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November 14, 2024

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NV Energy Should Do More to Tap VPP Potential, Report Says

NV Energy’s virtual power plant market potential could grow from an estimated 134 MW this year to 1,230 MW in 2035, according to a new analysis.

But the utility isn’t taking full advantage of VPPs in its resource planning, Advanced Energy United said in the July 23 report, “Moving the Needle on DERs and VPPs in Nevada.”

And that means a missed chance to reduce the need for new gas-fueled generation in the state, said AEU, an association representing the alternative energy industry.

In March, Nevada regulators approved NV Energy’s proposal to convert its coal-fired North Valmy Generating Station to gas. And in its 2024 integrated resource plan (IRP) filed in May, the utility is seeking approval for a 411-MW gas-fired unit at North Valmy to start operating in mid-2028. The estimated cost is $573 million.

“Adding new gas instead of maximizing virtual power plant (VPP) capacity is a mistake Nevada cannot afford to make,” AEU staff said in a blog post accompanying the report’s release.

VPP Benefits

In a virtual power plant, customers allow a utility or third-party firm to control their distributed energy resources in a coordinated way to provide grid benefits, such as reducing peak-hour demand.

VPPs can help utilities address resource adequacy concerns and meet decarbonization goals, proponents say. They can keep costs down for a utility, and customers who participate in VPPs receive compensation that may help offset rising utility bills.

The AEU report is the latest analysis touting the potential of VPPs.

The Brattle Group released a report in April for GridLab that estimated California’s VPP market potential in 2035 at 7,671 MW — an amount roughly equal to 15% of peak demand. (See Virtual Power Plants Could Save Calif. $750M a Year, Study Says.)

A Brattle study for Google last year found that VPPs could provide resource adequacy at a net utility system cost that’s about 40% of the net cost of a gas peaker and 60% of the net cost of a battery. (See Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy.)

“If VPPs are left out of resource planning as load grows and fossil fuel assets retire, Nevada runs the risk of saddling ratepayers with unnecessarily expensive sources of capacity,” AEU said in its report.

‘Meaningful’ Compensation

NV Energy’s new IRP includes a distributed resource plan and a demand-side management plan. It features a proposed “grid value” portfolio, aimed at providing “flexible resources to manage operating conditions of the power grid,” the IRP states.

“It’s definitely going in the right direction, but we see areas for improvement,” AEU industry analyst Chloe Holden told RTO Insider.

AEU is concerned about the “vagueness” in NV Energy’s plan, Holden said, including a lack of detail about how different devices would be treated and how customers would be compensated.

“It is essential that customers are compensated in a predictable, meaningful fashion for VPP participation and that the level of compensation drives ongoing enrollment in the VPP,” AEU said in its report.

As another “best practice,” AEU recommends that NV Energy invite collaboration with third-party VPP companies and allow VPP participants to bring their own devices rather than being restricted to utility-owned equipment.

Holden said AEU took a conservative approach in its estimates of VPP market potential in Nevada. The potential increases from 134 MW in 2024 to 552 MW in 2029, 750 MW in 2031 and 1,230 MW in 2035.

The figures reflect the share of DER capacity that VPP participants are expected to provide at peak times, accounting for expected customer behavior.

DERs included in AEU’s analysis are smart thermostats, residential and commercial behind-the-meter battery storage, managed residential EV charging and managed commercial and public EV charging for both light- and heavy-duty vehicles.

The analysis doesn’t include traditional commercial demand response.

According to AEU, the 100 highest load hours for the NV Energy grid could be moderated with 721 MW of DER capacity, which is expected to be reached by 2031.

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Rhodium: US Accelerating Reductions in GHG Emissions

U.S. greenhouse gas emissions have decreased significantly over the past decade and are on track to decrease even more precipitously in the next decade, according to the Rhodium Group’s annual update of its “Taking Stock” report, issued July 23. 

The organization found the country’s GHG emissions were 18% lower in 2023 than in 2005, and it estimates they will be 32 to 43% lower in 2030. 

This is a marked acceleration just from 2022, the report’s authors write, but even a continuation of that would leave the U.S. short of the 50 to 52% reduction by 2030 that it committed to under the Paris Agreement in 2015. The country might not achieve a 50% reduction until the mid-2030s, the report indicates. 

Under a midrange scenario, the report projects a 65% reduction in emissions from power generation through 2035, as fossil-burning generators are replaced by renewables, and a 26% reduction from transportation, as the number of internal combustion engines decreases.

Past and projected future average annual growth in U.S. electricity demand | Rhodium Group, EIA

But industrial sector emissions are projected to decrease only 5% through 2035, at which point it would be the largest U.S. source of GHG emissions. And emissions from the agriculture sector actually could increase slightly, according to the analysis. 

Rhodium issued its first “Taking Stock” report in 2014 and has updated it annually. In announcing the 2024 update, it noted the historic confluence of factors in the past few years that has accelerated emissions reductions in the U.S., including the Inflation Reduction Act and the Infrastructure Investment and Jobs Act, which have helped spark a clean energy boom. 

It is a marked change from the conclusion of the 2014 report, which incorrectly predicted GHG emissions would increase through 2020. 

The report notes potential obstacles to continued progress, including the Supreme Court or the next president striking down or weakening the regulations that have been instrumental in bringing about the reductions to date. 

Ironically, attempts to build a domestic clean energy manufacturing base could result in an increase of emissions; meanwhile, interconnection delays, local opposition, transmission constraints and robust growth of GDP could slow the decrease of emissions. 

The report also flags supply chain constraints and data center demand as disruptors. Difficulty building renewables and the continued proliferation of data centers would result in 2035 power sector emissions that are substantially higher than in a scenario in which neither complicating factor existed. The report notes fossil generation retirements already are being reconsidered because of these two factors. 

Because of all these variables, the report gives a range of potential outcomes under three models: 

    • a high-emissions scenario where emissions-free energy deployment is slowed by high costs for renewable technologies, low costs for fossil fuels, interconnection queue delays and supply chain constraints; 
    • a low-emissions scenario where low-cost clean energy technologies and expensive fossil fuels drive a rush of investment in emissions-free power; and 
    • a mid-emissions scenario that splits the difference. 

The report anticipates a 38 to 56% reduction in U.S. GHG emissions by 2035 over 2005 levels, factoring a few trends into this projection: 

    • Zero-emissions sources such as wind, solar and nuclear could account for 62 to 88% of total generation by 2035, and coal could be nearing zero. This would yield a 42 to 83% drop from 2023 power sector emission levels. 
    • By 2035, 64 to 74% of light-duty vehicles sold could be electric, and 30 to 45% of medium- and heavy-duty vehicles sold could be zero-emitting, causing transportation sector emissions to drop 22 to 34% from 2023 levels. 
    • Emissions from oil and gas production could drop 12 to 28% below 2023 levels because of EPA regulations that limit release of methane. 
    • Regulatory changes phasing out hydrofluorocarbons could cut building emissions by 9 to 12%. 

Sources of electricity demand growth from 2023 through 2035, as modeled in a midrange emissions scenario | Rhodium Group

The report bases its projections for the next decade on state and federal policies in place in June 2024, which is an unstable foundation, the authors note. “The only thing that we can be certain of is that these policies will change by 2035 — probably many times over.” 

States can step up and take action if the federal government will not, they add. 

“What’s certain is that more policy action is needed for the U.S. to put itself on track for its 2030 commitment under the Paris Agreement and for deep decarbonization by midcentury.” 

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MISO Sets Sights on 50% Peak MW Cap in Annual Interconnection Queue Cycles

MISO said it plans to pursue a more straightforward, 50% peak load megawatt cap to limit the number of generator interconnection requests it would accept annually.

At MISO’s July 23 Interconnection Process Working Group teleconference, the grid operator revealed the cap would be based on 50% of peak load per study region. MISO divides its footprint into West, Central, East and South regions for queue study purposes.

MISO Manager of Generation Interconnection Ryan Westphal said using 2022 study modeling, a queue cap would have been about 68 GW. He said the simpler cap would take the RTO’s future resource adequacy need into account as FERC recommended, though he didn’t offer specifics.

MISO attempted last year to enforce an annual megawatt cap on its interconnection queue. FERC rejected the attempt on concerns over too many cap exemptions, the formula to establish the cap and potential resource adequacy deficits stemming from limiting new generation onto the grid. (See MISO: New Interconnection Queue Cycle to Wait on MW Cap Filing.)

MISO’s original cap formula was intended to be rooted in its ability to develop a reasonable dispatch for studying interconnection requests based on the existing system and considering regional and subregional peak loads. The complex calculation involved landing on load remaining to be served after existing generation and higher-queued generation proposals are dispatched at the lowest possible megawatt output while remaining online.

Westphal said MISO hopes to submit a fresh FERC filing for a more uncomplicated cap before the end of the year.

NextEra Energy’s Erin Murphy asked how MISO arrived at the 50% value. Westphal said the RTO assessed its rounds of potential generation submittals prior to the 2022 “explosion” of queue requests. He said before the exponential growth, MISO was processing about 60-GW entry classes. MISO is processing 123 GW of queue hopefuls that lined up in the 2023 cycle. If all projects proceed, MISO could have a more than 300-GW queue on its hands.

Westphal said MISO doesn’t have a “specific date” for when it will close the current queue cycle. Its application portal is open for interconnection customers to submit projects for MISO to review application completeness. However, MISO is holding off on processing the queue in earnest until it secures FERC permission to administer a cap.

Stakeholders asked whether projects that don’t make the cutoff would have priority access to MISO’s next queue cycle. Westphal said any projects shut out of a queue cycle would be “first in line” for the subsequent cycle.

MISO also said a few projects put forward after the cap is reached might be selected to proceed if other projects don’t successfully clear its validation process.

MISO staff said the grid operator would use the timestamps on project submittals to determine their place in line. Westphal said MISO wouldn’t refund study deposits to developers that don’t make the cap cutoff but hold on to them to prepare for processing them during the next queue cycle.

Derek Sunderman, of Shell subsidiary Savion, said MISO’s proposal doesn’t seem to address late-stage project withdrawals. He also said the cap won’t encourage developers to only put their most promising projects forward and not “hammer” the queue with several projects to secure a position.

Westphal said MISO is open to use of a volumetric price escalation in addition to the cap, where interconnection customers’ fees and penalties rise as they submit more projects to the queue for study. He said the RTO is considering starting at $8,000/MW for the first milestone fee.

Last month, Savion suggested MISO enact escalating financial commitments to prevent a handful of interconnection customers from submitting a disproportionate number of applications. MISO said raising fees based on a corporation’s project count would introduce several new requirements.

MISO once again proposes exemptions to the cap, though not as many as in its first filing with FERC. Westphal said MISO would exempt generators with provisional generator interconnection agreements; generators seeking to replace retiring counterparts and in need of extra interconnection service; and those generators wanting to convert their unguaranteed energy resource interconnection service with the higher-quality network resource interconnection service.

MISO again plans to exempt generation singled out as necessary by state commissions, though it would limit those exemptions from an unlimited number to three apiece annually per regulatory body.

Bill Booth, a consultant to the Mississippi Public Service Commission, questioned MISO’s three-project limit on regulator-backed projects. Booth said the restriction doesn’t make sense if the RTO’s goal is to cut down on speculative projects. He said a project backed by regulators usually is a sure thing.

Westphal said MISO needs some kind of limit in place, per FERC’s 2023 rejection of the first cap.

“FERC basically said without some kind of limit, we undermine the cap. We need to put some kind of limit on here based on what we heard from FERC,” he said.

Westphal said the cap is essential to make interconnection studies more manageable. He said as more projects vie for entry, more upgrades become necessary, and the more complex and insurmountable studies become.

“The point of the cap is to speed up the queue,” Westphal said.

Murphy asked what MISO is doing beyond proposing a future queue cap to address the backlog of projects now.

Westphal said MISO will build more automation into the 2023 modeling. The grid operator has solicited help from Pearl Street Technologies to determine whether their software can speed up interconnection studies.

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CenterPoint CEO Promises PUC Utility Will ‘Improve’

CenterPoint Energy executives appeared before Texas regulators July 25 to apologize for the company’s slow restoration following Hurricane Beryl’s landfall and promised to do better next time. 

The Houston utility had 2.6 million customers without electricity in the storm’s immediate aftermath, with some waiting more than a week to get their power back. CenterPoint was roundly criticized for the slow response and its poor communications with customers. 

“In times of emergency, our responsibility is to respond quickly, to communicate clearly, to provide accurate information and to restore power as rapidly and safely as we can,” CenterPoint CEO Jason Wells told the Public Utility Commission during its open meeting. 

“I take personal accountability on areas where we fell short of our customers’ expectations,” he continued. “Most importantly, I want to apologize. While we cannot erase the frustrations and difficulties so many of our customers endured, I, my entire leadership team, will not make excuses. We will improve and act with a sense of urgency.” 

Wells said CenterPoint will begin immediately to improve its communication with customers as part of an action plan with two other “pillars of action” focused on resiliency and greater collaboration with local partners and emergency responders. The intent is to address issues for the remainder of the hurricane season and beyond. 

Central to the plan is strengthening the utility’s vegetation management efforts. Wells said that as of July 16, CenterPoint had nearly doubled its vegetation-management workforce “to immediately address the higher risk areas … throughout the rest of this calendar year.” 

The utility plans to roll out a new cloud-based outage tracker Aug. 1, replacing the previous version that never was able to recover after being swamped following a derecho in May. It also will use composite poles to replace about 1,000 distribution poles currently planned for 2024. 

CenterPoint said its crews removed or trimmed more than 35,000 trees during the restoration effort, walked over 8,500 to repair damage and replaced more than 3,000 poles. 

Wells said CenterPoint will hire a new senior executive team member with expertise in emergency and storm response. More actions will be taken based on internal reviews, independent analysis and counsel from emergency response and communications experts, and feedback from the PUC, elected officials and community leaders, and its customers. 

“Going forward, our most important priority today and in the months ahead will be to improve our emergency response with a sense of urgency to re-earn your trust and the trust of the millions of people who depend on us,” Wells said. 

The PUC has opened a “rigorous” study of CenterPoint over repeated failures in its footprint. The utility also is being probed by state lawmakers, with hearings scheduled July 29 and July 31. (See CenterPoint Under Fire for Its Beryl Response.) 

The commission threatened to recall CenterPoint’s $2.3 billion resiliency plan — filed in April and currently in settlement negotiations — and preside over the hearings. However, it agreed to give the utility time to reach an agreement with the other parties (56548). 

“I want to ensure that we have the right, as in the law, to modify any plan that’s presented to us,” Commissioner Jimmy Glotfelty said. “Even if there’s a settlement, we must be willing to bring this back to the commission to get deeper into the specifics of how we will ensure resiliency on the CenterPoint system.” 

“You have an obligation to serve. You have an obligation to provide continuous and adequate service,” fellow Commissioner Lori Cobos said. “Getting a resiliency plan approved does not stop you from doing what you should be doing already to maintain continuous and adequate service for your customers and your service territory.” 

CenterPoint promised the PUC it would provide an update on the settlement negotiations within a week.  

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DOE Awards $371M to Regulators, Communities Grappling with New Tx

The Transmission Siting and Economic Development (TSED) grants that the U.S. Department of Energy’s Grid Deployment Office announced July 24 are not — as most of the office’s grants have been — targeted at building major new transmission projects or upgrading existing lines, said GDO Director Maria Robinson. 

“This program is different,” Robinson said during an advance press call July 23. “It’s specifically designed to uplift communities impacted by transmission development, and we’re doing that by making investments that generate benefits for them beyond resilience and reliability.” 

Funded by the Inflation Reduction Act, the TSED initiative will award $371 million to 20 projects in 16 states, with grants unevenly divided between two programs. Four grants totaling $17 million will go to four state and county regulatory agencies to “accelerate siting and permitting of high-voltage interstate transmission projects,” Robinson said. 

The remaining $354 million is slated to go to 16 economic development projects, many in counties and towns with populations under 20,000 people, according to DOE. 

So, in Baker City, Ore. (estimated population: 10,250) — near the path of the 500-kV Boardman-to-Hemingway (B2H) line — the Baker School District has been awarded $1.1 million to help establish a Lineman College and Training Hub to meet growing and future demand for utility, broadband and electric infrastructure workers. B2H will run 290 miles, connecting substations in Idaho and Oregon and delivering up to 1,000 MW of clean power in both directions, according to Idaho Power, which is building the line. 

New Jersey’s Economic Development Authority will be getting $50 million, with part of the money going to coastal communities that will be affected by the development of new transmission lines for offshore wind farms. The goal is for community residents to propose, vote on and lead the development of projects that will provide local benefits. 

The funds will also be used for electrical apprenticeship programs and to build bike paths along existing transmission rights-of-way, which will link to other paths to state, county and municipal parks. 

“We’re very focused on making sure utilities and developers are engaging affected communities that are involved with transmission,” Robinson said. “Sometimes folks think about transmission projects as providing economic development in the short term — the construction piece, but these projects are really ensuring sustained economic development, not just during that transmission construction period. … 

“This is one more piece in that overall puzzle … getting communities really invested in the idea of transmission by helping them see tangible effects through economic development.” 

The grants announced July 24 represent the first round of TSED funding. The IRA provided $760 million for the program, and Robinson said a second funding announcement could be released this year. She also stressed that once the contracts are signed and funds obligated, it would be difficult for any new administration to “change direction” on the program. 

Strings Attached

But the TSED grants come with significant strings attached, Robinson said. For economic development grants, the awardees will not be able to receive the funds until the transmission projects affecting their communities have actually broken ground.  

For example, Idaho Power has pushed back the B2H groundbreaking a few times, so development of the Baker School District’s Lineman College and Training Hub could also be delayed. 

For the siting and permitting awards, regulatory commissions and planning organizations will be able to get the money once they finalize their contracts with DOE, but they will have to commit to permitting the designated transmission lines in their states within two years.  

Having that kind of hard and fast deadline could provide a challenge or new motivation for state regulators in Illinois and Wisconsin, both of which have been awarded grants to accelerate permitting on lines from the first tranche of MISO’s Long Range Transmission Planning (LRTP) portfolio, a web of 345-kV lines crossing nine states. 

As originally approved in 2022, the 18 projects in Tranche 1 are expected to come online between 2028 and 2030 at an estimated cost of $10.3 billion. (See MISO Board Approves $10B in Long-range Tx Projects.) 

To help the Illinois Commerce Commission (ICC) up its permitting game, the state will receive a TSED grant of $8.2 million to streamline its approval processes while also protecting of the state’s natural resources and incorporating community concerns into transmission siting and approval, according to the ICC. A major focus will be on updating customer-facing databases related to the LTRP lines in the state.  

The Wisconsin Public Service Commission intends to use its $3 million grant to increase staff and resources to accelerate permitting for three LTRP projects. According to DOE’s project description, the commission will “increase its outreach and engagement with the public, improve its coordination with other siting entities and develop plain language educational materials on high-voltage transmission lines.” 

The other two siting and permitting grants include: 

    • $4.5 million to the Pennsylvania Public Utility Commission to improve its siting processes for projects from PJM’s Regional Transmission Expansion Plan crossing the state. The funds will go toward “expanding [PUC’s] public and community engagement, participating in more site visits and public input hearings, and providing education and training opportunities to its staff.” 
    • $1.7 million to Alamosa County in southern Colorado (estimated population: 16,655) to conduct an extensive analysis and broad community outreach to evaluate three potential corridors for increasing transmission capacity in the region and northern New Mexico. 
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NextEra Reports Continued Growth in Renewables

NextEra Energy reported solid quarterly earnings July 24, and its renewables business turned in its second-best quarter ever, signing agreements for more than 3 GW of new renewables and storage.

Data center agreements with Google totaling 860 MW and other additions brought the NextEra Energy Resources backlog to 22.6 GW, even as it placed more than 1.6 GW into service in the second quarter.

During a conference call July 24, CEO John Ketchum updated financial analysts on other aspects of the company’s business landscape, including the figurative elephant in the room: The political party that has embraced the pachyderm as its symbol.

A week after the Republican Party formally designated a truculent renewable energy skeptic as its standard bearer, one of the world’s largest operators of wind, solar and storage might be concerned about the shape of things to come.

But Ketchum reeled off a list of reasons why he is not alarmed by the prospect of a second Trump presidency:

    • Money from Democrat-backed clean energy programs is going disproportionately to Republican-leaning states.
    • Republican lawmakers increasingly are embracing IRA tax credits when they see the impact in their districts.
    • Tax laws are difficult to change.
    • Party majorities are likely to remain narrow in the House and Senate.
    • Renewables create jobs, they sidestep fuel price volatility, they bring down constituents’ power bills and they help meet the growing demand for electricity.

“We’ve always been able to work with both sides of the aisle in the 22 years that I’ve been at NextEra, and I don’t think this time around is any different,” Ketchum said.

The company expects 6 to 8% annual growth in earnings per share through 2027.

NextEra Energy Resources benefits from multiple growth paths, Ketchum said:

There is the replacement cycle, by which higher-cost, lower-efficiency generation is replaced by renewables and energy storage. The company says with its affiliates, it is the world’s leading generator of electricity from wind and sunlight and one of the leading storage operators.

There also is rising demand.

Most markets have seen stagnant demand for decades, Ketchum said, with one of the exceptions being Florida, where NextEra’s FPL operates as the nation’s largest electric utility.

But now, growth is coming across multiple sectors in multiple markets.

“We expect the demand for new renewables to triple over the next seven years vs. the prior seven to help meet this increased power demand,” Ketchum said.

NextEra is ready to help meet the rising demand for clean energy, but it is not ready to turn off its fossil generation — an all-of-the-above solution is needed, he said.

“As the owner and operator of a large natural gas-fired fleet in Florida, we are also conscious of the importance of natural gas-fired generation as a bridge fuel,” Ketchum said.

That said, building new gas-fired generation has become challenging, he added — more expensive and time-consuming in many states.

An analyst asked about the other emissions-free part of NextEra’s portfolio: nuclear. Has there been any thought to restarting the Duane Arnold Energy Center in Iowa?

Its license had been extended to 2034, but it shut down in 2020 after sustaining wind damage.

Yes, Ketchum said — but only thought.

“Sure, we’re looking at it, but we would only do it if we could do it in a way that is essentially risk-free with plenty of mitigants around the approach, and there are a few things that we would have to work through,” he said.

NextEra Energy reported second-quarter 2024 net income of $1.62 billion, or $0.79 per share, on $6.07 billion in revenue.

This compares with net income of $2.8 billion, or $1.38 per share, on revenue of $7.35 billion in the second quarter of 2023.

NextEra Energy stock closed 4.6% higher in trading July 24. It is part of the S&P 500, which was down 2.3% for the day.

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Order 1920 Debated at House Hearing with All 5 FERC Commissioners

At full strength for the first time since the beginning of last year with the addition of Judy Chang this month, all five FERC commissioners appeared at a House oversight hearing July 24 during which representatives questioned them on Order 1920. 

Rep. Jeff Duncan (R-S.C.) — chair of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security — praised Chair Willie Phillips for moving through the backlog of natural gas infrastructure projects but criticized the landmark transmission rule.

“We are concerned the commission has strayed from its responsibility as an economic regulator to an entity focused on assisting the buildout of so-called ‘green energy’ technologies,” Duncan said. “This is happening despite the continued alarms from [NERC] and … grid operators across the country.” 

Duncan said Republicans are concerned the order’s “skewed ‘categories of factors’ approach to transmission planning” will drive up costs and threaten reliability. He argued that FERC prioritized Democratic-led state renewable energy targets, Biden administration goals and corporate clean power purchases. 

Democrats on the subcommittee supported Order 1920, with Rep. Frank Pallone (D-N.J.), chair of the full committee, saying it builds on the progress of orders 888, 890 and 1000. 

“Failing to plan is planning to fail,” Pallone said. “And the basic principle of Order 1920 is that grid planning is essential to maintaining just and reasonable rates. I agree, and I’ve been encouraged by the reception the rule has received from nearly every corner of the political world except from congressional Republicans. It seems Republicans would prefer that their constituents be slapped with higher power bills because utilities are not required, for example, to plan for the impacts of severe weather on the grid.” 

Phillips said Order 1920 would unlock cheaper sources of power for customers while bolstering grid reliability. 

“Order No. 1920 requires utilities to plan today for the factors that we know will drive tomorrow’s reliability and affordability needs, while requiring that customers pay for new transmission only to the extent that they benefit from that infrastructure,” Phillips said. “Let me say that again: If you don’t benefit, you don’t pay.” 

Commissioner Mark Christie dissented on Order 1920, and he explained his disagreement with the majority on how the order would spread the cost of implementing state policies across multistate RTOs. 

“Order 1000 said that you can cost allocate public policy projects separately from reliability projects; this rule says ‘no, you cannot.’ That is a major, radical change from Order 1000,” Christie said. “So, it didn’t build on Order 1000; it was a radical break from Order 1000.” 

Under the order, public policy and reliability have to be planned for at the same time around a set of required factors, including state renewable targets, with one cost allocation formula based on a set of prescribed benefits for all those projects. Christie said that would spread the costs across all the states in an RTO. 

“The states can even agree on a different formula, and the rule says the transmission provider can just ignore it, so I don’t think that’s fair,” Christie said.  

Order 1920 does require that transmission providers give states a chance to weigh in on cost allocations, Phillips said later in the hearing. But as many rehearing requests pointed out, the transmission providers are not even required to file any proposal coming out of that with the commission. (See FERC Order 1920 Sees Wide-ranging Rehearing Requests.) 

The order was approved in May by Phillips and former Commissioner Allison Clements. The three new commissioners did not get into the debate at the hearing, with Commissioner Lindsay See noting she still is staffing up her office. 

See, who comes to FERC after serving as solicitor general of West Virginia, noted the changing legal landscape facing the commission. 

“In response to the now-smaller margin of error for agency orders after the Supreme Court’s recent decisions cabining agency discretion, I welcome the important check judicial review offers in our separation-of-powers system,” she said, referencing the court’s decision in Loper Bright, which ended Chevron deference. (See Phillips, Christie Debate Loper Bright’s Impact on FERC Order 1920.) 

Chang said her position working for the state of Massachusetts gave her firsthand experience highlighting the importance of having adequate infrastructure, efficient market frameworks and viable approaches to growing the economy while working to cut greenhouse gases. 

“As a commissioner, one of my priorities is ensuring a robust and reliable transmission system, including the use of advanced technologies, to deliver affordable energy to all consumers,” Chang said. “This is paramount to the economic growth of our nation, and this is how the United States will continue to lead the world and compete on the global stage in technological innovation and infrastructure development.” 

Commissioner David Rosner said a key task for the commission is maintaining reliability and affordability in light of the ongoing clean energy transition in terms of both supply and demand. That will require FERC to remain vigilant to the realities of the resources that power the economy. 

“That means continuing to faithfully implement the commission’s longstanding policy of resource and fuel neutrality to allow the next generation of technologies to play their role in the energy system,” Rosner said. “It means continuing to harden the energy system to withstand evolving threats to reliability, including weather, physical and cyber risks.” 

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Pacific NW Hydrogen Hub Launched with 1st Round of Federal Funds

The Pacific Northwest Hydrogen Association (PNWH2) said July 24 that it had secured the first slice of the $1 billion U.S. Department of Energy grant the group won last fall to develop a network of clean hydrogen suppliers and consumers across the region. 

Receipt of the $27.5 million in federal funding marks the official launch of the PNWH2 hydrogen hub, one of seven such hubs across the U.S. being supported by up to $7 billion in funds allocated through the Infrastructure Investment and Jobs Act. (See DOE Designates Seven Regional Hydrogen Hubs.) 

The Northwest hub is the second to launch, coming on the heels of last week’s announcement that California’s Alliance for Renewable Clean Hydrogen Energy Systems hub had secured $30 million in its first round of DOE funding. (See California Reaches Funding Agreement to Launch Hydrogen Hub.) 

Phase 1 funding for PNWH2 will be used to cover “initial planning, permitting and analysis activities to ensure that the overall hub concept is technologically and financially viable,” the group said in a statement. 

The Northwest hub is intended to focus on production of “green” hydrogen, derived from the splitting of water molecules using electricity generated by emissions-free resources. 

“We are excited to embark on Phase 1 and lead the way in building a new clean energy commodity in the U.S. that will benefit generations of families throughout the region,” PNWH2 President Chris Green said. 

The group expects the hub to consist of eight “nodes” across Washington, Oregon and Montana “that will leverage the region’s innovative technology and abundant renewable energy to address the hardest-to-abate end users, such as public transit, agricultural products, medium and heavy-duty transport, and the electric power industry.” 

The hub’s “partners” consist of a range of suppliers, including: Fortescue Future Industries, ALA Renewable Energy, Atlas Agro, Express Ranch Hydrogen and St. Regis Solar for production; Air Liquide for liquefaction and distribution; and Williams Field Service Group for transmission and storage. 

Potential offtakers include Amazon for decarbonizing operations, Portland General Electric and Puget Sound Energy for electricity generation and Northwest Seaport Alliance for deploying hydrogen port trucks and cargo-handling equipment. Two hub partners, MHI Holdings and Lewis County (Wash.) Transit, plan to be both producers and consumers of the fuel. 

Washington State University, with assistance from its Consortium of Hydrogen and Renewably Generated E-Fuels (CHARGE), will manage the “community benefits” plan for the hub in accordance with the Biden administration’s Justice40 initiative, which aims to ensure that 40% of benefits from federal clean energy investments flows to disadvantaged communities. 

“These benefits will include the creation of more than 10,000 quality jobs and the development of STEM-based education programs from K-12 through college to ensure a pipeline of trained and qualified workers to build, then operate and maintain the hub’s hydrogen projects,” PNWH2 said. 

Project management for the hub will be headed by AtkinsRéalis, a Montreal-based global engineering services company. 

“I look forward to seeing how this effort helps us decarbonize transportation and industrial sectors and create good-paying jobs for Washington workers and families for decades to come,” Washington Gov. Jay Inslee said in a statement. “This is exactly what we have been working for here in Washington state over the last 12 years, and the PNWH2 is among the leaders in this effort.” 

“Mitigating climate change requires enormous effort and prioritization of resources. It takes a multistate approach to get things done, like the Pacific Northwest Hydrogen Hub,” Oregon Gov. Tina Kotek said. 

PNWH2 will host a webinar Aug. 21 to share more information about its Phase 1 plans. 

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NRDC: Coal Plants Squeezing Out Cheaper Resources in MISO Market

Coal plants in the Central U.S. are elbowing out lower-cost, cleaner generation and have collected more than $1 billion in uneconomic payments over a three-year span, the Natural Resources Defense Council said in a new report.

NRDC secured Grid Strategies to conduct the report: “The Consumer and Environmental Costs from Uneconomically Dispatching Coal Plants in MISO,” which concluded uneconomic dispatch of coal plants remains a problem in MISO, where coal plants operate even when inexpensive wind and solar generation is available through self-commitment, self-scheduling and unrealistic market bids.

The report found that coal plants collected about $1.1 billion in uneconomic payments from 2021 to 2023 and forced 3.8 million MWh of renewable generation curtailment while emitting 5.2 million short tons of avoidable carbon pollution.

According to the report, coal plants in MISO are operating for extended periods when their marginal costs are run at a loss for extended periods of time while “crowding out cleaner, cheaper resources.”

NRDC said the problem was the starkest in Louisiana and Indiana, which accounted for $341 million and $338 million in economic losses, respectively. The report also called out North Dakota, where coal plants realized $120 million in unjustified payments from 2021 to 2023. Otherwise, the report found that coal generators in MISO states took in anywhere from $2 million to $69 million in uncompetitive payments.

NRDC said the worst offenders included Cleco’s Big Cajun II in Louisiana, Duke’s Gibson Generating Station in Indiana and NIPSCO’s R.M. Schahfer Generating Station in Indiana.

North Dakota was host to the most renewable energy curtailment to accommodate uneconomic coal generation, NRDC said, at 1,516 GWh in curtailments over the three-year period. Two other wind-rich states rounded out the most renewable curtailments: Iowa at 755 GWh and South Dakota at 671 GWh.

“Customers shouldn’t have to pay higher bills to keep dirtier, more expensive coal plants online,” Dana Ammann, policy analyst at the Sustainable FERC Project at NRDC, said in a press release. “Grid operators need to stop this inefficient practice and make these plants compete on a level playing field.”

NRDC said MISO should clamp down on coal operators’ “ability to supply power to the grid more or less at their own discretion — regardless of cost or rules.” The organization said power markets have an obligation to ensure the cheapest resources are run first.

NRDC recommended MISO resolve to decommit uneconomic generators, move to a probabilistic unit commitment system, design voluntary multi-day markets or look-ahead tools and work to ensure the accuracy between generator bids and units’ actual operating parameters. FERC also could “act on the basis that conventional generator self-scheduling and self-commitment result in undue discrimination against renewable resources,” NRDC said.

The organization further said state commissions should stop utilities from recovering uneconomic dispatch in costs and review fuel supply contracts to “ensure they do not perversely incentivize uneconomic dispatch.”

“When uneconomic coal plants displace wind and solar power, it sends a signal to reduce future development of those projects. Coal plant operators shouldn’t get a bailout from customers,” Ammann said.

MISO said it has not reviewed the findings or the report’s methodology.

“MISO works closely with our members, state regulators and our independent market monitor to ensure our markets are efficient,” spokesperson Brandon Morris said in an emailed statement to RTO Insider. 

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GE Vernova Finds Defect in Vineyard Wind Blade

A manufacturing defect has been identified in the high-profile failure of a wind turbine blade off the Massachusetts coast. 

The defect is believed to be isolated, but the other hundred-plus blades made at the same factory will be inspected to be sure, GE Vernova told financial analysts July 24 during a conference call about its second-quarter earnings. 

The company said its wind-power operations continue to operate at a loss, and the Vineyard Wind 1 blade failure on July 13 could expose it to potentially significant claims for monetary damages, but it still expects its wind business to become profitable in 2025. 

Accelerating growth for its gas power business — including orders for 49 gas turbines totaling 9 GW of nameplate capacity in the first half of 2024 — gave GE Vernova a profitable quarter. 

The company expects gas turbine orders to be even higher in the second half of this year. 

Wind Problems

The breakup of iconic conglomerate General Electric concluded at the end of the first quarter of 2024, when its power components spun off as GE Vernova from what is now known as GE Aerospace. 

GE Vernova is heir to 130 years of electrical innovation founded by Thomas Edison in Schenectady, N.Y., and it posts some impressive numbers: Its 7,000 installed gas turbines are the largest fleet worldwide by megawattage, the company boasts, while the 55,000 wind turbines bearing its name exceed 100 GW of nameplate capacity and hold the largest segment of the U.S. market. 

A technician works on a gas turbine system generator under construction at GE Vernova’s plant in Schenectady, N.Y. | GE Vernova

But there have been some quality control problems in the wind business. 

In an October 2022 call, General Electric CEO H. Lawrence Culp Jr. spoke of the warranty costs that had become a drag on the financials of what then was GE Renewable Energy. 

In mid-2024, two AEP subsidiaries — Public Service Co. of Oklahoma and Southwestern Electric Power Co. — sued GE Renewables North America LLC in a New York court. 

They claimed numerous material defects had arisen within two to three years of start of operation of a fleet of 426 turbine sets at three facilities in Oklahoma, knocking a significant number out of service and suggesting expensive repairs ahead for many others. The lawsuit describes a damaged blade being “liberated” from its hub in May 2023. 

The Vineyard Wind blade failure was a much higher-profile affair, given the controversial nature of offshore wind, the number of opponents fighting to keep it from developing as a U.S. clean energy sector and the summertime beach closures that resulted as fragments washed ashore. (See Blade Failure Brings Vineyard Wind 1 to Halt.) 

In its communications about the incident, Vineyard has emphasized that it was a GE Vernova equipment failure. 

GE Vernova CEO Scott Strazik said July 24 that the search continues for the root cause of the Vineyard Wind failure but that a “manufacturing deviation” has been identified in the blade that buckled and disintegrated. No design flaw has been identified, nor any connection to a recent blade failure at the Dogger Bank Wind Farm in England, which was blamed on an installation error. 

The Vineyard Wind blade was fabricated by GE Vernova subsidiary LM Wind Power. Strazik said the quality assurance process should have caught the defect, so it will reinspect the roughly 150 other offshore wind blades that have been manufactured at the same factory in Gaspe, Quebec. 

Construction has been halted on Vineyard as the investigation continues, with about a third of the turbines installed. But Strazik said installation work continues at Dogger. 

Strazik indicated the company is looking to make more money in future offshore wind contracts. 

“Going forward,” he said, “we will remain highly selective on new offshore orders, focused on achieving substantially higher pricing and disciplined commercial terms.” 

The finances of GE Vernova’s wind business were a recurring theme on the call. 

“Right now, wind remains the most challenging segment,” Strazik said.  

And that is not just offshore — onshore wind customers are navigating challenges with permitting delays and higher interest rates. Then there are the defects. 

“We are nearly two years into our onshore wind quality improvement program, and we are making progress, with no new significant issues identified,” he added. 

GE Vernova is trying to accelerate updates to the existing onshore fleet, adding crews in the field and lining up more cranes. A blade inspection robot has been used to enhance the manufacturing process, and the company is optimistic about the future. 

“Longer term, wind should play a critical role in the energy transition,” Strazik said. 

Gas Growth

In the shorter term, GE Vernova is doing a brisk business selling and servicing equipment that could continue to burn natural gas for decades. 

The company announced July 10 it would expand generator production and add more than 150 jobs at its ancestral home, the Schenectady campus that General Electric shrank relentlessly over the course of decades.  

A financial analyst asked if the sharp growth in gas power orders is due to GE capturing a greater percentage of the existing market or the market itself expanding. 

“It’s a combination of U.S. orders and global orders,” Strazik replied. “We’re not in a place today where this is one transaction, one market.” 

Demand for electricity is rising amid the growth of data centers and the push to electrify large segments of the economy. CFO Ken Parks said: “Looking ahead, we see increased demand for gas as a reliable source of baseload generation, which is resulting in incremental growth opportunities for both gas equipment and gas services over the medium to long term.” 

Another analyst asked if GE Vernova could meet the rising demand for gas equipment that utilities are voicing. 

GE Vernova’s facilities have capacity to grow, Strazik said, but there are chokepoints. 

“We do have challenges and need to work across our supply base and supply chain to gain access to more parts — think castings and forgings. That very well may lead to some investments we need to make to support this growth on a go-forward basis.” 

GE Vernova’s smallest business segment by revenue, electrification, reported strong demand and significant revenue growth for the second quarter. 

For the three months ended June 30, GE Vernova reported $1.28 billion in net income on total revenue of $8.2 billion, yielding diluted earnings per share of $4.65. This compares with revenue of $8.1 billion in the same quarter of 2023 and a net loss of $149 million, or $0.55 per share. 

GE Vernova stock closed 4.5% lower July 24. It is part of the S&P 500 index, which was down 2.3% for the day.