Funding for the Massachusetts electric vehicle rebate program expires at the end of June, and while it’s likely to be renewed in some form, both the Baker administration and the Massachusetts legislature are eyeing policy tweaks to factors from the size of the rebate to the price cap on vehicles.
The state’s Department of Energy Resources commissioned a report on the program, published in March, which lays out several recommendations for targeting consumers in a no-longer-nascent industry.
DOER Commissioner Patrick Woodcock told RTO Insider that the Baker administration will pursue many of those tweaks as the state government prepares for a gubernatorial transition.
“We would like to begin to target the types of vehicles that provide the most emission benefits … and put these programs in a position to have some fiscal stability with them for our successors,” Woodcock said.
Another goal his department is eyeing is to improve equity in the program and reduce the number of “free riders” taking part, who would be purchasing EVs anyway, regardless of the rebate.
The program has shifted several times in its eight years of existence, but in its current form it offers a $2,500 rebate for battery or fuel cell EVs with a purchase price below $50,000, and a $1,500 rebate for plug-in hybrid EVs.
The price cap of $50,000 is one of the main targets for Woodcock and the Baker administration, who are recommending lowering it to $47,500.
“Reducing the vehicle purchase price cap is highly likely to improve financial sustainability, cost-effectiveness and equity,” the report said. It would reduce the percentage of EV sales eligible for the credit, reduce “free ridership” and ensure that more rebates are available for lower-cost vehicles.
Limiting rebates for plug-in hybrids (only allowing them when there are no EV alternatives in the same price point) is another central plank of the administration’s plans.
“We do think we’ve gotten to a saturation level that we really should be encouraging battery EV purchases,” Woodcock said.
The administration is also looking at moving the rebates to point-of-sale, expanding the rebate to used EVs and adding separate incentives for low- and moderate-income (LMI) consumers.
In the Legislature
Changes to the program might not all be up to the administration or even the next governor.
The two chambers of the Massachusetts legislature are working on an energy bill that could include new EV provisions. (See Mass. Legislators Try to Hash out Next Climate Bill). The House version is narrowly focused on offshore wind, but the Senate has proposed changes and an influx of money for EVs.
The Senate proposal takes a different tack from what DOER is putting forward. It would create a $100 million EV Adoption Incentive Trust Fund to keep the money flowing past June.
But it would maintain the $50,000 price cap, while increasing the rebate amount to as much as $5,000 and adding point-of-sale rebates and an extra value to the rebate for LMI consumers.
The Green Energy Consumers Alliance, which has been tracking possible changes to MOR-EV, notes that the funding itself would support less than 30,000 EVs.
“Let’s get the new MOR-EV program up and running with the understanding that we will need other policies beyond consumer rebates to reach the larger goal,” the advocacy group wrote in a May 9 blog post.
Short-term Solvency?
Unaligned priorities mean that DOER may have to dig into its reserves to keep the program running this summer.
MOR-EV funding expires at the end of June, but the legislature has until the end of July to agree on a compromise for the negotiation.
Woodcock said that a funding shortage for the program in 2019 forced the department to balance its resources in a way that prepares it for gaps.
“We have full confidence that we’ll be able to continue to administer this program for a number of months even if there isn’t an extension of the budgetary language,” he said. “We certainly hope there’s clarity as soon as possible with the program, but we don’t see that there would be a significant disruption in July or August.”
Woodcock wants to ensure stability for the program heading into the gubernatorial transition.
“Stability is one cornerstone of good public policy,” he said. “From my vantage point, from the discussions in the Massachusetts legislature … it’s just a question of how long, by what duration, and what funding levels the program will be in.”
New England might not be facing the same dire system reliability warnings as other regions this summer, but periods of above average temperatures could still stretch the grid and force ISO-NE into emergency action, the grid operator said Wednesday.
The region is “expected to have sufficient resources to meet consumer demand for electricity this summer under typical weather conditions,” ISO-NE said in its summer outlook.
But peak system conditions brought on by above average hot and humid weather could lead to “tight supply margins,” the RTO said. That could lead ISO-NE to call on emergency imports or reserves, ask residents to conserve energy, or issue controlled power outages in extreme cases.
“Climate change has caused weather to become more volatile and less predictable, increasing the potential for system operators to resort to these actions,” it said.
NERC has warned that large swaths of the country in the West, Midwest and Texas are facing possible supply shortfalls this summer. MISO in particular is facing a “high risk of energy emergencies during peak summer conditions” because of a capacity shortfall and the outage of a key transmission line. (See West, Texas, Midwest at Risk of Summer Shortfalls, NERC Says.)
ISO-NE is forecasting that under typical weather conditions, demand will reach 24,686 MW. An extended heat wave could push demand to 26,416 MW, which would be higher than last summer’s peak of 25,801 on June 29. The all-time record for electricity demand is 28,130 MW in 2006.
The region has more than 31,000 MW of capacity available for the summer, including generation, demand response resources and imports.
The summer forecast incorporates more than 2,100 MW of energy-efficiency measures, ISO-NE said, as well as a reduction of more than 900 MW from solar PV installations during peak hours.
Bluebird Renewable Energy says its plan to transport renewable natural gas from existing anaerobic digesters in Western New York will reduce their on-site emissions, disputing claims to the contrary by environmentalists (21-G-0576).
In a late May exchange of arguments filed with the state Public Service Commission, a group of environmentalists continues to question the developer’s emissions analyses for a proposed facility that would take RNG produced from manure of nearly 7,000 dairy cows and truck it 70 miles to an interstate pipeline.
Bluebird Renewable Energy (BRE) is seeking approval of its project as furthering the state’s Climate Leadership and Community Protection Act (CLCPA) commitment to 100% zero-emission electricity by 2040 and a reduction of at least 85% below 1990-level greenhouse gas emissions by 2050. (See Western NY Dairy RNG Project Draws Opposition.)
A May 25 filing — by Irene Weiser, coordinator for Fossil Free Tompkins; Brian Eden of the Campaign for Renewable Energy; and Bob Wyman, a self-employed electrification advocate who is currently running for Congress — urged Administrative Law Judge James Costello to move the proceeding to a discovery period, followed by an opportunity to provide testimony. The signees said they believe that the emissions data provided by BRE reveal material issues of fact that interfere with attainment of the CLCPA greenhouse gas-reduction goals.
“In particular, we assert that BRE’s emission analysis does not account for all the emissions it should and that once a more complete emissions analysis is provided, it will demonstrate that the current system has lower emissions than the proposed RNG project,” they said.
Emissions from the proposed equipment and the electricity required to replace the on-site generation (and emissions from truck transport of the RNG to the pipeline interconnection, which are very small comparatively) are summed and represent total annual Proposed Project emissions. | BRE
Specifically, they claim that BRE’s analysis has not accounted for emissions from the end use of the RNG; the transmission and distribution of the RNG following injection into the gas pipeline system; and the increased production of biogas.
In its May 27 response, BRE accused the intervenors of fishing for information in an untimely fashion and using the regulatory process to “request an opportunity for additional discovery at the 11th hour to, presumably, delay the proposed project from being approved.”
BRE said the information from its emissions analyses has been available since March and that the intervenors “could have, and indeed should have, executed the protective order, reviewed the emissions analyses and proffered additional information requests in a timely manner.”
Information relating to the emissions associated with transporting the RNG to the injection site were included in the emissions analyses, as were anticipated fugitive emissions, BRE said.
“The proposed project will not have any impact on the end use of gas, gas demand or the interstate pipeline itself. The RNG will be a one-for-one replacement of geologic natural gas in the interstate pipeline. As there will be no impact on the interstate pipeline, calculations relating to the emissions associated with the interstate pipeline are unnecessary. Moreover, the interstate pipeline is outside of the commission’s jurisdiction,” BRE said.
BRE also said it has not specifically calculated the potential emissions associated with compressing and decompressing the RNG for use in the interstate pipeline, and that nonetheless, such operations are outside the scope of the commission’s jurisdiction.
The developer asked Costello to determine that the letter filed by the intervenors fails to establish that issues of material fact exist; determine that no additional process is needed; and refer the petition to the PSC for approval.
In a May 31 response “correcting” BRE, Wyman said that he and the other environmentalists have consistently asserted that BRE’s statements that their proposed system will reduce emissions are incorrect or, at least, subject to significant doubt.
“The existing record, although incomplete, already establishes that BRE’s claim of emissions reductions is false. No additional information is required to support the development of testimony that establishes and explains the incorrectness of BRE’s claims,” Wyman said.
The request for additional discovery is motivated not by a desire to prove that an issue of fact exists, but rather to ensure that the issue and relevant facts are as well established in the record as possible, he said.
“The desire is not to discover information needed to make testimony possible, but rather to increase the quality and correctness of at least some of the testimony which will certainly be submitted, when the time for such testimony arrives,” Wyman said.
Depending on which high-level computer model is used to map out the role of nuclear in decarbonizing the U.S. power system, by 2050 the country could have anywhere from 2 to 329 GW of nuclear power in its generation mix, according to a new report from the Electric Power Research Institute (EPRI).
Such broad variability shows the inherent weakness of such widely used models — most of which have been developed by federal agencies — and the assumptions embedded in them. But the report also finds strong commonalities across the models, such as the critical role decarbonization policy, cost and regional economies may play in nuclear deployment. For example, the models all suggest that regions with strong decarbonization policies, but low wind or solar resources, will tend to have more nuclear, the report says.
Similarly, lowering costs — from $5,000/kW to $2,000/kW — will be a key factor in increasing nuclear capacity on the grid. Lower costs, plus a zero-carbon policy, pushes 2050 capacity to the high end of the range: 285 to 329 GW.
EPRI CEO Arshad Mansoor underlined the integral and intertwined role nuclear power and computer modeling must play in the energy planning needed to reach President Biden’s goal of decarbonizing the U.S. grid by 2035, especially for federal agencies.
The models in the study include EPA’s Integrated Planning Model, the Energy Information Administration’s National Energy Modeling System and the National Renewable Energy Laboratory’s Regional Energy Deployment System, as well as EPRI’s Regional Economy, Greenhouse Gas and Energy model.
Benchmarking and coordinating across these models will be critical to advancing nuclear power in the next decade, Mansoor said at a launch event for the report on Thursday in D.C. “We have to make sure there is an operational [small modular reactor]. We have to make sure there is an operational [next-generation] non-advanced lightweight water reactor. We have to make sure that the [Defense Department’s] Alaska project for microreactors actually works,” he said.
With 100% carbon-free policies, the U.S. would maintain its existing nuclear plants, with cost again driving rapid growth, across all models. | EPRI
Without solid progress, Mansoor said, the current surge of interest in nuclear “will fizz out.”
Echoing Mansoor’s urgency, Alice Caponiti, deputy assistant secretary for reactor fleet and advanced reactor deployment at the Department of Energy, said, “It is essential that we have the ability to accurately model and communicate the benefits of nuclear energy, and therefore it’s critically important that we understand how these models account for nuclear energy production and where they have limitations and gaps.
“We need to ensure that planning tools are not biased by poor or outdated assumptions or by limitations in the tools, such as the ability of nuclear to operate flexibly or to assume that a plant is shut down at the end of its license,” Caponiti said.
The data that go into these models are therefore critical, said Brent Dixon, national technical director for nuclear systems analysis and integration at the Idaho National Laboratory. For example, with no new advanced reactors yet built, current models cannot accurately project how costs may go down over time, Dixon said.
Assumptions based on algorithms may produce different and less accurate results than actual data from the field, he said. “We need to look closer to find out why there is a difference between the data and what these algorithms predict.”
Angelina LaRose, assistant administrator for energy analysis at the EIA, agreed, noting that computer models are frequently wrong, but “the goal is to make them wrong in a useful way … so policymakers can identify attractive points of leverage, potential pitfalls and unintended impacts, both beneficial and detrimental, and approaches to achieve whatever policy goal they have in mind.”
Clean, Firm Electrons
Nuclear power now accounts for 20% of all electricity — and 50% of all carbon-free power — generated in the U.S. The need to keep the current fleet online into the next decades, beyond the existing licenses of individual plants, is one point of agreement across models in the study.
The public is still divided on nuclear, with a recent poll from the Pew Research Center showing 35% of those surveyed in favor of federal support for nuclear versus 26% against and 37% neutral. But as increasing amounts of solar and wind have come onto the grid, nuclear has become a focus in the industry as a source of clean, firm, dispatchable power, Dixon said.
“All electrons are no longer the same,” he said. “Some are worth a lot more, and those are the electrons that are clean, firm electrons, and that’s your area for nuclear to compete in as we go forward.”
The study tests the different models across a set of policy, economic and technical variables — what analysts call “sensitivities” — beginning with a “native” scenario based on existing policies and regulations, plus scenarios aimed at reducing greenhouse gas emissions by either 80 or 100% by 2050. The models were also run with “harmonized” cost and technology assumptions, a low-cost scenario, and one assuming regulations providing a nuclear “carveout” that would increase nuclear on the grid over time.
The variability of results can be dramatic. With federal policy pushing an 80% carbon reduction by 2050, EPA’s model provides mostly conservative estimates of nuclear growth ― below 100 GW ― except with a nuclear carveout. The EIA and NREL models, on the other hand, show a low-cost scenario with 250 GW of nuclear, but only 150 GW with a nuclear carveout.
The results of these different scenarios come with a big caveat: The technology and policy assumptions used in the study “do not reflect policy or market expectations of the modelers or their respective organizations” and are not intended as a “policy development exercise.” The modeling for the study was also completed before passage of the Infrastructure Investment and Jobs Act, so the law’s incentives for nuclear and other clean energy technologies were not factored into the scenarios.
But the report repeatedly shows that differences in results also provide major insights. For example, models using different “temporal resolutions” — that is, how many time units are factored into a scenario — demonstrate that simplified resolutions based on seasonal averages or the levelized cost of energy “tend to understate the value of broader technological portfolios … and can overstate the value of solar generation,” the report says. “The need for dispatchable, firm capacity is clearer with higher temporal resolution across all policy scenarios.”
In a recorded video message, Kathryn Huff, DOE assistant secretary of nuclear energy, pointed to the study’s work on temporal resolution as one of its significant advances. “Unless you accurately capture the two-minute or two-hour sorts of time scales on which our energy system has to balance, you may not get a realistic understanding of what our grid needs to look like,” she said.
Going forward, Mansoor said that models also must be able to incorporate the different values of nuclear, as a provider of inertia or for energy security in volatile markets. “We need an integrated model that values not just nuclear as an electricity provider but also as a tool to help industries to decarbonize,” he said.
Nevada regulators on Tuesday approved a permit for NV Energy to build a 220-MW battery storage system at the former site of the Reid Gardner coal-fired generating station in Clark County.
The two-hour, lithium-ion battery storage system will cost an estimated $217 million and is expected to be operating by May 2023. The Public Utilities Commission of Nevada (PUCN) approved the construction permit on a 3-0 vote.
The project includes a new 230-kV substation, a 230-kV transmission line and interconnection facilities at the existing Reid Gardner substation. The site was formerly home to the Reid Gardner generating station, which closed in 2017 and was NV Energy’s last coal plant in southern Nevada.
NV Energy said the battery storage project would help it more efficiently manage the growing number of solar resources coming online as part of the utility’s decarbonization efforts.
The project is still subject to approval by other state and local authorities.
Part of IRP Amendment
The Reid Gardner battery storage project is one piece of a proposed amendment to NV Energy’s 2021 integrated resource plan (IRP). Tuesday’s approval assumes the commission will also approve the IRP amendment. A hearing on the amendment is scheduled for July 20.
The proposed IRP amendment also includes a power purchase agreement for 25 MW of renewable energy from the North Valley geothermal facility.
The amendment proposes upgrades to three peaker projects that would increase peaking capacity by a combined 48 MW and cost $24 million. The upgrades would be in service by May 2024.
In addition, NV Energy wants to spend $3.5 million to continue exploring a 1,000-MW pumped hydro storage project in White Pine County in eastern Nevada. The expenditure would give the utility exclusive rights to acquire the project. The project, which is being developed by rPlus Hydro, would interconnect at the Robinson Summit substation.
In its application filed with the PUCN, NV Energy said the IRP amendment would help address concerns about regional market capacity.
As a result of climate change, NV Energy said it must “re-evaluate established practices, in particular large reliance on market purchases, to ensure sufficient capacity to meet peak demands during the summer.”
NV Energy pointed to an energy emergency alert event on July 9, 2021, when a Southern Oregon wildfire cut off about 5,500 MW of transmission capacity on two primary lines from the Pacific Northwest to the Southwest. At the same time, demand was surging as Nevada and other states experienced near record-breaking temperatures. NV Energy set a new combined system peak load record that day.
“Climate related incidents such as this no longer appear to be isolated events,” the utility said.
Sierra Club Support
The Sierra Club filed comments with PUCN in strong support of the proposed Reid Gardner battery storage system.
“The project will provide peak capacity during times of high demand, reduce reliance on market capacity, and support the integration of solar energy resources into the grid,” wrote Elspeth DiMarzio, senior campaign representative for the Sierra Club’s Beyond Coal campaign.
Battery storage projects are a more cost-effective way to increase capacity than the utility’s proposed gas plant upgrades, DiMarzio said.
And by building at the Reid Gardner site rather than on undeveloped land, NV Energy will minimize environmental impacts of the project, DiMarzio wrote.
The World Economic Forum welcomed 2,500 state and government officials and private sector business leaders to its annual meeting last week. Securing the energy transition and supporting the growing green economy were top themes at the meeting.
Here’s a look at three takeaways from the climate-related discussions that took place during the meeting in Davos, Switzerland, from May 23 to 27.
‘First Movers’ Expands
During the meeting, U.S. Special Presidential Envoy on Climate John Kerry announced the expansion of the First Movers Coalition (FMC), an initiative launched during last year’s U.N. Climate Change Conference that comprises companies committed to making certain purchases from near-zero or zero-carbon suppliers.
FMC “leaps from the 35 initial companies … to 55 companies, with additions of major corporations,” including FedEx (NYSE:FDX), Ford Motor Co. (NYSE:F) and Microsoft (NYSE:MFST), Kerry said during a May 25 press conference.
In addition, the coalition is expanding the sectors it will address, adding carbon dioxide removal and aluminum to the original four sectors of shipping, aviation, steel and trucking. Microsoft, Alphabet (NASDAQ:GOOGL) and Salesforce (NYSE:CRM) plan to invest a combined $500 million in advanced CO2 removal technologies by 2030.
“We’re talking about durable and scalable removal processes that could have a span of storage for 1,000 years or more,” Kerry said.
Breakthrough Energy, one of the FMC’s implementing partners, will support the coalition members’ carbon removal purchases.
FMC’s core purpose is to engage the private sector on the demand side of the economy and reduce the often high “premium price” of clean technologies, Breakthrough founder Bill Gates said during the press conference. “The opportunity now to bootstrap green steel … green cement … or green aviation is stronger than ever,” he said.
Breakthrough’s new technology accelerator program, Breakthrough Energy Catalyst, will make its first few grants this year, according to Gates. Even though new climate technologies are often government-driven, Gates said, he believes that the private sector should “have a seat at the table” so that projects see viable cost reductions.
Ford and Volvo Cars were part of a group of companies founding the new aluminum segment, promising to have near-zero carbon emissions from 10% of their primary aluminum purchases by 2030.
FMC also welcomed Sweden, India, Japan, Norway, Italy, the U.K., Singapore and Denmark as new government partners.
Governments can support FMC’s goals by “implementing policies that augment each of the [hard-to-abate] sectors,” Kerry said. “Tax policy, public policy incentives, various budgets or concessionary funding will excite the private sector to be able to embrace these goals.”
Faster to Net Zero
FMC members’ efforts to accelerate clean technology are critical to meeting the concurrent challenges now stemming from climate change and the pressure on global energy markets from Russia’s invasion of Ukraine, Kerry said during a May 24 panel on “speeding up on the road to net zero.”
“No one should believe that the crisis of Ukraine is an excuse to suddenly build out the old kind of infrastructure that we had,” Kerry said, adding that governments need to be “smarter” and “more creative” in finding a solution to energy security.
Europe’s recent move to reduce its dependence on imported Russian fossil fuels represents a “permanent change” that addresses fossil fuel sources and promotes smart climate solutions for the energy transition, according to Frans Timmermans, executive vice president for the European Green Deal at the European Commission.
The EU’s approach includes:
reducing energy consumption;
accelerating renewable energy deployment;
creating renewable energy zones;
doubling biomethane production; and
securing LNG contracts with diverse global providers interested in building a hydrogen economy.
The entire transition plan is currently estimated at 300 billion euros, Timmermans said.
“That sounds like a lot of money, but it isn’t if you compare it to the 100 billion euros we’re spending every year on Russian oil and gas,” he said. “If you could spend that money on something that’s future-proof, that’s a lot better.”
French multinational utility ENGIE, which provides electricity to 27 European countries and operates in the renewables, natural gas and petroleum markets, is advancing its net-zero transition through diversification, according to CEO Catherine MacGregor.
Wind and solar resources are important, but gas will need to “play a strong role” in the energy transition to ensure affordability, MacGregor said. The company, she added, is also accelerating renewable energy deployment, with half of the company’s capital expenditures going to the segment.
The current climate and energy security challenges make partnerships a critical part of achieving the company’s goals.
“We cannot do anything in isolation,” MacGregor said, pointing to FMC’s ability to address the chicken-and-egg problem.
FMC is aggregating green technology demand “so that we can give strong signals to get the new economy kickstarted,” she said.
Financing Net Zero
A lack of climate-related disclosure standards for companies, coupled with the growing interest in green investing, are creating challenges in financial markets that the London Stock Exchange Group (LSEG) is working to resolve, according to CEO David Schwimmer.
The people and entities with capital to allocate are making “enormous demands” to support the energy transition, but they “don’t understand the impact of those demands on issuers” or the “confusion … and challenges” they create, Schwimmer said during a panel on “financing net zero.”
The Glasgow Financial Alliance for Net Zero (GFANZ), of which Schwimmer is a principal, is trying to bridge the disconnect between those entities with capital to invest and those looking for capital. To that end, a working group of GFANZ will release a report in September that focuses on transition pathways for the real economy, with a focus on the high emitting sectors of aviation, steel, oil and gas, he said.
LSEG is working on another problem that is directly affecting the ability of investors to identify clean investment opportunities. Major players in the global markets, Schwimmer said, do not have the necessary guidance on climate disclosures as they relate to finance.
“We’ve made progress in this area, but 40% plus of global large and mid-cap companies do not disclose their emissions,” he said. And because there’s no standardized framework for emissions disclosures, data from companies that do report their emissions are “often wildly inaccurate.”
LSEG has called on governments globally to require publicly traded companies to disclose their emissions and break down their revenues by clean and non-clean sources. Doing so, Schwimmer said, will help green investors allocate their capital effectively.
DALLAS — Grid-enhancing technologies (GETs) took center stage last week at a WATT Coalition summit on ways to wring efficiencies out of existing transmission facilities. Held in conjunction with the May 23-25 Distributech/PowerGen International Tradeshow, the summit laid out actions utilities can take to optimize the existing grid and transition to a decarbonized economy.
“Grid-enhancing technologies could save U.S. energy customers billions of dollars every year,” WATT (Working for Advanced Transmission Technologies) Coalition Executive Director Rob Gramlich said, setting the tone. “Grids in Europe, Australia and South America are tapping into these benefits, but the U.S. is lagging. U.S. electricity customers pay the price for inaction on grid-enhancing technologies, and it’s time to fix that.”
The summit focused on three primary technologies:
Dynamic line ratings (DLRs) that adjust ratings based on actual weather conditions, including ambient temperature and wind, in conjunction with real-time monitoring of line loading;
Advanced power flow controls that inject voltage to increase or decrease resistance, pushing power off overloaded facilities or pulling it on to under-used facilities; and
Topology optimization, which automatically re-routes flow around congestion while respecting reliability criteria.
FERC Commissioner Allison Clements compared GETs to the early days of VHS tapes and web search engines.
“I think we’re all here because we’re hopeful that this is the future we see,” she said. “Everyone makes an iPhone joke, but that transition happened through a heavily regulated industry. How do we make the changes that provide for those competitive forces to take hold [on the grid]?”
Clements said GETs have been top of the mind at the commission for some time. She pointed to FERC’s December ruling that requires all transmission providers to use ambient-adjusted ratings to evaluate near-term transmission service (RM20-16). (See FERC Orders End to Static Tx Line Ratings.)
In February, the commission also opened an inquiry on whether dynamic line ratings should be incorporated in ratings as well (AD22-5). (See FERC Opens Inquiry on Dynamic Line Ratings.)
Then there’s FERC’s April Notice of Proposed Rulemaking on regional transmission planning requiring consideration of DLRs using advanced power flow control (RM21-17). (See FERC Issues 1st Proposal out of Transmission Proceeding.)
“So, there’s a lot of opportunities,” Clements said. “But it’s very far from … that more seamless platform upon which all these services could be of interest.”
Incentives for GETs
Stacey Crowley, CAISO’s vice president of external affairs, said the evolution of the grid has accelerated with the increasing integration of renewables.
“The operators are learning how to work in a different world,” Crowley said. “We continue to look at all types of technology when we go through our transmission planning process. We’ve had a couple of occasions [in which] we have approved projects that were pretty simple technology, smart wires, data storage as a transmission asset and a couple other things.
“We need to see more of that. [We need] transmission owners … to see the value and find a way for that to work in our business model,” she said.
“In my career, I never saw an infrastructure project I wanted to say no to,” said former FERC and Texas Public Utility Commission chair Pat Wood, now CEO at Hunt Energy Network. “The nice thing about where we are now with the transition to a cleaner and more decarbonized grid is that you need plenty of … plain ol’ transmission service. We need that in spades.”
Wood noted that two of his successors on the PUC, Commissioners Will McAdams and Jimmy Glotfelty, have taken a keen interest in DLRs and ambient line ratings. “I’m happy to see that with this issue, which we knew about when I was at FERC, but we didn’t quite know what to do with it.”
Gramlich, who served with Alison Silverstein as aides to Wood at FERC, said the three often talked about carrots and sticks when discussing how to encourage changes.
“We need carrots and sticks and orange sticks,” Gramlich said. “It’s really important to make sure that there’s incentives as well as the planning requirements” because requirements can be overly prescriptive. “Who’s to say where’s the exact transmission facility to deploy — what technology or what time and in what degree?”
He called for action “very soon” on interconnections. “That’s another area where GETs can come in.”
Addressing Congestion
Participating on a panel of renewable developers discussing the cost of curtailments, Enel Green Power’s Betsy Beck recalled a GETs presentation she saw almost 10 years ago. “I just remember thinking how perfectly built this technology was to deal with [curtailment and congestion] issues that we were starting to face then. [The issues have] really grown and exacerbated since then,” she said.
“Seeing deployment and case studies out there … is really exciting. … These technologies could not come at a better time.”
“Transmission bottlenecks can kill your project,” Invenergy’s Venkata Ajay Pappu said. “You have wind and solar being curtailed because of the constraints that you’re seeing on the system on multiple 345-kV paths. We’re talking about not just developers not being able to build and deliver the power but also future savings back to the ratepayers.”
“We’re now actively thinking about creative ways to meet, to make sure that we meet our renewable energy goals. It’s our view that all options need to be on the table,” Amazon Web Services’ Craig Sundstrom said. “We are driving as much renewable energy deployment on the grid as we can to offset our load, but we also have a significant load and we are major customers. [To have] a proactive and productive discussion [with utilities] around grid modernization is something that we would welcome.”
RTOs, Utilities Weigh In
Grid operator and utility representatives agreed GETs will play a key role in integrating renewable resources. The RTOs and ISOs may be generation agnostic, as SPPs Casey Cathey said, but they also follow the markets. “Obviously, the market is moving towards renewables,” he said.
Cathey asked the audience to imagine themselves as a CEO out to improve existing assets, saying, “If you can extend the value of the transmission system that you already have, then you made a good call as a CEO.”
With 14,000 wind turbines totaling 31 GW across its 14-state footprint, SPP has a lot of existing assets. A 2009 study forecast wind accounting for 40% of the RTO’s fuel mix. Today, wind penetration regularly eclipses 70% and has hit as much as 90%.
“We export to MISO, but by and large, a lot of our renewables sink within us,” Cathey said. “When you see 100 [GW in the interconnection queue], that’s actually pushing the bounds a bit. There’s a massive amount of benefit” with GETS.
National Grid’s Babak Enayati said the grid operators need to move quickly to take full advantage of GETs.
“We’re going to have to adapt and adapt quickly to get everything that we want done in the next three or five years,” he said.
Enayati said two roadblocks must first be resolved: the slow pace of adopting solutions and the planning process.
“The [RTOs’ and ISOs’] process of adopting DLR solutions has been going slow because they have their own concerns with … upgrades and how all that data will be adopted and accepted by their operations,” he said. “The other thing is the planning practice so we can quickly move towards combined solutions and merge solutions, like DLR plus power flow control. … Then we’re going to see a significant shift.”
Supporters of a bill to ban fossil fuel use in new buildings in New York are pushing to get the legislation passed before the State Legislature adjourns its session on Thursday.
“Beneficial building electrification is at the heart of New York’s climate plans and the only way we will meet our climate goals,” said Raya Salter, executive director of the Energy Justice Law and Policy Center and New York Climate Action Council (CAC) member. “The All-Electric Buildings Act represents the kind of step forward we must take to turn the corner on combustion in buildings.”
Salter joined other supporters for a press conference Friday to urge passage of the bill (S6843), which has received support in the Senate but stalled in the Assembly, according to Anne Rabe, environmental policy director at the New York Public Interest Research Group (NYPIRG).
“We have 50 co-sponsors, and we’re getting more every day,” Rabe said. “We are going to pass this bill into law this session.”
In December, the CAC identified a need to reduce buildings emissions in its state draft scoping plan to meet the targets of the Climate Leadership and Community Protection Act (CLCPA).
“One key component of our plan was a call to prohibit gas and other fossil fuels in new construction of single-family homes and low-income residential buildings by 2024,” said Robert Howarth, professor of ecology and environmental biology at Cornell University and CAC member.
The bill would require the state Fire Prevention and Building Code Council to prohibit systems that use fossil fuels in newly constructed buildings under six stories by the end of next year and by July 1, 2027, for all other buildings. Certain systems, such as emergency backup for hospitals and commercial food establishments, would be exempt.
To ensure affordable implementation of the law, state agencies would report to the governor and legislature on necessary changes related to rate design and policy in February 2023.
The legislation is similar to a New York City statute banning fossil fuel combustion technologies in new construction that former Mayor Bill de Blasio signed in December.
An Assembly joint committee hearing on all-electric buildings, held May 12, drew comments from opponents of the policy, including natural gas service providers in the state and workers’ unions.
Speaking on behalf of the New York State Association of Electrical Workers, attorney and former Assemblymember Addie Jenne said a pathway to electrifying the state already exists in the CLCPA, and additional policies that circumvent that plan could be detrimental.
Randy Rucinski, deputy general counsel and chief regulatory counsel for National Fuel, concurred with Jenne’s comments. Passing an all-electric buildings law would shortcut the “careful evaluation of complexities related to the energy transition” and could have “serious repercussions” on reliability, resilience and affordability, he said.
“No single form of energy will be sufficient to achieve the goals of the climate act in a safe and responsible way,” he said.
On May 25, 110 local elected officials in New York sent a letter to Gov. Kathy Hochul, Senate Majority Leader Andrea Stewart-Cousins and Assembly Speaker Carl Heastie asking for their support in passing the bill.
Stakeholders at last week’s PJM Markets and Reliability Committee meeting unanimously endorsed a revised proposal from the RTO and the Independent Market Monitor addressing start-up cost offer development worked on through the Cost Development Subcommittee (CDS).
The CDS initially brought two proposals for first reads to the October MIC meeting, but a vote on the proposals was postponed, allowing for more discussions and stakeholders to reach consensus on a single proposal. (See “Start-up Cost Offer Development,” PJM MIC Briefs: Oct. 6, 2021.)
Manual 15 allows the start-up costs for combined cycle units to include fuel costs after generator breaker closure and synchronization to the grid, a feature not available to other unit types, such as steam and nuclear plants. The revisions align start-up costs for all units with a soak process, or units that use steam turbines.
For units with a soak process, including steam, combined cycle and nuclear units, some of the soak costs will be included in the start-up costs from PJM’s notification to the “dispatchable output” and from the last breaker open to the shutdown process.
PJM’s revised steam unit start-up cost offer procedure | PJM
Units that don’t have a soak process, like combustion turbines and reciprocating engines, maintain the status quo, with start-up costs that include costs from the time of PJM’s notification to the first breaker close and from the last breaker open to the conclusion of the shutdown process.
The approved revisions include several other changes to Manual 15 to provide additional guidance and clarification, Hauske said, such as equations to calculate start-up costs, station service calculations for units with and without a soak process, and unit-specific parameter limits on includable costs.
Manual 15 allows generators to include an additional labor cost in their start-up costs, Hauske said, but generators already are permitted to include the labor cost in the unit’s capacity offer through its avoidable-cost rate (ACR). The revisions eliminate the labor cost language in the tariff and OA offer cap sections and the start-up cost calculation so that all the operating labor is includable in the ACR.
PJM is providing a six-month window for implementation to allow market sellers the opportunity to have their fuel costs or net generation used for the offset to be reviewed by the Monitor prior to the revisions going into effect.
Hauske described the new start-up cost definition included in Manual 15, which states it will “consist primarily of the cost of fuel, as determined by the unit’s start heat input (adjusted by the performance factor) times the fuel cost. It also includes operating costs, maintenance adders, emissions allowances/adders and station service power cost. Start costs can vary with the unit offline time being categorized in three unit temperature conditions: hot, intermediate and cold.”
Adrien Ford of Old Dominion Electric Cooperative offered a friendly amendment that was adopted by stakeholders to the end of the definition, which says, “Units with a soak process include nuclear, steam and combined cycle units. Units without a soak process include engines, combustion turbines, intermittent and energy storage resources.”
Ford said the suggestion came from ODEC staff to “provide clarity” for the units impacted by the changes.
“We were just looking for it to be better defined upfront when you’re first reading this, so that the puzzle has some of the overview pieces up front, and then you can get into the detail pieces later,” Ford said.
DEA Proposal Denied
Members rejected a PJM proposal to address changes to the Designated Entity Agreement, sending the issue back for more stakeholder discussions.
The proposal, which PJM was seeking a quick-fix approach to make changes, received a sector-weighted vote of 2.51 (50.2%), falling short of the necessary 3.33 threshold for adoption.
FERC in February rejected a filing by PJM in its Order 1000 compliance docket that would have updated the definition of “designated entity,” agreeing with a coalition of stakeholders that it infringed on their due process rights. (See FERC Rejects PJM Redefinition of ‘Designated Entity’ Under Order 1000.)
Ken Seiler, vice president of PJM’s planning department, said the proposal was meant to accommodate the “lack of clarity” in the OA regarding the DEA. Seiler said the existing OA language is “a little too broad,” and PJM wanted to clear up the definition.
Seiler said PJM wants to look at all construction-related activities in the RTO to make sure the process is being done efficiently.
“We’d like to take a holistic look at everything and consider how this is impacting any risk to any stakeholders, consumers or ratepayers; how it’s impacting our ability to get work done; how it’s impacting our coordination with all the other projects coming through the [transmission planning] process,” Seiler said.
Caven said the OA language can be interpreted differently because of the “imprecise” use of the term “designated entity,” so PJM’s proposal called for several revisions to “eliminate the ambiguities” and “align the OA language with the intent and use of the DEA.”
“Given the urgency associated with compliance considerations and the narrow scope of the issue charge, PJM believes this issue is well suited for the quick-fix process,” Caven said.
Several stakeholders questioned the use of the quick-fix process on the issue, saying the complexity of DEAs warranted more in-depth discussions.
Two different alternatives to PJM’s proposal were also presented for stakeholder consideration. Greg Poulos, executive director of the Consumer Advocates of the PJM States, offered an issue charge on behalf of the Delaware Division of the Public Advocate to allow for more education on the DEA process and the formation of a senior task force to work on any possible OA changes if needed.
Denise Foster Cronin of the East Kentucky Power Cooperative presented an alternative issue charge from EKPC, Exelon and Public Service Enterprise Group that called for endorsing PJM’s OA changes and also starting a stakeholder process to discuss other possible changes to the DEA.
In a sector-weighted vote of 3.95 (79%), members voted to table the two additional proposals until the June MRC meeting.
Dynamic Line Ratings Proposal Endorsed
Members unanimously endorsed PJM’s proposal and manual revisions supporting the interim integration of dynamic line ratings (DLRs) into its operations.
PPL is tentatively scheduled to go live in June with a DLR system on some of its transmission lines, Callaghan said, and PJM wanted to “enable the operational implementation of dynamic ratings” through temporary manual revisions, which will be in place pending submission of the RTO’s FERC Order 881 compliance filing.
In December, FERC ordered transmission providers to end the use of static line ratings in evaluating near-term transmission service and required transmission providers to employ ambient-adjusted ratings for short-term transmission requests of 10 days or less for all lines that are impacted by air temperature. (See FERC Orders End to Static Tx Line Ratings.)
The manual revisions are meant to have new guidance and requirements related to the operational and technical implementation of DLR systems, Callaghan said. Some of the manual revisions include adding timeline requirements to notify PJM about any new DLR systems to be installed on the grid and to provide details on requirements for real-time and forecasted DLR submissions.
Rate and Waiver Filings
Steve Pincus, associate general counsel of PJM, reviewed a proposed problem statement and issue charge addressing service to members’ tariff rate and waiver filings under the RTO’s governing documents.
In 2018, Pincus said, PJM proposed a new OA requirement as part of a larger group of changes from the Governing Document Enhancement and Clarification Subcommittee (GDECS) that called for ensuring the RTO is “properly served with members’ and interconnection customers’ rate and waiver filings” impacting PJM and stakeholders’ rights and obligations.
Pincus said a motion was made at the September 2018 MRC meeting to defer the consideration of the revisions after some stakeholders objected to the scope of the changes coming from the GDECS. PJM approached stakeholders earlier this year about reviving discussions on the issue.
The proposed problem statement says that PJM has experienced incidents when relevant FERC filings are made by members but are not served to the RTO, including tariff and service agreement filings.
“Service of such filings on PJM is important to ensure PJM is able to intervene and participate in such proceedings to protect the interests of PJM members and markets,” the problem statement said.
Key work activities in the issue charge include education on PJM’s need to be served with rate, waiver and other filings and the development of a solution to include any changes to governing documents or manuals.
Pincus said work on the issue charge is planned for special sessions of the MRC and is expected to take six months.
Consent Agenda
Stakeholders unanimously endorsed several manual changes as part of the MRC consent agenda. They included:
revisions to Manual 3: Transmission Operations resulting from a periodic review. The changes include updating stability limitation process language in accordance with docket ER21-1802 and aligning language with the current TO/TOP matrix language.
revisions to Manual 21A: Determination of Accredited UCAP Using Effective Load Carrying Capability Analysis addressing an effective load-carrying capability model run timing update. PJM rules allow voluntary submission of unit-specific wind and solar parameters for development of backcasts for newer resources, but manual language has an expiration date of March 1 for voluntary submissions. The quick fix removes the March 1 expiration date.
revisions to Manual 36: System Restoration resulting from a periodic review. The minor changes include replacing the System Restoration Coordinators Subcommittee with System Operations Subcommittee and updating the under-frequency load shed table with new data.
CAISO convened two days of stakeholder meetings last week to discuss its straw proposal for adding an extended day-ahead market (EDAM) to the real-time Western Energy Imbalance Market — an effort that could bring more of the West under the ISO’s umbrella without forming a Western RTO.
The ISO fast-tracked the EDAM initiative last fall following a monthslong hiatus. Three stakeholder working groups met from January through mid-March to offer input on important design elements, and CAISO incorporated the groups’ results into the EDAM straw proposal. (See CAISO Issues EDAM Straw Proposal for the West.)
Mark Rothleder, CAISO | CAISO
“In the first three months of this year, we convened working groups at an expeditious — some would say ‘crazy’ — pace,” CAISO COO Mark Rothleder said, opening the two-day meeting Wednesday. “Nonetheless, we listened and processed the information that we heard to develop the straw proposal on schedule on April 28.”
“Today, we are here to discuss the straw proposal,” Rothleder said. “We are also here to listen and receive initial feedback from you all on the straw proposal. We know the straw proposal is not the final proposal.
“I’m expecting you will come out of here maybe a little bit disappointed that there’s not more detail, maybe wanting more,” he said. “I think that’s OK. This is a longer process. We will be going through several iterations, and we can’t go through all the details today. So, I just wanted to make sure that our expectations are set.”
Panel discussions May 24 involved the EDAM’s proposed resource sufficiency rules and transmission commitments, two of the more contentious issues in the process.
Resource Sufficiency
The EDAM straw proposal would require participants to pass a day-ahead resource sufficiency evaluation (RSE) to show they have enough supply to meet internal demand and reserve requirements to avoid “leaning” on the market for additional supply. Failure to pass the RSE could lead to transfer limits or an opportunity for the entity to cure the deficiency through residual supply for a fee.
Jim Baggs, regulation and market development officer for Seattle City Light, moderated a panel on resource sufficiency. He asked panelists why resource sufficiency is so important in EDAM design.
Mike Wilding, PacifiCorp | CAISO
Mike Wilding, vice president of energy supply management at PacifiCorp, answered that “at the risk of being Captain Obvious up here, if we’re all going to go in this together — if we’re going to go into the EDAM footprint together — we have to have confidence that each of us has the ability to serve our load, and that if any single [balancing authority] gets in trouble, that that does not cascade to the rest of us.”
Jeff Spires, director of power at Powerex, said reliability remains the top priority in the West, and that much of that effort is now focused on the work of the Western Power Pool to develop its Western Resource Adequacy Program (WRAP). (See NWPP Rebrands as Western Power Pool.)
“One of the areas of concern that we have when we’re looking at EDAM and market design is whether the design can be compatible with the WRAP program,” Spires said.
Jeff Spires, Powerex | CAISO
Many EDAM participants are likely to be WRAP participants too, but it is unknown if WRAP’s resource adequacy construct and CAISO’s RSE requirements will be compatible, he said.
“That’s inherently a difficult place to start from for a market design because we are, in effect, combining two different RA programs,” Spires said, adding, “Our concern is, will the rules be designed in a way that complements WRAP or not?”
Scott Ranzal, director of portfolio management with Pacific Gas and Electric, agreed that bridging gaps between the WRAP and EDAM processes is important but said the EDAM’s proposed “resource sufficiency test is a critical step in order to actually achieve a successful operating paradigm and provide reliable service. I’ve heard no argument in this room about anybody in here saying they don’t want reliable service. The question becomes, how do we get to that, and how do we define it?”
Reliability is “not an easy task,” Ranzal said. “No argument there. But there’s plenty of really smart people here working on this problem. I do think that while it has challenges, it is a solvable problem.”
Transmission Commitment
Making sure transmission is available for EDAM transfers is one of the more difficult issues facing the program’s designers. The straw proposal offers alternative proposed approaches, which still must be weighed by stakeholders and agreed upon.
“Before the day-ahead market run, each EDAM entity will identify the transmission that may be available to the day-ahead market to support transfers between EDAM entities across the EDAM footprint,” the straw proposal says.
But how to go about it?
The CAISO working group on transmission grouped transmission into three “buckets” to “define how entities can make transmission capacity available for transfers.” Its work was incorporated into the straw proposal:
Bucket 1 is transmission required to support resource sufficiency. It consists of “transmission rights held by transmission customers of the EDAM entity or another transmission service provider within the EDAM [balancing authority area] that have contractual agreements for energy or capacity transfers for RSE accounting purposes in the day-ahead timeframe,” the straw proposal says. “These transmission rights holders must make Bucket 1 transmission available to the market because it is needed to support resource sufficiency plans across an intertie with an adjoining EDAM BAA.”
Bucket 2 consists of “transmission rights held by transmission customers of the EDAM entity or another transmission service provider within the EDAM BAA that are not associated with contractual obligations used to demonstrate resource sufficiency,” it says. “This transmission has already been sold similarly to bucket 1 transmission, but the transmission rights holder can voluntarily make it available to the EDAM in return for transfer revenue. To ensure reliable transfers, Bucket 2 transmission must be firm or conditional firm.”
Bucket 3 transmission consists of “unsold firm available transfer capability (ATC) offered by the EDAM entity, in its transmission service provider function, to support transfers at interfaces between EDAM BAAs,” the straw proposal says. “The EDAM entity would be expected to make available all remaining unsold firm ATC at an intertie with an adjoining EDAM BAA by 10 a.m. in the day-ahead market and to stop [open-access transmission tariff] sales of firm ATC at that intertie between 10 a.m. and 1 p.m. while the day-ahead market is running.”
The working group focused on two approaches to make Bucket 3 transmission available to the market.
Under Approach 1, “EDAM entities would make Bucket 3 transmission available to the market for optimization at a hurdle rate (i.e., the published tariff rate),” the straw proposal says. “The hurdle rate allows the transmission provider to recover its costs of unsold transmission supporting EDAM transfers. However, including a hurdle rate in the optimization may cause pancaking of transmission hurdle rates, limiting efficient transfer and resource scheduling in the day-ahead market.”
Scott Ranzal, PG&E | CAISO
Under Approach 2, “entities would make Bucket 3 transmission available to the market hurdle-free through a reciprocity framework, similar to the [Western Energy Imbalance Market] today, to derive mutual benefits of higher volumes of EDAM transfers. There would be no compensation for the transmission usage through the market. EDAM entities would forego transmission revenues for overall efficient use of the transmission and the associated EDAM benefits.”
In a panel discussion, Kevin Smith, an attorney representing the Balancing Authority of Northern California (BANC), said that as the working group members planned, “we were trying to put some structure around how transmission is going to be viewed, how it’s utilized and so forth. And so, the buckets just became a simple convention.”
Bucket 3, it became clear, would be a problem for EDAM.
“As we looked at this and started talking hurdle rates,” Bucket 3 became the focus, Smith said.
“I would personally like to put a dagger in the heart, forever, of the hurdle-rate concept, but that’s just my own personal view,” he said.
Kathy Anderson, senior manager of real-time operations and markets with Idaho Power, said that as the working group’s discussions continued, “it became apparent that the more hurdle rates you stick in … the less economic and effective and optimized your solution becomes.”
“So that kind of led to that concept of, well, how can we maybe not put a hurdle rate in there,” as the group ultimately proposed in Approach 2.
Stakeholder comments on the straw proposal are due by June 16. CAISO plans to hold technical workshops on EDAM in late June and July. It also plans to post videos of the May 25-26 stakeholder meeting on the initiative’s webpage.
