio of NYISO raised a warning flag on retiring fossil fuel generation before new renewable energy projects come online.
“There’s plenty of projects in the pipeline; the issue is we need some projects to be commercial, and that we have not seen yet,” he said. “So the outlook is delicate. … We are expecting the first wave of peaker retirements in 2023, and the next wave would be in 2025.
“At the same time, we’re staring at a future reserve margin of zero-ish, maybe negative, and we’re very interested to see how the forecast might come out.”
Dawn Fenton of Volvo Group North America spoke about the transition away from internal combustion engines in heavy-duty vehicles. “I think we’re in a real paradigm shift in the transportation sector. … I’m also excited about the fact that I feel we’ve hit a transition even in the last several months, that we’re getting beyond the pronouncements and the lofty goals. … We’re finally getting to the point of people recognizing the challenges of charging infrastructure; the challenges of permitting reform; all the work that needs to be done to actually realize this goal.”
Shweta Kapadia of Crayhill Capital Management highlighted the impact that financial volatility has had.
“I think one thing that … developers are doing and we as vendors are doing is, we are very cautious when we are signing a [power purchase agreement] because we did see a lot of projects that signed PPAs … are now underwater because prices have gone up.”
Maureen Leddy, director of the New York Department of Environmental Conservation’s Office of Climate Change, said the state’s climate law requires her agency to promulgate key emissions-reduction regulations by Jan. 1, 2024. Given the complexity of those rules, and the amount of stakeholder input and feedback DEC will need to seek out, the statutory deadline is “very ambitious and highly unlikely.”
Kara Podkaminer, of the U.S. Department of Energy’s Vehicle Technologies Office, spoke of the importance of not only redesigning central components of modern life but doing it so that they will be functional together.
“The transportation system and the power system are two of the largest systems we’ve ever made, and now we need to actually make them work together, because if we don’t, we actually need to build more infrastructure.”
Marguerite Wells of Invenergy said she does not expect a significant increase in onshore wind capacity in New York, beyond what is already in the pipeline. “Most of the windy hilltops already have turbines on them, and most of the remaining windy hilltops are nowhere near transmission lines. So I don’t believe there’s all that much more wind resources to build out because fundamentally, that wind is competing in every [request for proposals] with solar.”
David Whipple of Empire State Development was asked why a green energy manufacturer might build a new factory in New York rather than Georgia or some other state where the cost of doing business is lower.
He cited net-zero policies, which have become an important consideration for some corporations: “If they want to manufacture this technology with green energy, they’re going to get there a lot faster in New York than they would in many Southern states.”
Joe White, Consolidated Edison’s (NYSE:ED) distributed generation ombudsman, was asked with his fellow panelists what had been the best thing and worst thing to happen in recent history. He identified the COVID-19 pandemic as both best and worst, because it has been so disruptive and because so many people have adapted so well in response: “On both sides of the meter, we’ve had to be more creative, more innovative than we ever have before in trying to get things done from an office and field environment.”
ISO-NE and NEPOOL last week asked FERC to approve changes to the Inventoried Energy Program to reflect recent volatility in the global natural gas market and gas contracting prices in the region.
The program was designed as a stopgap for longer-term market reforms to ensure winter reliability and is designed to pay resources for maintaining inventoried energy during the next couple winters. The RTO initially filed the program in 2019, and it was approved by FERC in 2020 to go into effect for the winters of 2023/24 and 2024/25.
Russia’s invasion of Ukraine last year led European nations to seek alternate sources to Russian gas, which has increased volatility greatly. Demand from Asia has also gone up in the interim, ISO-NE’s consultant Todd Schatzki of the Analysis Group said in testimony filed at FERC.
“Since the commission’s acceptance of the IEP, global energy markets have experienced dramatic and unprecedented changes in pricing levels and volatility,” ISO-NE said.
One of the most significant changes was to replace the fixed rate for resources procured in the IEP to an indexed rate that will be able to reflect any changed prices going forward, as the recent volatility is expected to last for the next couple winters. The initial program featured both a forward and spot rate, allowing resources to sign up ahead of time or during the winter, and both of those are moving to indexed pricing.
The forward rate FERC approved was $82.49/MWh for inventoried energy, but the new price will be based on a formula using the price for liquefied natural gas at the “Dutch TTF” (Title Transfer Facility), a proxy for European prices that have recently set the price of LNG in the entire Atlantic basin.
The formula also includes a liquidation price to reflect the possibility that New England generators might procure too much LNG, which would have to be sold after the winter season when prices are typically lower.
The base rate is capped at $288/MWh, which reflects the opportunity cost from participating in the IEP and liquidation costs and is based on the price needed to secure inventoried energy given real-world constraints.
The spot price now in place is just $8.25/MWh, but the RTO asked FERC to change that one-tenth of the applicable base payment rate, which is consistent with the current market design.
The updates also include changes to natural gas contract eligibility requirements and fuel allocation for shared fuel inventory, which are meant to be better aligned with current contracting practices in New England.
IEP participants will have to submit contracts that do not restrict when the gas can be called on during a day beyond the North American Energy Standards Board’s Wholesale Gas Quadrant scheduling and nomination standards.
The currently effective rules are also too restrictive, ISO-NE and NEPOOL said, because they require a level of gas delivery firmness that is not commercially available from the interstate pipelines that serve New England, so that part was updated to reflect market realities.
If a natural gas contract specifies an indexed strike price, then that specified index must be at one of the Northeast trading locations for which Platts publishes a daily value in order to ensure the contract in question reflects regional prices.
ISO-NE and NEPOOL asked FERC to make the changes effective June 6, which will ensure the rules attract inventoried energy for next winter given the increased volatility in natural gas prices. The new indexed rate will also make it easier for market participants to hedge their program costs.
“Without the proposed changes to reflect actual market prices and contracting practices, the current commission-accepted IEP runs the risk of providing insufficient incentives for participants to procure and provide inventoried energy when needed to ensure reliability on the coldest winter days, when fuel supplies are stretched to their limits,” the filing said. “Relying on well established and reliable price indices ensures that the IEP is providing accurate price signals reflective of the actual costs of providing the service, while avoiding overcompensation at the expense of regional consumers.”
A new report from NERC, WECC, and the California Mobility Center (CMC) suggests that electric utilities and the electric vehicle industry need to start working together to address the charging behavior of EVs during grid disturbances, which could have “catastrophic consequences … if left unchecked.”
The report stemmed from a working group that NERC, WECC and the CMC formed last June to assess the impact to grid reliability of the anticipated increase in EV charging loads across the U.S. (See NERC, WECC to Examine EV Charging Risks to Grid Reliability.) Additional participants in the EV Grid Reliability Working Group included representatives from Lawrence Berkeley National Laboratory, CAISO and the Electric Power Research Institute.
“The efforts of the joint EV Grid Reliability Working Group illustrate the benefit of proactive cross-industry collaboration to achieve a common reliability objective,” WECC CEO Melanie Frye said in a media release. “Building on the work of this group, we can now improve the tools and assessments needed to understand the reliability risks and mitigation strategies for a future with much higher levels of electric vehicles and high-power charging stations in the West.”
While the working group has multiple topics of research, the new report focused on a “relatively unexplored” aspect of EVs’ intersection with the broader power grid: their performance during short-duration grid disturbances lasting from milliseconds to several seconds.
EV charging presents new challenges to grid reliability, unlike traditional end-use loads such as lighting, resistive heating and cooking. These older applications “were considered grid-friendly because their electric characteristic is constant impedance.” This means that when voltage drops slightly, the devices’ power draw also falls, supporting “stable steady-state operation of the grid.”
By contrast, EVs and other “electronically coupled loads … seek to maintain either a constant current level or a constant power level regardless of system voltage or frequency.” While the constant current approach is considered grid-friendly, because it allows power consumption to drop when system voltage declines, constant power chargers are grid-unfriendly because during times of lower voltage, their current draw increases to maintain the power level.
Another factor in grid-friendliness of EV chargers is ride-through performance and their ability to dynamically respond during mild grid disturbances. Citing data from Pacific Northwest National Laboratory, the report’s authors identified grid-friendly and unfriendly responses to disturbances.
In the grid-friendly case, the charger reduced current nearly instantaneously and kept it low for a short time; the grid-unfriendly charger did not respond to the fault until it was already cleared and then immediately resumed consuming current without giving the grid a chance to return to normal voltage levels.
The report presented its data as a starting point for a larger conversation between grid planners and manufacturers of EVs and their charging infrastructure on how best to safeguard the reliability of the grid during the ongoing electrification of transportation. Part of this work is being done by NERC and its partners in industry, which are developing a “new aggregate EV charging load model that can be used in … grid reliability studies.”
The ERO is planning further work in this area, including outreach to EV manufacturers to discuss additional areas of collaboration. The report said that building a framework for information sharing between utilities and EV manufacturers is “a key objective of NERC’s present engagement with the … working group,” which CEO Jim Robb agreed with in the release.
“As the electrification of the transportation sector continues to grow, the North American grid must be prepared,” Robb said. “Collaboration, innovation and information sharing are critical if we are to be able to meet future demands successfully. NERC is committed to working with stakeholders to unify our efforts in these areas to advance our shared reliability goals.”
Washington low-carbon fuel standard (LCFS) credit prices will likely range from $35 to $45 per metric ton by 2025, according to a company that analyzes carbon markets.
Analysts from cCarbon provided their estimates during a webinar on March 29.
A 2021 law that went into effect Jan. 1 requires Washington fuel providers to reduce the carbon emissions from gasoline and diesel sold in the state to 10% below the 2017 baseline by 2028, followed by 20% reduction below the baseline by 2035. The bill excludes from those targets any fuel that is exported out of state or used by waterborne vessels, railroad locomotives and aircraft. The goals apply to overall vehicle emissions in the state and not to individual types of fuels. Northwestern Washington has five oil refineries.
The law includes interim annual goals for individual fuel providers. Providers whose total emissions fall below their targeted goals will receive credits, while those exceeding targets will be required to buy credits from the lower-polluting providers. The law applies to providers selling fuel in volumes greater than 360,000 gallons per year.
During the webinar, cCarbon associate Bikash Maharaj noted that California LCFS credits are currently priced at $66.70/MT, as the state seeks to reduce vehicle emissions to 20% below the 2010 level by 2030, while Oregon credits are going for $117, as that state looks to cut vehicle emissions to 37% below 2015 levels by 2035. British Columbia credits are currently priced at $334, as the province seeks to reduce its vehicle emissions to 20% below 2020 levels by 2030, he noted.
In an email to NetZero Insider, Mafer Barrera, cCarbon client insights and partnerships manager, said the company’s estimate of a comparatively lower $35-$45 price range for Washington’s LCFS credits is based on speculation that the state’s biofuel supply chain faces fewer economic pitfalls than California and Oregon. The lower estimate is also based on growth projections for zero-emission vehicles in the state over the next several years.
The purchase and selling prices will be decided solely by the market with no state government influence, Maharaj said during the webinar. The emission thresholds are expected to shrink by 0.5 to 1.5% annually, he said.
Washington’s 7.6 million vehicles emitted roughly 40.3 million MT of carbon in 2017, accounting for 39 to 45% of the state’s overall carbon emissions, according to various estimates. The state wants to shrink that by 4.3 million metric tons annually by 2038.
A Montana court last week invalidated an air quality permit and ordered construction to halt on NorthWestern Energy’s (NASDAQ:NWE) planned methane gas plant, citing insufficient analysis of greenhouse gas emissions.
The 13th Judicial District Court in Yellowstone County ruled April 6 that the Montana Department of Environmental Quality’s (DEQ) 2021 issuance of a permit for NorthWestern’s 175-MW Laurel Generating Plant did not fully evaluate the facility’s environmental consequences and was not within the law (DV 21-1307).
The Montana Environmental Information Center (MEIC) and Sierra Club challenged the DEQ permit, saying the 20-page environment assessment didn’t adequately consider greenhouse gas emissions and climate repercussions. They said the permit ignored the plant’s sulfur dioxide emissions, and it did not analyze water-contamination risks of drilling under the Yellowstone River to build a pipeline to Laurel.
The court said DEQ’s exclusion of the pipeline’s environmental impact was appropriate because the State Land Board has that purview. However, it agreed that the agency violated the Montana Environmental Policy Act by issuing the permit without considering the full environmental harm caused by the plant’s construction and operation.
The court found that DEQ “reasonably examined” the plant’s impact on regional sulfur dioxide levels, but it did not conduct a substantive analysis of the plant’s greenhouse gas emissions. The agency argued that because it cannot regulate carbon emissions, it should not have to evaluate those pollutants.
District Court Judge Michael Moses said that counter to DEQ’s claims, the agency was not absolved from analyzing emissions.
“DEQ misinterprets the statute. They must take a hard look at the greenhouse gas effects of this project as it relates to impacts within the Montana borders. They did not take any sort of look at the impacts,” Moses wrote.
The court determined that DEQ must take another “hard look” at the project.
“This project is one of NorthWestern Energy’s largest projects in Montana. It is up wind of the largest city in Montana. It will dump nearly 770,000 tons of greenhouse gases per year into the air. The pristine Yellowstone River is adjacent to the project,” Moses said. “This project will have a life of more than 30 years. That amounts to in excess of 23 million tons of greenhouse gases emissions directly impacting the largest city in Montana that is less than 15 miles down wind. To most Montanans who clearly understand their fundamental constitutional right to a clean and healthful environment, this is a significant project.”
NorthWestern Energy did not respond to RTO Insider’s request for comment concerning the next steps it will take.
The MEIC and Sierra Club worked with the Thiel Road Coalition, a local group of landowners. The groups celebrated the ruling.
“My business, my family and my home will be directly impacted by NorthWestern’s proposed project. We have raised our concerns every step of the way, and state and local governments keep ignoring us,” Thiel Road Coalition’s Kasey Felder said in a press release circulated by MEIC. “We were worried we would get a ‘Braveheart’ ending to this story. It’s a relief to know the scales of justice are still in balance, and the little guy can be heard.”
“For too long it’s felt like a David versus Goliath battle. I’m so tired of the government and NorthWestern ignoring us. We live here. We have raised concerns time and time again about the impacts of this plant,” Carah Ronan, another coalition member, said. “When the government breaks the law and refuses to listen to the folks who live in the area, we have nowhere else to turn but the courts. We are thankful that the courts are willing to side with average Montanans who are just concerned about their health, property, businesses and future generations.”
With hours to go until the end of their 2023 legislative session, Maryland lawmakers on Monday passed the Promoting Offshore Wind Energy Resources (POWER) Act (S.B. 781), committing the state to developing 8.5 GW of offshore wind by 2031.
After the House of Delegates passed the bill on April 4, with amendments from its Economic Matters Committee, a conference committee was quickly formed Monday and hammered out final changes, removing some of the amendments. The bill was approved first in the Senate by a vote of 35-12 and then in the House of Delegates, 101-38. (See Maryland Lawmakers Vote to Raise Offshore Wind Target.)
In addition to more than quadrupling the state’s 2-GW pipeline of projects in development, the bill now headed to Gov. Wes Moore’s (D) desk would require the Maryland Public Service Commission to ask PJM to set up a State Agreement Approach planning process for offshore wind transmission, similar to New Jersey’s agreement with the grid operator. However, the bill calls on the PSC to reach out to other PJM states to evaluate regional transmission cooperation that could help it meet its offshore wind goals, according to the legislature’s analysis of the bill.
The PSC or PJM will have to issue one or more competitive solicitations for transmission projects by July 1, 2025. Additional solicitations could be issued after that if needed.
The bill requires PJM or the PSC to study specific transmission solutions, including one that uses an open-access collector system to allow for the interconnection of multiple offshore wind projects at a single substation.
One of the House amendments to the bill states that such studies must also “demonstrate net benefits to ratepayers in the state when compared with an alternative baseline scenario under which 8,500 MW of offshore wind capacity is connected to PJM Interconnection independent of an offshore wind transmission project.”
Such an alternative scenario might connect offshore projects to PJM via individual radial lines as opposed to networked transmission linking multiple projects to onshore substations. Industry experts increasingly favor networked, meshed HVDC systems as the most flexible and efficient for offshore transmission. (See OSW Developers Look to Europe on Meshed HVDC Tx.)
Moore is expected to sign the bill, after voicing his support for its 8.5-GW goal at the recent Business Network for Offshore Wind (BNOW) International Partnering Forum in Baltimore. The new target would produce “enough energy to power nearly 3 million homes” and provide opportunities to rebuild and expand steel manufacturing in the state, he said. (See U.S. Wind Industry Set to Take Off.)
Industry Response
Industry response was immediate and celebratory, heralding both the bill’s clean energy and economic benefits.
“The POWER Act establishes a comprehensive strategy to plan, connect and deploy offshore wind at the scale necessary to support supply chain investments and decarbonize Maryland’s economy at the lowest possible cost to Marylanders,” said Evan Vaughan, deputy director of the Mid-Atlantic Renewable Energy Coalition.
The law will allow the state to reclaim “national leadership in offshore wind [by] establishing a first-in-the-region initiative to proactively plan a 21st century transmission grid,” Vaughan said.
BNOW CEO Liz Burdock agreed that “the POWER Act repositions Maryland back into a leadership position, and with the federal government opening up new lease areas next year, offers the state a rare opportunity to attract major manufacturing and supply chain investment.
”Maryland must capitalize on this opportunity by moving quickly from legislation to execution and commercialization,” she said.
“The POWER Act is a real game changer for Maryland,” said Jeff Grybowski, CEO of Maryland-based offshore wind developer US Wind. “It sets a path for the people of Maryland to reap the benefits of huge amounts of clean energy in the coming years. It also tells the entire offshore wind industry globally that Maryland is back big time as a major player. Companies looking to invest in offshore wind have to seriously consider Maryland.”
Echoing Vaughan, Nick Bibby, Maryland state lead for Advanced Energy United, hailed the bill’s regional approach to transmission planning, saying it “will improve the transmission infrastructure planning process to improve grid efficiency and resiliency, lower utility bills for homes and businesses, and create good-paying jobs that connect Maryland to wind and solar resources.”
Maximize Opportunities
Other amendments to the bill include a call for the state to “maximize the opportunities” for obtaining federal funds for offshore wind and transmission projects by aligning its labor and domestic content standards with those in the Infrastructure Investment and Jobs Act and Inflation Reduction Act.
Provisions in the two laws either require projects to pay prevailing wages and offer registered apprenticeship programs. Tax credits provide bonus incentives for ensuring clean energy projects include made-in-the-U.S. materials and components.
Here are some other key sections of the bill:
Transmission proposals could include upgrading the existing grid, extending the transmission grid both onshore and offshore, interconnecting between offshore substations, adding energy storage, and using high voltage direct current converter technology to support potential weaknesses in the transmission grid.
The PSC will have to pick one or more transmission proposals by Dec. 1, 2027, and then work with the developers, PJM, FERC, potentially other states, and other stakeholders to ensure the lines get built. If the solicitation does not lead to any beneficial or cost-effective proposals, the PSC can end it without picking one and would then have to notify the legislature of its decision by Dec. 1, 2027.
The bill also includes language for the 2 GW of offshore wind developments that have already cleared earlier procurements, allowing developers to ask the PSC for an exemption to the requirement that they pass along to ratepayers 80% of the value of any state or federal grants, rebates, tax credits, loan guarantees or other benefits. Developers must prove that the exemption is needed to meet their contractual obligations.
