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November 2, 2024

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MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects

CARMEL, Ind. — MISO is scrapping an earlier suggestion that it accept and study expedited transmission project requests quarterly. 

Now the grid operator is turning to its stakeholders for ideas on how to handle mounting requests for accelerated approval.   

Senior Manager of Expansion Planning Amanda Schiro said while batching expedited project review requests into quarterly studies works for MISO internally, members have indicated a quarterly schedule likely would result in missed construction deadlines. However, Schiro said MISO still hopes to put a “more defined time frame” on expedited request submittals and cut down on receiving them “whenever.”  

“Time is truly the driving factor we need to take into account,” Schiro said during a May 1 Planning Subcommittee meeting. “We want to continue to meet the needs of this community.”  

Schiro also said members had concerns that quarterly groupings that contain especially large transmission projects would hold up other projects lining up for expedited treatment.  

MISO late last year said it’s become inundated with expedited review requests as load flourishes and that it likely needs to rethink its approach to transmission projects that cannot wait until the usual December board approval to begin construction. (See MISO to Re-examine Schedule for Reviewing Expedited Tx Projects.) The grid operator suggested this year a quarterly schedule might solve the problem.  

MISO currently accepts and studies expedited projects reviews every month as they come in, a schedule Schiro said is difficult to manage. The RTO conducts individual studies on the expedited requests to confirm the projects won’t result in reliability violations before allowing them to proceed ahead of the annual Transmission Expansion Plan cycle.  

Schiro asked stakeholders to decide whether they would back an every-other-month timetable for studying expedited reviews and if they would support adding a requirement that developers pay study deposits and fees alongside their requests for expedited treatment. 

“Part of putting a fee in place would allow MISO to supplement our staff to accommodate all the requests coming in,” she explained.  

Schiro also asked stakeholders how they feel about removing the requirement that the Planning Advisory Committee’s approval of expedited reviews occur strictly during meetings.  

“Are there ways we can engage with the PAC outside of a meeting?” Shiro asked.  

Schiro said she didn’t think the PAC has ever rejected a MISO study finding of no reliability harms for an expedited review. However, WPPI Energy’s Steve Leovy said the PAC in recent years hasn’t been granting explicit approval of expedited reviews, with study results merely posted with meeting materials and not discussed during meetings.  

Schiro said MISO views a lack of objections from PAC members as approval of its expedited review findings.  

MISO and stakeholders will continue to mull changes to the expedited project schedule at upcoming Planning Subcommittee meetings.  

NextEra Asks MISO to Study New Load and Generation Duos

Additionally, the Planning Subcommittee this year will address NextEra Energy’s request that MISO work out a method to study new load and generation concurrently when they’re proposed as a double act.  

NextEra Energy approached MISO publicly in April and asked it to craft specialized rules in its interconnection queue to recognize when new generation is entering the queue for the sole purpose of supporting a specific new load, such as a large data center.  

NextEra pointed out that large industrial loads increasingly want new renewable energy sources onsite, but MISO’s interconnection rules aren’t designed to account for them in tandem. NextEra said MISO and its transmission owners take stock of load growth through the annual Transmission Expansion Plan (MTEP), with that process separate from MISO analyzing new generation through its interconnection queue. NextEra said that to sync up generation and load dependent on one another, either generation owners must secure their interconnection agreements before MTEP studies kick off that year or the owners of the new load in question must get their approval to join the system before queue studies begin.  

NextEra said the uneven process results in either the load or generator being subject to network upgrades without knowing the upgrade costs the other will face. The company said MISO should allow for co-located load and generation behind the same point of interconnection and recognize that “neither will show up alone if the other is not built.”  

NextEra asked that MISO devise a way to study the load a generator is designed to support alongside the generator itself in its interconnection queue process. The company also asked that the interconnection agreements MISO issues to such generation be contingent on the load showing up.  

Stakeholders at the May 1 Planning Subcommittee meeting said the need to address growing load is timely and the topic should be placed on the subcommittee’s calendar as soon as possible. WEC Energy Group’s Chris Plante said the issue overlaps with the need for improvements with expedited transmission project reviews, because many expedited reviews are compelled by new load. 

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WEIM Q1 Benefits Report Adds to NW Cold Snap Debate

CAISO’s first-quarter Western Energy Imbalance Market benefits report offers another footnote to the debate over the market’s role in responding to the January deep freeze that brought parts of the Northwest to the brink of rolling blackouts. 

“The Western Energy Imbalance Market’s cumulative benefits rose to $5.49 billion during the first three months of this year, while also demonstrating the value of regional coordination by helping maintain system reliability during a January cold snap that stressed grid conditions in the Northwest,” the ISO said in a press release accompanying the April 30 report. 

The report shows the WEIM produced $436.3 million in economic benefits for its participants during the first three months of 2024, a 4% increase from a year earlier and a new first-quarter record. 

That bump was partly from the addition last spring of three new members, including the Avangrid balancing authority area in the Northwest, El Paso Electric and the Western Area Power Administration Desert Southwest Region (WALC). The market now includes 22 participants representing over 80% of the load in the West — including CAISO itself. 

The unsettled debate over the Northwest cold snap began to take shape shortly after the Jan. 12-16 weather event triggered five energy emergency alerts (EEAs) in the Northwest, including one critical EEA 3 in Idaho Power’s territory. 

The dispute has centered on disagreements over how vital CAISO and the WEIM were in supporting the Northwest during the event, with some parties contending that the region’s utilities relied heavily on imports from the Desert Southwest and Rockies region to support operations, while others argued the ISO and its real-time market were key to facilitating those transfers. 

The debate has become something of a proxy for the broader competition for market participants between CAISO’s Extended Day-Ahead Market (EDAM), which builds on the WEIM, and SPP’s Markets+ day-ahead offering, which has attracted strong interest in the Northwest and Arizona. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

The Economics of Rebalancing

The quarterly benefits report adds modestly to the 80 pages of analysis CAISO released March 6 on the WEIM’s January performance. 

That paper focused on how the WEIM helped manage energy flows throughout the West during the cold snap, attempting to answer critics arguing that the ISO’s status as a net importer of energy during the five-day event offered evidence that the Southwest was the real source of the Northwest’s rescue. The analysis noted that the WEIM transfers into CAISO were not the product of limited supply within the ISO but the result of the “economic displacement and opportunities optimized by the market and bounded by the transmission and transfers availability in the wider footprint.” (See NW Freeze Response Shows WEIM Value, CAISO Report Says.) 

The benefits report riffed off that theme. 

“During the winter conditions experienced in January 2024, the Western Energy Imbalance Market economically rebalanced supply across the West to meet increasing demand as real-time conditions evolved over the Martin Luther King Jr. Day weekend,” it said. 

On the surface, the data contained in the report seems to back up that contention, even if it doesn’t drill down into specific days. The data show that in January, the CAISO BAA facilitated 350,271 MWh of WEIM wheel-through transfers, a 46% increase from the same month a year earlier. The ISO’s net exports for the month also increased 46%, to 363,837 MWh, while net imports decreased by 21% to 353,353 MWh. 

The areas with the next-largest volumes of January wheel-throughs were Arizona Public Service (158,625 MWh), WALC (130,870 MWh) and PacifiCorp’s West BAA (92,240 MWh). 

The second-largest net importer of energy through the WEIM that month — behind CAISO — was British Columbia’s Powerex at 336,809 MWh (compared with 177,954 MWh in January 2023), as the province and other parts of the Northwest dealt with record electricity demand during the cold snap. 

“The market identified least-cost solutions within the wider WEIM footprint, transferring lower-cost electricity from the Southwest into California. These transfers allowed exports scheduled in the day-ahead and hour-ahead markets to flow to the Northwest, replacing more expensive generation while managing congestion on key transmission lines,” the report said. 

According to the report, PacifiCorp earned the largest share of WEIM benefits during the first quarter, at $73.83 million, followed by CAISO ($54.33 million), the Los Angeles Department of Water and Power ($46.80 million), Puget Sound Energy ($25.88 million) and Powerex ($24.83 million). 

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PSEG Sees New Market for Nuclear in AI, Data Centers

Public Service Enterprise Group is looking to use excess capacity at its three South Jersey nuclear generators to provide clean energy for data centers and artificial intelligence development projects that could be sited in the state in the future, CEO Ralph LaRossa said in the company’s first-quarter earnings call April 30. 

The proposal is part of the company’s ongoing effort to “pursue potential investment opportunities for future regulated growth,” LaRossa said. Other possibilities include doing work to upgrade the state’s transmission lines in preparation for offshore wind energy, he said. 

PSEG is the majority co-owner of Salem Generating Station Units 1 and 2, with Constellation Energy, and is the sole owner and operator of the Hope Creek plant. It recently informed the Nuclear Regulatory Commission that it intends to seek operating license extensions that would add an additional 20 years to the plants’ life. (See PSEG Plans for 80-year Nuclear Generation in NJ.) 

LaRossa said the nuclear fleet is “pursuing multiple growth paths with modest capital spending needs” and that thermal upgrades planned for one of the Salem units “could potentially add up to 100 MW of additional capacity.” That capacity could “qualify for clean hydrogen tax credits,” he said, created by the Inflation Reduction Act that in some circumstances can be awarded to nuclear plants that produce hydrogen. 

“Beyond these opportunities in nuclear, there has been discussion lately about the potential for direct power sales to data centers from our three-unit Artificial Island site,” he said, referring to where the nuclear plants are located. At present, the site has additional space available. 

“We’ve had discussions related to both sides of the meter in recent months,” LaRossa said. They have included “new business inquiries at PSEG for midsized data center construction of approximately 50 to 100 MW and behind-the-meter inquiries for co-located facilities that prioritize highly reliable, carbon-free baseload power from existing facilities, all without the challenges faced by non-dispatchable generation,” such as wind and solar. 

“This data center opportunity has the potential to create a nexus between economic development and [state] energy policy,” LaRossa said. 

Offshore Infrastructure

In a separate issue, LaRossa said the company is still waiting for guidance from the U.S. Treasury on how it can apply for production tax credits, also available under the IRA, to support the three nuclear plants.  

PSEG and Constellation in November withdrew from New Jersey’s Zero Emission Certificate (ZEC) program, which had awarded subsidies of $300 million a year since 2019 to keep the plants open. PSEG said it would instead focus on seeking federal tax credits.  

The companies’ withdrawal from the program has effectively shut it down, with the Board of Public Utilities approving an order in February that will end the fees customers have paid to fund the subsidies. (See NJ Closes Nuclear Subsidy Process as PSEG Looks to Feds.) 

The three plants generated 42% of the electricity produced in the state in 2022 and are key to Gov. Phil Murphy’s goal of reaching 100% clean energy by 2035. In addition, Murphy has outlined plans to create an AI hub at Princeton University, and on April 11, he spoke at the state’s first AI Summit. 

LaRossa said that as part of the company’s search for “competitive transmission solicitations in the Mid-Atlantic region,” it submitted bids in April to the BPU’s “pre-build infrastructure solicitation, for which the selected projects are expected to be announced in the second half of 2024. The solicitation is designed to award projects that can connect offshore wind farms to the grid through the onshore infrastructure approved in October 2022. (See NJ BPU OKs $1.07B OSW Transmission Expansion.) 

In addition, PSEG is evaluating a possible bid for New Jersey’s second solicitation for offshore transmission infrastructure under the second State Agreement Approach with PJM, he said. The company is looking to participate in “PJM’s 2024 Regional Transmission Expansion Plan Window One solicitation, which is expected to include the impacts of higher load growth forecasts that have been influenced by increased electrification expectations and data center load growth throughout PJM.” 

PSEG’s first-quarter results for 2024 fell short of those in 2023. The company reported net income of $532 million ($1.06/share), compared with $1.287 billion ($2.58/share). Non-GAAP operating earnings for 2024 were $657 million ($1.31/share), compared with $695 million ($1.39/share) in the same period in 2023. 

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SPP Markets+ Tariff Sparks Concerns for PacifiCorp, NV Energy

Although PacifiCorp has formally committed to joining CAISO’s Extended Day-Ahead Market (EDAM), the utility is still voicing concerns about a competing day-ahead market, SPP’s Markets+, in a FERC filing. 

In its April 29 comments, PacifiCorp asked FERC to reject the proposed Markets+ tariff, but allow SPP to refile it without the tariff’s “Markets+ transmission contributors” transmission availability option. The utility said the option “purportedly empowers transmission customers to ‘contribute’ their transmission rights on nonparticipating systems.” 

In a separate filing, NV Energy also expressed concerns regarding the “transmission contributors” option. 

But other comments filed by the April 29 deadline — including those from three Arizona utilities and a member of the Arizona Corporation Commission — supported the Markets+ tariff. 

Transmission Providers, Contributors

PacifiCorp became the first Western entity to formally commit to one of the two competing day-ahead markets April 26 when it signed an implementation agreement with CAISO for EDAM. (See PacifiCorp Fully Commits to CAISO’s EDAM.) 

But as a major Western grid operator, PacifiCorp is concerned about potential impacts of transmission provisions in Markets+. 

Under the proposed tariff, one source of transmission would be from transmission service providers who sign a Markets+ agreement. Transmission could also come from market participants who contribute their rights from transmission providers who aren’t Markets+ participants. 

But it’s unclear how those so-called Markets+ transmission contributors “would be entitled to make such decisions on behalf of transmission providers,” PacifiCorp said. 

In addition, allowing transmission customers to potentially offer transmission rights to different day-ahead markets “is uneconomic and inefficient,” PacifiCorp said, and could potentially undermine EDAM operations. 

NV Energy said it has asked for clarification on the issue of contributors’ transmission rights. Although SPP has proposed a “service flow constraint” respecting transmission contributors’ and transmission service providers’ capabilities, the tariff “is not clear as to the entity that can establish the Service Flow Constraint and ‘carve out’ this transmission capacity from the market,” NV Energy said. 

NV Energy also urged SPP to keep working to ensure interoperability between Markets+ and Western Power Pool’s Western Resource Adequacy Program (WRAP). 

“SPP should confirm that the Markets+ tariff maintains the ability of the transmission service providers participating in Markets+ to provide support to WRAP wheel-out and wheel-through transactions on a firm basis, even if the need arises after the close of the day-ahead market run,” NV Energy said.  

Arizona Support

Three Arizona utilities — Arizona Public Service (APS), Tucson Electric Power (TEP) and Salt River Project (SRP) — supported the Markets+ tariff, pointing to the proposal’s independent governance and the stakeholder-driven development of the tariff. 

They view the requirement that Markets+ participants be WRAP members as another plus. 

“The defined RA standard for WRAP ensures Markets+ programs will maintain adequate resources,” TEP said in its filed comments. “The requirement also establishes uniformity, which imparts a high degree of simplicity and transparency for resource adequacy in Markets+.” 

The utilities’ comments echo those in an April letter to SPP from 26 entities supporting Markets+. (See 26 Western Entities Signal Continued Support for Markets+.) 

Commissioner Nick Myers of the Arizona Corporation Commission also weighed in to support Markets+ “as a market option in the Western region.” 

Myers said that as a member of the Markets+ State Committee (MSC), he could contribute to discussions on addressing different greenhouse gas policies within the market. 

“The Markets+ tariff strikes a balance by adopting a market design that enables states with GHG regulations to meet their identified goals without holding market participants in other states to the same GHG policy requirements,” Myers said in filed comments. 

SPP filed its proposed Markets+ tariff with FERC on March 29 and asked FERC to issue an order on the tariff by July 31. (See SPP Files Proposed Markets+ Tariff at FERC.) 

SRP was among commenters who supported that time frame. 

“Approval on this timeline will provide Salt River Project and potential market participants certainty regarding market rules and allow the timely development and testing of the systems and processes necessary to implement Markets+,” SRP said in filed comments. 

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NERC Seeks Comment on Changes to Mediation Procedures

NERC is seeking comments from industry stakeholders on revisions to its Rules of Procedure (ROP) for the ERO’s Compliance and Certification Committee (CCC) to conduct hearings and mediate disagreements between it and its regional entities. 

NERC staff and the CCC developed the revisions together, and the committee agreed at an April 26 meeting to post the changes for feedback. The comment period began April 30. 

The proposed changes apply to Appendix 4E of the ROP and are meant to bring this section in line with the ROP revisions FERC approved in May 2022. Those updates concerned the governance and integrity of NERC’s System Operator Certification Program and moved responsibility for credential maintenance from the ERO’s Reliability and Security Technical Committee to the Personnel Certification and Governance Committee, along with changes to the Compliance Monitoring and Enforcement Program. (See FERC Partially Rejects NERC CMEP Changes.) 

According to a statement, the proposed ROP changes are “relatively non-substantive but help to ensure Appendix 4E is consistent and up to date with other provisions of the ROP.” The revisions would affect three sections of the appendix: 

    • CCCPP-004-3 — CCC hearing procedures 
    • CCCPP-005-2 — CCC hearing procedures for use in appeals of certification matters 
    • CCCPP-006-3 — CCC mediation procedures 

In the first section, NERC removed references to challenges brought by regional entities. This change was motivated by the dissolution of the SPP Regional Entity and the Florida Reliability Coordinating Council, which were the last REs required to comply with NERC’s reliability standards; as a result, NERC will only hear challenges from registered entities “monitored directly by NERC.” 

NERC added language to the section clarifying that hearing officers, technical advisers and members of hearing panels must disclose potential conflicts of interest related to the proceedings before them. Additional updates were made to align the document with NERC’s current nomenclature preferences. 

For the section concerning hearings over certification appeals, NERC updated the template for the procedure from the previous version published in 2010. Other changes are intended to bring the section in line with the CCCPP-004-3 revisions, including the conflict-of-interest and nomenclature updates. 

The final section concerns the CCC’s role in mediating disagreements or disputes between NERC and the REs relating to the ERO’s performance audits of RE compliance programs. NERC’s ROP and delegation agreements require it to perform such audits at least once every five years. 

These updates clarify the CCC’s role as “an acceptable, impartial, third-party panel” to assist both NERC and the RE involved “in voluntarily reaching an acceptable resolution” of whatever issues are in dispute. They specify that at the direction of NERC’s Board of Trustees, the CCC’s chair will appoint three committee members to serve on the mediating panel. 

Mediators will be “disinterested parties [who] shall not be registered in the [RE] or … otherwise have any conflicts prohibiting the member from playing a role in the disagreement or dispute.” The revisions also state that mediators would be required to attend a training course before the negotiations begin. 

The comment period will end June 14, after which the CCC will work with ERO staff to review and respond to comments. 

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Data Center Load Growth Driving PPL’s Plans

Rising demand from data centers will lead to increased investment in transmission in PPL’s utility territories, and the company is even working to serve Data Center Alley in Northern Virginia with a competitive transmission project, executives said May 1 during a first-quarter earnings call. 

“We continue to advance plans to support prospective data center development in both Pennsylvania and Kentucky,” PPL CEO Vincent Sorgi said. “As we work with data center companies, we feel we are very well positioned to serve their needs for a variety of reasons. For starters, we have capacity on our grids such that the needed investment by the data centers is not too significant.” 

That allows them to connect to the grid quickly, in line with their desired commercial operation dates. Both Pennsylvania and Kentucky have cheap land for the facilities, while Rhode Island Energy is near major population centers in New England. 

“In Pennsylvania, we continue to see record numbers of requests within our service territory, including some very large centers that are projecting more than a gigawatt of load at full capacity,” Sorgi said. “We currently have approximately 3 GW of data center demand in advanced stages. The potential upside for PPL comes in the form of additional required investments in transmission and returns on the related rate base through the FERC formula rate.” 

Sorgi said that 3 GW should come online beginning in 2026. The power purchase agreements with those facilities enable PPL to begin readying its system, and it would be reimbursed if they do not go forward. 

PPL expects to know more about specific data center projects going forward in its territories later this year and into 2025. 

Each planned data center now would require $50 million to $150 million in investments depending on its size and specific needs. Every $125 million in investment translates into earnings per share of 1 cent, Sorgi said. 

Current customers in Pennsylvania should benefit from the additional data centers because they will spread the cost of transmission across a wider rate base, he added. 

“The more significant upside potential from additional data center to demand is due to the vertically integrated nature of our Kentucky business,” Sorgi said. “A significant ramp in electricity demand could also result in incremental generation needs in our service territory. Any additional generation investment would also represent upside to our current capital plan.” 

The data centers proposed in Kentucky are smaller and would only require PPL to spend $25 million to $75 million on its wires, but the chance for new generation, likely a new combined cycle natural gas plant, makes them potentially more profitable than the Pennsylvania projects, Sorgi said. 

PPL also was awarded a $100 million to $150 million project under a competitive transmission process to serve some of the major data center load in Northern Virginia, where PJM is expecting 7,500 MW of new demand later this decade, Sorgi said. (See PJM Board Approves $5 Billion Transmission Expansion.) 

Data Center Alley shows that the facilities tend to co-locate, Sorgi said, and PPL expects that trend to repeat around the country as more facilities are needed to meet artificial-intelligence applications’ growing demand for computing power. 

“It’s not necessarily just one-and-done,” he added. “If they can build one there, their intention is to expand upon that. And so, I think you’ll start to see data center hubs start to get created around the country. Obviously, there’s economies of scale if they’re kind of bundling together, and … that creates a demand for transmission into those areas.” 

PPL reported $307 million ($0.42/share) in net income for the first quarter, a 7.7% increase from the same period last year, off a 4.6% decrease in total revenue, at $2.304 billion. 

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Audit Faults NY Renewables Office on Speed of Reviews

The New York state office created to expedite permitting of large-scale renewable energy development should offer a better accounting of permitting speed, an audit concluded. 

The Office of New York State Comptroller on April 24 reported the findings of its review of the New York Office of Renewable Energy Siting. 

The audit said that while the process has gotten faster since the formation of ORES, it still is quite slow — 1,333 days from start to finish, on average. 

In its reply to the audit, ORES countered that it takes only 239 days on average to issue a siting permit, once an application is deemed complete, and as such, ORES is well within its statutory deadline — 365 days. 

The audit countered that highlighting the speedy final phase of the process obscures how slow the process is and prevents a better assessment of the progress the state is making toward its clean energy goals. 

The pace of progress in New York is well known if not exactly quantified — developers, lawmakers and regulators alike regularly express the need for speed. 

RTO Insider has covered presentations by ORES Executive Director Houtan Moaveni in 2023 and 2024. He generally has focused on how ORES has sped up review of completed applications and increased the number of permits issued. But he also has acknowledged the delaying effect of incomplete applications. 

ORES was created in 2020 to help the state meet the goals of its 2019 Climate Leadership and Community Protection Act. Its role is to issue siting permits for land-based renewable energy proposals with capacity of 25 MW or greater; projects rated at 20 to 25 MW can also opt in. 

As of April 30, ORES has permitted 15 projects and denied one application; nine applications are designated “incomplete” and four “complete” applications are under review. 

None of the 15 permitted projects has been completed and contracts for 10 have been canceled. 

ORES is empowered to ignore local laws in pursuit of the state’s climate goals, but it also is charged with ensuring that environmental, social and economic factors are fully considered. As a result, a lot goes into an application, and it takes time to put together a complete and correct application. ORES will bounce an incomplete application back to the applicant. 

The audit acknowledges that ORES cannot control an application’s quality or an applicant’s responsiveness but suggests ORES could provide a more realistic accounting of the total time needed to obtain a permit. 

Moaveni, in a written reply roughly as long as the audit itself, lauds the performance of his staff as they set up the first office of its kind in the nation. In each review, ORES has met every deadline the Legislature set for it, he said, generally by a wide margin. 

Moaveni said ORES concurs there is a need to constantly evaluate the timeliness of its performance but said it already tracks and reports each step of the process. 

He added that the state Legislature did not place a time limit on application completion because each project and each developer is different. 

“ORES takes no solace in issuing a notice of incomplete application, and is working steadily at improving both tracking of applications and communication with the applicant community on application requirements,” Moaveni wrote. 

Transmission Addition

ORES recently has been assigned an expansion of its duties: It now will provide the same type of one-stop shop for environmental review and electric transmission permitting. 

The Renewable Action through Project Interconnection and Deployment (RAPID) Act included in the recently approved 2024/25 New York state budget will remove ORES from the state Department of State and embed it in the state’s utility regulator, the Department of Public Service. 

It has become apparent since the climate law’s passage that the state’s bulk and local transmission facilities need significant upgrades to handle the increased load that will be placed on them in the clean energy transition, the bill explains, so review of transmission upgrades must be consolidated and expedited. 

ORES now will be the Office of Renewable Energy Siting and Electric Transmission, although it appears it will retain the ORES acronym. 

The RAPID Act saw pushback for the same reason ORES is unpopular in some places: It will allow unelected state officials to override local regulations, thus undercutting the state’s strong home-rule tradition. 

But RAPID was embedded into the state budget, as are many contentious proposals, and the budget vote is an all-or-nothing proposition. 

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Huge Load Growth Propels AEP to Strong 1Q Earnings

American Electric Power said April 30 that 10.5% growth year over year in data centers and other commercial load within its 11-state footprint can be attributed to prior investments in transmission infrastructure.  

“I like to say here at AEP that we’re really wired for growth,” interim CEO Ben Fowke told financial analysts during the company’s first-quarter earnings call. “We’ve been making significant transmission investments over the years, and that’s going to allow us to accommodate this first wave of growth we’re seeing from data centers.” 

Fowke said additional infrastructure and “perhaps even generation” will be needed before the decade is up. The company plans to invest $27 billion in transmission and distribution infrastructure over the next five years to meet service requests that could add an additional 10 to 15 GW of load by 2030. 

“We’ve done a lot of groundwork to put ourselves in this position, and you’re also seeing data center load ramp up at the same time. That’s a natural trend,” he said. “The good news is we believe that the load growth coming on will be fair to all customers and, in fact, will help us keep our rates affordable across all our jurisdictions. That load growth benefits all customers.” 

At the same time, a voluntary severance program announced this month will save about $100 million in labor costs and “mitigate impacts from inflationary pressures and interest rates,” Fowke said. 

AEP told hometown newspaper The Columbus Dispatch that about 7,400 of its 16,800 employees are eligible for the program.  

The Ohio-based company reported earnings of $1.003 billion ($1.91/share) for the first quarter, compared to $397 million ($0.77/share) for the same quarter a year ago. 

Fowke replaced Julie Sloat as CEO in January when she was forced out after 14 months on the job. (See Interim CEO Fowke Explains AEP Leadership Change.) He said the search for a permanent CEO is “well underway” but will take six to 12 months. 

“We will take the time necessary to find the best candidate,” Fowke said. “Based on the talent pool that we’re looking at, we will find the right person to lead AEP.” 

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2023 Flat for Wind Turbine Makers in West, Huge in China

A new report indicates Western wind turbine manufacturers saw demand for their products ease in 2023 amid a stalled market, while Chinese companies saw surging demand due to their country’s rapid buildout of wind energy generation. 

The May 1 report by Wood Mackenzie indicates that for the first time, Chinese manufacturers accounted for four of the top five companies globally by 2023 sales capacity: Goldwind (16.3 GW), Envision (14.1 GW), Windey (10.1 GW) and Mingyang (9.9 GW).  

Denmark’s Vestas was the only Western manufacturer in the top five, coming in at No. 3 with 11.5 GW, the data and analytics company said in its report. 

The four Chinese manufacturers achieved their sales volume almost entirely in China, but competition in that country was intense enough that turbine prices dropped 16% for onshore models and 9% for offshore. 

Wood Mackenzie said Western manufacturers accounted for 93% of wind turbine sales outside of China. The top five in this category were Vestas (28.5% market share), Siemens Gamesa (24.3%), GE (18.1%), Nordex (15.9%) and Enercon (6.1%). 

And 2023 was the sixth year in the top position for Vesta, Wood Mackenzie said. It noted that GE’s ranking was due in part to the strength of its U.S. onshore market. 

GE Vernova, the recent spinoff of the conglomerate’s power business, released its first-quarter financial results April 25. 

During a conference call with financial analysts that morning, CEO Scott Strazik said the onshore segment of the Wind business recorded a positive EBITDA for the third straight quarter despite a lower volume of orders. The offshore segment saw improvement but still recorded a loss. 

The company expects onshore revenue to be substantially higher in the second half of 2024 than in the first, he said, but cannot say exactly when U.S. orders will pick up, due to trouble customers are having with permitting. 

“Importantly, we see North American developers rebuilding their project pipeline as evidenced by the growing onshore interconnection queues,” CFO Ken Parks said. 

Strazik said the company would work through its offshore wind segment backlog and remain “highly selective” on new orders. 

GE Vernova’s offshore segment was in the news April 19, when New York state canceled its entire third offshore wind solicitation because GE Vernova had opted not to bring to market an 18-MW variant of its Haliade-X turbine the company previously said it would develop. (See NY Offshore Wind Plans Implode Again.) 

Provisional contracts for three offshore wind farms totaling 4 GW of capacity had been designed around the 18-MW platform, and the prospect of using lesser-capacity turbines rendered the provisional contracts unworkable, the state said. 

A week later, on the conference call, Strazik did not directly address that issue except to say the company believes offshore wind will play an important role in the energy transition and appreciated the partnership of New York as it pursues its ambitious offshore wind goals amid repeated setbacks. 

However, he did speak about the U.S. offshore wind industry generally, and made no mention of a future 18-MW Haliade-X: 

“With the phase that offshore wind has been in generally over the last few years, it’s been hard to get projects to a point that they’re ready to thrive,” he said. 

“But through our iteration with our customers and where we’re going, I want to tell you, we’re excited about our future product here, a 15.5-MW product that has an ability to have a power boost up to 16.5 MW. We’re working hard to have that prototype running by the end of 2025. And when we look at where we are with our Haliade-X product today, the 14-megawatt product, by the time you get into 2026, we’re going to have somewhere in the neighborhood of 5 million to 6 million operating hours with that product.” 

Strazik appeared to indicate the terms of GE Vernova’s current backlog of orders are unfavorable. 

“We’ve been pretty consistent for a while that we are only going to add to that backlog with materially different economic terms than what is in our backlog today. And that’s a combination of many things: price, other terms and really leaning in on projects that are set to thrive. And there’s a lot of complexity in offshore wind that we’re all learning from, and we’re going to keep working on it every day.” 

Wood Mackenzie Principal Analyst Endri Lico gave an assessment of the wider market: 

“Western OEMs practiced commercial discipline, showing little appetite for price reduction to grow market share. 2023 saw some improvement in financial performance as some of the supply chain disruptions eased, but quality and reliability issues have emerged as another source of instability for western OEMs,” Lico said. 

The never-ending drive toward bigger and better turbines, with their potential of greater return for developers on investment, have been blamed for some of these quality control problems — it prolongs the research and development phase, and it complicates attempts to achieve standardization or economies of scale. (See Big Offshore Wind Plans Face Multiple Major Obstacles.) 

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FERC Approves Changes to SPP’s GI Process

FERC has accepted SPP tariff revisions designed to increase study deposits for generator interconnection requests, add a nonrefundable application fee and clarify the process of evaluating modifications to requests. 

In an order issued April 30 and effective May 1, the commission found the revisions will improve the efficiency of SPP’s GI request process, reduce administrative burdens for both the RTO and its interconnection customers, and clarify modification study procedures (ER24-1362). 

“These revisions will contribute to increasing the overall efficiency of the generator interconnection process, which will help ensure that interconnection customers are able to interconnect to the transmission system in a reliable, efficient, transparent and timely manner,” FERC wrote. 

SPP said processing costs to study proposals have averaged $7,100 per request and they have exceeded $10,000 per request for two of its three most recent study clusters. The RTO’s GI process has been plagued by developers filing requests to gauge costs or withdrawing those requests, leading to frequent restudies. Staff still are processing study clusters dating back to 2017; the queue numbered 1,139 requests for 221 GW when the backlog-clearing effort began. 

The grid operator will increase the study deposits for new requests to align with the framework required by FERC Order 2023, which ranges from $35,000 to $250,000 depending on the generating facility’s size. Proposed projects of fewer than 80 MW will be responsible for a $35,000 deposit, plus an additional $1,000/MW. Replacement requests will pay $60,000 to $120,000, generating facility modification requests $10,000 to $60,000, and surplus interconnection service requests $15,000 to $60,000. 

SPP said the proposed revisions will streamline the study process and reduce the financial exposure for itself and its members by increasing study deposits. It said requiring a $10,000 nonrefundable application fee for each interconnection request will mitigate the “significant” financial risk between the deposits and actual study costs.  

FERC found that while SPP’s proposed application fee was double that established in Order 2023, the RTO had proved the new fee, to be adjusted every three years for inflation, “reasonably reflects” the costs to process interconnection requests before a cluster’s close.  

The commission said while some tariff revisions deviated from FERC’s pro forma Large Generator Interconnection Procedures, SPP still demonstrated the proposed variations are just and reasonable.