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November 12, 2024

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Federal Court Rules in Favor of Transource Congestion Project in PJM

A federal court has ruled that the Pennsylvania Public Utility Commission violated the Constitution’s Commerce Clause in denying Transource Energy a certificate of public convenience to construct the Independence Energy Connection (IEC) transmission project, ruling that the rejection was rooted in economic protectionism rather than siting concerns (1:21-CV-01101).

To proceed, however, the project will have to clear a new PJM benefit-cost analysis that considers other transmission projects approved in the last several years. (See Transource Challenges Pa. PUC Decision in Court.)

“After carefully considering defendants’ arguments, the court is not persuaded that the PUC’s decision was, in substance, about siting. Much of defendants’ argument attempts to deconstruct PJM’s analysis, following FERC-approved methodology, for assessing the project. Defendants’ argument picks apart the FERC-approved methodology and whether it was sufficiently open, allowed for evidentiary hearings, permitted cross-examination or allowed argument by interested parties. But in making these arguments about the various flaws in PJM’s analysis of the need for the project, defendants have not provided a substantive basis for this court to conclude that the PUC’s decision actually related to siting as opposed to determining whether there was a need for the project,” Judge Jennifer Wilson wrote for the U.S. District Court for the Middle District of Pennsylvania in a decision released Dec. 6.

The project is aimed at alleviating congestion on PJM’s AP South interface by constructing two 230-kV lines between Ringgold substation in Washington County, Md., to the Rice substation in Franklin County, Pa., and between the Conastone substation in Harford County, Md., to the Furnace Run substation in York County, Pa.

The PJM Board of Managers approved the project in 2016, stating that it was the most cost-effective way of addressing congestion in Virginia, Maryland, D.C. and western Pennsylvania. (See “Transource Re-evaluation,” PJM TEAC Briefs: Nov. 30, 2021.)

The Maryland Public Service Commission also approved the Maryland sections of the project in June 2020 in a settlement that included a reconfiguration of the Harford County section of the project to run in an existing Baltimore Gas and Electric right-of-way.

Due to the denial and Transource’s subsequent litigation, the PSC has granted the company and BGE a series of extensions on the deadlines for beginning and completing construction of the lines.

On Dec. 13, the PSC approved a third extension, to Dec. 31, 2024.

Similar extensions have also been approved for another component of the IEC, a Potomac Edison rebuild of an existing single-circuit 138-kV transmission line to a 230-kV transmission line between the Ringgold and Catoctin substations in Frederick and Washington counties, Md. Speaking at the PSC meeting Dec. 13, J. Joseph Curran III, an attorney with Venable and counsel for Transource, said the litigation was the primary driver of the extension requests.

The PUC defended its May 2021 decision to deny siting and eminent domain permits by arguing that the benefit-cost analysis PJM conducted didn’t address all the requirements for a project deemed to be necessary under state law and didn’t take into account the full breadth of costs — namely the increased rates some will pay should congestion be alleviated.

PJM’s market efficiency process considers whether the reduction in rates attributed to the project would outweigh its construction costs at a 1.25-to-1 ratio. In a 2020 reanalysis of the project, PJM estimated that it would reduce congestion costs $845 million and cost $509 million to $528 million, which would be assigned to ratepayers in the regions benefiting from the reduced congestion. (See Transource Tx Project Rejected by Pa. PUC.)

Transource argued that the commission was seeking to preserve the cheap power enjoyed in some areas at the expense of others without access to that energy due to congested lines. The company told the court that if states were to be permitted to reject projects on the basis that they don’t benefit their ratepayers, it would defeat the purpose of transmission planning aimed at alleviating congestion resulting in regional price disparities.

“If states could override FERC by applying a conflicting method for determining need, solely to preserve the benefits of congestion for their own citizens, that would eviscerate FERC’s ability to plan the interstate transmission grid in an efficient and fair manner,” Transource said in court documents.

The court rejected the PUC’s jurisdictional arguments, stating that the federal government’s interests go beyond planning projects and extend to seeing that they are built, with the states’ role focused on enforcing local siting, environmental and public safety regulations.

“The PUC is attempting to supplant the role of the RTO and expand its state authority into the regulatory territory occupied by the federal government. If permitted, the PUC’s second-guessing of the methods sanctioned by federal law and employed by the RTO would severely handicap the ability of FERC to ensure just and reasonable rates. Because the PUC’s decision presents an obstacle to achieving federal objectives, it is conflict preempted and violates the Supremacy Clause,” the court wrote.

The commission also argued that the congestion had decreased since 2014 and the project’s benefits would be lower than presented in PJM’s 2016 approval of the IEC project. The benefits would be further diminished, the commission said, if the benefit-cost analysis included the increased rates that might manifest once the congestion was eliminated.

PJM Re-evaluates

While welcomed by Transource, the federal court decision does not mean IEC is out of the woods. First, the PUC has 30 days to file an appeal, and some local permitting remains.

However, Hector Garcia-Santana, senior counsel for American Electric Power, which partnered with Evergy to form Transource, told the PSC on Dec. 13 the IEC projects are “very mature at this point. Materials are in the United States, and they are specific for the project. They are already in hand. The transformers, which are long-lead items, are already in the United States as well. … They were acquired at a time prior to now; so, the price for that type of equipment has increased since then.”

Garcia-Santana added that 70% of the rights of way for the projects have been secured, as well as rights for substations in Pennsylvania. Pending final approvals from the PUC, construction could take 12 to 18 months, he said.

Garcia-Santana’s optimism was somewhat tempered by William Fields, deputy people’s counsel in the Office of the People’s Counsel, who cautioned that PJM will be re-evaluating IEC in the spring of 2024 to consider whether it is still cost-effective and necessary “because of all the tremendous activity going on in this general area of the grid.”

Since IEC was originally approved, New Jersey has selected its first projects under its state agreement approach with PJM, intended to start building out the transmission needed for offshore wind projects, and the PJM board approved Window 3 projects for its Regional Transmission Expansion Plan (RTEP) on Dec. 11.

PJM filed a waiver request asking FERC for more time to complete its required annual reanalysis of the project in November due to how the RTEP projects could interact with the project.

“Performing a reevaluation of the Transource IEC Project before year end with a base case that does not resolve the 2022 RTEP Window No. 3 reliability violations will produce incomplete results until the market efficiency model is updated for reevaluation purposes, which will frustrate PJM’s ability to provide meaningful updates to the [Transmission Expansion Advisory Committee] and the PJM Board. Either way, performing an analysis on incomplete data is an inefficient use of PJM engineers’ time,” the waiver request argues.

The waiver request states that PJM staff will need about three to four months to prepare a base case including the approved RTEP projects to run the analysis on whether the IEC project continues to pass the benefit-cost threshold. It asks that FERC extend the deadline for the analysis to the second quarter of 2024.

PSC members also raised concerns about the potential closing of the 1,238-MW Brandon Shores coal-fired plant outside Baltimore. PJM has said taking the plant offline in 2025, as planned by owner Talen Energy, could result in “degraded grid reliability.”

Commissioner Michael T. Richard queried Fields on whether OPC or PSC staff have “had a chance to hear from PJM about how this cluster of [IEC] projects interacts with these other projects, and really, if they are still needed and cost competitive.”

“We don’t know exactly where PJM is going to be on that,” Fields said. “But it seems a good chance that [the IEC projects] have been overtaken by events from these other activities. I think the real question is going to be, in the spring, when PJM runs the power flow models … [will] they look and say, ‘How much is this going to save in market prices over the future, from that point on?’ And you compare that to the cost of the project.”

Fields told RTO Insider his office would support the project if it continues to promise the benefit-to-cost ratio PJM has projected in the past. However, he noted that it was approved years ago and the grid in that region has seen a lot of change.

“There’s been a huge amount of activity in this part of PJM with respect to new transmission that’s already been built, transmission that’s planned to be built, generation retiring and I think it’s an open question whether when PJM reevaluates the costs and benefits of this plan, if it’s still going to be beneficial in reducing customers’ energy bill,” he said.

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PJM Board Approves $5 Billion Transmission Expansion

The PJM Board of Managers on Dec. 11 approved an estimated $5 billion package of transmission projects in the third window of its 2022 Regional Transmission Expansion Plan. 

In its announcement of the approval, PJM said it is forecasting 7,500 MW of new data center load in Virginia and Maryland, much of which is expected to be clustered around Dulles Airport in Northern Virginia. The RTO is also expecting about 11,000 MW in generator deactivations, most notably the 1,295-MW Brandon Shores plant outside Baltimore. 

The package is made up of dozens of components submitted by Dominion Energy, FirstEnergy, Exelon, PPL, NextEra Energy, Transource Energy and Public Service Enterprise Group. (See “Second Read of $5 Billion in RTEP Projects,” PJM PC/TEAC Briefs: Dec. 5, 2023.) 

The work includes constructing new 500-kV lines from Northern Virginia northeast to the Peach Bottom substation in Pennsylvania, northwest to the 502 Junction substation in West Virginia and south to the Morrisville substation in Southern Virginia. 

The board’s approval caps off a process that began with the opening of the competitive window for transmission owners to submit projects in February. The normal 90-day window was extended to close May 31, and PJM presented three shortlisted packages on Oct. 3 before an Oct. 31 presentation of the proposal to the Transmission Expansion Advisory Committee that it ultimately brought to the board. (See PJM Shortlists 3 Scenarios for 2022 RTEP Window 3.) 

Maryland Office of People’s Counsel Deputy William Fields told RTO Insider that presenting the recommended set of projects at the end of October with the plan of bringing it to the board in December left little time for stakeholders and the public to evaluate the projects and draft comments to the board to allow them to come to a fully informed decision. 

“It’s certainly true that this general issue has been talked about for many months, but we saw this actual list of projects Oct. 31 … and here it is weeks later being approved,” he said Wednesday. 

Fields said his office had received high-level information about cost allocation from PJM on Dec. 12 and is in the process of evaluating the potential impact to Maryland ratepayers. 

The functioning of the cost allocation formula in PJM’s tariff is understood by stakeholders, but Fields said that the scale of the package will present that methodology with a test it has yet to face. 

“We’ve just gotten some preliminary information, and we’re trying to evaluate it and look at it in more detail. But the question is, does the usual allocation method produce reasonable results when you’re talking about extremely large amounts of new load?” he said. 

During the second read of the proposal at the TEAC meeting Dec. 5, several members of the public objected to the package, citing concerns about disruption to historic regions along the proposed route, the inclusion of greenfield construction components, the cost and the likelihood of requiring additional major transmission expansions should load growth continue in the region. 

PJM’s Sami Abdulsalam said the proposal represented the most efficient, cost-effective and resilient combination of the 72 project submissions received during the competitive window and that minimizing greenfield disruption and siting risk were among staff priorities. The RTO included with its TEAC meeting materials an FAQ detailing its role in selecting the proposals in the window. 

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Washington State’s Cap-and-trade Auction Generates $373M

Washington raised another $373.6 million in its final carbon emissions allowance auction for 2023, the state Ecology Department announced Wednesday. That translates to the state raising slightly more than $2 billion in 2023, the first year of what the state refers to as the “cap-and-invest” program.   

In Washington, carbon-emitting corporations bid every three months on state allowances for the pollution emitted by their facilities. The winning bidders all pay the same price on these allowances after the auction. The “settlement” prices in the first few Washington auctions were $48.50 for roughly one metric ton of carbon for the first quarter of 2023; $56.01 for the second quarter; and $63.03 for the third. The result of the Dec. 6 auction, which was announced Wednesday, was a settlement price of $51.89 per allowance.  

The cap-and-invest system, passed by the Legislature in 2021, is aimed at decreasing carbon emissions to a fraction of their current levels by 2050. The program has been linked to an increase in Washington’s price at the gas pump from 15 cents to 50 cents per gallon, depending on who’s doing the calculating. Republicans have been slamming Democratic Gov. Jay Inslee over those increases.  

Washington traditionally has had one of the highest gasoline prices in the nation due to various geographical and economic factors outside of the cap-and-invest program.  

The Washington Legislature has appropriated $2.1 billion in cap-and-invest revenue to be spent on numerous climate mitigation programs from July 1, 2023, through June 30, 2025. On Monday, Inslee announced the state expects to collect $941 million in extra cap-and-invest program money in the first half of 2024, bringing the overall income to roughly $3 billion over the system’s first 18 months.   

The extra $941 million will be added to Inslee’s 2024 supplemental budget request to the Legislature in January. It’s up to the Legislature whether it will approve some or all of that request, which includes:  

    • A one-time $200 credit to the utility bills of roughly 750,000 low- and moderate-income households in Washington;  
    • Speeding up the transition from diesel school buses to electric zero-emission school buses across the state;   
    • Installing electric heat pumps in low-income multiple-family homes, replacing gas heat;  
    • Providing matching funds for competitive federal grants to obtain clean energy jobs; and   
    • Converting a large diesel ferry into to a hybrid fuel-electric ferry. Washington’s ferries are breaking down in increasing numbers. Inslee said Monday that future cap-and-invest income could speed up replacing the old ferries with new hybrid ferries.  
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NERC: Growing Demand, Shifting Supply Mix Add to Reliability Risks

Rising demand and the potential for higher generator retirements are raising reliability concerns over the next 10 years, NERC said in its 2023 Long-Term Reliability Assessment, released Dec. 13.

“In our latest assessment, it really confirms that we’re in an absolute step change in terms of the risk environment we’re seeing on the system, both in terms of reliability, as well as energy assurance,” John Moura, NERC director of reliability assessment and system analysis, said on a webinar with reporters. “The electric power industry continues to face challenges in the future: a rapidly changing resource mix, threat landscape, extreme weather and inverter-based resources.”

Moura said ensuring reliability as the resource mix changes involves stopping plants from retiring early and making sure new resources can provide enough of the same needed services.

Peak demand net energy growth rates in North America are growing more rapidly than at any point in the past three decades, according to the LTRA. Electrification of heating and electric vehicles, as well as increased demand from commercial and industrial customers such as data centers, has reversed the decadeslong trend of falling or flat growth rates.

The aggregated summer peak demand forecast is expected to grow by 79 GW over the next 10 years, while winter demand growth is expected to rise by nearly 91 GW in the decade. Winter demand is growing so fast that NERC expects the Northeast and Southeast to become winter-peaking, or at least dual-peaking, in the coming years.

The supply side is seeing overall growth, dominated by solar power, while fossil generation is expected to decline in the coming decade.

“We are projecting moderate growth,” NERC Manager of Reliability Assessments Mark Olson said. “But it’s not quite keeping up with where the demand projections are going in this most recent forecast that we received. Our total capacity growth is expected to be about 34 GW over the next 10 years.”

New England and New York are expected to have higher winter peaks by the mid-2030s, while the Southeast has already gone through changes.

“SERC-Central and SERC-East became dual-peaking systems in recent years,” the report says. “SERC-Southeast recently began experiencing slightly higher peak demand in winter compared to summer.”

SERC-Central, made up of six states centered around Tennessee, joins MISO as one of the two “high-risk areas” in NERC’s report. That means they are more likely to have insufficient supplies to meet demand at some point in the next decade.

Despite its high risk, MISO has actually improved since last year, when shortages were expected this year, but delayed retirements and some new resources now have NERC expecting a 4.7-GW shortfall in 2028. SERC’s shortfall is expected to hit in 2025-2027 as the region retires 5 GW of coal and brings online 7 GW of natural gas.

Many more regions were “elevated risk areas,” meaning NERC is not worried about them in normal weather, but their systems could run into issues under extreme conditions. Five of the ISO/RTOs are included in the category.

California has also improved because of new capacity additions, as now NERC is expecting negligible risks next summer, but it warns by 2026 that unserved energy risks emerge in the summer.

ERCOT is seeing huge additions of solar power but faces elevated risks during the off-peak periods when its output is lower. Those risks are during peak summer days, and when dispatchable generation is down for maintenance in the shoulder months. Extreme winter weather is also still a concern and warrants continued efforts ensuring generators and the fuel they need to keep running remain available.

New England continues to face elevated risks in the winter with persistent concerns about fuel availability being exacerbated by electrification as its winter peak demand growth rate is the highest in North America, with a 3.46% compound annual growth rate over the next decade.

NERC confirmed NYISO’s own reliability studies, which show a risk of shortfalls for New York City starting in 2025 as peak demand rises and generators become unavailable because state laws reducing the emission of nitrogen oxide.

SPP has a surplus now, but it is going to drop rapidly over the next few years because of retirements and rising peak demand. The RTO also raised its reserve margin from 16% to 19% in the past year.

The only RTO to have a normal risk level — meaning NERC expects its system would handle even extreme conditions — is PJM. While NERC’s forecast has healthy reserve margins in PJM throughout the decade, it noted that accelerated retirements and higher demand growth could still pose challenges in the later years of its assessment.

Ultimately, the shortfalls NERC identified in its report can be resolved with additional procurements of supply, Olson said.

The power industry’s ongoing transition is playing a role, as the move to net-zero emissions is driving electrification that is pushing up demand and is also changing the resource mix on the supply side of the equation. The industry, policymakers and regulators all have to balance reliability with affordability and addressing environmental concerns, Moura said.

“I think when we get tripped up is when in how we prioritize those,” he added. “And so, reliability is something that needs to be prioritized. It’s the heart and soul, for the health, safety and the prosperity of our consumers and all of our communities. And so that needs to be at the heart of it.”

As policy continues to move forward on net-zero issues, reliability must not be forgotten, and the industry needs to continue focusing on it, Moura said.

Reactions to LTRA Highlight Risks

National Rural Electric Cooperative Association CEO Jim Matheson put out a statement saying EPA’s proposal to curb emissions from power plants would only exacerbate the situation NERC’s report highlights.

“NERC’s latest assessment paints another grim picture of our nation’s energy future as demand for electricity soars and the supply of always-available generation declines,” Matheson said.

The coal power trade group America’s Power also used the report to highlight its qualms with recent energy policies.

“Unfortunately, NERC’s latest assessment is deeply troubling because it indicates that, despite several years of warnings about the possibility of electricity shortages in many parts of the country, the risk of electricity shortages has grown worse,” said America’s Power CEO Michelle Bloodworth. “This is largely due to coal retirements, EPA policies and dangerous subsidies for unreliable sources of energy. We again urge Congress and federal and state policymakers to act immediately on these continued warnings.”

On the other side of the debate, the World Resources Institute held a webinar earlier in the day to highlight a new working paper on how to maintain reliability throughout the clean energy transition. Author Kelli Joseph, WRI senior fellow, noted it was more focused on operating reliability, while the LTRA is all about resource adequacy.

“We don’t spend as much time talking about operating reliability,” Joseph said on a webinar. “And I think what we need to recognize going forward, especially through the transition, is that operating reliability becomes a bit more challenging.”

Operating reliability refers to the ability of the system to withstand sudden disturbances, which many of NERC’s mandatory standards address.

If anything, the clean energy transition is going to make reliability more important, as more of the economy is connected to the grid through electrification, Karen Palmer, director of Resources for the Future’s electric power program, said at the WRI event.

“But it’s also important in the near term for continued progress on electricity sector decarbonization,” Palmer said. “Any reliability events or outages or mandatory load-shedding events that could be in any way pinned on decarbonization efforts, rightly or wrongly, could really stall clean energy progress in its tracks. And that wouldn’t be good for meeting domestic and international climate targets.”

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Good COP, Bad COP: Thoughts from the Edge of COP28

NetZero Insider correspondent Dej Knuckey | © RTO Insider LLC

DUBAI, UNITED ARAB EMIRATES — When an official meeting the size of COP28 brings powerful people to one place, a slew of conferences and events emerge on the periphery like a fairy circle. Put COP in a city known for tourism and well-equipped for a mass influx, and the side events begin to challenge the main show. 

So while most journalists at COP28 were in the Blue Zone, where the global negotiations and other official meetings were held, I took a tour of the edge, attending events hosted by analysts and news organizations (S&P Global, The Wall Street Journal and Bloomberg Green), consultants (IDEO, McKinsey, Neol), incubators (Future Mobility Hub, Hub 71) and the sizeable Climate Action Innovation Zone, an umbrella event for multiple summits, forums and roundtables. And there was one event that can’t be named, but I’ll get to that later. 

One Phrase to Hold on To

“Slow, then fast.”  

It was a comment about change, about innovation, about the many new technologies in our world that, once they got going, accelerated faster than anyone could imagine. That phrase came back to me countless times in the days that followed. 

Personal computers, cell phones, cars, lightbulbs: once they started to take off, they quickly became ubiquitous. And in the same way cell phones leapfrogged the Global South to better connectivity without the interim and expensive step of building landline infrastructure, climate solutions may leapfrog the most climate-harmed parts of the world to a clean energy future without the dirty and slow steps of building hydrocarbon-based generation and a grid. But it will require change that is “slow” today to quickly scale to “fast.” 

Slivers of Hope in Unexpected Places

The topics covered by the multitude of events were rarely surprising: challenges in financing the energy transition, advances in the hard-to-decarbonize steel and concrete sectors, accelerating green building, the future of mobility. All interesting, but little new. The frank admissions that we are not moving fast enough and there are massive hurdles that could not be solved by the Blue Zone alone were not surprising to anyone who follows climate solutions. The same faces appeared at the different conferences, and when I found myself watching John Kerry, the U.S. special presidential envoy for the climate, for the second time, I knew it was time to dive into topics I knew less about.  

Yet for all that is not moving fast enough, there were slivers of hope in unexpected places.  

One area of hope came from the insurance industry: Small changes in underwriting rules can lower project insurance costs and open up better financing. Two examples: First, an industry-wide decision to define “nuclear” in a more nuanced way means that the risks of fission will no longer impact the cost of insuring fusion projects; second, after studying cross-laminated timber (CLT), an important green building material, a major underwriter reassessed its risk and will make buildings using the material easier to insure. The insurance industry had assumed CLT reacted to water the way the Ikea pressboard cabinet in your college dorm did after a spill. Not so. 

Another surprising sliver of hope came from a comment tossed out on a panel about lowering carbon in industrial projects. Pumps account for around 10% (10%!!!) of all energy consumed, a solid two TW-years, yet most pumps are highly inefficient. New technologies could make pumps 80% more efficient, unlocking massive savings from a simple piece of technology we all use daily and rarely think about.   

John Kerry shared news about global satellite methane tracking, giving hope that increased visibility will end the massive methane leakages in oil- and gas-rich basins that are currently uncounted in emissions statistics. 

Finally, there was a story about toothpaste that’s worth a full article. But the bottom line that inspired hope was that one of the world’s largest consumer goods companies, Colgate-Palmolive, is sharing its IP to enable toothpaste tubes — which contain aluminum mixed with plastic — to become recyclable. 

A Visit to the Green Zone

Within COP28 itself, the Green Zone is where all those without credentials — neither press nor official negotiating parties — can visit freely. While the first few days of the Green Zone required an invitation, by day four, events were open to anyone who registered online, including numerous groups of elementary school kids.  

Inside the tented “hubs” spread out across the massive Expo 2020 site, it was trade-show-as-usual, albeit with fewer salespeople. The Climate Finance Hub had large booths mainly sponsored by banks; the Energy Transition Hub had yet more booths and scale models of green hydrogen and renewable energy plants. Aside from the Knowledge Hub, which was home to McKinsey’s stage and a handful of other consulting firm booths, most hubs were dominated by major corporations based in the Middle East. It was interesting for a day, and the stages in the hubs had a few good panel discussions, but most of the Green Zone felt like an ad for doing business in the UAE. 

Solar collectors in the Green Zone | © RTO Insider LLC

Long on Questions, Short on Answers

There are meetings around the skirts of COP28 that aim to make a difference, but it was rare to find one that really could have. I found myself at an invite-only event in the stunning Museum of the Future. It was the first time ever that I needed both hands to count the number of billionaires in the room. Add in former and current prime ministers, presidents and indigenous leaders, and I’d be taking off at least one shoe.  

Held under Chatham House Rule, the details and attendees are confidential, but the gist is shareable. The intent was idealistic: a frank conversation about hard-to-solve issues, a focus on building models for the future, with everyone as participants, not audience. Yet even at this confluence of changemakers and captains of industry, the micro-TED-talks of the distinguished guests left little time for the hoped-for conversations. 

I left at lunch — hurrying off to the next event — with scribbled notes on a page labeled “What if?” and questions that I wanted to ask should the microphone have ever reached me: 

    • What if we incent the hydrocarbon industry to strand dirty assets sooner? Do we finance the unbuilding of damaging sectors or is that rewarding past bad behavior? 
    • What if a “protection sector” is paid to protect and regenerate nature, and in a self-perpetuating way? Can blended financing change the mindset about risk in developing nature-based solutions? 
    • What if the cost of clean energy in far-flung regions is brought closer to parity with the developed world, when today solar, for example, costs 20 to 50 times as much on a Pacific island as in major markets? 
    • What if we preemptively manage the loss and damage that remote and indigenous communities will suffer as we ramp up mining for the essential ingredients of a cleaner future? 

Dubai’s Museum of the Future provided a stunning backdrop to a power-packed event subject to the Chatham House Rule. | © RTO Insider LLC

A Fountain of Excess

If you haven’t been to Dubai, imagine Vegas but bigger, hotter and newer. A lot bigger, hotter and newer. With a bigger, higher and more-Bellagio-than-Bellagio fountain at the base of the highest built structure in the world. Excess, thy name is Dubai. 

Aside from the offensiveness of extreme wealth displays in a city whose wealth was derived from the very industry that is destroying poor parts of the planet, it does have one aspect that gave me hope: This whole invented place shows just what massive amounts of money can build when it’s spent with resolve. And solving climate change will require more money and more resolve than a thousand Dubais. But if Dubai is doable, perhaps solving climate change is too. 

An Oasis of Hope in the Desert

There’s a much-needed day off in the middle of COP, though it was my last day in the UAE. I traveled with clean energy accelerator New Energy Nexus to an agricultural incubator launched by Silal, a diversified ag leader in Abu Dhabi with an eye on the region’s food security.  

After more than an hour driving through flat sandy lands dotted with camels and low-slung buildings, we turned off the highway to a dirt road surrounded by construction vehicles. Two more turns, and I was on the doorstep of two startups building a new ag future: Desolenator and iyris by Red Sea.  

They deserve a deeper dive, which will come, but I left with hope: If solar panels can supply clean water and a literally cool greenhouse can deliver a mountain of cherry tomatoes amid the desert, perhaps humankind can innovate fast enough to stay ahead of climate-driven food shortages. 

Whether green innovation and capitalism can solve the climate crises created by last century’s hydrocarbon-centered innovation and capitalism is unclear. What is clear is that innovation and capitalism are moving faster than diplomacy. The final day of COP28 yielded some groundbreaking agreements on cutting fossil fuel use — albeit less vigorous than many had hoped for — but policy doesn’t always precede action.  

Innovations in risk management, finance, corporate cooperation, energy efficiency, hard-to-decarbonize sectors, clean energy and food may drive change that is “slow, then fast.” And we need to reach “fast” as soon as we can. 

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LP&L Moves Remaining Customers into ERCOT System

ERCOT said Dec. 12 it has completed the largest single transfer of customers in its history with the final migration of Lubbock Power & Light (LP&L) customers from SPP.

The city of Lubbock joins San Antonio and Austin as municipalities in ERCOT’s competitive retail market. The more than 107,000 LP&L customers will be able to begin choosing their power providers in January.

That is a big change from the West Texas city’s previous experience with “alley-by-alley” competition that existed until 2010, said Matt Rose, LP&L’s public affairs and government relations manager, this year.

During the Gulf Coast Power Association’s fall conference in October, Rose recalled when LP&L and Xcel Energy subsidiary Southwestern Public Service (SPS) both had distribution facilities on either side of alleys.

“Depending on who you wanted to go with, you chose and then you got hooked up on one side in the alley or the other,” he said.

In 2010, LP&L bought SPS’ infrastructure and LP&L became more of a traditional municipality, serving all the customers in its footprint as a vertically integrated utility. Faced with spending about $700 million to build more generation, LP&L reached a decision point in 2014.

“We said, ‘We have a choice. We can build a power plant, stay in the Southwest Power Pool and operate as we have the past 100 years. Or we can take a look outside Lubbock.’ We could see that these transmission lines for ERCOT are really one county north, east and south of us,” Rose said, alluding to ERCOT’s transmission system.

LP&L said in 2015 it intended to transfer its load to ERCOT, beginning a process that culminated with the Public Utility Commission’s approval three years later. The process involved paying SPS $77.5 million for early termination of a power contract that would have cost the utility more than $17 million a year through 2044. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)

The utility successfully transitioned 70% of its load to ERCOT in 2021. The remaining 30% was moved into ERCOT in what LP&L said was a “seamless migration,” beginning early Dec. 9 and concluding midmorning Dec. 11.

Now, rather than choosing a provider on one side of the alley or the other, LP&L consumers can select from more than 85 retail providers during a six-week “shopping” window that begins Jan. 5. The utility then will begin migrating the customers to their chosen providers in March and become a transmission and distribution entity.

“This has been an interesting and a fun experience, but Lubbock was able to do this because Lubbock is uniquely situated,” Rose said. “We were ending all business in the Southwest Power Pool in order to move to ERCOT, and that allowed us the liberty to go pursue this.”

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Study Finds 11% Dip in Housing Prices Near Wind Turbines

A newly published Berkeley Lab study finds that sale prices temporarily decrease for property located within a mile of newly announced and newly built utility-scale wind projects.

The conclusion runs counter to earlier studies published by the lab, some of which were compiled by some of the same researchers but relied on limited sales data.

During a webinar Dec. 13, one of the authors said vastly more real estate transaction data is available now than a decade ago, many more large-scale wind turbines have been erected, and the methodology for analyzing the information has evolved.

The bottom line: Shortly after a commercial wind turbine site is announced, houses located within a mile begin to sell for less than those three to five miles away from the same site. Over the next nine years, the difference grows to 11% on average, then gradually declines until the disparity is statistically insignificant.

“We see a dipping of values after the announcement of the project that kind of bottoms out right around the ending of construction and the beginning of operation,” said Ben Hoen, a research scientist at Lawrence Berkeley National Laboratory.

Hoen, Eric J. Brunner, Joe Rand and David Schwegman are the authors of “Commercial Wind Turbines and Residential Home Values: New Evidence from the Universe of Land-Based Wind Projects in the United States,” which was published this month in the journal Energy Policy.

To reach their conclusions, the researchers took CoreLogic’s database of more than 260 million U.S. residential property transactions from 2005 through 2020 and cross-referenced it with the 72,000 towers listed in the U.S. Wind Turbine Database.

Wind turbines are proliferating nationwide. | Lawrence Berkeley National Laboratory

After applying a rigorous set of filters and conditions, they were left with 496,000 transactions within five miles of a turbine rated at more than 600 kW; those transactions occurred no more than four years before and 10 years after the turbine was announced.

The greatest price impacts were seen in the 20,331 properties within a mile of a turbine that had been announced or built.

That is vastly more data than some of the previous studies. A 2009 report described by Berkeley at the time as “major” analyzed not quite 7,500 transactions in total.

That study and other studies found no statistically significant impact on sale prices.

But more recent studies in the EU and southern New England did show a negative impact on sale price of houses near wind projects.

“This was a curious finding for us,” Hoen said, “given our past work of not finding statistically significant impacts.”

A key factor is Europe is that the population density is much greater than in the United States, the authors said. It is harder to site a wind turbine away from people there. Similarly, the housing price impacts recorded in Massachusetts and Rhode Island were greatest in the more densely populated eastern portions of those states.

Finally, the authors emphasize that in their own analysis for the new study, the greatest price impact was seen in counties that were part of, or adjacent to, metropolitan areas with population greater than 250,000.

Wind power’s impact on home prices is not just a statistical curiosity. It can be a significant factor in building support for a project.

“Property values remain one of the top concerns for local communities that are considering hosting a wind energy project, or have a wind energy project in their midst,” Hoen said. “Often, a home is a family’s most valuable asset, and therefore protecting [it], and protecting its value, is of extreme importance.”

Because a geographically identifiable group of residents has been shown to be impacted economically by wind power projects, it may be possible to directly compensate them, the authors write.

And because the impacts of a project have been shown to begin well before any wind turbines are erected, it may be possible to do a better job explaining the actual impacts of the towering equipment, rather than leave it to speculation. Better line-of-sight photo simulations or location-specific audio simulations might help ease the concerns of nearby residents and the people who buy their homes.

Hoen said the analysis found no variation by size. The largest wind turbines had the same effect on prices as their smaller cousins.

Nor, he said, was there any attempt with this study to analyze the positive impacts of wind power generation, such as job creation or tax revenue.

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House Democrats Introduce Bill to Spur Interregional Transmission

A bill introduced in the U.S. House of Representatives by Democrats on Dec. 13 would grant FERC numerous new authorities over interregional transmission in a bid to spur large projects and increase the flow of renewable energy across state lines.

The 210-page Clean Electricity and Transmission Acceleration (CETA) Act, introduced by Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), would add six new sections to the Federal Power Act, many of them directing FERC to issue new regulations for how it can site new interregional projects. Most significantly, it would require the commission to solicit plans from grid operators and other transmission providers identifying interregional transmission projects every three years.

The bill details the criteria for how FERC would evaluate the plans and the projects they identify. The commission would be required to issue its solicitation within a year and a half of the bill’s enactment.

FERC also would gain explicit siting authority over interstate transmission lines with capacities over 1 GW, if the commission finds they enable the use of renewable energy, increase reliability and reduce congestion, among other provisions.

The bill also would set new cost allocation rules for any transmission facility “of national significance,” defined as a new line that has a capacity of 1 GW or more; any transmission connecting offshore generators; and upgrades that increase an existing line’s capacity by 500 MW or more. Costs would be allocated “to customers within the applicable transmission planning region or regions in a manner that is roughly commensurate with the reasonably anticipated transmission benefits,” the bill says.

Many of these projects would qualify for a 30% investment tax credit established by the bill. To carry out all its new responsibilities, FERC would be allowed to establish a new Office of Transmission.

“The biggest challenge facing the United States’ ability to meet its climate goals is the lack of capacity of our electrical grid to connect clean energy generation to the new demand that comes with economy-wide electrification,” the House Sustainable Energy and Environment Coalition (SEEC), made up of 93 Democrats, said in a press release. “CETA aims to inclusively and efficiently support the buildout of transmission lines to transport the electricity from its generation source to the homes of the American people.”

The release included statements of support from former FERC Chair Richard Glick, Grid Strategies’ Rob Gramlich, Americans for a Clean Energy Grid, the American Clean Power Association and several environmental organizations.

“The CETA Act is an important step in addressing some of the most pressing issues around transmission capacity and the diverse technologies that can deliver solutions at speed and scale,” AES said in a statement. “We commend the efforts of the SEEC caucus on this thoughtful bill, which aims to reduce bottlenecks and improve planning of and connection to the transmission system.”

The bill also would incentivize development of solar, wind and geothermal resources on public lands and establish a production goal for such resources of at least 60 GW by the end of 2030. It would direct the Department of Agriculture, in consultation with the Department of Energy, to identify priority areas for solar and wind.

Finally, CETA would codify President Joe Biden’s goals for offshore wind deployment, directing the Department of the Interior to issue permits for a cumulative of 30 GW by 2030 and 50 GW by 2035. It also would establish an Offshore Renewable Energy Compensation Fund in the Bureau of Ocean Energy Management “to compensate eligible ocean users for damages experienced as a result of the development of an offshore renewable energy project through a claims-based process and to provide grants to eligible recipients to mitigate future damages from such projects.”

With Republicans in control of the House, the bill has virtually no chance of passing as drafted. And the increased authority it would grant to FERC is likely to draw some opposition from states both red and blue, along with their utilities.

The permitting reform debate has been on apparent hiatus for months, as the House battled over the speaker position and the debt ceiling. Several bills have been introduced in both houses, but none has been viewed as a starting point for party negotiations. The last hearing by the Senate Energy and Natural Resources Committee on the subject was held in July. (See Members of Congress Debate Transmission Permitting.)

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NYISO Stakeholders Balk at Proposed Day-Ahead Market for Demand Resources

NYISO stakeholders continued their criticism of the ISO’s effort to improve its demand response programs, saying its recent “issue discovery” report inadequately addressed their concerns and that its proposal to allow demand-side resources (DSRs) to participate in the day-ahead market is hollow.

During the Dec. 6 Installed Capacity/Market Issues Working Group (ICAP/MIWG) meeting, NYISO presented findings from its Engaging the Demand Side (EtDS) report, a response to stakeholders’ request that the ISO investigate whether rules could be improved to reflect DSR’s “evolved … capabilities while keeping participation options for these resources simple.”

The report recommended investigating a day-ahead-only addition to the DER participation model that it said could increase participation opportunities for DSRs that can operate for longer than the four hours required by the special case resource (SCR) program but cannot participate in the dispatchable DER model, which requires daily bidding and scheduling in the energy market. The report rejected requests to expand the SCR model.

nyiso market

Historical enrollment in NYISO’s EDRP and ICAP/SCR programs by MW | NYISO

Stakeholders representing demand response providers expressed reservations about the feasibility and cost implications of the proposals, repeating concerns expressed at previous meetings. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.)

“I am very disappointed in this report and the outcome of this yearlong process of analysis and engagement with the stakeholders,” said Amanda De Vito Trinsey, a partner at Couch White, representing the City of New York and large industrial, commercial and institutional energy consumers.

Jay Brew, managing director of Stone Mattheis Xenopoulos & Brew, who represents Nucor Steel Auburn, said he felt NYISO did not appreciate the risks their recommendations could pose to SCRs. “I’m generally disappointed with the level of effort here,” he said. “It would seem to me you’d want to be enhancing demand response as much as possible, particularly peak load response, as opposed to seeing the SCR program wither and die.”

SCRs are DSRs capable of being interrupted or curtailed by the ISO for at least four consecutive hours each day, and they act as installed capacity suppliers.

A DER can be a DSR, a generator or storage resource of 20 MW or less, or a facility of up to 20 MW composed of two or more technology types behind a single point of interconnection.

The report recommends exploring market rules that would enable SCRs to participate in the day-ahead market and allowing them to submit bids or receive schedules without re-evaluation in the real-time market. These DSRs could be able to register with energy durations of two, four, six or eight hours.

The ISO said it hasn’t decided whether day-ahead only DSRs should be allowed to aggregate, as dispatchable DER and SCRs can.

Telemetry

NYISO requires DER aggregations to provide telemetry on a six-second basis, or in real time for aggregations of at least 100 kW.

Stakeholders said this requirement could be financially burdensome, particularly for smaller SCRs.

Aaron Breidenbaugh, senior director of regulatory affairs at aggregator CPower Energy Management, said the proposal would be uneconomical for SCRs below 5 MW.

“We’ve seen the numbers for our customers that range between $10 [thousand] and $30,000 for telemetry,” he said.

“And certainly, the vast majority of existing SCR resources are below five MW.”

Breidenbaugh also questioned the ISO’s commitment to incorporating stakeholder input.

“I think [the report] is misrepresenting this concern. … The issue we have with respect to telemetry isn’t just for small customers, it is more pronounced with smaller customers, but this is a big barrier for all sizes,” Breidenbaugh said.

Expanded SCR Program Rejected

Stakeholders had urged expansion of the SCR program, saying many SCRs are now capable of operating for longer than the four-hour minimum requirement and can respond in less than the minimum 21-hour notice they now receive.

But ISO staff said the program requires extensive manual processes, making expansion impractical. Expanding the SCR model also would continue reliance on out-of-market actions, contrary to the need for more grid adaptability due to increased penetration of intermittent generating resources and storage, staff said.

Rules allowing SCRs to have multiple energy duration limits and startup/shutdown times would require the ISO “to call on them individually like DER,” staff said in the presentation. “NYISO would no longer be able to call SCRs to activate based on load zones.”

NYISO proposed using its existing DER participation model software instead of modifying the SCR program, saying it adds flexibility and cost efficiency to grid operations.

“Adding the stakeholder-requested flexibility to these processes is expected to affect the ability of NYISO grid operators to respond to system conditions quickly and efficiently,” the report said. “Making the requested modifications to the SCR program would require grid operators to understand the unique operating characteristics of individual SCRs to determine which resources are best positioned to respond to a given set of conditions.”

The ISO recommended maintaining the SCR program for the time being due to its simplicity, acknowledging that the DER model is more complex. “The NYISO does not intend to eliminate or modify the SCR model at this time, providing existing and future DSRs flexibility to choose the participation model that best fits their operating characteristics,” the report said.

ISO staff also rejected stakeholders’ request to eliminate the ISO’s proposed 10-kW minimum size for individual DER participation, which they have called discriminatory and counterproductive. (See Clean Energy Groups Protest NYISO DER Proposal.)

Staff said eliminating the threshold could significantly increase the number of small DER seeking to enter New York markets, increasing administrative costs. Staff also noted that software automation being developed for Order 2222 compliance that could help will not be in place until at least 2026.

Stakeholder Feedback

Stakeholders at the ICAP/MIWG meeting criticized the EtDS report, the ISO’s project prioritization process and what they called a lack of clarity on next steps.

De Vito Trinsey said the ISO was simply going through a “check the box” exercise rather than making a genuine effort to enhance demand-side participation.

Julia Popova, NRG Energy’s manager of regulatory affairs, concurred, questioning why ISO staff’s only recommendation was to explore the development of a day-ahead DER enhancement. “This issue seems to address only one issue among many that were raised [in previous conversation], so why was this the winning issue?” she asked.

Francesco Biancardi, a market design specialist with NYISO, responded, “We’re trying to find a path that both addresses external stakeholder feedback and addresses NYISO’s concerns regarding reliability and market efficiency. So a day-ahead demand response enhancement seemed like a good way to check all those boxes.”

De Vito Trinsey asked the ISO to explain why it hired a consultant to examine only small-scale residential DERs and not anything else within the demand-side program.

James Sweeney, a senior attorney with the ISO, responded that the consultant was hired because ISO staff did not have the bandwidth to study a group of resources that were not originally part of the EtDS project and which they were not experts in.

These specific concerns were compounded by stakeholders’ belief that the ISO failed to heed the warnings expressed previously.

“The assumption [from NYISO] is that moving demand response, particularly large customers, to the DER model will go smoothly,” Brew said, “and that seems to disregard the repeated comments that were raised by others regarding DER participation.”

Breidenbaugh had a similar view, saying, “If you’re holding [this day-ahead recommendation] as the principal outcome of this Engaging the Demand Side effort, you’re essentially ignoring all of the input that you got from stakeholders during this process.”

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MISO to Reformulate Parts of Order 2222 Filing with Stakeholder Input

MISO this week promised five months of additional stakeholder discussion on its Order 2222 compliance plan before it attempts a second filing with FERC to take care of the commission’s concerns.  

In October, FERC ordered MISO to propose an earlier start date than its proposed 2030 date and explore the possibility of allowing DER aggregations across multiple pricing nodes. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)  

FERC allowed MISO an extension until May 10 to hold additional discussions with stakeholders before proposing a new Order 2222 effective date and deciding whether it can handle multinodal aggregations. The conversations largely will take place in MISO DER Task Force meetings. 

During a Dec. 11 DER Task Force meeting, Managing Assistant General Counsel Michael Kessler said MISO is in the process of evaluating whether multinodal aggregations might be possible within the footprint.   

Kessler also said while FERC appeared to agree MISO needs its new market platform in place before it can handle offers from DER aggregations, it must land on a closer go-live date. The RTO plans to reveal a new date and its reasoning behind it to stakeholders at the April meeting of the task force. 

“We’re going to have a busy run for the next few months,” said DER Task Force Chair Zac Callen, who also is an economic analyst with the Illinois Commerce Commission.  

MISO’s DER Program Manager Paul Kasper said creating bidding parameters under a multinodal aggregation will be “technically intensive.” He also said MISO will need coordination with distribution utilities to answer FERC’s questions about MISO’s proposed reliability reviews for aggregations and coordination protocols between MISO, distribution utilities and aggregators.  

MISO originally said it would handle a new go-live date and multinodal aggregations in a filing separate from FERC’s other, less-intensive clarifying questions on MISO’s compliance plan. However, the grid operator since decided to make a single filing to satisfy the commission’s asks.