CAISO stakeholders have voiced multiple concerns about a straw proposal to revamp the ISO’s interconnection process, with some cautioning that the timeline to draw up a final plan is too ambitious given the lack of progress on the effort so far.
Stakeholders shared their views at an Oct. 24 meeting of CAISO’s Interconnection Process Enhancements Working Group. Top among their concerns: the ISO’s plan to introduce scoring criteria designed to rank requests to join the grid based on project readiness, as well as a proposed interconnection cap to limit any one developer’s ability to dominate the queue.
Stakeholders expressed frustration over a lack of information on how to implement the scorecard, including uncertainty about in which transmission zones projects would be developed, how open access and equal competition would be upheld and fears that the initiative’s timeline was rushed.
CAISO’s 2022-2023 Transmission Plan, developed in coordination with the California Public Utilities Commission and the California Energy Commission, outlined action items that could help transform the process of connecting new resources to the grid.
Key among the items, also discussed in the ISO’s Interconnection Process Enhancements straw proposal, was the introduction of designated geographic zones that should be prioritized for resource development. The approach would prioritize projects in areas where there are planned capacity additions approved in CAISO’s transmission planning process.
According to the plan, the CPUC would direct load-serving entities (LSEs) to focus energy procurement in those zones, and the ISO proposal will use the scoring criteria to select projects once the resources in a transmission zone reach 150% of the available or planned capacity in that zone. But some stakeholders contend that the straw proposal contains insufficient information regarding the location and details of the zones.
“If we’re going to move forward with this scoring criteria, it needs to be absolutely clear to both the CAISO and developers what locations are in and out of a zone,” Bridget Sparks, interconnection policy manager at AES Clean Energy, said. “If you’re asking developers to invest millions of dollars in land and other development activities, there shouldn’t be any uncertainty on whether or not a certain point on a transmission line is in or out of a zone.”
Cathleen Colbert, director of CAISO market policy at Vistra Corp., echoed that concern, saying that CAISO hadn’t provided enough data transparency on zone locations. She asked the ISO to use the heat maps requested in FERC Order 2023 (RM22-14-000) to provide more clarity, and that they be available in time to inform the next opening of an interconnection cluster window. Sparks also suggested CAISO provide line diagrams to identify zones.
Anish Nand of the Northern California Power Agency asked that CAISO provide line diagrams before the release of the draft final proposal, but Danielle Mills, the ISO’s principal of infrastructure policy development, said the grid operator could not commit given the strict timeline.
Approval, Pushback on Scoring Criteria
In a presentation at the meeting, Southern California Edison pushed back on a few key aspects of the scoring criteria, including the proposal to include demonstrated interest from off-takers as part of the scorecard. Because letters of interest from off-takers are non-binding, SCE proposed instead to include a bonus point system in which LSEs are given a certain number of points based on their load share. This modified process, according to the utility, would allow LSEs to better identify projects that serve their mandated needs, increase the scrutiny of projects and, in turn, decongest the queue.
The utility also proposed adding the procurement of long-lead equipment that could indicate commercial readiness as one of the scoring criteria.
“I think something like the bonus points concept is appropriate,” said Lauren Carr, senior market policy analyst at CalCCA. “It would be a good way to get some more granularity around LSE interest, where there can be a range of points assigned based on how interested an LSE is on a particular project.”
Some independent power producers (IPPs) expressed support for the proposal, but others, such as Terra-Gen LLC, were concerned that the addition of an LSE bonus points system could hinder open access and equal competition.
“We also believe that doing a load-ratio type share would unfairly favor larger LSEs,” said Terra-Gen Director of Energy Market Policy Chris Devon. “This addition of another bonus point criteria for LSE interest would further give more negotiating power to the LSEs and reduce competition.”
Interconnection Caps
Another key element in the straw proposal was the introduction of an interconnection cap. CAISO proposed that each developer be limited to only submitting projects that would take up 25% of available transmission across the footprint to address market power and domination of the queue by a small group of developers.
However, in a presentation to the working group, AES highlighted that the ISO provided no evidence or data to prove that market power is a current issue.
AES also raised concern over an interconnection cap leading to discriminatory treatment between IPPs and utilities, since non-CPUC jurisdictional utilities are automatically accepted into the queue without capping and included in the studied 150% of available transmission. On the flip side, IPPs would be subject to both the developer cap and the scoring criteria within the studied 150% of available transmission.
Strict Timeline
The draft final proposal is set for Nov. 15, leaving some stakeholders frustrated by the lack of solid progress with the initiative despite the strict timeline in which to move forward.
“It seems like CAISO isn’t really giving enough time for the stakeholder process to work and [is] so wedded to a specific end timeline, and you’re considering such a radical change in the way that the interconnection process is done,” Sparks said. “We would rather get this right the first time than to rush through a process that has a lot of unintended consequences or hasn’t been thoroughly thought through.”
CAISO acknowledged the frustration.
“I know the pace is exhausting,” Mills said. “We’re just really trying to push it as fast as we can for you, not because we don’t care what you think.”
Several Midwestern states on opposite ends of the political spectrum have taken steps this year signaling receptiveness to small modular reactor (SMR) development while a factory in Ohio has begun producing uranium tailored to the smaller plants.
Most recently, Maryland-based Centrus Energy opened a uranium enrichment plant this month in Piketon, Ohio, to produce high-assay, low-enriched uranium (HALEU).
The Department of Energy awarded Centrus a competitive, cost-shared contract in 2022. The company was required to begin production of HALEU by the end of 2023 under the agreement. HALEU is tailored for types of SMRs and contains between 5% and 20% fissile uranium, while large nuclear reactors use fuel with up to 5% fissile uranium.
“We hope that this demonstration cascade will soon be joined by thousands of additional centrifuges right here in Piketon to produce the HALEU needed to fuel the next generation of advanced reactors, low-enriched uranium to sustain the existing fleet of reactors and the enriched uranium needed to sustain our nuclear deterrent for generations to come. This is how the United States can recover its lost nuclear independence,” Centrus CEO Daniel Poneman said in a press release.
Deputy Secretary of Energy David Turk said that for the first time ever, “an American company is producing HALEU on American soil.”
The 16-centrifuge cascade produces only about 900 kilograms of HALEU per year, but Centrus said it could expand the Ohio operation to 120 centrifuge machines if it secures enough offtake commitments and funding.
Centrus has TerraPower and Oklo Inc. lined up to execute fuel supply contracts; both are trying to get their own SMR designs certified with the Nuclear Regulatory Commission (NRC). Oklo plans to build two of its liquid metal-cooled, metal-fueled fast reactors in Piketon to supply energy for Centrus and the surrounding area. The plants will be situated on land owned by the Southern Ohio Diversification Initiative, a community reuse organization. The plans are part of the Department of Energy’s push to re-industrialize the area around the Portsmouth Gaseous Diffusion Plant.
Elsewhere in Midwestern states, utilities were in the early stages of development while bills meant to assist SMR progress were drafted.
Early this year, a bipartisan group of Minnesota Senate lawmakers backed a bill that would direct the state’s Department of Commerce to conduct a study exploring the feasibility of SMRs (SF 1171). The Minnesota House and Senate also mulled allowing the Minnesota Public Utilities Commission to issue certificates of need to build new nuclear plants less than 300 MW in capacity (SF 2824). Both bills have been referred to the Climate and Energy Finance and Policy Committee.
Minnesota’s nuclear moratorium is nearly three decades old, but some environmental organizations are rethinking their stance on new nuclear as a zero-carbon, baseload backstop to renewable power. Minnesota law mandates that the state reach 100% clean energy by 2040.
In general, SMRs are designed to yield anywhere from 50 to 300 MWs of electricity, as opposed to the typical 1 GW from traditional, large-scale reactors. They can be built indoors and then shipped to sites to be assembled. The U.S. doesn’t have any SMRs in operation.
Meanwhile, Xcel Energy is exploring whether it wants to become operator of a NuScale VOYGR SMR under development at the Idaho National Laboratory. That plant isn’t expected to be commercially operational until 2030.
NuScale’s VOYGR is the first SMR design to win certification from the NRC.
Dairyland Power Cooperative, based in western Wisconsin, has partnered with NuScale Power to evaluate use of small-scale nuclear reactors in Wisconsin.
NuScale also is planning to build a dozen 77-MW pressurized water SMRs for Ohio and Pennsylvania in order to energize two Standard Power data centers by 2029.
If passed, Michigan’s House Bill 4753 would create tax credits of 15% for qualified research and development expenses related to the “design, development or improvement” of SMRs and activities that will hasten them to market. The bill was referred to the House Committee on Tax Policy.
“Per capita, Michigan employs the highest number of engineers in the country,” said state Rep. Pauline Wendzel (R), who introduced the bill. “We have the talent, and we have the capability. Now we need to put our foot on the gas to develop this safe, clean and reliable form of energy.”
Efforts to resurrect the Palisades nuclear power station in southwest Michigan also involve SMRs. Last month, Wolverine Power Co-op signed an agreement with owner Holtec International to buy power, hoping Palisades reopens in 2025. That agreement includes a contract expansion provision to include up to two small modular reactors onsite.
Last year, Indiana Gov. Eric Holcomb (R) signed S271 into law, which mandated that the Indiana Utility Regulatory Commission work with the state’s Department of Environmental Management to devise rules around granting of certificates of public convenience for the construction, purchase or lease of SMRs. Those rules were adopted at the end of June.
Purdue University and Duke Energy have recommended that Indiana consider public funding of studies dedicated to new nuclear and issuing state tax credits for advanced nuclear technology. Those recommendations were in an interim report of a joint study issued midyear.
Purdue and Duke are exploring the feasibility of using SMRs to meet the energy needs of Purdue’s main campus.
Finally, the Missouri legislature this year weighed HB 225, which would have allowed utilities to file with FERC to raise rates to pay for SMRs. The bill, which cleared the house but failed to gain traction in the Senate after a public hearing, would have modified the state’s 1976 law that prevents utilities from raising rates to pay for the construction of new projects.
Whether SMRs are economical enough to compete in the market remains untested. This month, researchers published a cost analysis of SMRs in the peer-reviewed international journal Energy. They analyzed the levelized cost of electricity among 19 SMR designs and said the costs to generate electricity from SMRs seems to be “non-competitive when compared to current costs for generating electricity from renewable energy sources,” even when accounting for system integration costs that double renewable energy’s price tag.
Researchers also concluded that manufacturers’ cost estimates for SMRs “are mostly too optimistic compared to production theory” and that a Monte Carlo simulation showed “that no concept is profitable or competitive.”
Xcel Energy management told financial analysts last week that it has made “significant progress” on what it calls “industry-leading clean energy transition plans.”
“Given that the regions where we serve customers are the most resource rich in wind and solar,” CEO Bob Frenzel said during the company’s third-quarter earnings call Friday, “we believe that we can lead this clean energy transition for our customers more cost-effectively than almost any other company.”
The Minneapolis-headquartered company is relying on its Steel for Fuel 2.0 program, which builds on its plan to swap fossil generation for fuel-free wind and solar that the company rolled out seven years ago. Xcel has increased its capital investment plan through 2028 to $34 billion, with another $10 billion potentially necessary after state regulatory approval of clean energy projects. (See Earnings Up, Xcel Touts ‘Steel-for-Fuel’ Strategy.)
In September, Xcel’s Colorado subsidiary filed what it called the largest clean energy transition effort in the state’s history. The plan includes shutting down its remaining Colorado coal plants with approximately 6.5 GW of renewable energy and battery storage, doubling the state’s renewables, and about 600 MW of natural gas resources to ensure reliability during times of low wind or solar conditions.
Including about $3 billion in required transmission investments, Xcel will invest nearly $11 billion in the state. The company expects Colorado’s regulatory commission to rule on the proposal early next year.
In Minnesota, Xcel has received regulatory approval to add 250 MW of new generation at its Sherco Solar project, bringing the facility’s capacity to over 700 MW. The project will use existing interconnections from the Sherco coal plant, which is retiring by 2030.
Its Southwestern Public Service Co. (SPS) subsidiary filed a resource plan in New Mexico earlier this month that lays out a need for between 5 GW and 10 GW of new generation by the end of this decade. SPS already has proposed 418 MW of company-owned solar and battery projects that are pending commission approval.
“We have the potential to deploy [15 GW] to [20 GW] of new clean generation on our systems by 2030, dramatically lowering our emissions profile,” Frenzel said.
The company said it will appeal a Colorado district court decision Wednesday that awarded CORE Energy $26.5 million in damages for a breach of contract and mismanagement of Xcel’s Comanche 3 unit. CORE owns a 25% share of the plant, which has averaged 91 days of unplanned shutdowns a year since the unit went online in 2010.
“We have a strong legal basis for challenging that $26 million award,” Xcel CFO Brian Van Abel said.
The company reported earnings of $656 million ($1.19/share), compared with $649 million ($1.18/share) for the same period in 2022. The results reflect the effect of increased recovery from infrastructure investments, higher sales and demand, and lower operating and maintenance expenses, partially offset by increased interest charges and depreciation, the company said.
Its share price lost 2.4% Friday, closing down $1.46 at $58.31.
COLLEGE PARK, Md. — Maryland has already cut its greenhouse gas emissions to 30% below 2006 levels, putting it halfway to reaching the 2031 goal of a 60% reduction set in the 2022 Climate Solutions Now Act (CSNA), Secretary of the Environment Serena McIlwain told the recent Maryland Clean Energy Summit.
Implementing existing state policies will cut emissions 55% by 2031, which means “we really only need 5% to take us to the finish line,” an achievement worth celebrating, McIlwain said, leading off a panel of state officials at the event sponsored by the Maryland Clean Energy Center. Still, she warned, getting to 60% “will not be easy for any of us.”
The law also sets a 2045 target for Maryland to slash its greenhouse gas emissions to net zero. “What this really means is we have to create new policies, and new policy action may not be welcomed by everyone, because [the policies] are bold, they are specific; they will be specific for sectors and for this entire economy,” she said.
Former state Sen. Paul Pinsky (D), who sponsored the CSNA, put it more bluntly.
“We have to shift from fossil fuels to clean energy. Period. End of discussion, end of paragraph,” said Pinsky, now director of the Maryland Energy Administration. “We can’t hang onto the old ways of doing business, we just can’t. It won’t get us where we need to be.”
According to McIlwain, Pinsky and other speakers at the day-long summit, the CSNA emission-reduction goals — coupled with Democratic Gov. Wes Moore’s 2035 target for a decarbonized electric system — are among the most ambitious in the nation. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)
As reported at the conference, the CSNA and other recently passed laws have triggered a range of model projects and programs. The state’s largest investor-owned utility, Baltimore Gas and Electric (BGE), is preparing for a November ribbon-cutting at a new electric-vehicle (EV) fast-charging station in Johnston Square, a low-income, historically African American neighborhood in Baltimore.
One of the new laws passed this year (HB 908) made Maryland’s pilot community solar program permanent. Soon after, Solar Landscape, a New Jersey-based solar installer, announced a partnership with Public Storage to put community solar installations on the roofs of 57 of the company’s storage facilities throughout the state.
Solar Landscape will focus on signing up households in low-income communities, according to Elizabeth McKeever, the company’s general counsel. The first projects are currently under construction.
The state is also in the process of finalizing regulations for building energy performance standards for commercial buildings of 35,000 square feet or more, another provision in the CSNA. The proposed regulations could go into effect in 2025, when covered buildings will have to benchmark and start reducing their energy use, said Mark Stewart, climate change program manager at the Maryland Department of the Environment (MDE).
The law sets a 2030 target for a 20% emissions reduction from 2025 levels and a 2040 target for net zero.
But attendees also heard about some of the tough obstacles ahead.
State Sen. Brian Feldman (D), chair of the state Senate Committee on Education, Energy and the Environment, reported on a recent meeting with officials from PJM, who warned of rolling blackouts in the Baltimore region if the Brandon Shores coal-fired generation plant in Anne Arundel County is closed in 2025, as is currently planned. The grid operator said it would need another three years to complete up to $800 million in grid upgrades to ensure system reliability when the plant is shut down.
“This is where things get a little more complicated,” Feldman said. “Moving forward, in 2024 and beyond, we’re going to have some very challenging policy calls.”
Maryland’s natural gas utilities could also slow progress toward the state’s emission reduction goals, with their plans to continue investing in new infrastructure at current levels, despite projections that demand for the fuel will taper as more homes and businesses electrify, said People’s Counsel David Lapp.
He foresees costs for recovering those investments shifting to lower-income customers through higher rates as more affluent households go electric.
The Right Policies
The CSNA required the MDE to produce a plan to implement the law, with an initial draft due in June of this year, to be followed by a final report sent to the governor and state legislature by the end of December.
Authored by the Center for Global Sustainability at the University of Maryland College Park, the draft plan laid out a range of policy options, some very aggressive, without making any recommendations. The report’s potential pathways included a 500% increase in solar deployments, the launch of an in-state, economywide cap-and-invest program and shifting all the electricity Maryland imports to 100% clean energy. (See Maryland Climate Report Lays out Pathways to Achieving Goals.)
Looking ahead, McIlwain was mum on specifics, but she hinted at the general direction the final report would take.
“It’s going to lay out a clear strategy that focuses on creating new statewide policies around transportation and buildings, and we’re going to explore, as we’re doing now, renewable energy pathways as well,” she said. “We’re going to focus on the right policies because when we do that, it’s going to allow us to accelerate, and when you accelerate you push the markets to respond.”
McIlwain also stressed the health and economic benefits of Maryland’s emission reduction goals. Lower emissions could result in a reduction of respiratory illnesses in the state, which could provide $591 million in health savings by 2030, she said.
The clean energy incentives and tax credits in the Inflation Reduction Act are another driver for Maryland to move fast on its climate policies and programs, she said: “It makes decarbonization way more affordable.”
Pinsky said decarbonization has to start with energy efficiency, electrification and renewables, and encouraged companies to leverage state and federal dollars to grow their markets. “We have to put our creative juices and your dollars to invest when you see a good idea that can be scaled up and has implications not just for the state of Maryland but for the nation.”
But, like McIlwain, he warned of opposition — “people who want to take potshots” at the state’s clean energy goals — and called for broad business and social support.
“We need the public and the advocacy community … the business community to get behind [this] and say, ‘There’s no wavering.’ … We’re not going to make this tentative. We’re going to implement this damn thing if we’re going to move our state forward,” Pinsky said.
Business Opportunities
Business leaders at the conference talked about both the economic opportunities and risks in decarbonization.
For A.O. Smith, a manufacturer of water heaters, the potential market is enormous, according to Josh Greene, the company’s vice president for government affairs. Of the 10.2 million units of water heating equipment shipped in the U.S. in 2022, only 145,000 were heat pump water heaters, he said.
But while heat pumps are the most efficient technology for water heating on the market, a range of factors can affect adoption, such as a state’s decarbonization goals and regulations, local utility distribution systems, consumer awareness and, of course, cost.
About 25,000 water heaters are either repaired or replaced every day in the U.S., Greene said. After one cold shower, “when you think about that turnover and what consumers are looking at, are you going to wait a few days” to get a heat pump water heater, he asked.
Overcoming such barriers to market growth also means educating contractors to stock and install heat pump water heaters, Greene said. A.O. Smith is training 2,000 contractors a week on heat pump installation, he said.
The opportunities for utilities are also significant. For example, EV programs can simultaneously support state and local decarbonization efforts, increase electricity demand and allow for new capital investments — in the form of EV chargers — that can be included in their rate base.
Alexander Núñez, BGE vice president of governmental, regulatory and external affairs, framed the utility’s EV programs as part of its efforts to “leave no one behind.” Using federal funds, BGE has partnered with ride-sharing company Lyft to help develop a fleet of 100 EVs that Lyft drivers in Baltimore can rent at discounted rates.
The first 25 EVs in the Lyft fleet were Kia Niros, which “have been on the road for just over a year, and already they have produced an aggregate of more than one million miles,” Núñez said. “These are one million miles of new people getting into an EV, experiencing … the comfort, the quiet, getting them a chance to consider whether that’s going to be their next car.”
He also noted that about one half of the Lyft drivers renting the EVs are “diverse,” and one half of the rides are either starting or ending in the city’s disadvantaged neighborhoods. The rest of the fleet will be unveiled at the ribbon-cutting for the Johnston Square EV chargers in November, he said.
But Núñez said that leaving no one behind also means maintaining service for the utility’s 700,000 natural gas customers. BGE has been working to replace gas equipment, he said, including more than 350 miles of main distribution lines, with newer equipment that helped the company lower its greenhouse gas emissions by 27% by the end of 2022.
The Coming Gas Cost Shift
Lapp and the Office of the People’s Council (OPC) have countered arguments of BGE and other utilities in proceedings before the Maryland Public Service Commission.
While acknowledging the role utilities play in providing critical services to all Maryland residents, Lapp also stressed that they are monopolies making decisions that primarily benefit the interests of their investors.
“It is the state’s job, through the legislature and the Public Service Commission, to regulate monopolies,” he said.
If Maryland gas utilities continue to invest in distribution infrastructure at their current rates, the cost of those investments could triple by 2050, from just over $1 billion to $3.1 billion, an OPC analysis projects.
Lapp said the concern is that customers will leave the gas system as electrification becomes more economic “just on a pure technology basis.”
“Climate policy will also drive further customers [off the system] for incentives like the IRA and other policies … increasing [natural gas] rates because those revenues have to be recovered from fewer and fewer sales and fewer customers,” he said.
While Lapp does not oppose all gas infrastructure spending, he said “we don’t need to replace entirely the existing systems we have today.” But even utilities that acknowledge that gas use is going to decline continue to argue for maintaining current investment levels to provide backup, he said.
Others claim that they are “not aware of any heat pumps currently available that would require no backup heating system,” Lapp said.
The OPC currently has a petition before the Public Service Commission asking it to open a proceeding aimed at ensuring gas utility planning is based on the state’s climate policies and a future of diminished gas use.
At the same time, as Feldman said, working with PJM to balance Maryland’s ambitious climate goals with grid reliability also will be critical.
Talen Energy had originally planned to convert its coal-fired Brandon Shores plant to natural gas, but found that fuel switching would not pencil out and set a closure date of June 2025. According to Jeff Shields, PJM’s media relations manager, the plant closure could result in “voltage collapse and thermal overloads on the transmission system, particularly in the greater Baltimore area.”
The issue underlines the extent to which Maryland’s dependence on imported power will affect its decarbonization efforts. A Brandon Shores closure could mean the Baltimore region will need to import 80% of its power from outside the state, Shields said.
To ensure adequate power imports, PJM has planned for system upgrades as part of its Regional Transmission Expansion Plan and is in talks with Talen to keep Brandon Shores online with a special contract, called a reliability-must-run agreement. (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.)
Speaking with NetZero Insider at the conference, Pinsky said Maryland will need to get more aggressive on transmission, but acknowledged that the state will have to figure out how to build the system it needs without putting all the costs on its ratepayers. “I think we’ve got to look at a period of years to do that,” he said.
U.S. Sen. Chris Van Hollen (D-Md.) raised concerns about the challenges states face in applying for the $8.5 billion in federal dollars available from the IRA for home energy efficiency upgrades, one of the law’s provisions that he worked on and supported.
“It’s our goal to make sure these [funds] can be provided to states in order that they can quickly get them out the door and into the hands of the people that are doing this work,” Van Hollen said. The current application process may be making that more difficult, he said.
RENSSELAER, N.Y. — NYISO on Thursday said a market software problem identified this year in the day-ahead and real-time ancillary services markets had a negligible financial impact and did not result in any market manipulation.
In an update to the Installed Capacity/Market Issues Working Group, NYISO staff disclosed that an issue with the automated mitigation process (AMP), a mechanism that identifies and mitigates instances of market abuse to keep conditions competitive, led to a mere $893 of missed real-time mitigation over two hours and $41,729 in day-ahead mitigation over three days.
NYISO determined that the issue did not meet the threshold to be considered a significant market problem because the issue was quickly resolved and no unfair market behaviors were observed.
The AMP validates and adjusts bids in the day-ahead market before settlement and conducts ongoing monitoring in the real-time market to ensure that market participants are not manipulating the market for their own gain. NYISO found that it was not working properly July 6 because of an April software deployment, which prevented the AMP from both effectively executing its mitigation procedures and evaluating start-up or minimum generation references correctly.
In response, NYISO issued a notice of a potential market problem July 11, initiating a confidential investigation in collaboration with its Market Monitoring Unit and FERC to determine whether the issue significantly disrupted the market or if any market participants were gaming it. (See NYISO Discovers Market Problem, Opens Confidential Investigation.) By July 18, the software issues were resolved for the day-ahead market.
Further investigation showed that the conditions for the AMP to “trigger” never materialized during the period it was malfunctioning, indicating that the impact was minimal. ISO staff noted how AMP activates infrequently to adjust bid offers, mitigating less than 0.5% of the unit hours throughout the previous year.
Mark Younger, president of Hudson Energy Economics, encapsulated stakeholders’ reaction to the $893 cost in the real-time market, exclaiming sarcastically, “That is outrageous!”
The U.S. Department of Energy on Wednesday released a draft of its “Transmission System Interconnection Roadmap,” which offers ways to improve the backlogged process of connecting new generation to the grid.
The draft comes after meetings with more than 2,000 individuals from 350 different organizations, the department said. DOE is hopeful that even more comment on the draft so it can come out with a final report, Becca Jones-Albertus, director of the department’s Solar Energy Technologies Office, said in an interview Thursday. DOE is working on another report on interconnection issues at the distribution level.
“We’re focused at DOE at how we can enable achievement of the president’s goal to decarbonize the electric grid by 2035,” Jones-Albertus said. “There are a number of big challenges we need to tackle to get there, and interconnection is one of them.”
Interconnection queues have about 2,000 GW of wind, solar and batteries in them; if they were all somehow built, it would be nearly enough to reach that decarbonization goal, Jones-Albertus said. Only about 20% or so of projects get built, but the fact that developers sit in them for an average of five years shows they are clogged and need reforms, she said.
DOE was working on the roadmap at the same time FERC worked on Order 2023, which covers about a quarter of its recommendations, according to the draft. The commission’s still-pending Notice of Proposed Rulemaking on transmission planning includes other proposals in the roadmap.
“Though this roadmap contains some solutions that relate to Order 2023, it also introduces additional ideas that support longer-term interconnection process evolution,” the draft says. “Such an approach is important not only to facilitate industry-wide discourse that builds upon Order 2023 but also to maintain usefulness for transmission providers that are not FERC jurisdictional.”
A major reason queues are so overstuffed is the transition to clean energy, which has led to a spike in requests. The report says that “queue volumes are likely to be large and potentially volatile for the foreseeable future.”
When FERC issued Order 2003 20 years ago, it did not contemplate the extent to which resource developers would use interconnection processes to obtain cost and siting information, the report says.
“Because the interconnection process provides accurate, binding information on interconnection costs and operational requirements, resource developers often use the interconnection process to determine ultimate project viability,” the report says. “Additionally, due to long queue wait times, resource developers may also submit interconnection requests to maintain a place in line, to be able to turn around projects more rapidly if they can find a buyer.”
Those “speculative projects” have contributed to the larger queues now; some of DOE’s recommended improvements are aimed at limiting them going forward.
“We really believe it’s possible to get to better processes and doing that by improving the data … [and] having more information available to developers about where to site projects,” Jones-Albertus said.
Order 2023’s requirement for transmission planners to offer heat maps should cut back on the use of speculative projects to find cheap spots to plug into the grid, she added. DOE is also focused on bringing new information technology solutions on the queue, upskilling the workforce and tackling the ever-thorny issue of cost allocation.
“By addressing all of these, I believe we can get to much better interconnection processes, where we can get timelines that are down from averages of five years to less than 18 months,” Jones-Albertus said. “We can have higher completion rates, lower cost uncertainty and better system reliability.”
CAISO and MISO have both proposed strategies that would “ration” interconnection capacity to reduce their queue volumes. CAISO does it by prioritizing interconnection in zones that have available capacity, or resource-rich areas, while MISO would limit interconnection requests to its annual peak demand.
“Administrative rationing may be a short-term strategy for temporarily clearing backlogs, but it would likely be inconsistent with open access and competition policies and may thus be more of a short-term, emergency solution rather than a longer-term one,” the report says.
Another reason to speed up the queues is that demand has started to grow for the first time in a decade in many regions. That is expected to increase with electrification efforts, while many traditional generators are retiring.
“Certainly having shorter queue timelines, higher completion rates [and] lower costs will help that additional capacity be built … in a predictable manner so that grid operators can count on when that generation capacity is going to be there for resource adequacy,” Jones-Albertus said. “I think it is a challenge now that it is hard to predict when some of these plants will come online, in part because of the lengthy interconnection process timelines.”
Vineyard Wind 1 is on track to start generating power by the end of this year and achieve commercial operation by the end of 2024, Avangrid told investors in its third-quarter earnings call for 2023.
The 806-MW project’s construction is about 60% complete, with the offshore substation, 15 array cables, 25 monopiles and two turbines already installed, Avangrid CEO Pedro Azagra said.
Vineyard Wind is competing with New York’s South Fork Wind to be the first utility-scale offshore wind project to begin operations in the U.S.
“The lessons learned will be invaluable as we continue developing this project and others in the U.S,” Azagra said.
On Oct. 25, the company announced a $1.2 billion tax equity transaction for the Vineyard Wind 1 project with J.P. Morgan Chase, Bank of America and Wells Fargo. The financing uses tax credits from the Inflation Reduction Act (IRA), and marks “the largest single asset tax equity financing and the first for a commercial scale offshore wind project,” the company said.
“The IRA is bringing tremendous opportunities to the industry,” Azagra said, adding that the act is essential to the company’s plan to repower up to 4.6 GW of renewable assets by 2032, with the goal of increasing production by about 30%. “Repowering does not require full development and permitting, allowing the projects to reach completion much faster.”
Azagra also touted the successful termination of the Commonwealth Wind and Park City Wind power purchase agreements.
“By terminating these contracts, we have improved the economics of our offshore wind projects, and avoided billions in write-offs at minimum costs,” he said. “Now we have two highly valuable leases ready to leverage, and experience as part of Iberdrola Group developing, financing and constructing offshore projects like Vineyard Wind 1.”
“We’re not going to put in danger the financial health of the company,” Azagra said. “We’re not going to be in the race of growth for megawatts, we’re in the race of making money.”
Azagra also addressed what he called the “challenging regulatory environment in Connecticut.” Earlier this year, the state’s Public Utilities Regulatory Authority (PURA) denied a request from Avangrid subsidiary United Illuminating for an 8% rate increase over three years. In response, United Illuminating has filed an appeal with the New Britain Superior Court.
PURA’s decision would prevent the company from recovering “reasonably incurred costs, and [earning] a fair return on enough capital,” Azagra said. He added that this would “hinder [Avangrid’s] ability to invest in the grid to improve the storm resiliency and reliability and would slow down the state’s progress on its clean energy goals.”
The Energy and Policy Institute (EPI), a utility watchdog group, has alleged the company was behind a pressure campaign that coordinated employees and charitable organizations to oppose a draft version of PURA’s decision. EPI found the comments contained similar or identical language that it traced back to a United Illuminating lobbyist.
Solicitor General Elizabeth Prelogar has urged the Supreme Court to dismiss a petition to review a 2022 appeals court ruling that found Texas’ right-of-first-refusal law violates the Constitution’s dormant Commerce Clause.
Prelogar filed a brief with the high court Oct. 23 asking it to deny Texas’ request for a writ of certiorari, a formal request to review a lower court’s judgment against the petitioning party (No. 22-601).
At issue is the 5th Circuit Court of Appeals’ ruling last year that the Texas law (Senate Bill 1938) giving incumbent transmission companies the right of first refusal (ROFR) to build new power lines within the state is unconstitutional. Texas, with former Public Utility Commission Chair Peter Lake as the lead petitioner, requested the review in December. (See Texas Petitions SCOTUS to Review ROFR Ruling.)
“The court of appeals correctly determined that SB 1938 discriminates against interstate commerce by prohibiting any company without an existing in-state presence from competing in the market for the construction and operation of electric transmission facilities that would be part of the interstate transmission grid,” Prelogar said in her filing.
She said the Texas law “discriminates on its face against interstate commerce” and that the state’s “contrary arguments lack merit.” Prelogar also noted that FERCOrder 2023, which would overhaul transmission planning, would render moot a review of the 5th Circuit decision.
“If FERC were to adopt the proposed rule (or some alternative) while this case was pending before the court, that development might require supplemental briefing or otherwise complicate this court’s consideration,” she wrote.
Consumer advocacy group Electricity Transmission Competition Coalition welcomed the solicitor general’s filing.
“ROFR laws are not just unaffordable, they are unconstitutional,” the organization’s chair, Paul Cicio, said in an emailed statement. “Texas’ ROFR law was unconstitutional from the outset, and this was affirmed by the [appeals court]. Electricity transmission competition benefits consumers in the form of lower electricity prices; the filing of the United States is a welcome addition to the cause of lower electricity prices.”
Chris Reeder, a partner with Husch Blackwell in Austin, told RTO Insider that the Supreme Court’s request for the solicitor general to provide its opinion “indicates the court views the legal issues as having significant constitutional implications on which the government should weigh in.”
The opinion also means briefing on Texas’ request has been completed, he said. The justices will vote on whether to grant review and, if they do, the case will be set for argument and additional briefing requested.
“If it declines review, then the Supreme Court proceeding is over as a practical matter,” Reeder said. “The 5th Circuit’s ruling would become the ‘law of the case.’”
Texas could seek a rehearing of the denial, but those rehearing requests are almost never granted, Reeder said.
NextEra Energy brought an appeal to the 5th Circuit after the U.S. District Court for Western Texas rejected the utility’s challenge of SB 1938. The district court ruled the legislation didn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.”
At the time, NextEra had been awarded a pair of competitive projects by MISO and SPP in Texas’ non-ERCOT regions. Both projects have since been cancelled, but NextEra has said it intends to pursue other projects in Texas.
The NYISO Management Committee recommended Oct. 25 that the Board of Directors approve the ISO’s proposed $194.8 million budget for next year, a $4.8 million (2.5%) increase. Because the spending will be allocated across a forecast throughput of 152.1 million MWh, a 2.9% drop from 2023, the Rate Schedule 1 charge/MWh will increase to $1.281/MWh, a 5.6% increase.
The spending plan adds 19 new positions, primarily in the planning and operations units. Other sources of the spending increase are hikes in consulting fees and staff salaries, which are proposed to increase by $7.1 million and $7.4 million, respectively. Much of the increase is offset by the $10 million increase in proceeds from debt.
The ISO said growth drivers, including new large loads, electric vehicles, heating electrification and economic growth, would be more than offset by growth in energy efficiency and behind-the-meter solar.
At the September MC meeting, some stakeholders were taken aback by the proposed staffing increases. (See “Draft Budget,” Emilie Nelson Named NYISO COO, Replacing Rick Gonzales.) Alan Ackerman, director of NYISO regulatory affairs at Customized Energy Solutions, however, justified the ISO’s draft budget, saying, “I think this does a great job of balancing the costs against the long list of items that need to get done next year.”
The spending plan was approved unanimously by the MC on Wednesday. The board is expected to vote on the budget Nov. 14.
NYISO/PJM Joint Operating Agreement
The MC recommended that the board approve proposed revisions to the ISO’s joint operating agreement with PJM, which governs coordination and data collection between the two grid operators.
The changes would migrate a list of interconnection tie facilities between NYISO and PJM from the JOA onto the web, add language clarifying that each operator adheres to its own procedures when developing and maintaining interconnection reliability operating limits (IROL), and make clerical edits to facilitate cooperation in the resource adequacy and transmission planning areas. The IROL are the limits the ISO and PJM develop to ensure steady state and transient performance on the grid, such as voltage stability and transfer capability.
Peer comparison | NYISO
Howard Fromer, who represents Bayonne Energy Center, asked about PJM’s status on this project and how the proposals would be filed with FERC.
Cameron McPherson, an associate market analyst with NYISO, responded, “we worked jointly with PJM to develop these revisions and they are in agreement on what we’re submitting.” He added, “[PJM] did present this information to their stakeholders earlier this month and did not receive any comments or questions.”
These proposals were approved by the Business Issues Committee in September and are projected to be implemented in the first quarter of 2024, assuming approval by the ISO’s board and FERC. (See “NYISO/PJM Joint Operating Agreement,” NYISO Business Issues Committee Briefs: Sept. 14, 2023.)
Interconnection & Transmission
The MC recommended that the board approve tariff revisions intended to improve the coordination between NYISO’s interconnection and transmission expansion studies.
The revisions would revise the criteria for including transmission projects in study assumptions, better capture generators outside NYISO’s interconnection procedures for the purposes of future system planning and improve coordination among transmission projects moving through the ISO’s interconnection processes.
The changes were recommended by the Operating Committee late last year, but the ISO delayed presenting them to the MC while it waited for FERC to rule on proposals by transmission owners concerning their right of first refusal for public policy transmission upgrades, which the commission approved in April of this year. (See “Interconnection & Transmission,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The board will vote on the revisions in November. Assuming they are approved, NYISO will request its proposals become effective 60 days from when they are filed with FERC.
September Operations
NYISO’s Emilie Nelson delivered her first monthly market and operations reports as chief operating officer, telling the MC that September experienced the summer’s highest peak load (30,206 MW) and that year-to-date energy prices were down 57% compared to last year, declining from $92.27/MWh to $40.06/MWh due to continued decreases in gas prices.
The peak load Sept. 6 happened during a multiday heat wave in which temperatures exceeded 90 degrees Fahrenheit. NYISO examined how this summer’s extreme weather events impacted grid operations and found that they currently pose little threat but will increasingly become a problem to the ISO’s operations should the pace of fossil fuel retirements continue to outpace the addition of renewable generators. (See “Summer Operations,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The ISO also added 20 MW of energy storage and 60 MW of behind-the-meter solar resources in September.
MC Election, Promotions
The MC voted to elect Glenn Haake, vice president of regulatory affairs at Invenergy, as new vice chair of the MC.
Haake reminded the MC that he was previously elected to be vice chair of the MC back in 2011, saying, “I’m excited at the prospect of being able to finish what I started a little more than a decade ago.”
He will work with MC Chair Julia Popova, NRG Energy’s manager of regulatory affairs, in his new role next year.
Nelson also told the MC that Shaun Johnson has been promoted to the ISO’s director of market design and Joshua Boles promoted to director of market mitigation and analysis.
CenterPoint Energy Thursday announced a leadership change atop the organization, with COO Jason Wells replacing the retiring David Lesar as CEO.
Wells will become CenterPoint’s CEO on Jan. 5. Lesar will work closely with his successor in the meantime to ensure a seamless transition, the Houston-based company said.
“I have full confidence that Jason is the right person to take the helm,” Lesar told financial analysts during the company’s third-quarter earnings conference call. “Now is the right time to advance this transition as our very strong third-quarter results demonstrate. We have great momentum and a solid foundation in place. Making this change at the beginning of 2024 allows Jason and the team to hit the ground running.”
Lesar, a former CEO with Haliburton, was brought out of retirement in 2020 to provide leadership after the Texas Public Utility Commission reduced a $161 million rate case settlement to $13 million. Scott Prochazka resigned as CEO shortly after the decision. (See New CenterPoint CEO Promises to ‘Simplify the Story.’)
Wells joined CenterPoint as its CFO in 2020, shortly after Lesar was appointed CEO. The two have worked together to “reshape and launch our utility-focused strategy,” he said.
Wells previously spent 13 years with PG&E Corp., where he worked his way up the ladder before eventually serving as CFO. He holds bachelor’s and master’s degrees in accounting from the University of Florida.
He thanked Lesar for his “tireless” leadership, mentorship and friendship and said he has “incredibly big shoes to fill.”
CenterPoint reported earnings of $256 million ($0.40/diluted share), compared to $189 million ($0.30/diluted share) for the same period a year ago. The company said the results primarily were driven by growth, regulatory recovery and favorable weather.
It was the 14th straight quarter CenterPoint has met or exceeded expectations, Lesar said. Zacks Investment Research had projected earnings of $0.37/share.
Commiserating with CenterPoint’s executive team over the Houston Astros’ recent elimination from the MLB playoffs, one analyst said, “You can win every year in the utility business, but you can’t in baseball.”
“So true,” Lesar responded. He closed the conference call by saying, “Just stick with us, because the best is yet to come.”
CenterPoint’s share price closed at $27.60 Thursday, a gain of 13 cents for the day.
