The Texas Supreme Court on Friday narrowly affirmed ERCOT’s sovereign immunity, granting it protection against fraud claims and allegations of overpricing during the 2021 winter storm, and asserted the Public Utility Commission’s jurisdiction over the grid operator in a pair of rulings.
In a 5-4 decision, the state’s high court found that ERCOT is a governmental entity and immune to lawsuits because “it prevents the disruption of key governmental services, protects public funds and respects separation of powers principles.”
The majority held that the ISO is entitled to sovereign immunity because the state’s Public Utility Regulatory Act “‘evinces clear legislative intent’ to vest it with the “‘nature, purposes and powers’ of an ‘arm of the [s]tate government’” and because doing so satisfies the ‘political, pecuniary and pragmatic policies underlying our immunity doctrines’” (22-0056, 22-0196).
Writing for the majority, Chief Justice Nathan Hecht said ERCOT is a “unique entity” and provides an “essential governmental service.” He said ERCOT operates under the PUC’s direct control and oversight, it performs the “governmental function of utilities regulation, and it possesses the power to adopt and enforce rules pursuant to that role.”
“ERCOT’s governmental nature is demonstrated most prominently by the level of control and authority the state exercises over it and its accountability to the state,” Hecht wrote. “In this regard, it is much like a state agency … the state has complete authority over everything ERCOT does to perform its statutory functions.”
In a 53-page dissent that outnumbered the 40-page decision, justices Jeffrey Boyd and John Devine wrote that “the public’s trust is undermined when the judiciary extends sovereign immunity, contrary to history and tradition, to what is undeniably not sovereign: purely private entities.” They called on Texas lawmakers to correct the court’s “mistake” and waive the grid operator’s “newfound immunity” so injured parties have the right “to claim the protection of the laws.”
Thousands of wrongful death and property damage lawsuits stemming from Winter Storm Uri have been combined in pending multidistrict litigation in a district court, where ERCOT is a defendant in most of the cases.
“The root justification for possibly protecting private entities with the [s]overeign’s immunity is that, by statute or contract, they act as arms of the state: the government acted through the entity and the actions are effectively attributed to the government as ‘action taken by the government,’” Boyd and Devine wrote. “Unlike any other entity previously granted immunity by this [c]ourt, no statute designates ERCOT as a part of the government.”
ERCOT said in an emailed statement that it was pleased with the decision.
“The [c]ourt’s careful consideration of these significant legal issues allows us to continue to focus on our core [s]tate responsibilities on ensuring a reliable grid for Texans,” the grid operator said.
The PUC responded that it would “let the ruling speak for itself.”
The high court affirmed a 2021 appeals court ruling that ERCOT is a “governmental unit” in a lawsuit brought by San Antonio municipality CPS Energy. The utility alleged that it was short-changed $18 million during the winter storm by ERCOT’s mishandling of power pricing.
It also reversed an appeals court’s judgment that the ISO is a private, membership-based nonprofit, not created or chartered by the state, in a case involving Panda Power that dates to last decade. The developer said ERCOT knowingly produced false market data in 2011 and 2012 reports that led Panda to build three power plants, a $2.2 billion investment that failed to meet its expectations.
The Department of Energy’s Loan Program Office (LPO) on Thursday announced a conditional commitment for a loan of up to $9.2 billion to help BlueOval SK, a joint venture between Ford and Korean battery manufacturer SK On, to produce electric vehicle batteries at sprawling plants in Kentucky and Tennessee.
The three plants, one in Tennessee and two in Kentucky, will together be able to produce 120 GWh of batteries per year, to be used in Ford and Lincoln EVs, the LPO announced. Already under construction, the Kentucky plants cover an estimated 2.3 square miles, with battery production to begin in 2025, according to the BlueOval website.
With a 6-square-mile “megacampus,” the Tennessee plant will be the largest in Ford’s portfolio and include both battery manufacturing and a factory for Ford EVs, according to BlueOval. As described on the company website, the plant will “be carbon neutral, use 100% renewable energy, send zero waste to landfill and use fresh water only for human consumption ― as [Ford] moves towards a closed-loop manufacturing process.”
Production in Tennessee also is scheduled to begin in 2025, the company said.
Job creation across all three plants will be about 5,000 during construction, with 7,500 permanent positions. BlueOval is working with community colleges in Kentucky and Tennessee to develop training programs “where thousands of employees will gain the skills required to work at the battery plants,” according to the company announcement.
BlueOval will be building a training facility next to the Tennessee plant to “really [focus] on the curriculum for training, deep learning, and getting people through that part of the training before they come out on the shop floor to be a part of the launch,” said Kel Kearns, the plant manager, as reported by WBBJ in Jackson, Tenn.
The LPO noted that the Kentucky and Tennessee projects are also located near or in disadvantaged communities, reflecting President Joe Biden’s “Justice 40” commitment to ensuring 40% of all federally funded projects benefit low-income and disadvantaged communities.
“The DOE’s commitment to this project will strengthen battery manufacturing in the U.S. while reducing carbon emissions, providing customers with high-performance vehicles, and creating good jobs for future generations,” said BlueOval CEO Robert Rhee. The company must meet additional LPO requirements before the conditional loan can be finalized.
A Domestic Supply Chain
Building out a domestic supply chain for EV and stationary batteries is a key priority for the LPO, as domestic content in EVs and batteries has become a political flashpoint for Biden’s push to make electric vehicles 50% of all new car sales by 2030.
The industry is highly dependent on China for batteries and the processing of critical minerals in them, including lithium, cobalt and nickel. Sen. Joe Manchin (D-W.Va.) made a U.S. supply chain buildout a key part of the Inflation Reduction Act.
According to Internal Revenue Service guidelines, to receive the full credit, the final assembly of an EV must occur in North America. In addition, 40% of the critical minerals in the battery and 50% of other battery components must be sourced, processed or manufactured in the U.S. or in a country with which the U.S. has a free trade agreement.
The domestic content percentages go up each year, with critical minerals increasing 10% per year, up to 80% in 2027, while the battery component also will increase 10% per year, rising to 100% in 2029.
Some, but not all, models of Ford’s top EVs — the Mustang Mach-e SUV and F-150 Lightning pickup truck — qualify for the full credit, according to the company website.
The LPO received $3 billion from the IRA specifically for its Advanced Technology Vehicles Manufacturing (ATVM) program, an amount that can be used to provide up to $40 billion in loan authority, according to an online fact sheet.
The BlueOval announcement is the latest conditional loan from the ATVM program. This month, the LPO made a conditional commitment for an $850 million loan to KORE Power for an Arizona plant that will produce battery cells to be used in both EVs and grid-scale stationary storage. (See LPO Announces $850M Conditional Loan for Ariz. Battery Cell Plant.)
In March, the office also announced a $375 million conditional loan to Li-Cycle Holdings to develop North America’s first recycling facility for battery-grade lithium, to be located in New York. (See DOE OKs $375 Loan for NY Battery Recovery Plant.)
FERC rejected a controversial pro forma transmission-to-transmission interconnection agreement filed by Pacific Gas and Electric that the utility said was modeled on CAISO’s large generator interconnection agreement as a means to streamline its interconnection process.
“PG&E states that the pro forma IA [interconnection agreement] will standardize and simplify new agreements and provide transparency and predictability for interconnection customers that are interconnecting their transmission system or transmission facility to PG&E’s transmission system,” FERC said (ER23-1661).
The utility argued that the new IA would “create efficiency since it anticipates 15 new or replacement interconnection agreements through 2025,” the commission said.
CAISO plans and operates PG&E’s transmission system, and its pro forma large generator interconnection agreement (LGIA), with revisions for transmission interconnections, contains “many terms and definitions … consistent with CAISO’s tariff, PG&E said as part of its explanation of why it had used it as a model.
The proposal elicited a slew of protests from utilities, state and federal agencies and balancing authorities that offered 18 categories of reasons why the standardized agreement would be unreasonable and discriminatory to those seeking to connect to PG&E’s sprawling transmission grid.
“Protestors request that the commission reject the pro forma IA or, in the alternative, that the commission establish hearing and settlement judge procedures,” FERC said. “Several protestors … note that the commission has never approved a pro forma ‘load’ interconnection agreement, and instead reviews interconnection agreements on a case-by-case basis.”
One group of protesters called the “Indicated Public Entities” included the city and county of San Francisco, the Northern California Power Agency, the Transmission Agency of Northern California, the Sacramento Municipal Utility District, the Port of Oakland and three irrigation districts that generate electricity.
“Indicated Public Entities argue that PG&E’s desire to ease negotiation of new interconnection agreements is no justification for limiting interconnecting entities’ ability to negotiate terms based on their own circumstances,” FERC said.
The U.S. Department of Energy, the Western Area Power Administration, and the California Department of Water Resources filed motions to intervene and protests.
“DOE asserts that providing uniformity is an insufficient justification for terms of the pro forma IA that conflict with legal rights and obligations of the United States,” FERC said.
DOE also emphasized that PG&E had not adequately explained why it had chosen CAISO’s pro forma LGIA as a “useful or appropriate template for transmission-to-transmission system interconnections,” the commission said.
FERC agreed with the arguments made by DOE and others.
“Rather than explaining why the specific provisions of its proposed pro forma IA are just and reasonable and not unduly discriminatory or preferential in their own right, PG&E places significant emphasis on the fact that it used the CAISO pro forma LGIA as a template for its proposed pro forma IA, and that the Commission previously accepted similar interconnection agreements,” FERC said.
But “CAISO’s pro forma LGIA is designed to address the specific issues associated with the interconnection of a generator to CAISO’s transmission system,” it said. “System-to-system interconnections raise different issues and require different considerations than those addressed in an LGIA.”
In addition, PG&E’s proposal included “significant deviations from CAISO’s LGIA without sufficient explanation, FERC found.
Another main reason FERC said it rejected PG&E’s proposal was because it “contemplates a pro forma IA that includes individually tailored and negotiated appendices that will replace existing IAs when they terminate.”
“We find that PG&E has not adequately explained how the individually tailored and negotiated appendices will be used to capture the customer-specific requirements of PG&E’s differently situated interconnection customers,” FERC said.
California’s gas-fired power plants experienced a surge in curtailments during last summer’s heat wave, according to a new report, which questions whether the facilities are a solution to preventing energy shortfalls.
At the same time, the gas plants’ emissions spiked, worsening air quality in disadvantaged communities, according to the report, released Wednesday by Regenerate California. The group is a coalition led by the California Environmental Justice Alliance (CEJA) and the Sierra Club.
“Gas simply does not do its job when it matters most,” said Ari Eisenstadt, energy equity manager at CEJA. “Gas plants’ mythical reliability value in keeping the lights on is far outweighed by their negative air quality impacts for environmental justice communities.”
Regenerate California partnered with consultant Grid Strategies to analyze power output and emissions from 107 gas plants in California during the record-breaking heatwave from Aug. 31 to Sept. 9, 2022.
Potential generation that was lost due to gas plant outages and derates during the heat wave totaled more than 1.1 million MWh, or nearly 5,000 MW on average, according to the analysis, which used CAISO data.
And during the peak period from 4 to 9 p.m., curtailments were about 200 MW higher on average.
“California gas plant curtailments track fairly closely with CAISO hourly demand during the heat wave, likely reflecting that derates due to high ambient temperatures coincide with periods of high electricity demand,” the report said.
The report didn’t include curtailment data from days outside of the heat wave. But Grid Strategies Vice President Michael Goggin said a standard assumption is that about 5% of the gas fleet will be unavailable during peak periods.
In contrast, a curtailment of 10% or even as much as 15% was seen at peak periods during last year’s heat wave, Goggin said Wednesday during a media briefing on the report.
That was due to gas plants running less efficiently when the weather heats up, along with an increase in equipment failures, Goggin said. Older plants that were fired up during the heat wave were less reliable, he added.
“It’s pretty clear that these gas plants fell well short of what was expected of them,” Goggin said.
When asked to comment on the report, a spokesperson with the Edison Electric Institute, which represents U.S. investor-owned electric companies, said EEI members are working to deploy wind, solar and energy storage resources while demonstrating technologies that aren’t yet available at cost and scale.
“As we continue to deploy those resources, nuclear energy and natural gas generation are essential partners in accelerating the clean energy transition,” EEI media relations director Sarah Durdaller told RTO Insider. “They allow our member companies to integrate more renewables into the energy grid while ensuring resilience and reliability.”
Emissions Spike
The report also examined gas plant emissions using data from EPA’s continuous emissions monitoring program. For the 107 plants for which EPA data were available, emissions of sulfur dioxide, nitrogen oxides and carbon dioxide increased by about 60% during the heat wave compared with a baseline period of Aug. 19-28, 2022.
Not only did overall emissions increase, but emissions per megawatt-hour were also up as older plants came online, Goggin said.
“There were some very dirty power plants that turned on during these really top hours of need,” he said.
The increased emissions came after Gov. Gavin Newsom issued an emergency proclamation at the start of the heat wave, loosening air quality requirements to allow gas-fired power plants to generate more electricity. (See Newsom Declares Emergency as Heat Stresses Calif. Grid.)
Blackouts Avoided
CAISO was able to avoid rolling blackouts during the heat wave, despite demand reaching a new high of more than 52 GW on Sept. 6. Several factors helped prevent a blackout, the ISO said, including an emergency text message sent out to 27 million cell phones on Sept. 6 urging consumers to conserve electricity. Within 20 minutes of the 5:45 p.m. alert, demand plunged by 2,385 MW. (See CAISO Reports on Summer Heat Wave Performance.)
“That’s really what kept the lights on,” Eisenstadt of CEJA said during Wednesday’s media briefing. “If we were paying people to do that — especially if we were paying low-income ratepayers to do that — the effect would be massive.”
Eisenstadt and others called on the state to fund clean energy projects rather than keeping gas plants going.
“We must invest in demand-side solutions and drive local clean energy buildout in environmental justice communities to improve air quality and ensure grid reliability,” said Teresa Cheng, senior campaign representative with the Sierra Club.
And Eisenstadt said the dense snowpack from California’s unusually wet winter — with its expected boost to hydropower this summer — gives the state a window of opportunity to move away from gas power plants to greener forms of energy.
Some older gas plants that were slated for closure now may be kept in service as part of the Strategic Reliability Reserve that the state developed last year as part of Assembly Bill 205.
For example, AES Corp. announced in April that it signed agreements with the California Department of Water Resources to extend operations of once-through cooling units at its Huntington Beach and Alamitos gas plants through 2026. The units had been scheduled to stop operating in December 2023.
Units at Huntington Beach and Alamitos made it onto a list in the Regenerate California report of the top 15 gas plants ranked by megawatt-hours of curtailment during the heat wave.
If the three-year extensions for the 1.4 GW at Huntington Beach and Alamitos are approved, AES will run the units during emergency grid reliability events within the Strategic Reliability Reserve Program, the company said.
“Our Southland legacy units continue to demonstrate that they are ready and able to support the reliability of California’s electric grid,” Andrés Gluski, AES president and CEO, said in a statement at the time.
NERC on Thursday released its 2023 State of Reliability report, which found that the North American bulk power system generally remains highly reliable and resilient.
Transmission system reliability has improved significantly for the fifth consecutive year, but conventional generation — challenged by more frequent extreme weather — saw its highest level of unavailability overall since NERC started gathering generator availability in 2013.
Generation saw its worst “weighted equivalent forced outage rate” last year, Manager of Performance Analysis Donna Pratt said on a conference call with reporters Thursday.
“When we analyze this by fuel type, we also observed increasing outage rates for coal over the five-year period, which correlates to higher numbers of start-ups and maintenance outages,” Pratt said. “And the unavailability of gas-fired generation recently has been consistently higher during the winter months.”
Those are two of the main reasons why generation is “surpassing transmission in contributing to major load-loss events,” she added. No apparent trends are discernable in other forms of generation, the report said.
“Higher overall outage rates for coal and gas generation, as well as some utility-scale solar generation not operating as necessary for reliability, indicate that there is still significant work to be accomplished to accommodate the rapidly changing weather and generation resource mix in conjunction with electrification of the economy in a reliable manner,” said Pratt.
The most significant reliability event of the year was the winter storm in December, also known as “Elliott,” which impacted the eastern U.S. and prompted a joint inquiry from FERC and NERC into what happened. The inquiry is expected to be completed late this year, so NERC’s report did not go into depth on Elliott. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
But in response to that and other recent cold weather events, NERC issued a Level 3 “essential action alert” this May to tell the industry to increase its winter preparedness. NERC has issued several new standards on winter readiness this year, and others are under development.
NERC’s report also highlighted a June 4, 2022, event around Odessa, Texas, where a failed surge arrestor caused the loss of 333 MW of synchronous generation, leading to the erroneous loss of another 511 MW and an unexpected loss of 1,700 MW of solar PV generation.
“The total generation lost exceeded the most severe single contingency and nearly exceeded the Texas Interconnection resource loss protection criteria, the design threshold that is used to establish the requirements for frequency recovery in the Texas Interconnection,” the report said.
That event and other similar ones indicate that the dynamic performance of inverter-based resources (IBRs) have to be improved if the grid is to benefit from their rapid expansion, NERC said.
Texas has had similar events with IBRs, as has the Western Interconnection, and NERC has highlighted the issues with IBRs since 2016. NERC is working to upgrade its standards to address the issue, and FERC launched a rulemaking on it last year. (See FERC Addresses IBRs in Multiple Orders.)
Immediate industry actions are needed to implement published guidelines and ensure the reliable operation of the grid as IBRs grow.
“IBR modeling requirements need significant improvement to ensure that high-quality, accurate models are used during reliability studies so performance issues can be identified before they occur during real-time operations,” NERC said.
Physical and cyberattacks on grid assets are increasing, and that reinforces the need for the further development and adaptation of standards and guidelines.
“The growing attack surfaces that result from the increasing penetration of distributed energy resources call for ongoing development and adaptation of cyber and physical security standards and guidelines to keep up with the ever-changing threat landscape,” NERC said. “Furthermore, cyber-informed planning should include designs and be considered when planning and integrating the technologies into the grid to strengthen the cyber robustness.”
Hostile nation states are continually targeting North American critical infrastructure and are constantly evolving methods to compromise the grid’s security, reliability and resilience. Homegrown extremists have also targeted the grid, NERC added.
The two offshore wind farms vying for first-in-the-nation status both now have “steel in the water.”
New York announced Thursday that the first monopile foundation has been installed for South Fork Wind, a 132-MW project being developed by Ørsted and Eversource off the eastern tip of Long Island.
Two weeks ago, installation of the first monopiles and transition pieces began at Vineyard Wind 1, an 800-MW project being developed by Avangrid Renewables and Copenhagen Infrastructure Partners south of Martha’s Vineyard in Massachusetts.
Vineyard and South Fork occupy the same patch of the Outer Continental Shelf south of New England that the Bureau of Ocean Energy Management is developing for emissions-free wind power.
Bokalift 2 is the center of activity on South Fork, supported by a fleet of smaller vessels and onshore personnel.
DEME’s slightly smaller Orion is performing a similar role for Vineyard, also supported by a cast of hundreds.
The heavy lift vessel Orion carries components to the Vineyard Wind project off the Massachusetts coast. | Vineyard Wind
Work on both began in 2022, and while Vineyard got a two-week head start on actual tower installation, the crews need to erect 62 turbines there, compared with only a dozen at South Fork.
Developers of the two projects and their fans in state government each say that theirs will be the first utility-scale or commercial-scale offshore wind project in U.S. waters; bragging rights presumably would belong to the one that goes online first.
South Fork expects to start producing electricity this year. Vineyard had previously specified a 2023 startup date in its publicity materials but no longer includes any prediction.
An increasingly interesting question is, which wind farm will be the third in U.S. waters?
Developers of three projects comprising 97% of New York’s contracted offshore wind pipeline and two projects comprising 67% of the pipeline in Massachusetts have all said they cannot proceed under the financial terms they agreed to before interest rates and input costs skyrocketed.
They’re seeking to cancel and renegotiate their deals. Whether or not they are successful, project delays and/or higher costs to ratepayers appear likely.
In that sense, being first worked to the advantage of South Fork and Vineyard — they locked in their contracts before costs increased.
New York Gov. Kathy Hochul said in a news release Thursday that South Fork will not only help protect the climate but also help the state develop economically.
“This progress on building the first utility-scale offshore wind project in the country cements New York as a national hub for the offshore wind industry,” she said.
Massachusetts has economic goals similar to New York’s in the offshore wind sector and has set a significantly higher per capita target for gigawatts of offshore wind power.
Massachusetts Gov. Maura Healey on June 7 offered an assessment similar to Hochul’s:
“Our administration is grateful for the important work being done by Vineyard Wind, Avangrid, CIP, DEME and labor partners to bring clean, affordable energy to Massachusetts. We’re thrilled to see this historic project move one step closer to completion and committed to supporting the offshore wind industry across the state.”
A white paper on a pressing matter — managing battery systems connected to the grid — bogged down in a debate over its details as NERC’s Reliability and Security Technical Committee (RSTC) met Wednesday.
A request for approval of “Grid Forming Functional Specifications for BPS-Connected Battery Energy Storage Systems” was tabled to allow time to seek industry comment and potentially rework the report.
It was the only matter on the 27-item agenda that drew any votes of opposition.
Shortly before the vote, RSTC Chair Greg Ford said the subject is important but that getting the report correct is important as well.
“As a matter of fact, it’s probably one of the more important documents we’ve talked about in a while as we move this grid transformation and this whole idea of bringing batteries into the fold of dispatch,” he said.
“We’re trying to make this paper as solid and informative as we can so that we can allow it to take us to the next steps, whether that be guidelines or SARs [standards authorization requests] in the future, depending on how batteries come into play.”
The debate and discussion touched on the input the Inverter-Based Resource Performance Subcommittee sought as it wrote the white paper — one speaker said he saw no NERC-registered entities on the list — but centered more on the wording of the report, which some felt was too strong.
Growing Need
The version of the white paper before the committee Wednesday states that:
Studies have shown that absent supplemental synchronous machine-based solutions, grids dominated by inverter-based resources (IBRs) need grid-forming (GFM) IBRs to maintain stable operation.
Accordingly, the need for GFM technology is expected to accelerate with the rapid growth of IBRs, and planning is necessary to ensure sufficient GFM IBRs are installed.
One of the largest obstacles to installing GFM on the bulk power system (BPS) is establishing clear interconnection requirements for the performance, testing and validation of the technology.
So, the paper addresses how transmission owners, planners and coordinators can establish these requirements and test interconnecting resources.
It gives generator owners clear performance expectations for GFM resource interconnections so they can work with manufacturers before interconnection studies begin and possibly streamline the interconnection queue process.
A common question among industry stakeholders is how many IBRs should be deployed with GFM functionality; there is not a single answer, but initial studies indicate upward of 30% may be necessary.
Since the current percentage is near zero in nearly all large, interconnected power systems, the paper recommends starting to require and enable GFM in all future battery energy storage systems (BESS), a relatively low-cost step to ensure system stability.
Industry should begin specifying, requiring and implementing GFM for all new BPS-connected BESS.
Sticking Points
Words like “requiring” and “should” were problematic for some at the meeting.
“I think in this white paper, if it was just providing the technical recommendations on the specifications, I think I would let it go,” one speaker said. “But this is going further and it’s recommending that you ‘shall,’ in all battery storage applications, install grid-forming and enable it. That’s quite a strong statement to make without having industry comment.”
Ford agreed on the power of words, saying that “should be doing” and “should be considering” are different things.
Others emphasized the importance of the issue beneath the semantic debate.
“This is critical for reliability, the work that y’all are doing, and this paper is really important,” another attendee said. “Bringing the grid-forming characteristics to the surface is pretty important because we can’t wait till we need it to start thinking about getting it, because it’s too darn late at that point.”
Another said: “This is something this group asked for. We’ve been talking about it for three years. Our interconnection queue is getting tremendously bogged down with battery storage. … We are always struggling on this. Any delay is not going to do us much of a service, quite honestly.”
Another sought to reverse-engineer a solution to the debate, asking: “What are we trying to achieve here with this white paper?”
“The goal is to provide some guidance to utilities in areas that are already … considering grid-forming today,” subcommittee Chair Julia Matevosyan said.
Another speaker said he saw a wide leap in functionality between a white paper offering helpful ideas and one leading to SAR that “sets off bells and whistles of importance.”
“There ought to be a way to distinguish between the two,” he added.
Matevosyan did her best.
“If I may, I would just like to reiterate that this is just a white paper, there is no talk of SAR,” she said.
Wednesday’s vote pushes any RSTC action on the white paper back at least until the group’s September meeting.
“That was — fun,” Ford said as he called a recess, closing the matter after more than an hour of discussion.
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
