MISO CFO Melissa Brown said last week that payroll and medical benefit expenses will push the grid operator over budget through year-end.
Brown said during a Wednesday meeting of the Board of Directors’ Audit and Finance Committee that as of April, base expenses are almost 3% over budget by $2.9 million. MISO expects to spend $324.5 million in base expenses and be over budget by $14 million, or 4.5%, before the year is up.
She told board members expenses are over budget mostly because of staffing levels, employee compensation and medical benefits.
Brown said MISO originally budgeted a 6.5% vacancy rate this year, expecting the same employee turnover it has experienced since 2021. However, that rate recently dropped to 4%. She said Human Resources Director Allegra Nottage and her team are doing a good job keeping MISO adequately staffed.
“We didn’t know how successful we’d be in getting our vacancy rate turned around. It’s very difficult to prepare for,” Brown said of the anticipated continuing trend of a tight labor market or a recession. She said MISO will forecast a further decline in its vacancy rate, “bringing us closer to full employment.”
Director Robert Lurie asked whether staff should be more conservative in forecasting spending given the current financial uncertainty. Brown said MISO will analyze this year’s variables and reflect those dynamics in next year’s budget.
MISO’s project investment expenses are under budget by about $1 million (10.6%) year-to-date, driven by equipment delivery delays and limited external resources. Brown said supply chain issues continue to persist, leading to “ups and down” among the RTO’s internal projects.
Brown will deliver a second financial report to the full board in Madison, Wis., this week.
Lurie asked that going forward staff include a statement in future financial reports that MISO is complying with its investment policy. The policy is conservative in nature because it invests its members’ funds to securities backed by the U.S. government, highly rated money market investments and dollar-denominated obligations held by entities rated AAA by at least one organization.
Lurie said that because MISO manages other people’s money, it is appropriate that it reiterate that investments comply with the policy.
Thursday’s ISO-NE Consumer Liaison Group meeting was largely a forum on the merits of energy storage and fossil-fuel generation and a critique of ISO-NE for continuing to power the grid with one instead of advancing the other.
The tone was due in no small part to the meeting being held in Peabody, Mass., where a controversial gas-fired peaker plant was recently built near environmental justice communities.
Two older gas- and oil-burning units stand near the new one.
Peabody resident Susan Smoller, a representative of Breathe Clean North Shore, asked: “What is the plan to replace these peakers with batteries and renewables?”
She called on ISO-NE to be sure the higher-emissions fuel — oil — is not used in the older units if gas is not available and urged that demand peaks be reduced so the Massachusetts Municipal Wholesale Electric Co.’s new 55-MW peaker plant is never turned on.
“In the least, let’s make sure that it is the last new fossil fuel infrastructure built in Massachusetts,” she said to applause from some of the 200-plus attendees.
“It’s ISO New England that holds the power to decide when our peakers run, and what they burn,” Smoller said.
Other speakers drilled down on the idea that ISO-NE favors fossil fuel interests.
“Every time we come and ask for a just transition, we hear these arguments that ‘ISO has to be neutral; we can’t take a political stance on one form of energy over another,’” another speaker said. “ISO is already deciding what fuels are present on our grid and picking fossil fuels. My question is, how do we fix this? Do we need to change the tariff? Do we need to abolish [the] ISO itself?”
Another speaker paraphrased a prior statement by ISO-NE that it would prioritize grid reliability and proper market function as the clean energy transition moved forward.
“I’d like you to reverse that,” he said — make preserving conditions for life on planet Earth the priority rather than keeping the lights on and the capitalist free markets functioning.
“What we really want to hear is that your heart is in saving life — not in the lights coming on every time someone wants to make an egg,” he said.
ISO-NE Vice President Anne George pushed back on almost every point.
“Reliability also affects lives,” she said to the last critic.
ISO-NE’s mission and vision statements show its commitment to a successful transition to a clean energy future, George said, but “we have to do it in a reliable way.”
Some of her other rebuttals:
Anyone can participate in the wholesale market ISO-NE operates, if they meet reliability standards.
The RTO is independent and is not beholden to fossil fuel interests.
It agrees climate change is a threat and will use its tools to facilitate the energy transition.
The RTO lacks authority to make the changes suggested at the meeting.
It has advocated putting a price on carbon and embedding that into the wholesale electricity market to make renewables more competitive, but the RTO has found little support for such a move.
ISO-NE provides the “huge” value of an independent body to oversee the market.
The transition of the market toward renewables will not be as rapid as critics are calling for, George said.
“It is not going to happen overnight, and it is not something we are dragging our feet on.”
Energy Storage
The variable nature of the wind and solar power the clean energy transition — at least in its early stages — will rely heavily on makes a fallback power source indispensable.
A major theme of Thursday’s meeting was using energy storage rather than fossil-fired peakers to meet that critical need.
Rosemary Wessel, founder of No Fracked Gas in Mass, and Chris Sherman, a vice president at Cogentrix, related their collaboration in western Massachusetts.
Wessel listed the health problems in neighborhoods surrounding two Cogentrix peakers in the heart of Pittsfield.
Sherman recounted the company’s decision to retire both, and to retire a third peaker in West Springfield, Mass.
The ISO-NE interconnection queue shows a large quantity of energy storage proposed in New England. | ISO-NE
The West Springfield site, with its three interconnections, will host a 45-MW/180-MWh battery energy storage system. The site could host as much as 100 MW, but 45 MW is what Sherman could convince the company and its investors to back.
Colette Lamontagne of National Grid said the utility has installed five storage systems in Massachusetts as demonstration projects and a nonregulated affiliate is developing renewable power generation.
Storage will be useful in easing the peak-demand transmission bottlenecks likely to arise as communities ramp up their use of electricity, she said, and provide a less expensive, more flexible alternative to building a new substation.
Jason Houck of Form Energy described the Massachusetts-based company’s pre-commercial efforts to develop longer-duration storage.
Sen. Joe Manchin and Energy Secretary Jennifer Granholm joined Form Energy in Weirton, W.Va., on May 26 to break ground on its first factory. At least 750 people are expected to eventually work there, fabricating iron-air batteries.
Form plans to build a 1.5-MW/150-MWh system in Minnesota next year for Great River Energy as a pilot project, then two 10-MW/1,000-MWh systems for Xcel Energy in 2025, one each in Minnesota and Colorado.
Both areas are seeing wind power replace coal power, Houck said, and have weather extremes, all of which creates the demand for storage.
An audience member at Thursday’s meeting asked him why Form Energy was not putting the projects in Massachusetts.
“We’d love to,” Houck said. “It comes down to the market structure. It’s a regulated market.”
It is easier to work under the other states’ integrated utility model, he added.
“In New York, New England, other markets, the utilities no longer own assets and don’t do planning; who do we partner with? In this region, the ISO has not historically played a role in commercializing new technologies.”
Priya Gandbhir, senior attorney at the Conservation Law Foundation, made a similar point about ISO-NE.
“We need the ISO to reform its market structure and prioritize getting clean energy up and running. We need the ISO to stop [looking] at the problem of how to fit clean energy resources into its existing market structures and rather to prioritize the just transition to our clean energy future.”
A bill that would require all electricity sold in New Jersey to be clean energy by 2035 has been delayed by concerns from environmentalists, labor groups and solar developers, according to the bill’s sponsor.
The measure would accelerate the state’s current goal of requiring 50% clean electricity by 2030.
Bill S2978 sponsor Sen. Bob Smith (D), who chairs the influential Senate Environment and Energy Committee, said he had hoped to bring the bill to the committee before the summer recess at the end of this month. But a triad of concerns raised by different groups proved too difficult to resolve, and the bill won’t be heard until after the November election, Smith said.
“We have issues right and left,” Smith said. “Everybody wants a bigger bill … So we’re trying to balance all the equities, get everybody in the room, lock the door and come up with a solution.”
Smith’s initial version of S2978 would have modified the state’s renewable portfolio standard, which presently includes the 50% by 2030 target, with a new requirement for 100% clean energy by 2045.
But the latest version of the bill notes the state is “on track” to generate 75% of its energy with “non-emitting” resources such as wind, nuclear and solar by 2025, on the way to 84% by 2030. The bill would now require the state to update clean electricity targets to 70% by June 2026, 85% by June 2030 and 100% by June 2035.
The bill seeks to establish in law a goal that Gov. Phil Murphy (D) laid out in a February executive order requiring 100% of the state’s electricity to be derived from clean sources by Jan. 1, 2035, preventing a future governor from altering or revoking the target. While Democrats have in recent years held both legislative chambers, the governor’s office has swung back and forth between the two parties for the last 40 years.
“The current governor is a pretty green governor,” Smith said. “And a new executive may not feel as sanguine about renewable energy.”
Competing Agendas
The bill is vigorously backed by the environmental groups, several of which held a press conference in Trenton Thursday morning with two Democratic legislators — Sen. Linda R. Greenstein and Assemblyman Robert J. Karabinchak — to advance the bill even as some environmentalists seek to remove elements they don’t like. They are particularly concerned the legislation would allow trash-incinerating plants to still be considered Class 2 renewable energy and continue operating, even though they add to pollution.
Press conference participants from the Sierra Club, League of Conservation Voters, Natural Resources Defense Council and New Jersey Progressive Equitable Energy Coalition urged legislators to support the bill and take other steps to accelerate the shift to clean energy.
“Climate change is not slowing down,” said Tom Gilbert, co-executive director of the New Jersey Conservation Foundation, who cited as an example the thick smoke and fumes that shrouded New Jersey Wednesday and Thursday because of wildfires in Canada. “This is climate change, and unfortunately it’s only going to get worse unless we act decisively.”
But Ray Cantor, deputy chief government affairs officer for the New Jersey Business and Industry Association, one of the state’s largest business groups, expressed concerns but said he couldn’t comment in detail because the bill is still being redrafted and he hasn’t seen the latest version.
“We are extremely skeptical of creating any artificial deadlines for taking such major actions, especially when experience and simple physics has shown that you cannot run an electrical grid on renewables alone,” he said. “In all likelihood this bill will have New Jersey ratepayers subsidize projects in other states to buy credits just to say we met a renewable standard. This is not good policy, and it will be costly.”
Smith said solar developers have pushed for changes to the bill that would resolve some issues they have with past incentive programs created by the New Jersey Board of Public Utilities. Electrical workers are concerned that in reaching for the 100% clean energy goal, the effort will “somehow result in the outsourcing of a significant number of energy jobs,” he said, adding, “That’s not the case.”
“We’ve had some of the best minds in the energy business analyze this, and they are all coming back with the same conclusion — which is this will increase jobs, labor-related jobs in New Jersey, by a huge factor,” he said. “You remember that anything over a megawatt has to be done with union labor.”
Burning Trash
Smith said the environmentalists have concerns because they want to use the bill as “vessel to put resource recovery facilities [trash-burning plants] out of business.”
That view was reinforced by Allison McLeod, policy director for the New Jersey League of Conservation Voters, who said her group strongly supports the 100% clean electricity standard but wants the state to move past “fossil fuel emitting power generation and into an equitable and just clean energy future.”
McLeod said the group is concerned that the current version of the bill allows trash burners to continue operating. The state has four such incinerators in Camden, Newark, Westville and Rahway.
“Trash Incineration is not clean energy, and it shouldn’t be considered clean energy,” she said. “When we’re defining clean energy in our renewable portfolio standards, we need to make sure that we’re defining things as truly renewable and truly clean, and for us that does not include trash incineration.”
The issue is particularly important, she said, because incinerators are frequently located in overburdened communities that have historically dealt with the “effects of fossil fuel and dirty energy production.”
Smith said the incinerators receive millions of dollars in state subsidies, and the operators argue that if they were shut down, the state would generate more methane, a greenhouse gas, because the trash would go to landfills instead of being burnt. He said he tried to adjust the bill with an amendment that would require the incinerators to meet emissions standards set by the New Jersey Department of Environmental Protection or else lose the subsidies.
However, the environmental justice community “is not happy with that at this point,” he said, adding that he questioned whether a bill to revise the state’s renewable energy portfolio standards is the “right vehicle” for an effort to shut down trash incinerators.
MISO planners say they have pinpointed several proposed projects in this year’s transmission planning cycle that might provide more system benefits with altered designs.
During a series of subregional planning meetings this week, staff said nine projects in the draft 2023 Transmission Expansion Plan (MTEP 23) are candidates for alternative designs because of their size and complexity. The projects account for more than 40% of the MTEP 23 price tag, currently standing at $8.8 billion across 578 projects.
During a MISO Central subregional planning meeting Tuesday, expansion planner Amanda Schiro said most of the projects singled out for alternative designs are for substation work in the southern region. They include the controversial $1.1 billion, 150-mile 500-kV line and substation project Entergy has proposed for southeast Texas and all three phases of its nearly $2 billion, 500-kV Amite South line and substation work in the state’s southern region. Entergy has said both projects are needed for reliability.
The $3.6 billion in localized reliability spending MISO South transmission owners proposed this year has sparked debate among stakeholders as to whether Entergy is attempting to dodge more efficient, regionally cost-shared projects. The grid operator this year pledged to examine the TOs’ proposals for larger, combined project opportunities. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)
Competitive transmission developers and clean energy groups have said the two Entergy projects resemble previous economic projects MISO recommended and ultimately canceled in 2016 and 2017. The economic projects’ costs would have been shared regionally, but reliability projects are billed only to the local transmission zone in which they’re located. (See NextEra, SREA Protest Canceled MISO Project at FERC.)
Other projects tagged for alternative exploration include Entergy Louisiana’s $164 million line and substation upgrades to alleviate the Downstream of Gypsy load pocket in southern Louisiana; Ameren Illinois’ $159 million, 138-kV substation and 29-mile line in south central Illinois; and Michigan Electric Transmission Company’s $63 million plan to construct a new 138-kV substation and related facilities to serve a new industrial customer. The projects all rank among the MTEP 23 portfolio’s most expensive.
Trevor Armstrong, manager of MISO South’s expansion planning, said during another subregional planning meeting Thursday that staff are evaluating the nine projects’ effectiveness and will announce any alternative recommendations in early September. MISO is hosting its final round of subregional planning meetings at the same time and will present its final MTEP 23 project recommendations.
Some alternative project costs might be higher than the original projects. The RTO’s planners said larger project costs aren’t necessarily a dealbreaker if the project can satisfy additional benefits criteria. They stressed that a higher price tag doesn’t necessarily mean the project is a worse option.
The proposed $4.3 billion investment for 68 projects in MISO South exceeds the entire MTEP 22’s $4 billion cost.
Armstrong said MISO is introducing an economic screen in the region this year for the five most expensive projects. The screen replaces the normal market congestion planning study, currently on hold while staff chart its four long-range transmission planning (LRTP) portfolios.
“In order to do our due diligence on these very large projects, we’re putting a screener on them to see if they warrant further economic study … and get insights into congestion relief,” Armstrong said. The screen could designate some of the proposals as market efficiency projects, with their costs allocated regionally.
Different project designs will be pursued if they are a “better alternative in terms of cost and performance,” Armstrong said. “MISO’s focus isn’t just keeping the lights on. We also plan for other benefits.”
“The Amite South project area is a hotbed of load growth. There are industrial requests along the Mississippi River … and they’re related to electrification,” MISO’s Clayton Mayfield said, noting that much of the state’s load growth is in a load pocket. “We’ve studied in excess of 8 GW of load growth. It’s really the foot of the wave coming our way, and customers have aggressive timelines. They’re looking to come online in 2026 through 2028.”
Armstrong said he would consider a request from stakeholders to share the economic screen’s results before announcing any alternative projects.
Southern Renewable Energy Association’s Simon Mahan urged MISO to search for alternatives that will “future proof the system.” He reiterated that stakeholders weren’t privy to the grid operator’s new generation and retirement data, which could have helped them propose more suitable project alternatives. Stakeholders had until the end of May to submit project alternatives.
Mahan also asked whether staff’s extensive alternative project analysis will cause MISO to abandon the LRTP’s third portfolio, the first to consider planning needs in the southern region. Jeanna Furnish, MISO’s director of expansion planning, said staff remain committed to examining South system needs with the LRTP.
The RTO is also including an exploratory study to alleviate near-term congestion in MTEP 23. The study will review historical congestion data and recreate system conditions in production cost models to distinguish between persistent trouble spots and temporary ones.
Because the study is informational, MISO won’t recommend any transmission projects. Stakeholders had requested that the grid operator come up with smaller, congestion-relieving projects like its interregional targeted market efficiency projects with PJM and SPP. Some expressed disappointment that the study won’t result in a new class of projects. (See MISO Adding Near-term Congestion Study to MTEP.)
MISO has said it first needs to better understand the nature of its near-term congestion before proposing a new project type and potential cost allocation.
A new report by the successor organization to the Cyberspace Solarium Commission this week warned that utilities’ relationships with the Electricity Information Sharing and Analysis Center (E-ISAC) are not as strong as they could be.
The report was published by the CSC 2.0 Project, created after the bipartisan, congressionally sponsored commission issued its final report in 2020 to “support continued efforts to implement outstanding CSC recommendations” and continue to research additional cybersecurity issues discovered by the group. The goal of the report was to review Presidential Policy Directive 21, issued during the Obama administration, which established the federal government’s approach to critical infrastructure security and resilience.
In a letter to Congress last year, President Joe Biden indicated that he planned to “review and revise” PPD-21 to address emerging cybersecurity risks. CSC 2.0 conducted its own review of the directive — and Executive Order 13636, which focused on improving engagement between critical infrastructure stakeholders on cybersecurity and information sharing — to develop its own set of recommendations and review the current state of public-private sector security collaboration.
The review focused on the performance of sector risk management agencies (SRMAs) in supporting U.S. critical infrastructure. The 2021 National Defense Authorization Act established SRMAs for each critical infrastructure sector to support sector risk management, assess sector risk, manage sector coordination, facilitate information sharing between private and public sector entities, support incident management, and contribute to emergency preparedness efforts.
Citing their review of the Colonial Pipeline ransomware attack of 2021, when cybercriminals since linked to Russia hacked the company managing the flow of almost half the supply of gasoline and other fuel products to the U.S. East Coast and caused it to shut down its entire pipeline, the report’s authors sought to highlight “the broader challenge of inconsistent capabilities and performance across SRMAs.” They chose three examples for the discussion, including the Department of Energy, designated as the SRMA for the electricity sector.
While the report acknowledged DOE as “one of the best performing SRMAs” and called E-ISAC “one of the best” among its counterparts in other sectors, the authors observed that even such praise needs caveats. In this case, the E-ISAC’s relationship with NERC — which reports to FERC on reliability standards compliance and enforcement — creates an unintended chilling effect that discourages entities from turning over evidence that could implicate them in compliance violations.
“Our interviewees relayed that, because the E-ISAC is located within NERC, which in turn is subject to oversight by FERC, in-house counsels on occasion advise electricity companies not to share certain information with the ISAC for liability reasons,” the report said.
The commission said the utilities’ concerns constituted “an obstacle without an obvious solution,” because separating the E-ISAC from NERC would deprive it of financial resources and relationships that help with its services to the electric sector. It also did not provide any examples in which NERC or regional entities may have used information provided to E-ISAC in enforcement actions.
In an email to ERO Insider, a NERC spokesperson did not dispute the report’s claims but pointed out that the report itself notes that “the electricity sector has one of the best ISACs due to the robustness of its member-driven information sharing.” The spokesperson continued that NERC and the E-ISAC actively work to keep the organizations separate to allay the fears outlined in the CSC 2.0 report.
“NERC has a code of conduct in place that prohibits E-ISAC staff from sharing information about potential violations and compliance monitoring staff from seeking to obtain such information from the E-ISAC,” NERC said — a claim also noted in the report. “In addition, a firewall between networks and a separation of E-ISAC and NERC staff exists to further enhance safeguards. To date, this process has worked effectively and without fail since its inception.”
The spokesperson added that ongoing cyber and physical security threats to the grid make “the nexus between NERC and the E-ISAC … more valuable than ever before.”
CAISO on Wednesday began a series of stakeholder meetings to deal with a surge of interconnection requests by focusing on generation and storage proposals more likely to meet California’s reliability needs and climate goals.
The ISO received a record 544 interconnection requests totaling nearly 350 GW during its Cluster 15 application window in April. That was five times the average number of requests it received in Clusters 8 to 13 during the years before 2021, the year application numbers began to soar.
The state needs to add 7,000 MW of clean-energy and storage resources to its grid each year for the next 10 years to meet its 100% clean energy goal by 2045 while maintaining grid reliability, CAISO and the California Public Utilities Commission estimate.
In a discussion paper published May 31, CAISO said that “given the rapid acceleration of clean energy development necessary to meet reliability and policy objectives and the unprecedented level of resource development activities reflected in interconnection requests to the ISO, this paper explores concepts for significant and transformative improvements to the ISO’s role in resource planning coordination, transmission planning, interconnection queuing and management, and power procurement.”
The paper kicked off Track 2 of CAISO’s 2023 Interconnection Process Enhancements stakeholder initiative. Wednesday’s meeting was held to present stakeholders with the ISO’s suggestions and elicit their initial feedback.
CAISO is breaking with its traditional stakeholder process by convening working groups to address the paper’s concepts and possibly come up with proposals of their own. Typically, the ISO presents a management straw proposal that is refined in a stakeholder process. But it used working groups last year to develop parts of its proposed extended day-ahead market for the Western Energy Imbalance Market.
“Given the complexities associated with this issue, the ISO is taking a different approach with this initiative and intends to initiate a robust stakeholder process to solicit feedback and suggestions to address the volume of new interconnection requests received in Cluster 15 and to encourage progress of existing projects in the queue,” it said.
CAISO is hoping to seek approval from its Board of Governors for Track 2 in December. The board approved Track 1, a timeline extension to study Cluster 14 requests, in May along with the ISO’s restructured transmission plan. (See CAISO Board Adopts Revamped Transmission Plan.)
The discussion paper proposed principles, problem statements and conceptual solutions. Its principles, or “process redesign parameters [and] objectives,” include prioritizing interconnections in “zones where transmission capacity exists or new transmission has been approved” and limiting the amount of interconnection studies to “reasonable capacity volumes that align with state resource planning.”
The paper’s first problem statement says: “The massive increase in interconnection requests seeking to meet the accelerated cadence of resource development now needed by the state on a sustained basis has overwhelmed critical planning and engineering resources across the industry. The current generator interconnection processes simply cannot efficiently accommodate all applicants and must be substantially redesigned to meet state policy and reliability needs.”
It then offers concepts for discussion in the working groups, including:
“a qualification process for determining projects studied for full capacity delivery status, and an alternative study path for all others;
a process where load-serving entities and other off-takers select projects for study as an indication of commercial interest in advance of the cluster studies; and
a process that selects the projects for study through an auction.”
Managing a large, unwieldly queue is another problem the paper targets. It offers concepts for queue management that include increasing deposit amounts and holding projects in the queue more accountable.
Stakeholders who spoke at Wednesday’s meeting asked for clarification of some aspects of the relatively novel process for CAISO.
“Just to clarify, these concepts that you introduce are not intended to limit the potential reforms that you’re open to exploring as it relates to managing interconnection requests,” said Ryan Millard of NextEra Energy Resources. “So, if we see something missing here, or see problems with some of these concepts, we’ll still be able to explore it in working groups. If we have some or reform ideas that don’t necessarily relate to just these concepts, there’s still opportunities to identify those concepts as part of the working groups. Is my understanding, correct?”
Robert Emmert, senior manager of interconnection resources at CAISO, said, “Yes, that’s correct. The main thing that we are looking for is that whatever proposals stakeholders bring forward … deal with the principles that we’re developing. That’s why the principles are so important.”
Some speakers took issue with CAISO asking for initial stakeholder comments by June 14, saying that was unrealistic.
Emmert said the comments the ISO is hoping for in that time frame are “at just a very high level on the various concepts that have been laid out.”
The working groups will begin meeting this month, CAISO said.
Though new federal incentives have made the U.S. increasingly attractive for clean energy investments, the industry suffers from a lack of ambition, the head of the Department of Energy’s Loan Programs Office told the American Council on Renewable Energy’s (ACORE) Finance Forum on Wednesday.
Faced with the massive financial incentives in the Inflation Reduction Act and challenges in permitting, transmission and supply chains, “there really isn’t a confident solution set to solving [these problems],” said Loan Programs Director Jigar Shah. “There is a modeling solution set. … We can model the crap out of everybody else, but the level of ambition that we have in this industry around actually taking control of our future is very low.”
Zeroing in on interregional transmission, Shah pointed to the industry’s “affliction … around believing that if we actually present a fantastic idea with a really good report, that someone’s going to read it and fix the problem for us.”
“It’s not that people don’t recognize the value of interregional transmission; it’s not that people don’t recognize the value of the offshore wind grid that would be built from Boston to New Jersey,” he said. “Clearly, there’s somebody who’s not wanting to do it, and so the question is who doesn’t want to do it? Why do they not want to do it, and what can you offer them to get them to do it?
“That’s the game,” Shah said. “That’s what it’s like to be at the big-boy table.”
Shah’s challenge to the developers and investors at the ACORE event in New York comes as the IRA has made the U.S. a focus for clean energy investment. A new report from ACORE released Wednesday shows that companies are spending more on new projects and, in some cases, risking more to take them on.
More than half of the companies surveyed by ACORE are planning to up their clean energy investments by more than 10% this year. | ACORE
While investments in renewables dipped slightly in 2022, more than half of the companies surveyed for the ACORE report said they would be upping their spending in the sector by more than 10% this year. On risk, the results were more divided, with 37% saying they would be moderately increasing risk and 32% moderately decreasing risk, reflecting industry concerns with “headwinds,” such as inflation, supply chains and permitting.
But the survey found universal agreement that the IRA has made the U.S. a major magnet for clean energy investment. ACORE CEO Greg Wetstone noted that for the first time in the six years of the organization’s annual finance survey, “virtually everyone we asked said that the U.S. would be a more attractive place for renewable investment compared to other countries” over the next three years.
Investors also ranked solar and storage at the top of a list of potential asset classes ripe for more investment. However, Wetstone cautioned, ”that doesn’t necessarily mean that’s where the investment is going to go. Storage has been near the top of this list for a long time, but the investment numbers have not been anywhere close to what we’re seeing in generation.”
Implementation Mode
The tension between industry optimism triggered by the IRA and ongoing economic and regulatory challenges was a theme throughout the opening panels at the event, and like Shah, other speakers called for the industry to focus on solutions.
Sandhya Ganapathy, CEO of EDP Renewables of North America, said her company could be committing more than 40% of its global capital to the U.S. renewables market.
“We now need to be in the implementation mode,” Ganapathy said. ”It’s a collective responsibility of the industry to actually sort of push ahead and see what are the challenges we have, make sure that we address those challenges and go ahead.”
“This is a time of optimism; this is a time of growth,” agreed Ingmar Ritzenhofen, chief financial officer of RWE Clean Energy, the U.S. arm of the German energy giant. “What’s crucial in this decisive moment is that we maintain the rational perspective on the things where we need solutions.
“We need to be clear [that] certain things don’t happen overnight. We cannot localize the entire supply chain overnight, even if we want to. … So, there needs to be a transition period; so, let’s have that conversation. I think that needs to be the mindset. How do we work through it? How do we resolve those things? And how do we deploy more?”
Project financing is a key part of the drive to increase deployment, and another point of risk and uncertainty for developers. The transferability provisions of the IRA will allow developers to sell their solar or wind tax credits to a third party, but the industry is waiting for the Internal Revenue Service to issue guidance on the provisions.
Ritzenhofen said transferability will provide a much-needed alternative to tax equity for financing clean energy projects. With renewable energy deployment expected to grow exponentially to meet the country’s decarbonization goals, tax equity alone will not be able to meet the demand.
“Transferability allows us to broaden that further,” he said. “And ultimately, I think we’ll see new structures. We’ll have some hybrid structures where you have a combination of the different [financing] elements and … that’s going to be helpful for all of us to deliver the growth that we’re all talking about.”
Hunter Armistead, CEO of Pattern Energy, also sees transferability as a spur for innovation in project financing.
“Transferability is going to effectively provide a floor or a ceiling value for monetizing your credits,” Armistead said. “I think the biggest issue is, we just need to get on with it.” The current U.S. renewables market is not large enough to “decarbonize the United States or take advantage of the IRA or implement the vision of what we all have to do,” he said.
Do Things Differently
The IRA creates immense opportunities, but it also means pressure on developers to pick up the law’s incentives and deliver, speakers at the Finance Forum agreed.
Shah said some are not taking full advantage of the law’s tax credits, instead writing off certain market segments or demographics, which in turn could hamper the drive for power sector decarbonization.
Less than 4% of U.S. single-family homes have rooftop solar, versus 30% in Australia, he said. Residential and small commercial are “gigawatts that we’ve somehow magically written off … . Are you really telling me that actually putting solar on rooftops is harder than transmission?”
The IRA also has “an enormous amount of incentives around working with tribes,” Shah said. Yet most developers are not pursuing such projects.
“They have the best land in the country for renewable development, the best land that’s not been picked over, that people haven’t secured. … They also have a special ability to jump interconnection queues. … But guess who’s not working with them? This industry.
“There was a notion for a long time that this industry was special, that everything it did was amazing … but that’s no longer the case,” Shah said. “So, I want to make sure that we’re crystal clear that as we move through this energy transition or energy transformation, we’re going to have to do things differently.”
Washington’s second cap-and-trade auction netted the state more than $557 million in revenue after bidders bought all 11.035 million carbon allowances on offer last week, preliminary figures show.
The May 31 auction administered by the state’s Department of Ecology cleared 8.585 million vintage 2023 allowances at a settlement price of $56.10, compared with $48.50 for first auction in February. Both auctions had a floor price of $22.20.
Prices for Washington carbon allowances continue to outpace those in the Western Climate Initiative program that includes California and Quebec, where an allowance currently trades for about $30. In both programs, a single allowance entitles its holder to emit one ton of greenhouse gasses.
“Today’s results from Washington’s second cap-and-invest auction — most notably selling 100% of allowances — continue to signal strong demand for allowances and confidence in the program, bringing significant revenue for the state to reinvest in Washington communities,” Environmental Defense Fund (EDF) analyst Caroline Jones said in a blog post.
The clearing price from last week’s auction exceeded the $51.90 soft cap that triggers use of the cap-and-trade program’s Allowance Price Containment Reserve (APCR), a mechanism designed to rein in the market when allowance prices reach a level considered overly burdensome for emitters.
As a result, the state will hold a special secondary APCR auction on Aug. 9, which carbon market analysis firm cCarbon said could release as many as 9 million additional allowances.
“Critically, these allowances available at the reserve auction are still a part of the overall allowance budget set by Ecology to keep Washington on track to meet its climate targets,” Jones said. “Even though triggering the APCR means that some more allowances are made available at auction, these allowances were budgeted out ahead of time for this exact purpose and do not put Washington over its planned emissions budget.”
The Ecology Department will hold a call June 9 to discuss details of the APCR auction.
Raised Eyebrows
Last week’s auction also included an advance sale of 2.45 million vintage 2026 allowances, which settled at $31.12. The price differential between the two vintages “raises eyebrows,” cCarbon said.
“The price discrepancy between the current and advanced auction is puzzling since both the V2026 and current allowances can be used for compliance at the end of the first compliance period,” cCarbon said. The company speculated that compliance entities — those that need to cover their physical emissions — “are scrambling to purchase allowances and build an internal bank, fearing a substantial rise in the price” in future auctions.
Fifty-four companies, utilities and public institutions bid into last week’s auction, down slightly from 56 participants in the previous one, according to the Ecology Department’s auction summary, which does not disclose the identities of successful bidders.
Compliance entities accounted for the lion’s share of both vintage 2023 (89.88%) and 2026 (73.55%) purchases, with financial entities making up the balance, the summary showed.
This was the state’s second quarterly auction since the cap-and-trade law went into effect in January.
The first auction on Feb. 28 sold all 6,185,222 allowances at $48.50 each to raise almost $300 million for the state’s coffers. In April, the state legislature divided that $300 million into 188 appropriations for solar panel farms, climate planning, pumped storage projects, developing a hydrogen industry, installing solar panels on buildings, constructing infrastructure for electric vehicles, developing hybrids fuel/electric ferries, and tackling other projects.
Revenue from the second auction will be appropriated in the state legislature’s spring 2024 session, which will allocate money from auctions in August and November, plus February 2024. In January, the Ecology Department estimated that the auctions would raise $484 million for fiscal 2023 (July 1, 2023, to June 30, 2024,) and $957 million in fiscal 2024.
The state is on its way to exceed its preliminary estimates.
The Ecology Department will issue a report on Jun. 28 confirming the final figures for the most recent auction.
A Texas appeals court last week reversed a Public Utility Commission’s scarcity-pricing order and remanded it back to the PUC for further proceedings.
The Texas 3rd Court of Appeals ruled June 1 that the commission violated the state’s Administrative Procedure Act’s (APA) rulemaking provisions when it approved an ERCOT protocol change related to pricing during certain extreme events. It also agreed with the lawsuit’s appellants, RWE Renewables Americas and Hereford Wind, that the order constitutes a “competition rule” and that the PUC exceeded its statutory authority with its approval (No. 03-21-00356-CV.)
The PUC declined to comment on what action it would take, saying agency policy is not to comment on pending litigation.
Attorney Katie Coleman, who represents market participants before the PUC, tweeted the ruling “could have implications for other major [revision requests] that were adopted without following the APA.”
At issue is a nodal protocol revision request (NPRR 1081) that the commission approved in July 2021, following its endorsement by the ERCOT board. The appeals court said the commission did not follow the APA in adopting the rule, as required by a legislative change passed during that year’s session.
“From our review, we conclude the commission complied with few, if any, of the requirements of [the] APA,” the court wrote. “The myriad ways in which the commission failed to comply with mandatory APA requirements for adopting or amending a rule cannot be characterized as ‘technical defect[s]’ … its actions in approving NPRR 1081 do not qualify as ‘substantial compliance’ with the APA’s mandatory rulemaking procedures.”
The NPRR modifies the real-time on-line reliability deployment price adder’s calculation so that, when combined with system lambda and the real-time on-line reserve price adder, it is equal to the value of lost load when ERCOT directs firm load shed during a level 3 energy emergency alert. The NPRR results in real-time energy prices clearing at the high system-wide offer cap, which was $9,000/MWh when it was adopted. (The PUC later reduced the cap to $5,000/MWh.)
ERCOT’s Independent Market Monitor filed the proposed change as a “more permanent solution” modifying the reliability deployment’s adder. The PUC told the appeals court that because not all demand can be served with available generation during firm load shed, “wholesale market prices should reflect that extreme scarcity and rise to the high systemwide offer cap.”
RWE and Hereford Wind filed a direct appeal challenging the order’s validity the same month it was issued by the PUC. They asserted the commission does not have the statutory authority when ordering load shed under EEA3 “to replace the price of electricity being set by the market with an inflated, fixed price set by the government.”
ERCOT and the PUC came under heat from the IMM and market for keeping prices at the systemwide cap while bringing the grid back from a near-collapse during the February 2021 winter storm’s frigid temperatures. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)
The commission argued that its order is not a “competition rule,” which the Texas Utilities Code allows to be challenged. However, the court found that NPRR 1081 falls within the APA’s definition of “rule” — “a state agency statement of general applicability” that “implements, interprets, or prescribes law or policy” — and within the term “competition rule,” allowing it to be challenged through the direct-appeal process.
Pointing to its March ruling reversing the PUC’s orders to keep prices at the $9,000/MWh cap during Winter Storm Uri, the court said it was bound by the precedent and held that NPRR1081 “exceeds the commission’s statutory authority and is therefore an invalid rule.” (See Texas Court Reverses PUC’s Uri Market Orders.)
The appeals court also rejected the PUC’s argument that the revision request constitutes a rule because ERCOT’s stakeholder process “substantially complied with the APA’s requirements for agency rulemaking.” The court said the commission failed to meet the APA’s requirements, which include: (1) notice, (2) public participation, and (3) contents of the agency order.
“Because we conclude that the commission has failed to demonstrate that it substantially complied with the APA rulemaking procedures, we hold that NPRR 1081 is, for that separate reason, an invalid rule,” the court said.
Texas Gov. Greg Abbott on Wednesday appointed the Public Utility Commission’s newest member, Kathleen Jackson, interim chair. She will lead the commission until a permanent chair is named, Abbott said.
Jackson was appointed to the commission in August and only confirmed by the Texas Senate in May. She replaces Peter Lake, who stepped down last week and will leave July 1. (See Texas PUC’s Lake Steps Down as Chair.)
“I’m honored and humbled by Governor Abbott’s trust and confidence in me to lead the Public Utility Commission at this very important time for the agency and for Texas,” Jackson said in a statement.
The commission’s other four members were all appointed in 2021. They replaced the previous commissioners, who all resigned after the February 2021 deadly winter storm.
Jackson has led the PUC’s grid-related energy efficiency efforts. She previously served as a board member of the Texas Water Development Board from 2014 to 2022.
