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November 14, 2024

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BOEM Announces Gulf of Maine Offshore Wind Lease Sale

The U.S. Bureau of Ocean Energy Management announced Sept. 16 it will conduct an offshore wind energy lease sale on Oct. 29 for eight areas on the Outer Continental Shelf in the Gulf of Maine.

The gulf stretches from Cape Cod to Nova Scotia and the leases include areas off Massachusetts near Boston, New Hampshire and Maine. Unlike the rest of the East Coast, the Gulf of Maine has waters that are too deep for traditional offshore wind, so any projects would have to use floating turbines.

The announcement comes less than a month after U.S. Department of the Interior and BOEM announced a “research lease” that will allow the state of Maine build up to 12 floating turbines that could produce 144 MW. (See Maine Approved for Floating Wind Research Lease.)

“The growing enthusiasm for the clean energy future is infectious,” said Interior Secretary Deb Haaland. “Today’s announcement — which builds on the execution of the nation’s first floating offshore wind energy research lease in Maine last month — is the result of years of thoughtful coordination between our team, the Gulf of Maine states, industry and the Tribes and ocean users who share our interest in the health and longevity of our ocean.”

The leases could produce about 13 GW of offshore wind power if fully developed, which could power more than 4.5 million homes. Since the beginning of the Biden administration, BOEM has held five offshore wind lease sales and approved 10 commercial-scale offshore wind projects.

The announcement is based on the best available science, including an ecosystem-based spatial suitability model conducted by the National Centers for Coastal Ocean Science. BOEM also spent more than two years engaging with Tribes, the fishing industry and other stakeholders across the region to help shape the lease areas.

The overall area is about 120,000 acres less than what BOEM included in its proposed sale notice that was announced earlier this year. The bureau tried to avoid offshore fishing grounds, sensitive habitats, and existing and future vessel transit routes, while retaining enough acreage to support the region’s offshore wind energy goals.

Winning a lease does not confer the right to build an actual power plant, but it gives developers the right to submit project specific plans that would be subject to environmental, technical and public reviews before any approvals.

BOEM has identified 14 firms that are legally, technically and financially qualified to bid in the lease auction: Avangrid Renewables, Equinor Wind US, US Mainstream Renewable Power, Diamond Wind North America, Hexicon USA, Seaglass Offshore Wind II, TotalEnergies SBE US, Pine Tree Offshore Wind, energyRe Offshore Wind Holdings, OW Gulf of Maine, Repsol Renewables North America, Maine Offshore Wind Development, Corio USA Projectco and Invenergy NE Offshore Wind.

Bidders wishing to participate have to file financial forms by Sept. 27 and post $2 million deposits for each lease area they plan to bid on (up to a maximum of two) by Oct. 11.

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EHV Tx Lines Coming into Focus for ERCOT

Texas regulators are narrowing in on a reliability plan for what one said will be a “monumental infrastructure buildout” and could include 765-kV transmission to meet growing petroleum and data center demand in West Texas. 

Native West Texan Lori Cobos is the commissioner behind the quote and leader of the Public Utility Commission’s effort to add transmission infrastructure supporting the oil-rich Permian Basin. She proposed during the PUC’s Sept. 12 open meeting three regulatory proceedings to secure the reliability plan’s approval (55718). 

Cobos recommended approving local projects required to serve the Permian through 2038; authorizing transmission service providers (TSPs) to begin preparing applications for five import paths into the region; and creating a monitor to oversee the plan’s completion. 

The reliability plan builds on a recent ERCOT report that projected oil and gas load peaking at nearly 15 GW by 2038 and an additional 12 GW of data center and other non-petroleum load by 2030. The total would come to about a third of the system’s current summer peak. Based on those projections, ERCOT said building the transmission facilities to meet that load could cost up to $15.32 billion. (See SPP Considering 765-kV Solution for Permian Basin.) 

The grid operator’s staff studied two case years, 2030 and 2038, and grouped projects as either local or import paths. The local projects are independent of the study years, while the import paths consist of 345-, 500- or 765-kV options. 

ERCOT filed an addendum to the plan identifying a new endpoint for one of the import paths. It said the new endpoint would “better align” with the PUC’s recommendation allowing TSPs to begin their preparatory work while the commission decides on voltage levels. 

Commissioner Jimmy Glotfelty, who has almost a decade of experience building HVDC lines, said if he had a magic wand, he would push for 765-kV lines over 345 kV. 

“Let’s just do the 765 and get it over with, but I recognize that we’re not all there, so I think the path forward that you’ve laid out in your memo is right,” he told Cobos and the other commissioners. “The only one question that I have is the default back to 345. I would almost like that reversed, but that’s not something we need to solve today.” 

PUC staff recommends the commission adopt the 2038 case’s import path, noting 90% of the forecasting load for that year also is present in the 2030 case year. They also suggested waiting until mid-March to approve the import paths’ voltage levels. 

Representatives from the petroleum industry agreed with the approach, saying earlier is better. ERCOT also said it could work with any of the PUC’s recommendations.  

Citing concerns from the region over the need for certainty on the plan, the grid operator’s Kristi Hobbs, vice president of system planning and weatherization, said the TSPs “desire to start working on the [certificates of convenience and necessity] that take a lot of time to go through the contracting periods before they can actually file at the commission, so that allows that work to start now.” 

ERCOT is hosting a workshop at its Austin headquarters Sept. 18 on extra-high-voltage (EHV) lines. Vendors in the space will share information on supply chains, timelines, costs, construction timelines and operational characteristics of EHV lines. The grid operator also has added an EHV transmission plan to its annual Regional Transmission Plan, which will be filed in December. 

The Permian reliability plan is a result of legislation passed last year and is due Jan. 30, 2025. The PUC will consider the issue again during its Sept. 26 open meeting. 

“I think we’ll see a lot of economic development as a result of this. I think it’s going to pay for itself over time because of the amount of economic development that’s going to come as a result of that,” Glotfelty said. “765 is used in the U.S. It’s used in Canada, it’s used in Brazil, Venezuela, Russia, South Africa, South Korea and India. It’s been used since the ’60s, so this isn’t a new technology. It’s just new to us at ERCOT.” 

CenterPoint Case Delayed

The commissioners extended CenterPoint Energy’s appeal of a recent court ruling rejecting its request to withdraw its rate case, saying they want to hear from Houston residents first (56211).  

The PUC is hosting a workshop Oct. 5 in Houston to give CenterPoint customers and others a chance to weigh in on CenterPoint’s slow restoration of power after July’s Hurricane Beryl. It agreed to take up the matter during its Oct. 24 open meeting. 

“I think it’s important that before we make any decision, we go through that process and have our hearing in Houston,” Gleeson said. 

The State Office of Administrative Hearings (SOAH) in August rejected CenterPoint’s request to withdraw its rate increase to recover $6 billion of investments made since its last rate proceeding in 2019 and expand its return on equity. SOAH said the withdrawal would conflict with state law requiring investor-owned utilities in ERCOT to file a comprehensive rate review within 48 months of their most recent rate proceeding. (See CenterPoint Energy Still in Eye of the Storm.) 

The commission has been directed to file a report on CenterPoint’s restoration efforts with Gov. Greg Abbott by December. It has received more than 16,000 responses to a public questionnaire and an additional 120 responsive filings from utilities, cities and trade associations. 

Engie-ERCOT Dispute Deferred

The commission heard oral arguments but took no action on a two-year dispute between Engie North America and ERCOT over compensation for the response reserve service (RRS) the company provided during the February 2021 winter storm. It deferred making a decision until a later open meeting. 

Engie and Viridity Energy Solutions ask to be reimbursed $47.5 million or credited for the 27 MW of RRS it delivered each day during Feb. 15-19, 2021. ERCOT said the complainants did not provide the RRS after Feb. 15, citing their failure to have confirmed trades for the ancillary service in the day-ahead market during those days. Engie and Viridity contend that following normal procedures was effectively impossible during the storm, when ERCOT’s grid came within minutes of a total collapse (53377). 

SOAH’s law judges in June rejected the Engie and Viridity complaint. They found the complainants did not show that ERCOT’s actions violated any applicable law. 

At issue is the grid operator’s requirement to have capacity that supports an ancillary service trade or offer. Its protocols define capacity for noncontrollable load resources as their net power consumption minus low power consumption, which is the load available for interruption. 

Engie’s legal counsel said the load resources lost their capacity when deployed, preventing them from being scheduled in the next day-ahead market. Engie and Viridity sought remedial relief to receive $47.5 million for the service they provided during the storm. 

ERCOT says the evidence indicated Viridity benefited by not participating in the day-ahead market, avoiding $65 million in ancillary service imbalance charges. 

PUC Adopts EOP Report

The PUC also adopted staff’s recommendation to approve a report on the power sector’s weatherization preparedness and companies’ emergency operations plans (EOPs). The report is due to the state legislature, which directed the report last year, by Sept. 30 (53385). 

Business management consultant Guidehouse reviewed 691 electric entities’ EOPs, checking the grid’s ability to withstand extreme weather events in the coming year. It found the sector is “largely prepared” across the state for extreme weather, and its participants exhibit “basic” emergency preparedness programs and have measures in place to respond to weather events. 

The firm noted its review was limited in scope and did not “comprehensively” cover resource adequacy, weatherization, system-hardening efforts or spare critical inventory. Guidehouse’s suggested improvements included financial penalties for noncompliance and a greater focus on EOPs’ actions to withstand extreme weather events.  

“One example identified in multiple EOP submissions is the inclusion of a detailed list of food items needed for an entity’s staff during emergency situations … but the plans did not include strategies or equipment needs for field response,” the report said. 

About 70% of applicable entities provided EOPs or affidavits on no material changes. Guidehouse said the remaining 30% were “overwhelmingly low risk.” 

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MISO Says 2nd Long-range Tx Plan to Cost $21B, Deliver Double in Benefits

MISO said its second, mostly 765-kV long-range transmission plan will provide the Midwest region with at least a 1.9:1 benefit-cost ratio and cost $21 billion, lower than its earlier estimated $23 billion to $27 billion.

The grid operator announced the approximations at stakeholder workshops Sept. 10 and 13. Even with the slightly lower costs, MISO’s Independent Market Monitor is incredulous the portfolio would deliver nearly double its cost in benefits.

Jeremiah Doner, MISO director of cost allocation and competitive transmission, said MISO refined its cost estimate using facility-specific details.

“That number may move around a little bit. But I think that $21 billion is where the portfolio stands,” he told stakeholders. “We don’t expect at this point in the process to be adding projects, so we don’t expect that number to materially change.”

Doner said MISO tried to minimize costs by proposing to co-locate some of the new 345- and 765-kV lines with existing structures.

“We know there’s always more risk in the regulatory permitting process when you have to seek new rights of ways,” Doner said. He added that MISO is in discussions with its transmission owners about what would be the most feasible route for the line.

MISO also is exploring routing a 765-kV line on an existing 161-kV route because it will cross an “environmentally sensitive” area from Wisconsin into Minnesota over the Mississippi River, Doner said. “We recognize that’s not a common practice,” he added.

At $21 billion and roughly 4,000 line miles, the second plan doubles the first LRTP portfolio, both in terms of costs and line miles. Doner reminded stakeholders the second portfolio has been in the works since 2022, when MISO moved to establish a projection of what the system would look like in 20 years.

The Ratio

Doner said the portfolio demonstrates “at least” a 1.9:1 benefit-to-cost ratio when analyzing its projects using MISO’s nine benefit metrics, which include the advantages of decarbonization, ability to withstand extreme weather and assistance in avoiding loss-of-load events, in addition to the more mundane adjusted production costs.

“We know these assets are going to be in service much longer than that,” Doner explained, adding that MISO was intentionally conservative to show the projects will more than pay for themselves over their first 20 years of service.

Doner said if MISO assumes the lines have a 40-year lifespan, total benefits could rise to 3.8:1. He added that with the conservative estimate, all of MISO’s cost allocation zones in the Midwest region are set to experience at least a 1.3:1 benefit-cost ratio.

“I think it’s important to show at least a 1:1 benefit-cost ratio in each of the cost allocation zones,” Doner said.

On a 20-year basis, MISO estimates the second LRTP portfolio will conservatively save MISO Midwest $16.3 billion because of the mitigation of reliability issues; $15.7 billion from avoided capacity costs; $8.1 billion in congestion and fuel savings; at least $7 billion in decarbonization assistance; nearly $3 billion in capacity and energy savings from a decrease in system losses; and $1 billion in avoided transmission investment. MISO also estimates the LRTP portfolio will save the Midwest at least $392 million from the reduced risk of extreme weather and $76 million in reduced transmission outage costs.

Skepticism

However, Monitor David Patton said he continues to believe three of the nine benefit metrics (avoided capacity costs, avoided reliability risk and decarbonization) are outright invalid or overstated and if they are deleted or significantly scaled back, the portfolio’s benefits would not come close to covering its costs. (See MISO Closing in on Final, $25B LRTP; Monitor Repeats Reservations.)

“If you adjust for those metrics, the overall benefit metric goes down to 0.5:1,” Patton said, adding he thinks it is “really, really important to scrutinize” MISO’s methodology.

“This is not about reliability. This is about a choice to build generation to further others’ policy goals,” North Dakota Public Service Commission staffer Adam Renfandt said in criticizing the portfolio.

Doner said when MISO developed its 20-year outlook that the portfolio is built upon, it examined which direction members were taking “across the whole footprint, not just in pockets of the MISO system.”

MISO planner Joe Reddoch said the analysis showed the portfolio would reduce constraints and increase system capacity so the RTO can meet its capacity needs with fewer resources.

Patton pushed back on the message that MISO faithfully followed its members’ resource plans when crafting the portfolio. He said that to model resources, the RTO relied on the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS), which he said only minimizes costs in deciding what to build and ignores potential revenues entirely, leading to “very unrealistic” fleet assumptions.

Patton said he doubted the avoided capacity costs MISO has estimated and that members naturally would build more deliverable resources on the other side of transmission constraints if the transmission were never constructed. He said it’s highly unlikely members would continue to build generation in sites that are undeliverable to load. Patton added that if MISO approached its members and said it was not going to meet its resource adequacy obligations, members would adjust resource planning, which “pretty quickly” would reduce the LRTP’s benefits by “tens of billions.”

“You’ve cited an undeliverable collection of resources if we don’t build [the second portfolio], but our markets are designed to take care of that. To characterize that as a benefit is pretty misleading,” Patton said.

Doner said members have asked MISO to build a dependable system around their future plans. He also said it is not so simple for members to “move generation around,” citing wind- and solar-rich locations in the footprint.

“We have transmission planning responsibilities, not resource planning responsibilities. We really do rely on what our members are telling us that they’re going to build,” Doner countered.

Patton also said MISO is off base by establishing the value of the portfolio’s avoided reliability risks on the value of lost load (VoLL). He said in “no world” would the RTO allow reliability risks to become severe enough to shed load. Instead of lost load, Patton argued MISO should base the benefit on which transmission facilities would be built without the LRTP portfolio. MISO needs “an accurate ‘but for’ case,” in which it analyzes which shape its system will take without the second portfolio, he argued.

“Calculate something that’s real. This is not real,” Patton said. It’s “unconscionable” to expose customers to transmission investment based on “imaginary” and “massively overinflated” benefits, he said.

Jim Dauphinais, an attorney representing multiple industrial customers in MISO, said the use of VoLL in the benefit is “highly problematic.”

However, Jeff Eddy, director of transmission planning for ITC Holdings, warned stakeholders “there are big dollars behind outages” and pointed to Texas as an example. Eddy said that if anything, MISO was being conservative on the portfolio’s $16 billion reliability value.

“We know that these backbone lines really do provide benefits,” Sustainable FERC Project attorney Lauren Azar added. “I hope no one is questioning the benefits that regional backbone lines bring to the region.”

Reddoch said it’s difficult to compare the numerous, scattershot baseline reliability projects MISO would need on a five- to 10-year horizon with the 20-plus-year reliability benefits that the second LRTP portfolio would achieve. However, he said the portfolio likely would be more economical than smaller, piecemeal projects to comply with NERC standards.

“This has always been a challenge in the industry to monetize reliability,” Doner added.

North Dakota PSC Commissioner Julie Fedorchak said she was “dubious” that all MISO members would know where their projects will be located 20 years into the future, suggesting the RTO took liberties with its siting assumptions.

WEC Energy Group’s Chris Plante said he would like MISO to admit its planners fashioned a hypothetical resource expansion only with its members’ carbon reduction goals in mind. “My expansion plans don’t go out much more than seven years,” he said.

Doner said while it is not “100% member plans” that make up the 20-year future, it nevertheless comprises mostly member plans, and where there are not explicit plans, MISO sought extensive member input.

MISO Vice President of System Planning Aubrey Johnson said the RTO made “over 500 adjustments” to its original resource siting assumptions after speaking with its stakeholders throughout the planning process.

“Good golly, I really wish we could build regional backbone projects sooner than eight to 15 years in the future,” Azar said, urging stakeholders to consider the timeline to build transmission. “MISO has no choice but to essentially site the resources in the models. All modeling is necessarily wrong, but that doesn’t mean we shouldn’t be doing it. I really just urge folks to think about the reality of how long it takes to build these really big projects.”

“I’ve never known a resource planner who can tell me exactly what they’re going to do,” Eddy agreed. “This is high-level stuff, and I support what MISO is doing.” He said stakeholders seem to be losing sight of what MISO’s big-picture, future planning was intended to accomplish.

Plante said it seems MISO is rushing for December board approval rather than making sure “sound planning principles” are applied to the portfolio.

“Given the magnitude of the expansion planning here, we need to be careful that we establish sound foundations,” Plante said, adding  the projects will be subject to scrutiny at state regulatory agencies.

“We disagree that there’s a lack of analysis here. We believe this is thorough,” said Jeanna Furnish, MISO director of expansion planning.

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Equinor Yanks Request for Empire Wind 2 Export Cable

An offshore wind proposal that was placed on hiatus amid the industry’s recent financial turmoil is taking a further detour, halting its attempt to bring an export cable onshore in New York. 

Empire Offshore Wind on Sept. 12 withdrew its application (Case No. 22-T-0346) with the state Department of Public Service for a Certificate of Environmental Compatibility and Public Need for the transmission line that would have served Empire Wind 2. 

Without a certificate, Empire cannot build a line. 

The application had become highly controversial in the 27 months since it was submitted, attracting strong resistance in Long Beach, the oceanfront city it would pass through. (See ‘What Did We Do to Deserve This?’) Nearly 1,000 comments have been submitted in the Public Service case. 

Gov. Kathy Hochul (D), a vocal wind power proponent, further complicated the effort when she vetoed an attempt to facilitate construction of the cable through the city. (See New York Governor Vetoes Planned Offshore Wind Transmission Act.)  

A spokesperson for Equinor said Sept. 13 the company remains committed to development of the Empire Wind 2 lease area in a manner that is profitable and will assess future offtake opportunities. 

Both Empire plans have been approved by federal regulators, but only Empire 1 is progressing at this point. (See BOEM Approves Empire Wind.) 

Equinor anticipates a final investment decision on Empire 1 this year. The company is building an $861 million offshore wind hub in Brooklyn to service this and future projects, and it is looking for an equity partner for Empire 1. 

Empire 1’s export cable would connect with the grid in Brooklyn, in a location and manner that has not attracted opposition similar to that seen in Long Beach. 

Empire Wind 1 and 2 and Beacon Wind 1 and 2 were joint ventures of Equinor and bp; the two companies previously were awarded New York state contracts for Empire 1, Empire 2 and Beacon 1. 

The anticipated cost of construction soared in 2022 and 2023, however, rendering the financial terms of those contracts untenable, and all three contracts were canceled, along with contracts for many onshore renewable projects. (See Sweeping Reset Underway for NY Renewable Development.) 

The two companies ended their partnership and split their portfolio. Beacon went to bp, which said in June it still was evaluating its options. (See Bp Says It is Still Evaluating Beacon Wind.) 

Equinor bid Empire 1 into the rush solicitation New York launched in an attempt to get its offshore wind aspirations back on track when its portfolio collapsed. Equinor won a new contract this year for 810 MW of capacity at a much higher price than the original contract. (See Empire, Sunrise Wind Back Under Contract in NY.) 

Equinor did not rebid the 1,260-MW Empire 2 into the rush solicitation, and the spokesperson said it also did not rebid the project into the current New York solicitation, which closed Sept. 9. 

The current solicitation attracted some other familiar names, however: Attentive Energy, Community Offshore Wind and Excelsior Wind all announced that they had submitted proposals for plans that have been in the works for years. (See NY OSW: If at First You Don’t Succeed, Try, Try Again.) 

New York awarded tentative contracts to all three proposals in October 2023, but they had to be scratched in April 2024, when development of the turbine specified in those contracts was halted. (See NY Offshore Wind Plans Implode Again.) 

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Mass. Gov. Healey Includes Permitting Reform in Budget Proposal

Following the failure of the Massachusetts House of Representatives and Senate to reach common ground on a climate bill this summer, Gov. Maura Healey (D) has proposed to include clean energy permitting and procurement provisions in a supplemental budget bill announced Sept. 11.

While the permitting and siting reform framework largely has been agreed on for months, legislators were unable to overcome disagreements between the House and Senate over natural gas and competitive electricity supplier reforms before the end of the formal legislative session in July. (See Mass. Lawmakers Fail to Pass Permitting, Gas Utility Reform and Mass. Legislature Faces Looming Deadline to Pass Permitting Reform.)

The permitting and siting proposal would consolidate the approval process for clean energy infrastructure projects and impose a 15-month cap on the review of large projects and a 12-month cap on the review of small projects.

Sen. Mike Barrett (D), the lead Senate negotiator on the climate bill, has argued that expediting the permitting process — while important for the clean energy transition — could lead to increased infrastructure costs to ratepayers, and therefore must be coupled with the gas and competitive electricity supplier reforms intended to help offset some of the costs to ratepayers.

The Senate version of the climate bill would allow gas utilities to retire portions of the gas network if viable alternatives are available, update the state’s pipeline replacement program with the goal of reducing ratepayer costs, and require annual filings from the gas utilities on their efforts to reduce emissions and minimize risks of stranded assets.

Healey’s supplemental budget, however, declined to include gas or competitive supplier reforms. The governor wrote in a letter to legislators that the clean energy permitting reforms would help the state “capitalize on the potential to grow our clean energy sector and advance our climate goals.”

The supplemental budget — if brought up in the informal session — could be halted by the vote of a single legislator; passing a bill in an informal session requires unanimous approval of all present lawmakers. This makes it unlikely the legislature will approve any of the more controversial climate proposals, and also could pose a challenge for the slimmed-down permitting and procurement proposals.

The legislature’s next formal session starts in January, although the governor and top lawmakers have signaled interest in calling a special formal session focused on a separate economic development bill that legislators also failed to pass in July.

The inclusion of the permitting provisions without gas reforms spurred criticism from Barrett and climate activists.

“The governor and the House want us to pay for two separate — and expensive — systems to serve the same population’s energy needs,” said Becca Glenn of the advocacy group Mothers Out Front in a statement. “Massachusetts residents can’t afford to prop up an aging gas system while also paying for a modern, clean energy system.”

Barrett told NetZero Insider he’s disappointed with the supplemental bill proposal, noting that “all the Senate reforms intended to provide ratepayer relief have been stripped out.” The proposal has undermined ongoing negotiations between the Senate and the House over the climate bill, he added.

“I’m not sure that the House will have any incentive to negotiate with us, because [the supplemental budget] gives them the minimalist outcome that they seek,” Barrett said. “We had actually reached agreement on a significant number of secondary items, so there was real promise to these negotiations. The governor has upset all of that.”

Rep. Jeff Roy (D), the lead negotiator on the House side, did not respond to requests for comment in time for publication, but he told the State House News Service he’s “encouraged by what the governor is attempting to do.”

Kyle Murray of the Acadia Center said the administration’s inclusion of the permitting reforms in the budget bill “probably signals that they didn’t sense likely movement” in the negotiations between the House and Senate.

He said reforms to expedite clean energy permitting and to enable the transition off natural gas are key aspects of the state’s clean energy transition but added that “any climate bill that moves forward must take practical and common-sense steps to address the gradual decommissioning of the sprawling natural gas system. Any bill that does not do so is not acceptable.”

A spokesperson for the Executive Office of Energy and Environmental Affairs said the governor’s office “included time-sensitive energy provisions critical to the procurement, permitting and siting of energy projects” in the supplemental budget, adding that the administration “continues to support the climate bill and will continue to work with the Legislature on its passage.”

Beyond the specific reforms at hand, Barrett also expressed dismay at the strong opposition that has come from the gas industry to the Senate’s efforts to facilitate a transition away from gas.

“This has been an eye opener,” Barrett said. “We’ve got to get off natural gas — consciously but effectively — but after this year’s experience, I can predict a tough road ahead even in a very blue state.”

The state’s electric and gas utilities historically have been the most influential interests on climate policy in the state, according to a 2021 analysis from Brown University researchers. Over the course of the 2023/24 legislative session, investor-owned gas and electric utilities cumulatively reported about $1.6 million in spending on lobbying in the state.

Clean Energy Procurement

The supplemental bill also proposed significant changes to the state’s clean energy procurement process, incorporating aspects of both the House and Senate climate bills.

The bill would enable the state’s Department of Energy Resources (DOER) to pursue coordinated solicitations with other states for clean energy generation or transmission that would help the state meet its policy goals in a cost-effective manner.

It also would direct the DOER to review the effectiveness of the state’s existing clean energy procurements, and to “make recommendations regarding the future procurement of clean energy resources for the purposes of ensuring compliance with statewide greenhouse gas emissions limits.”

It also specifically directs the DOER to solicit up to 5,000 MW of storage resources over the next four years, including 3,500 MW of mid-duration storage (lasting between four and 10 hours), 750 MW of long-duration storage (between 10 and 24 hours) and 750 MW of multi-day storage (greater than 24 hours).

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ICF Report Forecasts Significant Demand Growth This Decade

ICF International forecasts that demand could increase by 9% by 2028, while peak demand could increase by 5% over the same period, according to a report it published Sept. 12. 

The consulting firm expects that growth to continue, as overall demand will increase by 18% by 2033 and peak demand by 10.7%. The shift to demand growth comes after decades of relatively flat levels in the U.S. 

A robust economy, electrification, growth in manufacturing, data centers and cryptomining are all contributing to the rising demand for electricity. Growth will vary by region, with ICF seeing the largest increase overall in the Mid-Atlantic region because of vehicle electrification and data centers, where demand is expected to grow by 68% by 2050, compared to the national average of 57%. 

“What makes this stark increase in energy demand, particularly peak demand, so challenging is that it simply wasn’t [forecast] in most projections until very recently,” the report says. “The latest demand projections are significantly higher than projections made as recently as 2023. The divergence between last year’s projections and current projections is broad by 2033 and only continues to grow in the coming decades.” 

New supply, including utility-scale solar and wind, could help meet the rising demand, but ICF notes that it faces hurdles for that to happen, including the need to upgrade the grid, cutting the time frame of the permitting process and finding suitable locations to build. 

The grid is not designed to accommodate major amounts of new generation immediately, with ICF noting that on average, it can handle just 189 MW at once, with upgrades needed to handle additional supply. The Mid-Atlantic, northern New England, parts of the Southeast and the Upper Midwest are particularly constrained in that way, the report says. 

And the industry needs to worry about getting that down to the distribution level, with the average amount of such “withdrawal capacity” being 153 MW before upgrades are required, with the biggest challenges in areas with high peak demand growth such as Northern Virginia and parts of Texas. 

The growing demand could slow progress in the transition to clean energy, as it might force utilities to keep fossil-fueled power plants running longer than otherwise, the report says. 

“With enough investment, the U.S. can make major upgrades to the grid and install vast amounts of renewable energy, meeting demand growth while decarbonizing the grid. Americans will likely pay higher utility rates, taxes to pay for federal and state subsidies, or both.” 

The wholesale prices that many utilities pay for electricity could go up by an average of 19% by 2028, and “much of” that would be passed onto customers, the report says. ERCOT could see even higher price increases of 22% by that year. 

The report suggests utilities start engaging in more sophisticated planning that considers the entire system from generators to end-use customers. 

“This requires an integrated approach across all asset classes, including generation, transmission, distribution, distributed energy resources, conservation and load management,” the report says. “This holistic approach equips utilities to consider long-term investment strategies that enhance grid reliability, resilience and operational efficiency by adding greater flexibility and responsiveness to traditional generation and transmission solutions, like virtual power plants.” 

Other suggestions include identifying areas with plenty of renewable resources that can be connected to the grid, enhancing the distribution grid, expanding load-management programs, using artificial intelligence to improve planning and grid management, and staying engaged with regulators on the issues. 

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MISO, TOs Argue Self-funding Necessary for Transmission Development

MISO and its transmission owners defended their practice of allowing transmission owners to self-fund network upgrades in separate filings Sept. 11 responding to FERC’s Order to Show Cause (EL24-80).

FERC in June said grid operators’ practice of allowing TOs first crack at financing — and therefore earning a return on — the network upgrades necessary to bring generators online could be biased against interconnection customers, who may experience higher interconnection costs as a result.

The commission ordered MISO, PJM, SPP and ISO-NE to explain how their tariff language on the initial funding is fair or, alternatively, propose changes to make their policies impartial. It also suggested that TO self-funding creates barriers to interconnection (EL24-80, et al.). (See FERC Issues Show-cause Order on TO Self-funding in 4 RTOs.)

For more than a decade, MISO’s practice of TO self-funding has been the subject of oscillating rulings between FERC and the D.C. Circuit Court of Appeals. RWE Renewables, NextEra Energy and EDF Renewables recently claimed their costs “double or increase exponentially” when TOs take the lead on funding network upgrades.

In their filing, the TOs argued that eliminating their unilateral ability to self-fund upgrades would decrease, rather than promote, the capital investment needed for transmission projects. They also said FERC has no basis to eradicate TO self-funding after establishing it in Order 2003.

MISO insisted its TO initial funding practice is fair and said it never has “observed any instances of [it] being used as a tool to inflate the costs of network upgrades or create advantages for some generation projects vis-à-vis others.” The RTO said a TO electing to self-fund does not affect the interconnection service, but it did acknowledge it does increase the costs for interconnection customers.

“TO initial funding does increase the cost of interconnection service to the interconnection customer, but only because that cost would not otherwise include a … return on capital,” MISO said. “From the perspective of [a] transmission owner, the actual cost of the operating and maintaining the funded network upgrade is unchanged.” It added that eliminating the self-funding option will not necessarily result in lower costs because interconnection customers also could require a return on capital and shift that cost to ratepayers.

MISO also said its procedure affords interconnection customers the opportunity to suggest alternatives to and investigate the justification for a network upgrade so they’re not on the hook for oversized projects that would pad TOs’ bottom lines. The RTO also said interconnection customers can pursue alternative dispute resolution or choose to file unexecuted facilities service agreements to challenge upgrade costs.

The RTO insisted its three-phase interconnection queue design provides enough oversight so that “any network upgrade and corresponding self-fund election has a transparent, multistep history, with MISO involvement at each step.”

However, MISO added a caveat that it “has only limited insight into its transmission owners’ internal functions, needs and decision-making,” so it could not answer all questions posed by the commission. In those cases, MISO submitted its TOs’ answers.

The TOs adopted a more full-throated defense. They said FERC’s show-cause order “poses questions that make it apparent the commission has made up its mind” to eliminate the self-funding option “without regard to the long-term effect this will have on transmission owners and other customers they serve.”

They argued it is imperative they be able to earn a return on assets they will own, operate and maintain for the duration of their useful lives. They said the show-cause order amounts to “misguided policy goals behind an undue discrimination theory” and argued that no one has been able to produce evidence that TO initial funding causes undue discrimination “in the 13-plus years that TO initial funding has been before the commission.”

The TOs also said that, in an era of supersized transmission expansion, it appears FERC has forgotten to “balance interests and to ensure that native load customers are not negatively affected as a result of third-party generator interconnection.” They said their financial viability should be maintained and FERC should be careful not to “strike a one-sided ‘balance’ in favor of cheaper interconnections for generators.”

“Transmission owners bear substantial risks associated with owning, operating and maintaining said transmission facilities, and stand to lose the right to self-fund network upgrades and, with it, the ability to earn a just return on an entire class of interstate transmission facilities, in a grossly unfair proceeding,” the TOs said.

If they are denied the opportunity to make a return on network upgrades, the TOs argued it would constitute an attack on their business model and is akin to the “taking of private property for public use without just compensation.” It is “overly simplistic” and “reductionist” to think  TOs should not be able to earn a return on network upgrades simply because the money for them comes from generation developers, not themselves, they argued. They also said they never would build unnecessary network upgrades because MISO independently studies interconnection needs.

FERC should terminate the proceeding with prejudice, the TOs concluded.

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ERCOT Sets Go-live Date for RTC, ESR Project

ERCOT has set a target go-live date for its real-time co-optimization project, which is expected to add millions in savings to its market. 

The Texas grid operator said Sept. 13 that it has set a Dec. 5, 2025, goal for the market change, about six months ahead of its original mid-2026 timeline.  

Real-time co-optimization (RTC) is used by most other grid operators in North America. The market tool procures energy and ancillary services every five minutes, automating many processes that currently are managed manually. ERCOT currently procures ancillary services in the day-ahead market and typically does not move them between resources in the real-time market. 

CEO Pablo Vegas said RTC’s implementation is “the most significant market enhancement” to ERCOT’s nodal design since its inception in 2010.  

“The target go-live date represents an important milestone in ERCOT’s confidence for planning and tracking the completion of the RTC project for a more dynamic and efficient wholesale power market,” he said in a statement. 

The ISO’s Independent Market Monitor in 2018 released a report that evaluated RTC’s effect on the market. Using 2017 as its simulated operating year, it found a $1.6 billion reduction in total energy costs; an $11.6 million reduction in production costs to serve load; a $257 million reduction in congestion costs; a $155 million reduction in AS costs; and reliability improvements due to a reduced overloading of transmission constraints and a decrease in regulation up. 

Staff and stakeholders have been working on the RTC project since 2019, when the Public Utility Commission directed ERCOT to add the mechanism after the commission assessed its costs and benefits. (See “Real-time Co-optimization Go-live Date Could be Accelerated,” ERCOT Technical Advisory Committee Briefs: Aug. 28, 2024.) 

The project has been expanded to address the growth of energy storage resources in ERCOT. Texas began 2024 with about 5,000 MW of energy storage online, second only to California. It is expected to add more than 6,000 MW this year, according to the U.S. Energy Information Administration. 

System testing will begin early next year. Market trials are planned to begin in May and run through November. 

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ISO-NE Consumer Liaison Group Talks Potential of Offshore Wind

NEW LONDON, Conn. — Activists, ISO-NE officials and state representatives from across New England convened in this port city to discuss the benefits of offshore wind to the region’s power system — along with the challenges to deployment — at the RTO’s Consumer Liaison Group meeting Sept. 12.

The New London port is one of the region’s key staging areas for offshore wind. It was used as a staging and assembly point for the South Fork Wind Farm and is currently supporting the construction of the Revolution Wind project.

“We are bringing this industry to America,” said Ulysses Hammond, the recently retired executive director of the Connecticut Port Authority, kicking off the meeting.

Speakers at the CLG generally spoke favorably of the significant reliability, climate and public health benefits that offshore wind could provide the region, while citing costs and transmission challenges as the key factors that could slow its deployment.

While New England states have set ambitious offshore wind goals, high costs have caused project cancellations and smaller procurements than many advocates have hoped for. Massachusetts and Rhode Island recently announced their selection of 2,878 MW from their multistate coordinated procurement, which initially sought up to 6,000 MW. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)

Connecticut, which also participated in the coordinated procurement, announced that it is still evaluating the bids, putting into question the viability of one project selected by Massachusetts. (See NY OSW: If at First You Don’t Succeed, Try, Try Again.)

Although high bid prices appear to have given some lawmakers second thoughts, offshore wind PPAs will likely save ratepayers money in the long run, said Josh Berman, senior attorney at the Sierra Club.

He highlighted the results of a recent analysis commissioned by the Sierra Club that found that adding 9 GW of offshore wind would save the region an estimated $630 million annually due to lower market clearing prices. The estimate was based on a $150.15/MWh project cost, derived from the Sunrise Wind and Empire Wind projects. Massachusetts and Rhode Island have not yet announced the costs associated with their most recent solicitation. (See Offshore Wind Projected to Save New Englanders $630M per Year.)

Adding 9 GW of wind would also cut the region’s power sector emissions by about 42% and provide about $362 million in annual public health benefits due to lower NOx and particulate emissions, Berman said.

Berman emphasized that the benefits would be socialized across the region’s grid, even though the current PPA model largely revolves around individual states — or pairs of states — covering the entirety of a project’s costs. He compared the dynamic to Connecticut’s support of the Millstone nuclear plant and said collaboration and cost sharing between New England states will be a key component moving forward. (See Connecticut Zero-Carbon Awards Include Nukes, OSW, Solar.)

Susan Muller, senior energy analyst at the Union of Concerned Scientists (UCS), said offshore wind will also provide significant winter reliability benefits, as it typically performs better in lower temperatures. She highlighted a recent UCS analysis that found offshore wind additions would significantly reduce winter blackout risks in the region, echoing the findings of recent ISO-NE studies. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)

Muller added that ISO-NE’s inventoried energy program and Mystic cost-of-service agreement, both aimed at ensuring winter resource adequacy, have cost ratepayers nearly $1 billion. And while Enbridge has proposed a significant gas capacity expansion into the region to reduce winter gas constraints, Muller said it makes far more sense to invest in offshore wind resources.

“If you’re thinking about a new gas pipeline, you first need to talk with the communities that it is going through,” Muller said. “The pipeline really seems to be the wrong path to take. Because we have offshore wind as an incredible opportunity before us, we think it’s a no-brainer to go down the other path.”

Liz Mettetal, a director at the consulting firm Energy + Environmental Economics (E3), said offshore wind and long-duration storage will have combined reliability benefits that are “greater than the sum of their parts” as both technologies scale up.

Mettetal said the region should consider timing storage procurements with renewable energy solicitations. She told the CLG that “we don’t need storage on the grid until we have a ton of renewables, but they really will work together.”

Abraham Silverman, a researcher at Johns Hopkins University and the facilitator of the Northeast States Collaborative on Interregional Transmission, emphasized the importance of preparing the grid today for the offshore wind resources that will come online in the coming decade.

“We are making decisions today for projects that are not going to come online until the early 2030s,” Silverman said, adding that transmission projects to enable offshore wind will likely look like smart investments in 20 years, despite their significant upfront costs.

He said the long timeline of permitting and siting onshore transmission infrastructure makes today’s efforts especially important.

Siting and permitting are “probably the most difficult part of the clean energy transition,” Silverman said, adding that “getting the onshore grid ready is just as hard — if not harder — than getting the offshore grid done.”

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FERC Workshop Examines How to Speed up Interconnection Queues

FERC still is working to implement the changes to its generator interconnection rules from Order 2023, but it also is considering further changes, as it held a two-day workshop Sept. 10-11 to gather more input. 

Order 2023 made improvements, FERC Chair Willie Phillips said at the start of the event, but it was not meant to be a silver bullet to queues that are seeing massive interest from new resources and overlapping with widespread demand growth. 

“Our country has a severe interconnection queue backlog. We have over 2,000 GW of generation that’s waiting in the wings to be connected,” Phillips said. “We know right now that the average wait time is over five years for projects to get through the queue. That means that projects that are pretty much ready to go right now have to wait until at least 2029 before there’s a single shovel in the ground. I believe, I’m sure you agree, that’s unacceptable.” 

All five of the commissioners participated in or observed the staff-run workshop at different points over the two days. 

Commissioner Mark Christie argued that more changes are needed, as many power plants are shutting down while demand is rising. 

“Reliability is the overriding goal of interconnection,” Christie said. “That means prioritizing those generation resources that can be built quickly and efficiently and that give us the most generation capacity as quickly as possible, at the least cost burden to customers.” 

The glacial pace of the queues, along with the retirements and rising demand, is contributing to a looming reliability crisis, Christie said. Speeding up new supply can help. One idea that stood out to Christie was from Colorado Public Utilities Commission Chair Eric Blank, who proposed letting state regulators designate which resources would help ensure reliability and giving them preference. 

In his written testimony, Blank argued that the current process in Colorado is working well, but a law in the state requires it to join an RTO before 2030, and that could lead to delays. Resources that clear Colorado’s competitive resource solicitation are prioritized now, and Blank wants that to continue in an organized market. 

“It may be fundamental to Colorado’s ability to maintain resource adequacy and cost-effectively comply with our statutory emission-reduction goals by enabling us to select the type of resources we need, where and when we need them,” Blank said. “As our transmission utilities seek to join RTOs, we would implore FERC to allow us to continue to prioritize the winning bidders from our competitive resource solicitation process, at least for some transitionary period.” 

CAISO has taken queue reform further than most transmission providers, but its most recent cluster of new projects, Cluster 15, had 541 projects representing 354 GW of new supply, which is so much it just does not make any sense to study it all, said Danielle Osborn Mills, the ISO’s principal for infrastructure policy development. 

“We now have over three times the amount of capacity that we expect to need to achieve our 2045 objectives,” she said. 

The issue is not a lack of staffing, or the length of time it would take to study all that excess generation, but rather that developers have proposed so many projects that never will lead to steel in the ground, Mills said. 

“The ISO’s focus has been really on trying to find ways to increase competition earlier in the process, and to find the best and most ready projects that align best with system need and transmission availability early in the process, so that we’re using our study resources to really focus on the projects with the highest likelihood of success,” she added. 

PJM is working through a major backlog of resources and not accepting any new requests until 2026. The RTO is considering a parallel queue to get shovel-ready projects that can help it maintain reliability as its reserve margins are narrowing, said Adrien Ford, director of wholesale market development for Constellation Energy Generation. 

“Demand is increasing at an ever-growing rate, and the pace appears to only be getting faster,” Ford said. “I believe that RTOs have an obligation to facilitate the reliable and ready resources.” 

Constellation is the largest nuclear plant owner in the country, most of them in PJM, and they could expand available capacity quickly through uprates. The company has plans to expand two units by 135 MW, but PJM will not be able to even consider its applications for expanded interconnections until 2026, and that delay could be compounded by the units’ refueling cycle, which is when such work has to take place. 

“If resource adequacy and/or reliability aren’t anticipated to be maintained, then the rate cannot be just and reasonable,” Ford said. “So, I think it’s imperative that action is taken. The expedited reliability process could run in parallel to the existing queue.” 

FERC has maintained a commitment to open access and ensuring a level, competitive playing field for all resources, said Jason Burwen, vice president of policy and strategy for GridStor. Key precedents such as orders 888 and 2003 are focused on keeping barriers to entry low to allow for more competition to benefit consumers. 

“The energy storage industry, of which my company is a member, owes its historic growth to low barriers to market entry that this commission has upheld to date, and open access has been key to enabling capital formation and new market entrants, like my company,” Burwen said. “So, when we think about rationing interconnections, this is, first of all, something I just want to call out. This is a second-best, maybe a third-best, solution to the problem at hand. And we should also consider that it is a Band-Aid; that it is probably a temporary fix.” 

Proactive Planning’s Role

SPP is trying out a new approach to queue management, which Burwen and others called the “entry fee approach,” and solutions like that could mitigate the underlying issues without sacrificing open access, he added. 

The Consolidated Planning Process would mix transmission planning and generator interconnection, co-optimizing the processes and allowing SPP to plan lines that can be paid by both load and new generators, said Natasha Henderson, the RTO’s senior director of grid asset utilization. 

The CPP involves proactive planning for both new load and supply and then aligning the analysis for both processes, which will enable planners to co-optimize the future grid around both inputs. Then SPP needs to tackle cost allocation so the beneficiaries of those co-optimized lines pay their fair share, Henderson said. 

“The concept of the ‘entry fee’ SPP has in mind is to look for a 20-year transmission plan, determine what that transmission would look like, devise an entry fee based upon that and that entry fee would be known to generation interconnection customers before they would enter the queue,” Henderson said. 

Developers were in favor of the idea because getting one fee upfront eliminates a key problem they have with the current system: uncertainty. Several developers complained over the two days about frequent restudies upsetting their earlier expectations, and that even when they made it through a balancing authority’s queue, they sometimes could be hit with a major bill for upgrades in a neighboring “affected system.” 

“We need to provide certainty to generators sooner in the process, to allow decisions to be made earlier in the process,” said David Mindham, EDP Renewables’ director of regulatory and market affairs.  

SPP’s proposed CPP process would do that, he added. The idea of combining proactive transmission planning with interconnection was supported by many speakers at the conference, with R Street Institute Senior Fellow Beth Garza arguing it would make sense for consumers. 

“In too many areas, the interconnection process is being used, instead of comprehensive regional planning, to effectuate network upgrades, and this leads to inefficient outcomes,” Garza said. “These inefficient outcomes mean consumers are harmed because, make no mistake, consumers pay, either directly or indirectly, the cost of all transmission. Whether the transmission results from an interconnection process or regional planning process, costs and risks assigned to generators will find their way to consumers, either through higher prices or potentially an inability to procure or purchase the power from their desired sources.” 

The concept was the subject of a paper that Advanced Energy United and the Solar and Storage Industries Institute commissioned from Brattle Group and Grid Strategies ahead of FERC’s workshop. (See AEU Webinar Highlights Potential Queue Improvements.) 

“The transmission system is not built for new generation resources and load growth,” report co-author and Brattle Group Principal John Michael Hagerty said. “That results in a perpetually constrained system that requires complex studies to identify upgrades that are higher costs than they need to be, that does not consider other system needs and is built just in time for new resources.” 

Connect and Manage

ERCOT avoids the need to study generators’ impacts with its “connect and manage” approach to interconnection, in which any impacts new resources cause, like increased congestion, are dealt with in the transmission planning process, said Warren Lasher, president of Lasher Energy Consulting. 

“The benefit for the generator is it can move through it at its own pace, and you can see generation that comes online in two and a half, three years,” said Lasher, previously ERCOT’s senior director of system planning. “The downside is, as you have mentioned, the risk of curtailment. Now, importantly, the risk of curtailment is only shared by renewables at this time, because there are Planning Guide provisions that state that thermal dispatchable generation has to meet a certain amount of dispatchability for resources, specifically for resource adequacy concerns.” 

ERCOT has not been doing much proactive transmission planning lately, though Lasher said it is working on changes to its economic planning criteria that could lead to improvements. 

The Competitive Renewable Energy Zone lines were a pioneering effort in proactive planning and helped Texas shift huge wind resources from points west to its major cities in the eastern part of the state, Lasher said. Now the state’s Public Utility Commission is considering transmission development that would shift power the other way as large loads in the form of oil and gas drilling and data centers have located there, in part to take advantage of cheap renewable power that is caught behind constraints. 

The FERC equivalent of connect-and-manage is energy resource interconnection service (ERIS), in which generators sign up to be able to sell on the grid with a higher risk of curtailment. There also is network resource integration service (NRIS), which ensures enough deliverability to qualify for capacity auctions in markets that use them. But the difference between ERIS and NRIS can be narrow in some markets. 

“ERCOT is not the only transmission provider in the United States treating energy-only service in a significantly less restrictive way,” said Tyler Norris, a doctoral student at Duke University’s Nicholas School of the Environment, whose research focuses on electric power systems. “At least two other ISOs take a similar approach. Currently, in New York and California, both of those markets have concluded that all, or most thermal power flow constraints for transmission-scale generators can be managed in real time via redispatch, so generally, they are not assigning thermal upgrade costs to ERIS generators.” 

Interconnection Queue Automation

Another option FERC considered during the workshop was automation through software. 

“I believe automation can yield benefits in three principal areas,” said Clayton Barrows, senior researcher at the National Renewable Energy Laboratory: “first, identification of solutions that might not have been apparent to the engineers that traditionally conduct the interconnection studies; second, evaluation of significantly more conditions to improve the robustness of results; and then third, improving the transparency and quality of solutions and the mitigation options that might arise from them.” 

Pearl Street Technologies is one software firm offering a way to automate the system impact studies in the interconnection process in ways that can speed it up greatly, said its CEO, David Bromberg. 

“Even within the studies, there’s a whole lot of sub-steps involved, ranging from taking in the data, to building up the power flow models, running the power flow study, identifying the constraints, proposing network upgrades, estimating the costs, running the cost allocation, and then putting all of this in a report that’s digestible by interconnection customers,” Bromberg said. “So that’s a pretty long list. But even that is a simplification, it is a very complex process.” 

Some of those sub-steps have benefited from automation for years, but Pearl Street offers developers and grid planners ways to automate the entire process, he added. Developers use it to try to pick the best sites for new power plants, while Pearl Street is working with SPP and MISO to automate elements of their interconnection studies. 

“SPP has applied automation to our current backlog studies, and we’re making our way through those clusters,” said Jennifer Swierczek, the RTO’s manager of generator interconnection. “By next summer, every request will have a phase 1 and a phase 2 answer, and many more requests will have reached [generator interconnection agreement]. A lot of that is due to the automation that we put in place.” 

Artificial intelligence has been a hot topic in the electric industry for its projected impact on demand because of the required new data centers, but FERC asked whether the technology could help speed up the queue. 

The kind of large language models that consumers are familiar with are not the kind of AI that is capable of speeding up the queue, Bromberg said. Pearl Street’s optimization engine can help, but it is just modern computational software, he added. 

“We can’t tell AI to do even steady-state analysis, let alone transit stability, or if you have a weak grid area, like an electromagnetic transient study, something really complex,” said Cody Doll, NextEra Energy senior manager of transmission business management. “AI does, however, seem to do very good job at pattern identification for large datasets, and we’ve explored potential uses such as parameter verification.” 

Sifting through large datasets for patterns can be of some use, but it will require new AI technology to transform the interconnection process, he added. 

Automation in general has its limits for the complex and nuanced studies required by the interconnection process, said Donnie Bielak, PJM director of interconnection planning. 

“You need to have the oversight and the engineering judgment that goes into the scrutiny, and that does take time,” he added. 

PJM is automating and streamlining where it is possible, but going too far down that road could lead to “poor solution quality” in the interconnection process. 

“I like to think of PJM planning as kind of the bouncers at the door,” Bielak said.