Blackstone Infrastructure Partners will pick up a nearly 20% stake in Northern Indiana Public Service Co. for a little more than $2 billion, parent NiSource announced Tuesday.
NiSource has been on the hunt for a buyer for a noncontrolling equity interest in NIPSCO since late last year. (See NiSource Selling Minority Interest in NIPSCO.) The $2.15 billion deal will have Blackstone acquiring a 19.9% stake and pledging an additional $250 million in equity to fund a pro rata share of NIPSCO’s ongoing capital needs, according to NiSource.
NiSource said the purchase will help finance NISPCO’s continuing transition to a decarbonized fleet and reinforce grid resilience while “accelerating the reindustrialization of the Midwest.” It also said Blackstone is interested in a “long-term buy-and-hold approach to large-scale infrastructure assets.”
NIPSCO said it expects to invest $3.5 billion in the grid through 2030, with most of that going to new renewable generation to replace coal-fired assets. The company said it will end reliance on coal by 2028; that’s compared to the 75% coal generation mix it employed in 2018.
The transaction is expected to close by the end of 2023, pending FERC approval.
NIPSCO President Mike Hooper said the deal will allow NIPSCO to invest in large renewable generation projects while making capital improvements to its electric and gas infrastructure.
NiSource CFO Shawn Anderson added that the utility is “confident this is the right path forward” to boost NIPSCO’s balance sheet and “navigate the current challenging interest rate backdrop” while the utility establishes a more sustainable and reliable system.
“We’re pleased to reach this agreement at a compelling valuation following a robust and competitive process and are confident that Blackstone is the right partner for NIPSCO and NiSource going forward, given its global footprint and deep infrastructure experience, including in renewable development and procurement,” NiSource CEO Lloyd Yates said in a press release. “With this transaction, our commitment to Indiana remains unchanged, and we will be able to drive further sustainable growth for our stakeholders. This financing transaction will have no impact on NIPSCO’s current strategic direction or on our commitment to our gas and electric customers in Indiana.”
Blackstone Global Head of Infrastructure Sean Klimczak said the deal “underscores Blackstone’s commitment to decarbonization to create value for our investors and our desire to help facilitate the reindustrialization of the Midwest.”
After a strong showing last year, the U.S. energy storage market shrank in the first quarter of 2023, with grid-scale installations dropping 21% year over year, according to a new report from industry analysts Wood Mackenzie and the American Clean Power Association (ACP).
Installations fell from 697 MW in the first quarter of 2022 to 554 MW this year, primarily due to a backlog of more than 1.8 GW of storage projects that were scheduled to come online in the first quarter but have been delayed by supply chain and interconnection bottlenecks, the report says.
“Late-stage projects are facing rolling delays, with 80% of delayed projects from Q4 2022 scheduled to come online in Q1 once again pushed to later quarters of the year,” the report says.
Wood Mackenzie expects about 1.4 GW of the backlog to go online in the second quarter but cautions that “volatility quarter to quarter is still strong, and additional delays should be expected.”
On the upside, the residential storage sector hit a record high of 155.4 MW deployed in the quarter, while community, commercial and industrial (CCI) installed 69.1 MW, the sector’s second highest quarter on record. Wood Mackenzie defines grid-scale as storage interconnected to the transmission system, while CCI and residential are classified as on the distribution system. All sectors have experienced supply chain and interconnection delays. (See Report: Storage Projects Stymied at Distribution System Interconnection.)
Despite the grid-scale slowdown, which Wood Mackenzie says could continue through 2024, the report still expects the U.S. to add 75 GW of storage between now and 2027, with grid-scale accounting for 81% of the total.
But will that be enough to get to President Joe Biden’s 2035 goal of a completely decarbonized grid? Probably not, said Vanessa Witte, Wood Mackenzie’s senior analyst for energy storage. Using conservative estimates, “our base case analysis projects about 65% zero-carbon electricity by 2035, not 100%,” Witte said in an email to NetZero Insider.
An August 2022 study from the National Renewable Energy Laboratory sets a much higher target for energy storage by 2035, calling for 120 GW to 350 GW of “diurnal storage” — that is, with a duration of 2 hours to 12 hours.
However, the U.S. market is also lagging on duration, a critical need for grid reliability, according to Wood Mackenzie. For example, the 554 GW of grid-scale storage installed in the first quarter can deliver about 1,553 MWh of energy, which averages out to less than 3 hours of duration. The figures for residential and CCI are similarly low.
Witte sees duration as a reflection of how storage is currently being used on the grid, which varies by geography. California and Texas dominate the U.S. market, with about 84% of grid-scale deployments, the report says.
“In California, storage is predominantly being used across the hours that are required to gain resource adequacy, which are the ramping hours between around 5 p.m. to 9 p.m. … which has driven the 4-hour durations,” Witte said. “In other markets though, such as Texas, lower durations are more typical because there is no capacity [or resource adequacy] market, so storage is predominantly used to capture price spikes. It is a purely economic play, and this does not require or incentivize more than 1-2 hours of duration.”
“Outside of California and Texas is a bit of a mixed bag,” she said. “Storage isn’t always being used for firming or resiliency purposes, which would incentivize a 4-hour or longer duration,” although storage with 4-hour duration is becoming more common, she said.
Solar + Storage
The report sees several markers for storage market growth.
The pipeline of new projects is growing, the report says. Project announcements jumped year over year, from 42 GW in the first quarter of 2022 to 75 GW this year. Similarly, storage capacity sitting in interconnection queues rose from 315 GW to 430 GW.
Costs are also coming down, the report says, from $1,896/kW in the first quarter of 2022 to $1,778/kW this year, a 6% drop. Witte said those figures represent a median, “turnkey” price that includes not only the battery packs, but the balance of system and other installation costs, minus developer and interconnection fees.
The growth of the solar market is still another driver, as more solar systems are paired with storage, Witte said.
“Solar-paired systems made up 64% and 42% of installs in 2021 and 2022, respectively, and [are] projected to be about 54% of the 2023 installs,” she said. “Each year has some amount of variation, though we do expect solar-paired systems to take up a large chunk of the installs moving forward.”
One highly uncertain variable is the energy storage supply chain — specifically, how quickly the U.S. industry can wean itself off its dependence on China for the processing of critical minerals such as lithium, cobalt and nickel — and manufacturing of storage cells and battery packs.
The tax credits and other incentives in the Inflation Reduction Act will have a “tremendous impact” on the storage supply chain, Witte said. A recent report from ACP found that 10 utility-scale battery storage manufacturing plants had been announced since the IRA passed in August.
FERC commissioners on Tuesday questioned ISO-NE officials and New England state regulators on the region’s short-term winter reliability challenges and the need for the Everett LNG import terminal, at a forum on gas-electric coordination in Portland, Maine.
While much of the discussion focused on similar topics to the FERC reliability forum held in Burlington, Vermont, in September 2022, the tone of this year’s conference was less dire. A joint study released in May by ISO-NE and the Electric Power Research Institute (EPRI) found that the risks of a supply shortfall in New England during extreme winter weather events are “manageable” through 2027, even without Everett, though the RTO has pushed to keep the terminal operating because of longer-term reliability concerns. (See FERC Comes to Vermont and Leaves with a New England-sized Headache and Study: Limited Exposure to Supply Shortfall for ISO-NE During Extreme Weather.)
But this led to skepticism from Commissioner James Danly, who has warned of a looming resource adequacy crisis because of retiring fossil fuel-fired generators. He repeatedly questioned RTO officials on the study’s assumptions.
One of the findings of the study was that behind-the-meter solar was underestimated.
“I have to admit, I’m surprised to think that the hopes for winter reliability in New England hang entirely on one set of assumptions on one technology that is ‘surprisingly’ being deployed at the rate that it is,” Danly told ISO-NE COO Vasmi Chadalavada. He asked what other assumptions have changed since last year.
Chadalavada noted that the RTO’s position that Everett should be retained has not changed, but that the study focused on the electric system, not the gas system.
“In the longer run, I’m still as concerned as I’ve ever been,” ISO-NE CEO Gordon van Welie told the commissioners. “I think it would be extremely unwise were we to let that facility go until we know where we are with regard to these variables.”
Commissioner Allison Clements said she found the study to be “really comprehensive” and that it “provides key parameters to consider, and the resulting low odds of load shedding are encouraging.” She acknowledged, however, that ISO-NE “notes itself that it’s not equipped to assess the gas system’s effects without Everett because only” the gas industry “can speak to that.”
Vermont Department of Public Service Commissioner June Tierney observed that “nine months ago, the message was, ‘Oh my word, the sky is falling’; today the message is, ‘Well, we’ve got some breathing room.’”
“I can relate to the bewilderment sense that Commissioner Danly has,” she continued, as nothing seems to have materially changed since the Burlington conference. But, she said, ISO-NE “did the analysis, and they’re to be congratulated for that. And it being ISO’s analysis, I have no question that it was done well.”
She advised FERC to formally solicit information from ISO-NE about the assumptions and inputs that it used for the study, not just for its ratemaking benefit but also for public transparency.
Everett
Much of the daylong forum’s discussions focused on Everett and the Mystic plant.
Richard Levitan, president of the consulting firm Levitan & Associates, called Everett “the insurance that helps to safeguard both electric and gas reliability on extremely cold days.”
Carrie Allen of Constellation Energy — the parent company of both Everett and its primary customer, the Mystic generation plant — agreed that the facility is needed and added that the region is “running out of time” to keep the plant open, noting the long regulatory process that would be required if an agreement is reached.
New Hampshire Consumer Advocate Donald Kreis, however, said ratepayers have been overpaying for reliability “insurance,” and he opposes burdening consumers with additional costs from new reliability programs.
“We can design markets to force ratepayers to buy every last aliquot of reliability that industry can conjure, but I beg you not to do that,” Kreis said. “In particular, I beg ISO New England not to seek, and I beg FERC not to approve, some new market mechanism — or worse, some out-of-market mechanism — to guarantee that the Everett terminal stays in business.”
In written comments submitted to FERC for the forum, Kreis expressed concern about the true benefits of the current Mystic agreement, designed to keep the generator in service through this winter. He cited the extreme weather conditions on Dec. 24 that required ISO-NE to declare a capacity deficiency as an example of what he said were dubious reliability benefits provided by the agreement.
“It was shocking to learn that Mystic station had not been dispatched as a resource adequacy crisis loomed, given the vast sums of free money that had been awarded to the facility’s owners via the FERC-approved reliability-must-run arrangement,” Kreis wrote.
In contrast, gas utility and pipeline industry representatives expressed their concern that ISO-NE is underestimating the reliability risks to the region and argued that the region should maintain Everett and look to build additional gas infrastructure to address reliability concerns.
James Holodak of National Grid said that until renewables can displace significant natural gas demand in the region, “the prudent decision would be to keep Everett open” while expressing his frustration with the difficulties of constructing new natural gas infrastructure in the region.
“All the solutions that we’re talking about are fairly expensive relative to the potential for a new pipeline into the area,” Holodak said.
Ernesto Ochoa, Kinder Morgan | FERC
Ernesto Ochoa of Kinder Morgan said the penetration of renewables will increase the need for gas infrastructure.
“We believe that more infrastructure is needed in the region, not less, and we’re going to continue to say so forever,” Ochoa said.
Richard Paglia of Enbridge agreed on the need for additional gas infrastructure to bring more natural gas to the region.
“To me, the glue that holds all of this together are the gas plants that are highly dispatchable … but we don’t have the supply to allow those plants to run when needed,” Paglia said.
Massachusetts Energy and Environmental Affairs Secretary Rebecca Tepper pushed back on the idea that the region should pursue additional gas infrastructure.
“The region’s problem is an overreliance on natural gas,” Tepper said, saying policymakers need to focus on valuing storage, energy efficiency and demand response programs. She declined to give a definitive answer as to whether Gov. Maura Healey’s administration supports the retention of Everett beyond the end of the Mystic agreement.
Notable Absences
Energy industry representatives and state regulators made up a large number of speakers at the forum, which notably lacked direct representation of environmental justice or climate-focused organizations, while Kreis was the only ratepayer advocate to serve as a panelist.
Massachusetts EEA Secretary Rebecca Tepper | FERC
“I think this hearing would have benefited from some additional voices today, particularly from the environmental and environmental justice communities, and particularly [from the city] of Everett,” Tepper said.
Vermont Commissioner Tierney echoed Tepper’s comments, saying, “There are voices out there of people who have not been a part of these discussions to date, and who are also not being directly addressed by this conversation.”
She noted that officials often stress the importance of gas during the transition to clean energy: “Every time we say that there are people saying, ‘Do you not get it? We need to stop burning fossil fuels.’”
“I worry that our conversation today — which, again, was expert and highly incisive and elucidating — I worry about it coming across as tone deaf. … The problem I see continues to be, to the folks we’re trying to reach — the hearts and minds that need to join us in this process — they continue to feel like they’re not included in the study thinking.”
While environmental justice groups were not included as speakers at the forum, several groups did submit written comments or release statements about it, including the Berkshire Environmental Action Team, No Coal No Gas and the Fix the Grid Coalition.
“As fossil fuel-dominated interests gather in Portland, Maine, on June 20 for the 2023 New England Winter Gas-Electric Forum, we expect them to double down on rhetoric that we need even more fossil fuel infrastructure, in the name of reliability,” No Coal No Gas wrote in a statement prior to the event. “Yet we expect that most of the panelists will be silent on lessons learned from the most recent epitome of winter reliability failure, a widespread failure of fossil fuel generators (particularly gas generators) to deliver on Dec. 24, 2022, a cold snap when they were most needed.”
In a letter signed by representatives of local climate and environmental justice organizations, Fix the Grid called for a “more holistic approach to grid planning and management,” taking into account “the public health and environmental impacts of current and future winter reliability policies and programs, including markets, on low-income environmental justice communities across New England.”
The campaign also advocated for an analysis of the reliability potential of increased transmission, energy storage and demand-side solutions including demand response, energy efficiency and conservation.
“We would like to see FERC encourage ISO New England to work with states and public interest organizations to envision a reliable grid that is also affordable and sustainable for all communities,” the group wrote
AUSTIN, Texas — ERCOT officials issued their first voluntary conservation call of the year Tuesday as the Texas grid flirted with peak-demand records during an oppressive heat wave.
The grid operator asked Texans to voluntarily reduce their electric use between 4 and 8 p.m., “if safe to do so,” because of extreme heat and forecast record demand. ERCOT also requested that the state’s government agencies reduce energy use at their facilities as much as possible.
Demand peaked at 79.2 GW during the hour ending at 6 p.m. Tuesday, the last official day of spring. That fell short of ERCOT’s record peak of 80.1 GW, set in August. It was also short of the new peak record for June, set Monday at 79.3 GW.
“ERCOT is not experiencing any emergency conditions right now,” CEO Pablo Vegas told the Board of Directors during its bimonthly meeting Tuesday.
Vegas told the directors that voluntary conservation is a “very widely used industry tool” to help lower demand during certain times of the day. ERCOT credited the conservation efforts and other reliability tools with surviving the tight periods Tuesday.
As it normally does when ERCOT needs every megawatt possible to meet demand, the Texas Commission on Environmental Quality accepted the grid operator’s request to exercise its enforcement discretion for any generator’s exceedance of the agency’s air-permit limits. The discretion ended at midnight Wednesday.
ERCOT recently rolled out a new notification system to help alert Texans to grid conditions before an emergency is called. Last week, it issued its first weather watch, extending through Wednesday, to draw public attention to potential high demand triggered by extreme hot temperatures. (See “New Grid Notifications Added,” ERCOT Monitor Recommends New Market Design in Report.)
A dangerous heat wave has settled over much of Texas since last week. Humid conditions have sent heat indexes above 120 degrees Fahrenheit in some portions of the state and caused the National Weather Service to issue excessive heat warnings and heat advisories.
ERCOT is expecting demand to exceed 83 GW next Monday and Tuesday. However, its projections have often come up short.
Extreme heat has Texans taking every precaution. | Mothers Against Greg Abbott PAC
Several cities have set record highs this week, with Laredo hitting 115 F on Monday. That day, Houston reached triple digits a month earlier than normal.
Despite the sizzling temperatures during the waning days of spring, Woody Rickerson, ERCOT’s vice president of system planning and weatherization, told the board that staff are expecting temperatures this summer to be average and not as extreme as last year, the second-hottest summer on record. A developing El Niño and May rains have lessened the chance for above-normal temperatures, Rickerson said.
Solar energy has carried the load for ERCOT, providing as much as 12.2 GW of energy Tuesday, close to its summer-accredited capacity of 12.6 GW, which is up 50% over last year. Rickerson said the increase in solar resources has moved the ISO’s normal summer peak from the 5 p.m. hour to 9 p.m.
“The amount of solar we have on the system has really helped mitigate what used to be our peak hour before,” he said. “Now, we’re a little more worried about moving to the 9 p.m. hour. Load will drop from 5 to 9 p.m., but the solar is dropping more than the load drops, so that makes your tightest hour to be later in the day.”
That makes ERCOT dependent on wind to meet the summer demand, Rickerson said. ERCOT has a little over 10 GW of summer-accredited wind resources, but more than three times that in nameplate capacity.
“That’s the reality of where we are. Every day, we’re going to have to look at what the wind is doing,” he said.
Washington is expanding efforts to make the state a leader in emissions-free aviation, Gov. Jay Inslee signaled at the Paris Air Show this week.
Inslee on Monday joined ZeroAvia CEO Val Miftakhov at the air show to announce that the state will invest $350,000 to aid ZeroAvia’s expansion at Boeing’s Paine Field in Everett, Wash., where the company is working to develop an electric engine to be installed in Dash 8-4000 76-seat aircraft. The state previously provided $350,000 to ZeroAvia in 2022.
Meanwhile, another Washington-based project will begin to use renewable energy and water to transform carbon dioxide into a synthetic aviation fuel.
Inslee is in Paris because aviation is a major state industry. The sector also accounts for 2.5% of the world’s carbon emissions, according to governor’s office.
ZeroAvia is developing hydrogen-electric planes, targeting a 300-mile range for nine- to 19-seat aircraft by 2025, and a 700-mile range for 40- to 80-seat aircraft by 2027. The company says it is has secured $10 billion in pre-orders from several airlines.
“ZeroAvia is a key member of the rapidly growing ecosystem of world-leading innovators located in Washington state who are building the future of sustainable aviation fuels and zero-emission propulsion systems,” Inslee said in a press release.
In the same release, Miftakhov said: “The support from Governor Inslee and the Washington Department of Commerce enables us to push forward quickly on our targets for commercial flight of up to 20-seat aircraft by 2025, and up to 80-seat aircraft by 2027.”
In April, the Washington legislature appropriated $6.5 million to build a sustainable aviation fuel (SAF) research center at Paine Field with the effort to be led by Washington State University.
‘Perfect Location’
In the second announcement, Inslee and SAF producer Twelve announced the company will break ground next month on a Moses Lake plant to produce jet fuel from renewable electricity, water, and CO2 — which will be sourced from landfills and waste from food processing plants. The company has dubbed its fuel E-Jet.
“Commercial-scale production of E-Jet fuel is a major milestone in our mission of creating a world run on air,” Twelve CEO Nicholas Flanders said in a statement. “Washington is the perfect location for our facility, with its abundant renewable energy resources to power our carbon transformation process and longstanding global leadership in the aviation industry.”
SkyNRG recently announced plans to build a $800 million sustainable aviation fuels plant at an undisclosed location in Washington. It was encouraged by the state legislature passing a major tax break for such plants.
The new law sets a business-and-occupation tax rate of 0.275 percent for any plant that would produce annually at least 20 million gallons of low-carbon jet fuel. Most B&O tax rates in Washington range from 0.47 percent to 0.9 percent. A B&O tax is a tax on the business’ gross receipts.
The law’s purpose is to construct an alternative jet fuel plant in Washington. A few years ago, the predicted cost of building such a plant was at least $1 billion.
The TransWest Express transmission project, designed to carry 3,000 MW of Wyoming wind power to the Southwest and California, broke ground Tuesday on a typically windy day in Carbon County, Wyo.
Energy Secretary Jennifer Granholm, Interior Secretary Deb Haaland and Wyoming Gov. Mark Gordon participated in the ceremonial groundbreaking at a cattle ranch where the line’s northern HVDC terminal will be built.
The Biden administration said the groundbreaking represented a milestone in its push for faster transmission buildout.
“The TransWest Express project will accelerate our nation’s transition to a clean energy economy by unlocking renewable resources, creating jobs, lowering costs and boosting local economies,” Haaland said in a statement.
TransWest got the go-ahead to build in April, when the U.S. Bureau of Land Management issued a notice to proceed. It was the final step in an approval process that began 15 years ago. (See TransWest Express to Break Ground After BLM Approval.)
The 732-mile high-voltage line will be capable of transmitting 3,000 MW of energy from wind farms near Rawlins, Wyo., to consumers in California, where it is regarded as an important component of the state’s push to achieve 100% clean energy by 2045.
To meet the goal, the state will need to import as much as 10 GW of out-of-state wind by 2040, at least half of it from Wyoming, according to projections by the California Public Utilities Commission and California Energy Commission.
CAISO’s inaugural 20-year transmission outlook estimated that carrying wind from the Great Plains and Rocky Mountain states to California to achieve 100% clean energy would cost $12 billion.
Last summer, TransWest’s developers asked to join CAISO as a participating transmission owner under a new subscriber model, in which a line’s subscribing customers pay its costs. The ISO’s Board of Governors approved the request in December, and FERC approved the agreement between CAISO and TransWest in March as a step toward PTO status. (See FERC OKs CAISO-TransWest Move Toward PTO Status.)
If the arrangement wins final FERC approval, CAISO will operate the line, and its entire capacity will be allocated to the Power Company of Wyoming (PCW), owner of the 3,000-MW Chokecherry and Sierra Madre Wind Energy Project being constructed in the south-central part of the state. FERC approved the arrangement in February 2022.
Both TransWest and PCW are wholly owned affiliates of The Anschutz Corp., a privately held company controlled by billionaire Phillip Anschutz.
Once built, TransWest will consist of 732 miles of transmission lines in three linked segments: a 405-mile, 3,000-MW HVDC system between Wyoming and Utah; a 278-mile, 1,500-MW HVAC line between Utah and Nevada; and a 49-mile, 1,500-MW HVAC transmission line in Nevada.
It will connect in Utah to lines serving the Los Angeles Department of Water and Power and in Nevada to CAISO’s balancing authority area.
Construction is expected to begin by the end of this year, with energization scheduled for 2027, TransWest has said. The line is expected to create about 1,000 jobs during its construction phase.
Other major Western lines being developed to transmit wind energy from the Great Plains and Rocky Mountains include PacifiCorp’s Gateway South transmission line across Wyoming, Colorado and Utah. PacifiCorp, owned by billionaire Warren Buffet’s Berkshire Hathaway, plans to add more than 3.7 GW of new wind power by 2040 in Wyoming and five other Western states.
Pattern Energy’s SunZia transmission project, a 550-mile line from New Mexico to Arizona, received route approval from BLM in May, with construction expected to start this summer. The line will carry energy from Pattern’s 3,500-MW SunZia Wind project in central New Mexico to markets in Arizona and California.
The American Council for an Energy-Efficient Economy released a report Wednesday finding that increasing efficiency would help avoid most of the annual load that must be met with non-renewable resources on a net-zero-emissions grid, even without widespread electrification.
“While the role of energy efficiency is well established in global and economy-wide decarbonization efforts, its value proposition is positioned to change as the electricity consumption it offsets decarbonizes,” the report said. “Because solar and wind are carbon-free energy sources, energy efficiency has been perceived by some as a less valuable decarbonization tool in a high renewable energy future.”
Efficiency can offset between 31 to 46% of net peak load by 2030 and 39 to 86% by 2050, varying between the five regions studied in the report, called “Energy Efficiency in a High Renewable Energy Future.”
“These results hold regardless of the speed of renewable energy deployment, though we find that energy efficiency is likely to be more valuable in avoiding total electricity system costs under a more rapid supply-side decarbonization scenario,” the report said.
Efficiency measures that affect thermal space conditioning loads (heating and cooling) are likely to have the greatest impact on both energy savings and avoided costs through 2050, the report said.
The resource could prove especially valuable for low-income housing, which often is inefficient, and low-income consumers face a higher burden in paying for energy, which can be mitigated by using less overall.
The paper included a review of literature around decarbonizing the grid and found some of those focused on the supply-side alone, ignoring efficiency. However, those that do include the resource list it as among the most important tools needed to meet decarbonization goals.
“Our modeling finds that energy efficiency measures reduce burdens on the power sector, avoiding billions of dollars’ worth of energy and capacity costs in 2030, and two to three times as much in 2050 even with high deployment of renewable energy,” the report said. “We estimate that by 2050 annual power sector savings will range between $10 billion and $19 billion per grid region analyzed.”
The study specifically modeled California, Texas, the Southeast, Midwest and Northwest, using two renewable energy scenarios: one with electric sector decarbonization by 2050, and another where the job is mostly done by 2035.
Examples of energy-efficient interventions include improving a building’s thermal envelope through insulation and other weatherization techniques, upgrading heating and cooling systems, installing smart thermostats, converting to heat pumps and upgrading appliances. The report looked into 12 efficiency measures and found that thermal envelope improvements would be the most impactful.
The impact of improving buildings’ thermal envelopes varies by region and has the biggest impact in areas with lower baseline energy codes, lower-quality existing building stock and more extreme temperatures, which the study said includes Texas and the Southeast.
“To maximize electricity system benefits through demand-side interventions, utilities should prioritize thermal space conditioning measures within their portfolios,” the paper said. “Replacing low-performance air source heat pumps or electric furnaces with high-performance air source heat pump models will guarantee savings and lower demand on the grid.”
Getting energy-efficient equipment in place often has a limited window around when customers are replacing old equipment, so the paper recommended that educational materials be rolled out well before then so they are aware of the options when the time comes.
The commercial sector has tremendous potential for efficiency, with the paper suggesting utilities have programs that have robust integrated efficiency offerings for them that deal with heating, cooling, ventilation, insulation, lighting and energy-management systems.
The report’s literature review found that many studies do not compare efficiency’s demand-side impacts along with the supply-side resources such as solar, wind or natural gas.
“Consequently, energy efficiency measures do not emerge from least-cost energy system optimizations as a resource of choice, which may reduce their procurement,” the paper said. “Capacity expansion models should therefore ensure that all supply- and demand-side resources are fairly compared against each other, and not marginalized by default.”
ALBANY, N.Y. — New York has emerged from the COVID-19 pandemic forever changed and now faces a growing list of challenges — including climate change and uncertainty in energy prices — that it must adapt to, according to a presentation given by Moody’s Analytics during NYISO’s Spring Economic Conference last week.
Moody’s economists believe a national recession is avoidable but that New York has a troubling future ahead as it continues to recover from the systemic shocks experienced during the pandemic while confronting a changing work culture, unfamiliar housing and demographic dynamics, and climate change.
Moody economists’ subjective probability of a U.S. recession in 12 months | Moody’s Analytics
Energy and resource prices also remain a sticking point for the economy, but Moody’s noted that prices have come into clearer focus as pandemic-era volatility abates and geopolitical tensions cause fewer fluctuations.
“It was a very mild winter … and that helped keep a lid on prices,” said Adam Kamins, a senior director at Moody’s. “We’ve also seen the U.S. and OPEC fill the hole left by the lack of supply from Russia; while on Russia’s end, they have been able to increase exports to countries like China and India at relatively cheap prices.
“That has all been good news for the affordability of oil and gas and brought it down to a much more stable place,” he said. “Our expectation is that we’re going to see continued increases in prices for the next year or so, but by 2024 prices will begin to come down as more U.S. supply comes online.”
Questions & Discussion
Kamins answered NYISO stakeholders’ questions, including concerns about natural gas and climate change impacts.
Given the recent volatility of energy prices, Anthony Abate, lead energy market adviser with the New York Power Authority, asked whether Moody’s was comfortable with assuming that the new normal for natural gas prices would be around $5/MMBtu instead of the previous $3 range.
Outlook for energy prices becoming clearer | Moody’s Analytics
“Natural gas prices have a lot of variation,” Kamins said. “And there are lots of factors, including geopolitical ones, that no model can pick up … All of this means that there’s a high degree of uncertainty around these forecasts.”
“Our model suggests prices will move upward, but I would not take that to the bank,” he added.
Erin Hogan of the state’s Utility Intervention Unit pointed out that gas supplies are unlikely to be a limiting factor but rather pipeline congestion will be more determinative of prices. She asked whether building more pipeline capacity could influence price.
“It could,” Kamins said. “But there are some potential supply issues just around the fact that drillers have been hesitant to drill because they want to keep prices as high as they can … and so that could keep a ceiling on supply that puts upward pressure on prices. But I think that you’re right that the bigger limiting factor would be capacity.
“We thought there’d be a glut of U.S. oil and gas production after Russia’s invasion, but producers are being very disciplined and want to keep supply in check to keep prices relatively high,” he said.
New York at most risk for climate change impacts | Moody’s Analytics
Abate also asked how Moody’s has begun reflecting the growing threat of climate change in its state models or assessments to help predict future outcomes.
Kamins said that “we have made adjustments to our baseline forecasts” that typically include “some state intervention,” but “we also create custom forecasts that show the more extreme outcomes in terms of either more severe damage from climate change or a more complete and early intervention.”
In an email to RTO Insider, Kamins referred to his recently published whitepaper to provide context on how Moody’s accounts for climate change in its forecasts, writing, “we used our model to account for transition risk based on the industrial composition of states and metro areas.
“Then we used exposure scores from RMS [Risk Management Solutions] … to adjust upward or downward for acute and chronic physical risk for individual economies based on their level of risk relative to a
weighted average.”
Other Decarbonization Presentations
The New York Power Authority, National Grid, and the Electric Power Research Institute (EPRI) also gave presentations during the conference, examining different parts of New York’s decarbonization.
NYPA updated NYISO on its advanced solar forecasting project, which gathers irradiance and load patterns to improve New York’s solar operations. The project uses ground-based “sky imager” sensors and advanced weather modeling systems to “true-up” New York’s solar load forecasting capabilities, said Greg Pedrick, a senior engineer with NYPA.
National Grid presented study results examining what it would take for New York to implement an electric vehicle highway charging network, finding that the state must act now to align net-zero transportation goals with wider electrification system planning. Some highway charging sites will use the same amount of power as small towns, so planning needs to consider how to centralize energy delivery to these “no-regret sites.”
The EPRI presented findings from a report that examined different scenarios New York could pursue to decarbonize its building stock and what those outcomes would be. The report, which builds on an earlier evaluation of electrification opportunities within New York, found that long-term economic and environmental benefits to decarbonizing the state’s building stock outweigh the costs, and that immediate action would deliver quicker results.
MISO appears set on restricting the interconnection requests it will accept and under what conditions they can leave the line in order to purge speculative generation projects from its queue.
Staff again this week said they need to toughen rules around entering and exiting the interconnection queue so that MISO doesn’t devote time to studying projects that aren’t a sure thing. The RTO debuted its plan in late May. (See MISO Wants Tougher Obligations on Queue Entry and Exit.)
The collection of changes will likely include more expensive milestone payments, a clampdown on penalty-free withdrawals, stricter proof that developers have secured land and reinforcing harm calculations so withdrawing projects have a better chance of owing money as they exit the queue.
MISO plans to present a straw proposal at the July 19 Planning Advisory Committee meeting.
“We’ve come to the point where we need to make some enhancements to the queue intake process so we’re getting better projects and a smaller number of projects, and we need to do that before we have a ‘23 cycle,” MISO’s Andy Witmeier said at Tuesday’s Interconnection Process Working Group.
Witmeier said if MISO kicks off the 2023 queue cycle with its existing rules in place, it will likely be hit with 200 GW of new interconnection requests. Last year, the grid operator fielded 171 GW of requests. MISO’s current queue contains 1,379 active projects totaling a little more than 237 GW.
“As the queues get larger, they slow down because there are more points of interconnection, more dispatch assumptions and more potential overloads to study,” he explained. He said a queue comprised of fewer, more successful projects will lead to faster queue processing and more cost certainty on transmission upgrades.
Most of the projects in MISO’s queue that haven’t yet proceeded to generator interconnection agreements are experiencing delays. All entrants in the 2021 and 2022 cycles are trailing the queue’s approximate yearlong timeline because of studies MISO must undertake.
Witmeier said he’s already been in private discussions with “key” stakeholders to put together a proposal.
MISO is aiming to file its proposal with FERC by early September, get FERC permission on the plan by early November and close the currently open-ended 2023 queue application window in late November or early December, months later than usual. MISO has been keeping the 2023 queue deadline fluid while it works out how it can make its bursting-at-the-seams queue more scalable.
Witmeier said it’s currently much too easy for speculative projects to enter the queue and then drop out penalty-free, getting “all their money back with interest.” He said MISO needs to “weed out” the number of submissions.
He said withdrawn projects should be on the hook for some fees for disturbing other projects’ network upgrade cost estimates.
Witmeier also said MISO’s $4,000/MW second milestone payment could be ratcheted up to about $10,000/MW, considering current inflation trends and his opinion that MISO’s milestone fees are already too low in the first place.
He said in the past five to six years, MISO has levied harm payments on withdrawing projects for the consequences to lower-queued projects “fewer than a dozen times.” He said that’s evidence that MISO’s harm calculation payments are “way too lenient and need to be adjusted.”
“We are responding to consumer demand, but we realize that an unmanageably large queue doesn’t work for anyone,” Invenergy’s Sophia Dossin said.
Witmeier added that developers don’t tell MISO why they’re dropping out of the queue, whether that’s land or permitting issues or climbing network upgrade costs.
Stakeholders asked if MISO has considered limiting the number of interconnection requests or megawatt values that individual customers can submit per annual cycle.
Witmeier said that while MISO has discussed enacting a “hard cap” on individual developers, he said the RTO runs the risk of discriminatory treatment and still more proposed generation than MISO load can snap up. He said large developers typically account for only about a third of queue submittals and are often better prepared than their smaller counterparts when submitting projects.
“It would certainly help competition but is that better?” he asked hypothetically.
Pickup trucks, vans and SUVs account for a disproportionate share of the gasoline consumed in Washington state.
On Tuesday, an engineering and consulting firm offered state lawmakers on the Senate-House Joint Transportation Committee ideas on how to replace those gas guzzlers with electric vehicles.
Jeff Doyle, a project technical leader from the Seattle office of Boston-based CDM Smith, told lawmakers that 10% of Washington’s vehicles account for 26% of the gasoline consumed in the state. Meanwhile, 6.3% of the state’s vehicle burn more than 1,000 gallons of fuel a year — the majority of those being pickup trucks, vans and SUVs.
The owners of those so-called “high-consumption fuel users” value them for their hauling and towing, Doyle said. Also, they are used for heavy commuting, rideshare programs and delivery services.
CDM Smith provide four suggestions to encourage owners of those heavy fuel users to switch to EVs:
Incentivizing owners to lease EVs for trips that don’t require medium-duty capacity. CDM Smith said the heavier vehicles average 25,000 miles annually, compared with an average of 9,000 miles a year for all vehicles. The incentives could be based on miles driven in the leased EVs.
Incentivizing trade-ins of fuel-burning pickup trucks and vans for EVs. The incentives could be based on miles driven annually in the new vehicles or on how much fuel is expected to be saved by switching to electric.
Creating a program in which drivers switch to EVs but are provided financial assistance to rent high-consumption fuel users when they need a vehicle to haul or tow. This program would be phased out as more medium-duty electric trucks and vans hit the market.
Providing rebates to all drivers — light- and medium-duty — to install electric chargers at their homes. The State Legislature has already exempted such installations from the state’s sales tax.
According to CDM Smith, gas-powered vehicle models still far outnumber EVs on dealer lots in the U.S. The company’s breakdown showed:
138 models of gas-powered light-duty cars, compared with 25 EV models;
174 models of gas-powered SUVs, compared with 22 electric models;
34 models of gas-powered pickup trucks, compared with four electric;
23 models of gas-powered vans, compared with one electric.
CDM Smith acknowledged that EVs are currently more expensive than gas vehicles but said their price tags are shrinking.
While some lawmakers asked clarifying questions on the presentation, none offered comments.
