Search
`
July 28, 2024

Posted on

PJM Recommends $5B in RTEP Transmission Projects

VALLEY FORGE, Pa. — PJM has proposed around $5 billion in transmission upgrades to address data center load growth and generation deactivations primarily in the northern Virginia region identified in the third window of the 2023 Regional Transmission Expansion Plan (RTEP). (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.) 

PJM Senior Vice President of Planning Ken Seiler told the RTO’s Transmission Expansion Advisory Committee (TEAC) the proposal would meet energy needs through the 2027/28 delivery year while providing long-term benefits to the grid by facilitating interconnection of new resources. 

Ken Seiler, PJM | © RTO Insider LLC

“It’s well-documented that there’s going to be a lot more transmission required as we go through the energy transition, and this is an area that’s a prime example of that,” he said. “We’re going to need a number of projects to meet those needs.” 

The proposal largely tracks the 500-kV combination proposal PJM presented during the Oct. 3 TEAC meeting, which would build new 500-kV lines from northern Virginia out to the Peach Bottom substation to the northeast, the 502 Junction substation to the northwest and the Morrisville substation to the south.  

PJM created the combination proposal by merging portions of the 72 proposals it received in the competitive planning process and directing some upgrades to infrastructure to address needs not resolved by any of the proposals. The final product includes work assigned to Dominion, FirstEnergy, Exelon, LS Power, NextEra, Transource and the Public Service Enterprise Group (PSEG). 

The largest portion of the work is centered on “Data Center Alley” near Dulles Airport in Loudoun County, with over $1 billion of projects assigned to Dominion in that region. The scope includes two new 500/230-kV substations and upgrades to the Mars substation. PJM’s Sami Abdulsalam said the lines between those substations would form a ring around Data Center Alley to feed energy into the facilities. 

The proposal also includes upgrades to several 230-kV lines and substations in Virginia running between the Dooms and Gordonsville substations, as well as to the Summit D.P.-Ladysmith CT 230-kV line. The work also includes a 500-kV line from the Otter Creek facility to the High Ridge substation. 

Abdulsalam said the RTEP window includes a significant number of deactivations, including the 1,295-MW Brandon Shores generator outside Baltimore. Given the lack of resources in the interconnection queue to replace Brandon Shores, new lines will be needed to prevent reliability issues in the Baltimore Gas and Electric (BGE) zone, he said. 

“If the transmission is delayed, something will have to give. Either load needs to be dropped … or some generation shows up. We don’t currently have any generation in the queue” that would come online in time, he said. 

About 11 GW of generation is expected to retire within the Window 3 time frame, which extends to 2028, while 7.5 GW of new data center load will come online. 

The proposal is expected to cost about $4.9 billion based on the cost estimates included in project submissions, while the independent estimates of those projects amount to $5.4 billion. 

Consumer Advocates Frustrated

A second first read of the proposal is scheduled for the Dec. 5 TEAC meeting, after which PJM plans to bring the recommendation to the Board of Managers for approval. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said advocates had been frustrated when previous RTEP windows were approved by the board in July with little time after the second read for stakeholders to submit comments. 

“There was significant frustration about the time given after the second read and what is the purpose of a second read,” he said. 

Philip Sussler, of the Maryland Office of People’s Counsel (OPC), said the RTEP process could be improved by creating a clearer way for comments to be submitted and for more documents to be public. Several members of the public requested information about how to write letters to the Board of Managers during the meeting. 

Residents who live along the proposed pathways questioned whether several aspects of the work would require new rights of way and expressed doubt about the feasibility of multiple transmission owners requiring certificates of public convenience and necessity (CPCNs). Maryland ratepayers also questioned why needs primarily in Virginia were being solved with transmission buildout across Maryland. 

PJM’s Augustine Caven said staff considered several factors in forming the proposal, including siting and permitting challenges. Other factors include cost containment provisions, constructability, outage coordination, development on new versus disturbed land and scheduling risks such as land and material procurement. 

“PJM recognizes the need for working the permitting process, the regulatory process in four states and that’s something that we’ll definitely have to tackle … but I think the idea here is to move forward with those conversations as quickly as possible and recognizing that it will be a parallel process trying to get the permitting in all four states,” Caven said. 

PJM said that much of the transmission work to the west would be brownfield, while the majority in the east would require new land or expanded rights of way. 

Posted on

Stakeholders Call for Structural Changes to CAISO’s Resource Adequacy Program

FOLSOM, Calif. — CAISO stakeholders last week questioned if the ISO’s resource adequacy fleet is sufficient to meet its needs.

At a Nov. 1 meeting of CAISO’s Resource Adequacy Modeling and Programming Design Working Group, Stephen Keehn, a senior adviser at Southern California Edison, said a change in the fleet requires a change in the way RA sufficiency is analyzed, and participants spent the bulk of the meeting dealing with how to adjust the framework.

Participants highlighted what they felt was a lack of visibility of non-RA resources, those resources that aren’t committed to serve an RA obligation of a load-serving entity within CAISO. Without transparency on what non-RA resources exist, what they’re being used for or whether they are under contract, market participants lack information on available capacity, therefore calling into question the efficiency of the RA program as a whole.

CAISO and its stakeholders are still in the early stages of grappling with how to redesign the RA program to account for changing conditions on the grid. The changes include a looming shortage of resources, increasing variability in energy supply and demand, and the evolving nature of resource planning frameworks in California and across the West.

The ISO is also contending with the rapid growth of energy-limited resources — such as batteries — on its grid, as well as the emergence in California of community choice aggregators (CCAs) as major LSEs, whose expansion has fragmented the landscape from a reliability perspective.

Representatives from CalCCA, Pacific Gas and Electric, Northern California Power Agency and the California Public Utilities Commission’s Public Advocates Office called for increased visibility into non-RA.

Lauren Carr, senior market policy analyst with CalCCA, said that while CAISO has visibility into all the resources in its footprint, it’s unclear what a resource is being used for if it’s not included in an RA showing.

“We don’t know, when we look at that list of non-RA resources, if it’s just that they’re not in a showing but could be dedicated to CAISO … or if they’re under contract or dedicated for some other use like substitution,” Carr said. “We think increased visibility into where supply that’s not on an RA showing is dedicated to would be useful.”

CAISO publishes monthly non-RA showings, though, leaving some confused about the lack of visibility.

“The ISO should have visibility into every resource within its operational footprint,” said Brian Theaker, vice president of Western regulatory and market affairs with Middle River Power. If a resource isn’t included in a showing, he explained, it’s likely because of substitution or holding back capacity for planned outages, which is a problem of its own.

Larger Structural Issues

In line with Theaker’s thinking, Chris Devon, director of energy market policy with Terra-Gen, suggested that the lack of visibility into non-RA resources is representative of broader structural issues such as modeling and planned outages that, if addressed, would eliminate the larger problem.

“I think that this issue of needing to increase visibility of non-RA is a symptom of the California RA overall,” said Devon.

Stakeholders also suggested addressing the default planning reserve margin before discussing visibility of non-RA. Sibyl Geiselman, market policy adviser with Public Generating Pool, questioned whether the PRM was high enough to both ensure reliability and meet a one-in-10 loss-of-load expectation, adding that an increased PRM could decrease the need for backstop procurement of non-RA resources.

“If you fix the upstream issue of making sure that the program is truly providing an adequate fleet,” said Geiselman, “then some of these downstream issues become hopefully less critical and less challenging because you have enough resources.”

While stakeholders went further into the weeds discussing the plausibility of multiyear contracts for RA resources, counting rules and backstop procurement, they consistently returned to the theme of needing to address CAISO’s entire RA modeling structure.

Posted on

Infrastructure and Coordination Hot Topics at NECBC Conference

The U.S. and Canada must increase interregional ties and cooperation to ensure reliability and affordability in the clean energy transition, government officials and industry executives from both sides of the border said at the New England-Canada Business Council’s 31st Annual Executive Energy Conference. 

Speakers at the conference, which met in Boston on Thursday and Friday, highlighted the potential co-benefits of offshore wind and hydropower, arguing that increasing the bidirectional connections between New England and Eastern Canada would boost the reliability and affordability of the future grid. 

Two days prior to the start of the conference, the U.S. Department of Energy announced it will become the anchor off-taker for the 1,200-MW Twin States Clean Energy Link project, which will connect Vermont and New Hampshire to Québec. (See DOE to Sign up as Off-taker for 3 Transmission Projects.) The line will allow for the bidirectional flow of electricity, enabling New England to import hydropower from Québec and export excess offshore wind energy depending on regional needs. 

Maria Robinson, director of DOE’s Grid Deployment Office, said at the conference the project will “enhance the capacity of the grid here in New England as well as provide additional resilience, reliability and efficiency between our two countries.” 

“The line will certainly deliver clean energy from Canada through hydropower to New England, and potentially at some point soon to Canada through solar and offshore wind here in the United States,” Robinson added. 

Serge Abergel of Hydro-Québec touted the potential benefits of using hydropower to balance out wind power and reduce curtailment instead of simply using hydropower as baseload. 

Hydropower “can essentially follow the patterns of wind,” Abergel said. “There is the potential for us to optimize and not send 24/7 but send energy when needed and get back excess power when there’s too much [in New England].” 

Hydro-Québec on Thursday announced its plans to spend about $100 billion to increase its production and grid capacity. The company is hoping to add up to 4,200 MW of hydropower production capacity, from both new dams and renovations to existing facilities. 

A Difficult Transition

Throughout the conference, speakers emphasized the vast amount of infrastructure that will be needed to meet the energy transition, as well as significant costs and regulatory challenges. 

“On the broader permitting side, very few people, I fear, appreciate the scope of what net zero looks like,” said Christopher Guith, senior vice president of the U.S. Chamber of Commerce’s Global Energy Institute, citing the need for new transmission lines and pipelines to move carbon dioxide or hydrogen. 

Guith said there’s bipartisan acknowledgement the permitting process needs major changes, and Democrats and Republicans in the Senate ultimately will need to “sit down like big boys and big girls and figure out how to get the 60 votes.” 

“It is so much easier to make targets than actually achieve them,” said Monica Gattinger, professor of political studies at the University of Ottawa. “There is a growing recognition of ‘holy crap, this is a lot more complicated than we realized.’” 

Gattinger added that navigating the sometimes competing needs for decarbonization and affordability is proving to be a challenge for policymakers across Canada. 

“We do a lot of tracking of public opinion at the University of Ottawa, and when people have their hats on as citizens, they are all for climate action,” Gattinger said. “But if they put on their hats as consumers … affordability and issues around siting start to become much more important.” 

Multiple speakers emphasized the importance of community engagement to ensure tangible local benefits, and education to connect new infrastructure needs and rising electric bills to climate change and emissions reductions, as a way to help bridge this gap. 

“It isn’t engineering that’s our issue in Canada, and I don’t think it is in the United States either” said Jacob Irving, CEO of the Energy Council of Canada. “The No. 1 most difficult thing is public acceptance of these projects.” 

Irving, along with most of the Canadian panelists and presenters, spoke about the importance of strong relationships with indigenous communities. Several of the speakers acknowledged the historical disregard that energy developers have often had for indigenous communities, although no indigenous groups from either country were represented among the conference’s speakers. 

“If you do not have sufficient partnership with indigenous communities, you do not have a project in Canada,” Irving said. 

More Gas?

Asked whether New England needs to increase its gas import capacity to meet growing demand on the grid, Stephen Woerner, president of National Grid New England, and Joseph Purington, CEO of Central Maine Power, said gas may be needed until clean energy can displace it. 

“Any shortage of fuel to make electricity jeopardizes reliability, and if we’re going to become more dependent on the [electric] system, we have to make sure that that doesn’t happen,” Woerner said. “Cost-effective long-term storage can help, but it doesn’t eliminate the need for fuel.” 

“We need the bridge to get from where we are today to where we’re going to be,” said Purington. “I think that’s going to have to be part of that solution as it is right now. Especially if we’re continuing to stumble out of the gate.” 

From left: Paul Hibbard, Analysis Group; Heather Chalmers, GE Canada; Joseph Purington, Central Maine Power Company; Stephen Woerner, National Grid New England | © RTO Insider LLC

Enbridge announced earlier this fall it’s pursuing a project to expand pipeline capacity into New England to address projected demand increases from both the gas network and the grid. The project has been heavily criticized by local climate and environmental groups. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Meanwhile, Jamie Van Nostrand, chair of the Massachusetts Department of Public Utilities, expressed concern in September about the state’s gas utilities continuing to add connections to the distribution network, saying it seems to be “business as usual in the natural gas industry with respect to new residential hookups and continuing levels of load growth.” 

Posted on

FERC Environmental Justice Chief Explains Commission’s Efforts

The National Association of Regulatory Utility Commissioners hosted a webinar last week with FERC Senior Counsel on Environmental Justice and Equity Conrad Bolston, who explained how the commission has been stepping up its work around environmental justice since 2021.

Bolston took over the role in March after Montina Cole, the first person with the job, left late last year. Working out of the Office of the General Counsel, Bolston leads a small team focused on the subject.

“My primary mission is to provide leadership and steer implementation of environmental justice and equity policies, principles, practices and procedures at the commission,” he said.

Sometimes “Diversity, Equity and Inclusion” is conflated with environmental justice, but Bolston’s work is focused on the latter exclusively.

“On a day-to-day [basis], that might mean assisting in reviewing and editing documents, from NEPA [National Environmental Policy Act] documents to orders, draft rules [and] policies, or holding trainings and outreach like the one we’re having here today,” he added.

Environmental justice has a number of definitions, but Bolston said it means ensuring citizens are treated fairly regardless of their racial, economic and national backgrounds, or any other attributes when it comes to environmental regulation.

President Joe Biden in April issued Executive Order 14096 on recommitting the U.S. to environmental justice, which it defines as “the just treatment and meaningful involvement of all people, regardless of income, race, color, national origin, tribal affiliation or disability in agency decision-making and other federal activities that affect human health and the environment.”

The order explains the goal will be achieved when everyone enjoys the same degree of protection from environmental and health hazards, and equal access to the decision-making process.

As an independent agency, FERC voluntarily has complied with that and related executive orders, with both Chair Willie Phillips and his predecessor, Richard Glick, making it a priority, Bolston said. Under Glick, FERC released an equity action plan, which laid out its goals for improving equity and environmental justice in its processes.

A related term is “energy justice,” which has been defined by the Department of Energy as “the goal of achieving equity in both the social and economic participation in the energy system while also remediating social, economic and health burdens on those disproportionately harmed by the energy system,” Bolston said.

“I think if there’s a common theme, it’s that some communities face systemic barriers that are either procedural or substantive that might result in inequitable regulation,” he added. “And I think that achieving fair regulation and just regulation necessitates acknowledging the systemic barriers and tackling them head on.”

FERC has been increasing its work in the area broadly, not just on the team Bolston leads in the Office of General Counsel. The Office of Public Participation (OPP), founded in 2021, reaches out to the general public, and the Office of External Affairs is the chief contact with Congress, states, tribes and other levels of government. The Office of Energy Projects, which reviews natural gas and hydropower infrastructure, has its own groups dedicated to public outreach and environmental justice, Bolston said.

OPP is focused on community outreach and engagement, education and technical assistance, lowering barriers to public participation before the commission and internally advocating for improved public accessibility. The office is non-decisional, which means its staff can talk about all the issues before the regulator, Bolston said. The office helps everyday citizens better understand the complex issues FERC deals with so they can be better involved in its work.

The recent focus on these issues has made a mark on FERC’s NEPA documents, its environmental reporting and even the orders it issues, Bolston said.

“That’s not to pat the commission on the back and say that ‘we’re done with our work’; it’s just more of a way to level set for anyone out there that hasn’t seen any of these analyses, or maybe hasn’t seen the evolution,” Bolston said.

One of the more high-profile steps FERC has taken on the issue was to hold an environmental justice roundtable this year, on which it has taken comments. (See FERC Gets Advice, Criticism on Environmental Justice.)

“Those comments are not going to lie in some docket and never be seen,” Bolston said. “We actually read all the comments. We’re in the process of ingesting those comments and summarizing them. We’re in the process of taking those comments and adjusting our policies, practices and procedures, both internally and potentially externally.”

Posted on

Dominion Highlights Successful Offshore Wind Development on Q3 Call

Dominion Energy reported third-quarter earnings Friday, with executives focusing on why its offshore project is successful and on its business review that is nearing completion. 

“Our fully regulated offshore wind project is on time and on budget and is expected to save customers more than $3 billion in fuel costs over the first 10 years of operation while creating hundreds of jobs and millions of dollars of local economic benefit,” CEO Robert Blue said. 

The Coastal Virginia Offshore Wind (CVOW) project is being built off the coast of Virginia Beach and is planned to have 176 turbines producing a nameplate capacity of 2.6 GW. The wind plant won final approval from federal regulators earlier in the week and saw the delivery of the first monopiles to a nearby port facility in late October. (See BOEM Approves Coastal Virginia Offshore Wind.) 

“The next transport ship for monopiles is expected to be loaded at the factory later this month and delivered to the port in December,” Blue said. “Also worth noting is that turbine blades and the cells remain on track with a fixed production schedule and mature existing manufacturing facilities.” 

The monopile delivery included a ceremony with politicians from across the spectrum in the commonwealth, with Blue noting the project has “bipartisan support” a few days before an election that could give the Republican Party control over both chambers of the legislature and the governor’s office for the first time in years. The polling in the election shows a very close race. 

The project has a priority position in the offshore wind supply chain, and Dominion has proven successful at getting approvals from the required regulators, Blue said. 

The firm expects to complete CVOW by the end of 2026, and most of its $9.8 billion in costs already are fixed. 

“We updated the project expected [levelized cost of energy] in our filing earlier this week to approximately $77/MWh, as compared to our previous range of $80 to $90,” Blue said. “The decrease reflects updated and refined estimates around production tax credit, cost of capital and [renewable energy credit] values.” 

The project’s total lifetime costs are expected to come in well below the ceiling set by the legislature when it approved the development. 

Dominion will have invested $3 billion into CVOW by the end of the year, and the rest of the $9.8 billion is 92% fixed, with just the costs of interconnecting the project to the transmission grid, some commodities such as fuel used for construction, and installation and project oversight costs yet to be nailed down, Blue said. 

“We’ve been very clear with our team and with our vendors that delivery of an on-budget project is the expectation,” he added. 

Dominion has been in talks with counterparties to sell a minority share in CVOW to help raise the remaining equity. Blue said those talks have generated much interest. 

“It’s in the long-term best interest of our customers and shareholders that we make the right, not just the expedient, decision,” Blue said. “A properly structured partnership with the optimal counterparty is an attractive option. But only if the terms of a potential transaction make sense for our customers and shareholders.” 

A decision picking a counterparty for the wind project is the last part of Dominion’s ongoing business review, which has seen it sell its share of the Cove Point LNG project and exit the natural gas utility business, Blue said. The firm expects to make a choice in the next few months. 

The review was launched after investors expressed worries about the firm’s earnings, the Virginia regulatory model (which was revised early this year) and its balance sheet, Blue said. 

“The review must comprehensively and finally address the foundational concerns that have eroded investor confidence over the last several years,” Blue said. “This can’t be a series of partial solutions that leave key elements and risks unaddressed. That’s how we’ve approached this top-to-bottom review.” 

Posted on

NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules

RENSSELAER, N.Y. — Stakeholders at NYISO’s Nov. 4 Interconnection Issues Task Force meeting expressed reservations about the grid operator’s proposed interconnection queue rules, citing concerns over the length of time to make project decisions and deposit requirements.

Following the ISO’s presentation of proposed study deposits and withdrawal penalties, Troutman Pepper partner Stu Caplan, who represents the New York Transmission Owners, highlighted the uncertainty surrounding the transition to NYISO’s proposed phased cluster approach. “There’s a big variable that we don’t know the answer to yet, the feasibility of the timeframes to complete the [interconnection] studies,” he said.

NYISO’s proposal to comply with FERC Order 2023 would give developers a seven-day window after each phase to decide whether to proceed or withdraw from the queue based on results from the preceding study phase.

The ISO proposes to charge interconnection applicants a non-refundable $10,000 fee, as well as a one-time study deposit ranging from $100,000 to $250,000 based on the size of the proposed project. For capacity resource interconnection service-only projects, the deposit would be $50,000. Additionally, in lieu of regulatory milestones, developers would be required to make commercial readiness deposits to progress through the queue phases, with amounts escalating at each stage: depositing $4,000/MW to enter Phase 1, depositing the greater of either the Phase 1 deposit or 20% of the cost estimate determined in Phase 1 to move into Phase 2, and 100% of a project’s cost estimate to move out of Phase 2.

Proposed study deposits for certain generation facilities seeking interconnection | NYISO

NYISO also outlined penalties for developers who withdraw from the queue: up to 100% of their study deposit, plus 20% of the Phase 2 deposit if they withdraw during the decision period at the end of Phase 2.

Reid Wagner, a clean energy markets analyst with the Alliance for Clean Energy New York, said the ISO’s proposed timelines are too short. “Seven days could be hard for some companies, particularly international ones, to secure the funding in that short period of time,” he said.

ISO attorney Sara Keegan responded that developers would “have ample time to get their ducks in a row” and make decisions about whether to move a project forward through the queue. Project cost estimates would be available “well before the seven-day trigger,” she said.

Wagner then asked if the ISO would consider conducting a “harm test” at the end of each phase, as currently done by MISO, to “test how much harm a withdrawn project has caused to the other queued projects.”

Keegan responded that NYISO is not considering a harm test akin to MISO’s. “It is perhaps overly complicated, and we feel like that would make it incredibly difficult to administer, since we would end up needing a whole department to administer withdrawal penalties,” she said.

Stakeholders also expressed frustration with NYISO’s initial plan to accept only cash for study deposits, rather than allowing the use of credit.

Saad Syed, grid and interconnection manager with OW Ocean Winds, argued for flexibility, saying, “putting up much money in cash in such short intervals seems very difficult, on top of the withdrawal penalties that may occur. So, I strongly recommend using at least an ability to use letters of credit for [these deposits], since otherwise it might become untenable.”

Echoing this sentiment, Abhishek Josh Ghosh, associate director with Cypress Creek Renewables, recommended that NYISO draw insights from PJM, which allows letters of credit in its processes. “It would be nice to have some flexibility in posting these deposits,” he said.

Thinh Nguyen, NYISO senior manager of interconnection projects, acknowledged these concerns and committed to revisiting the payment options. “We are still considering whether a letter of credit is another option. But as you are aware, when we receive letters of credit, that means we have to do some kind of credit check on that entity,” he said. “That’s why we want to make sure that whatever the process we want to use is able to support and meet the very tight defined timelines.”

FERC last month extended the Order 2023 compliance deadline from Dec. 5 to April 3, 2024. (See FERC Extends Interconnection Queue Compliance Deadline.)

Despite the extension, Keegan informed the IITF that NYISO still intends to submit a partial compliance filing by Dec. 1. (See NYISO Plans Early November Filing for Partial Order 2023 Compliance.) The IITF will reconvene Nov. 14.

Posted on

$10B Fund for Gas Plants on Texas Ballot

Texas voters will finish casting their ballots Tuesday on Proposition 7, a constitutional amendment that would create a nearly $10 billion state fund for dispatchable energy that opponents say amounts to a handout for the natural gas industry.

A result of legislation passed earlier this year, the Texas Energy Fund is a $7.2 billion low-interest loan program intended for the development of up to 10 GW of natural gas plants. Some $5 billion will be set aside for 20-year, 3% interest loans to build new generation with at least 100 MW of fully dispatchable capacity. Power plants that come online before June 29 are eligible for bonus payments.

Another $2.8 billion will be dedicated to grants for infrastructure improvements in non-ERCOT regions and for grants to strengthen resiliency at hospitals, fire stations and other critical facilities through microgrids.

ERCOT considers energy storage as a dispatchable resource, but it is restricted from the program.

Prop 7 is supported by gas heavyweights such as ConocoPhillips, Koch Companies and Valero Energy, along with industrial users. They say the amendment will stabilize a creaky ERCOT grid that has struggled to meet growing demand since the 2021 winter storm.

The opposition, primarily environmental and consumer groups, object to what they call a “cleverly disguised handout to Texas gas companies that are already making record profits.”

“Proposition 7 is the key to building a stronger and more resilient energy infrastructure, ensuring that we always have the electricity we need, when we need it,” state Sen. Charles Schwertner, who guided Senate Bill 2627 through the Legislature, said on X, the social media platform formerly known as Twitter.

“We don’t need to subsidize power plants in a private market with taxpayer funds,” the Sierra Club’s Cyrus Reed countered on X.

During debate over the bill this spring, several generators came out against SB2627. The Association of Electric Companies of Texas said it was concerned about government intervention in the competitive wholesale market. Other company representatives said the loans are similar to other regional programs that create market distortions.

“If you’re a gas power plant developer, why would you ever develop another power plant in Texas without a grant and a low-interest loan? Do Texans need to put up billions more the next time we need more energy?” Stoic Energy CEO Doug Lewin said, while admitting “there’s virtually no chance” Prop 7 will fail.

The amendment enjoys wide public support, according to a poll released last month by the University of Houston and Texas Southern University. The survey found 68% of voters favor the amendment, with 15% opposed and 17% undecided, despite its costs filtering down to ratepayers.

ERCOT called numerous conservation alerts and a Level 2 energy emergency alert during a record-breaking summer this year. The grid operator set 10 records for peak demand this summer, topping out at 85.46 GW after just exceeding the 80 GW threshold in 2022. Four years ago, peak demand was 74.82 GW. (See ERCOT Voltage Drop Leads to EEA Level 2.)

The fund would be endowed with $10 billion taken from the state’s general revenue fund. More money from the revenue fund could be transferred into the Energy Fund.

Early voting began in Texas on Oct. 23.

Posted on

New Report Finds MISO, PJM Could Save Billions Through Interregional Tx Expansion

A new report from the American Council on Renewable Energy (ACORE) concludes MISO and PJM could save ratepayers $15 billion in a little more than a decade if they concentrate on building more interregional transmission.

The report, Billions in Benefits: A Path for Expanding Transmission between MISO and PJM, concludes more interregional ties between the Midwest and mid-Atlantic could reduce customer costs primarily through curbing the need for new generation capacity.

ACORE, Grid Strategies, the Solar Energy Industries Association (SEIA) and the American Clean Power Association (ACP) had a hand in producing the report.

Grid Strategies Vice President and report author Michael Goggin said greater interregional transfer capability along the seam would allow MISO and PJM to “tap into” their geographic diversity from renewable energy stretching from the Dakotas to Virginia. In turn, PJM and MISO Midwest could scale back capacity needs by about 11 GW. He said it’s unlikely extreme weather envelops both regions simultaneously and both have depleted capacity reserves.

Michael Goggin, Grid Strategies | Grid Strategies

During a Nov. 2 teleconference to discuss report findings, Goggin said if MISO-PJM lines are built, reduced capacity needs alone could save MISO and PJM ratepayers about $9 billion by 2035. The report also expects that expanded interregional transmission could provide more than $1 billion in energy market savings per year by reducing transmission congestion between the RTOs.

Goggin said more transmission capacity is valuable to maximizing existing generation during storms or heat waves “because of how weather systems move across the country,” with either MISO or PJM peaking first and then being able to export lower-cost power.

“In the likely scenario that solar penetrations are higher in PJM and wind penetrations are higher in MISO, PJM will export power to MISO during the day and during the summer, while it will import wind power from MISO at night and during the fall, winter and spring, when wind output tends to be highest,” Goggin wrote in the report.

The report didn’t analyze greater links between PJM and MISO South due to the subregion’s distance. It focused instead on the “long and tangled border across Illinois, Indiana, Michigan and Kentucky.”

Goggin said MISO-PJM interregional transmission “functions like an insurance policy, and we need to plan and pay for it accordingly.” He urged MISO and PJM to “look across the seam” and plan beyond their footprints.

Goggin said MISO and PJM’s interregional planning needs a “proactive, multivalue planning approach” that accounts for the most economic future fleet mix alongside state decarbonization goals and isn’t simply reactive to interconnection queue entrants.

“There are billions of dollars on the table. I think there’s a way PJM and MISO can come together and make this work,” Goggin said.

Goggin said congestion costs between MISO and PJM due to constraints last exceeded $1.7 billion in the 2021/22 planning year.

“This adds up to a large amount of money,” he said.

He also said from 2011-2020, interregional transmission builds nationally have averaged just 70 miles per year, a “dismal” figure.

Goggin recommended MISO and PJM model their interregional planning using the success stories from SPP, ERCOT and MISO’s own regional processes. He said MISO and PJM also could model planning after MISO and SPP’s Joint Targeted Interconnection Queue (JTIQ) study, which is meant to interconnect generation at the seams.

Goggin pointed out that PJM’s 2014 Renewable Integration Study and MISO’s 2017 Regional Transmission Overlay Study yielded similar, possible high-voltage solutions in northern Indiana and Illinois and at the MISO seam at the Iowa border.

He said MISO and PJM’s current affected system studies — the RTOs’ means of studying interconnecting generation near the seam — are designed so additional transmission upgrade costs are tacked on nearly at the finish line of the RTOs’ queues, a “nasty surprise that reshuffles the entire queue.”

Goggin said MISO and PJM should allow merchant transmission developers to “propose interregional solutions and be fully compensated for the value their projects provide.” He said projects like the Grain Belt Express and SOO Green HVDC Link are poised to be valuable in increasing links between the Midwest and mid-Atlantic and they should be accounted for in MISO and PJM planning processes.

However, Goggin warned PJM lags in building proactive, large projects even regionally, focusing instead on local reliability projects to replace aging infrastructure.

SEIA Counsel and Director of Energy Markets Melissa Alfano said more powerful interregional connections would allow the country to move away from “toxic” thermal resources that often fail during extreme weather events, especially in recent winter storms. She said a stronger interregional system also would help alleviate cascading project withdrawals in the MISO and PJM generator interconnection queues.

“All of these benefits are undeniable. … Yet here we are not building interregional transmission,” Alfano said.

She added that aside from groups urging MISO and PJM to do more, FERC should issue a rule on interregional planning standards. She said it seems meaningful interregional planning between MISO and PJM won’t happen absent a FERC mandate.

Jeff Dennis, deputy director of transmission at the Department of Energy’s Grid Deployment Office, said significantly more interregional transfer capacity between the Midwest and mid-Atlantic is one of the key needs outlined in last week’s National Transmission Needs Study from the DOE.

Katharine McCormick, assistant director of policy division at the Illinois Commerce Commission, said both PJM and MISO have been consistently warning over 2023 that they’re facing reliability risks by the end of the decade. She said building interregional transmission would aid reliability.

ACP Senior Counsel Gabe Tabak said DOE’s recent funding assist for MISO and SPP’s JTIQ $2 billion portfolio of 345-kV lines is a good starting point to encourage more interregional planning. (See DOE Announces $3.46B for Grid Resilience, Improvement Projects.)

“Meaningful” federal cost sharing is a way to “unstick the process that we all know needs to be advanced,” Tabak said.

MISO, PJM Mum on Conclusions

Both MISO and PJM said they still are reviewing the study and couldn’t speak to the findings.

“MISO is committed to interregional coordination in both planning and operations,” spokesperson Brandon Morris said in an emailed statement to RTO Insider.

At the Organization of MISO States’ annual meeting at the end of October, MISO Senior Vice President of Planning and Operations Jennifer Curran said MISO will attempt to plan a JTIQ-style portfolio with PJM. However, she warned that MISO and PJM employ different planning styles that are difficult to reconcile. (See OMS Leaders Reminisce on 20 Years at Annual Meeting.)

MISO and PJM have approved one large interregional market efficiency project in 2020 and four sets of smaller transmission projects aimed at relieving congestion since 2017.

Still, the nonprofits that signed onto the report are hoping for more from MISO and PJM.

“The U.S. Department of Energy has found that the MISO-PJM seam has the greatest need for expanded interregional transmission ties,” ACP Vice President of Markets and Transmission Carrie Zalewski said in a press release. “In fact, the intertie with MISO accounts for around 80% of PJM’s total need for interregional transmission. These grid operators must collaborate on the transmission planning necessary to bridge this gap, preserve reliability and benefit millions of customers.”

“Interregional transmission lines have helped save American lives during extreme weather events, yet today’s transmission planning processes do not value the added reliability they provide our grid,” ACORE CEO Gregory Wetstone said. “Consumers should not be forced to endure outages when study after study shows additional line capacity would help keep the lights on and reduce power costs.”

Posted on

AEP Discloses SEC Subpoenas, Investigation

American Electric Power has revealed it’s been issued two subpoenas from the Securities and Exchange Commission (SEC) as part of an investigation into the company’s involvement in Ohio legislation that eventually led to a politician’s bribery conviction. 

In its regular quarterly 10-Q disclosure filing to the SEC on Nov. 2, AEP said it had received subpoenas from the commission in 2021 and 2022. The first subpoena requested documents related to the passing of Ohio House Bill 6 and to the company’s policies and financial processes. The second sought additional documents related to the investigation. 

AEP said it is “cooperating fully” with the SEC’s investigation and is discussing resolving the inquiry with the commission and “potential claims under the securities law.” 

“The outcome … cannot be predicted and could subject AEP to civil penalties and other remedial measures,” AEP said in the filing. “Management is unable to determine a range of potential losses that is reasonably possible of occurring, but management does not believe the results of this investigation or a possible resolution thereof will have a material impact on results of operations, cash flows or financial condition.” 

The Columbus, Ohio-based company said it “does not believe that AEP was involved in any wrongful conduct in connection with the passage of HB 6.” 

The legislation provided $1 billion in subsidies to a pair of coal plants in which AEP has a 43% stake and two nuclear plants. AEP lobbied for the bill’s passage, which resulted in the federal indictment of Ohio House Speaker Larry Householder for his role in taking bribes from another in-state utility, FirstEnergy, to pass the legislation. Householder was convicted and imprisoned earlier this year. (See Former Ohio House Speaker Householder Sentenced to 20 Years in Prison.) 

AEP executives did not address the 10-Q filing during its quarterly earnings conference call with financial analysts, who did not ask any questions about it. 

The disclosure took a little shine off AEP’s reported quarterly earnings of $954 million ($1.83/share). That was an improvement from the same period in 2022, when earnings were $684 million ($1.33/share). 

AEP CEO Julie Sloat said the company continues to de-risk and simplify its business. She pointed to the completed sale of its 1,365-MW unregulated renewables portfolio that netted about $1.2 billion, and the sales processes for the company’s retail and distributed resources businesses that remain on track. 

AEP continues its strategic review of the Transource Energy joint venture with Evergy. Sloat said the review is expected to be completed before the year is up. 

Sloat said the company’s commercial load growth was up 7.5% year over year, attributing the vast majority of the increase to data centers in Ohio and Texas. 

AEP’s share price closed Friday at $79.72, a gain of $3.24 (4.2%) over the last two days of the week. 

OGE Earnings Down

OGE Energy, parent company of Oklahoma Gas & Electric, also reported third-quarter results Thursday, delivering earnings of $241.9 million ($1.20/diluted share). That compared unfavorably with the same period a year ago, when earnings were $262.8 million ($1.31/diluted share). 

Although earnings were down year over year from 2022, OGE CEO Sean Trauschke told financial analysts the “solid” performance was due to operational excellence. OG&E sent a new hourly peak on Aug. 21 during the height of the summer’s heat, and did so without calling for public conservation, he said. 

“Our system was designed, built and operated for conditions like we saw this summer, and I’m proud of our team for always meeting our customers’ need for reliable and safe electricity, and always keeping affordability top of mind,” Trauschke said. 

The company’s share price gained 75 cents after earnings were posted, closing Friday at $35.25.