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April 10, 2023May 9, 2024

IPF Panel: MSSC Limits Could Cut OSW Power Coming Onshore

BALTIMORE — Offshore wind turbines can — and in the coming years, will — produce thousands of megawatts of electric power, which is way more than the onshore transmission system is currently able to absorb, according to Bill Magness, senior principal consultant at DNV.

States and offshore developers “want to see the most bang for the buck. … [They] want to see the maximum transfer into the system of those offshore resources,” Magness, the former CEO of ERCOT, said during a panel at the Business Network for Offshore Wind’s recent International Partnering Forum (IPF). “Moving into the onshore grid is where the rubber really hits the road, or the water, or whatever it’s hitting.

“The onshore grid is where the load is … where the ratepayers are, and the onshore grid is where an extremely sophisticated, complex, several-decades-old, AC-based system lives … [with] limits on reliability and limits on interconnections that have to be honored,” he said.

The most severe single contingency (MSSC) is one of those limits, setting a maximum amount of reserve power a balancing authority is responsible for in the case of a sudden, large outage. For ISO-NE, the limit is 1,200 MW; in NYISO, it’s about 1,310 MW; and for PJM, it’s 1,500 MW — all of which “are suboptimal from the perspective of the technology that you want to bring onshore,” Magness said.

Reflecting the integral role it will play in offshore development, transmission was a major theme at IPF, with its own track of focused panels looking at the solutions that will be needed to efficiently and cost-effectively bring offshore power on shore. Meshed HVDC networks, as opposed to individual radial lines, have been identified as the most optimal way of connecting offshore turbines to onshore substations. (See OSW Developers Look to Europe on Meshed HVDC Tx.)

But the MSSC issue “is one that highlights a number of other issues that we’re going to be facing,” Magness said. To begin with, reliability standards based on the MSSC “were not written with HVDC in mind. … People are finding that, well, maybe the single contingency breach for HVDC is different than we thought.”

The MSSC is not itself a limit, he said, but NERC uses it to set the reserves a BA is required to have, purchased and ready to go in such contingencies.

“If you lose certain generation, you will have to make that up within 15 minutes; that’s the standard requirement,” said Gaurav Karandikar, senior manager for reliability analysis and technical services for SERC Reliability. “The balancing authority can actually study their system and determine that value … and that drives how much reserve you are going to carry.

Talking transmission at IPF were (from left) Sheri Lauten, National Grid Ventures (moderator); Bill Magness, DNV; Shahil Shah, NREL; Gaurav Karandikar, SERC; and Peter Shattuck, Anbaric. | © RTO Insider LLC

“The other aspect is that there is a 90-minute limit, where after that first contingency [where you] have used your contingency reserve,” Karandikar said. “You have to re-establish that contingency reserve within the next 90 minutes, so you’re ready for the next contingency.”

Factoring onshore wind into those equations may mean looking at the issue “in a more flexible way, in a more targeted way that can manage … the larger-end feeds that are coming onshore,” he said.

Echoing Magness, Shahil Shah, a senior engineer at the National Renewable Energy Laboratory (NREL), said the MSSC issue is complex; it’s part of the problem but also a potential solution. The current MSSC limits don’t “allow us to go for big cables that are currently available,” he said.

“We see many projects where cables are coming from the same lease areas going to the same substations, but there are multiple of them,” Shah said. The way forward will involve designing HVDC transmission that can quickly isolate and recover from outages or other contingencies, he said.

Super-fast, super-reliable DC circuit breakers and multivendor interoperability will be needed, as well as revised, more sophisticated MSSC limits, he said.

“We need to coordinate the reliability standards and the resource standards together,” which will also require coordination between regulators, Shah said.

Coming in with a developer’s perspective, Peter Shattuck, president of Anbaric Development Partners’ New England projects, called for an incremental approach to the tangled issues involved in MSSC limits.

“It’s really hard to navigate the challenge of finding the most cost-effective solution that’s responsive to signals we’re getting from procuring entities during a period where these myriad questions and challenges that have been laid out are not resolved,” Shattuck said.

Magness agreed that with new procurements coming, “it is really essential that we start to inventory what these [transmission] issues are, identify them and pick the ones that are most important and try to start solving them.”

A 2-GW Standard

The meshed, HVDC model is well established in Europe, where most recently TenneT, the transmission system operator in the Netherlands and parts of Germany, announced its plans for a standardized offshore transmission platform with 2-GW certified cable. The company intends to deploy this new system on at least 10 projects, a scale that could have significant impacts for offshore supply chains, Shattuck said.

“When there are tenders out there for 10-plus 2-GW systems, that’s where the supply chain is going to go,” he said. “So, if you want something else, if you want a customized solution or even kind of tweaking the 2-GW design to address some of these [MSSC] issues, that’s going to have implications for costs and the timelines for bringing [a] project online.”

At the same time, a standard 2-GW cable could provide considerable economies of scale, he said. While New England currently has about 6 GW of offshore wind in development, Shattuck cited an industry analysis that an additional 24 GW of projects or more will be needed to meet the region’s climate goals.

“If you’re doing that with 2-GW systems, then you’re going to need 12, and if you’re doing it with 1,200-MW systems, you need 20,” he said.

ISO-NE has taken the first steps toward resetting its MSSC from 1,200 MW to 2 GW, with a recent letter to its Joint Planning Committee with NYISO and PJM, asking for a feasibility study on the change.

“As the region moves forward with the interconnection of large-scale renewables, such as offshore wind resources, project developers may identify proposals larger than 1,200 MW,” Brent Oberlin, ISO-NE director of transmission planning, said in the March 27 letter. “The 1,200-MW limitation could constrain an otherwise optimal interconnection design. …

“Depending on system conditions in PJM and NYISO, this limit can be raised in real time to a maximum of 2,000 MW,” he said.

Magness also pointed to NYISO’s ongoing exploration of dynamic scheduling of reserves, which could allow New York to import more clean energy to meet its emission-reduction goals of 40% below 1990 levels by 2030 and no less than 85% by 2050. (See Study: NYISO Dynamic Reserves Could Lower Congestion, Costs.)

Panelists also said that, rather than trying to change any NERC standards — which would involve what Magness called a “baroque” process ― there are opportunities for regional changes that could address the MSSC limitations. Such solutions could “address reliability concerns and optimize the technology,” Magness said.

Low-hanging Fruit

NREL’s Shah argued that grid operators’ mandated levels of reserves are often higher than needed, “so we should be able to inject more power during those times. … That’s low-hanging fruit, just a slight modification in the standards.”

Multiterminal offshore grids might offer another option, assuming that not all terminals would be operating at full capacity, he said. “If the capacity factor is diversified, then also there is another way to make sure that we are within limits, but at the same time we are allowing points of high injections.”

Having 2-GW lines also could provide “head room” for capacity in the event of outages, Shattuck said. For example, with three 2-GW lines operating with a capacity of 1,500 MW each, if one line trips off, the other two lines can each pick up 500 MW of capacity, “so the system only loses 500 MW, well below the current contingency,” he said.

“The ability to pick up extra power just increases the more lines that are connected to shore and networked offshore,” Shattuck said. “So, in a way, the challenge is just getting over the near term … and getting these first projects built. In a way, the offshore grid becomes a solution to the constraints of the onshore side.”

Regional solutions can also be more finely tuned, Magness said.

“The regions that have seen more resources, wind and solar systems, some of what they have realized is … you’ve got to slice this thing a lot more finely than you used to,” he said. “You need to procure reserves during demonstrated hours and minutes when you need them, and you don’t need to procure reserves at the same levels when you don’t.

“You start to see what those patterns are, what seasons of the year in your particular region require [you] to have more reserves on hand, and you’re able to run the system more efficiently based on everything you’ve got on the system,” he said.

Such procurement strategies could also allow grid operators to take advantage of the “extremely fast response times” batteries can offer, he said.

Both Karandikar and Shah said that the foundation for such changes will be good research and good computer models, supported by industry.

“If you’re looking or asking people to come up with a realistic limit, we should be able to make sure that we are providing them with good information,” Karandikar said. It is incumbent upon industry to ensure “planners have enough tools,” he said.

“It will be possible that we can maintain reserves offshore, provided we are able to forecast accurately how much capacity is available,” Shah said, noting that NREL has run demonstrations of such forecasting. “It is possible if we have a coordinated design for the offshore wind generation.”

Magness sees a range of benefits for meshed HVDC offshore transmission and more flexible approaches to MSSC limits, including less curtailment and opportunities for redispatch, “being able to move the power around through software systems in much more effective ways,” he said.

The task ahead is to think “in terms of building out a network not only to optimize the amount of wind that comes into the system but provides the maximum controllability, flexibility benefits that we can get from HVDC technology,” he said.

“How do we imagine them in a world where we have a grid that serves load onshore but also a grid that doesn’t have load sitting next to it in the ocean?” he said.

April 10, 2023

New York 2023: Growing Pains for the Energy Transition

ALBANY, N.Y. — The 2023 New York Energy Summit last week focused on the financial, regulatory and technology landscape in the state as it presses forward with a hugely ambitious, complicated and expensive energy transition.

Opportunity tempered with challenge and uncertainty was a recurring theme in the comments of dozens of panelists and in the questions posed by scores of attendees of the April 4-6 summit.

New York’s leaders are still wrangling over key policy details, and federal guidance on how to leverage key tax incentives for clean energy finance is incomplete.

Meanwhile, despite some streamlining, the development process is still often slow and difficult in New York, and local opposition can be fierce. The grid interconnection process continues to be a bottleneck, as well.

But a confluence of factors — vision and opportunity backed by leadership and funding to make it reality — is present in New York in 2023.

Nick Addivinola, of community solar developer Nautilus Solar, observed that money is not a problem, even amid high interest rates and inflation.

“There is certainly more capital chasing projects today than ever,” he said. “There’s more capital than projects.”

The 19 presentations at the conference included discussion of New York’s landmark climate law, efforts to decarbonize buildings, grid resilience, and financing all the work that the state needs or wants to see accomplished.

High Needs

A frequent talking point at the summit was the large number of skilled workers who will be needed to carry out New York’s energy transition — more than 200,000 by 2030, according to a state estimate — and how far short of that the present workforce is.

Michel Delafontaine, president of Alternative Aviation Fuels, said the timelines specified in various state and federal laws and guidance “seem to be long, but it’s short. In terms of workforce development, we’re looking at a turnover of three to four years to form and shape folks that know what they’re doing in many aspects — electrical, pipefitting, number-crunching, legal and all the aspects of project development — and we’re short of them.”

“I can testify to that aspect,” he said. “We’re short of workforce.”

Jeffrey Andreini of Crowley Wind Services said it’s a topic that comes up often in discussion of offshore wind. “What I tell people all the time is you can have the all the assets you want, you can have all the [waterfront construction and maintenance] terminals that you want, but if you don’t have anybody that’s going to run a vessel, going to be able to do the logistics on the terminal, guess what? Nothing’s going to happen.”

Richard Lawrence of the Interstate Renewable Energy Council said this reality is sinking in as more projects go from concept to execution.

“In the 20 years I’ve been working on this, I’d say the last year has really been the first time I’ve seen companies working in this space really recognizing the challenges that it takes to develop the workforce. It’s coming up now as certainly in the top three of limiting factors to actually getting to our goals and building these projects out.”

He added: “We’re competing against every other sector that’s out there that’s looking for workers.”

The Inflation Reduction Act of 2022 recognizes this need, Lawrence said. He called it one of the first federal incentive/policy packages with labor and workforce development provisions baked in.

Gary McCarthy, who has pressed the Smart Cities technology initiative in his dozen years as mayor of Schenectady, said more emphasis needs to be placed on the value employees bring to an organization than to their sheer numbers.

“We’re looking for quantity now; everyone has a demand for employees,” he said. “It’s hard sometimes to step back and focus on quality; how do you do that outreach? How do you do that in a systematic way of building the rapport, getting the message and then creating the opportunity?”

New York law requires that more than a third of state spending on the energy transition benefit disadvantaged communities, and a main strategy to accomplish this will be training and employment opportunities — which are easier to mandate than achieve.

“I think the key piece here is to have really authentic organizations that have the trust of local communities partner with entities that have something to offer,” said Adam Flint of the Network for a Sustainable Tomorrow. “Transferring resources into disadvantaged communities rather than doing everything from the outside, actually hiring people to help build these programs, is a really good move.”

The clean energy sector also butts up against a multigenerational shift away from the skilled trades by a significant portion of American society, and it has trouble competing for the attention of young people entering the workforce amid the allure (and salaries) of the computer technology sector.

Both challenges are real, panelists said, but can be overcome.

The skilled trades should be introduced as a career option to children as young as 10 to 12, midway through their schooling, panelists said, and for those who are graduating now, clean energy should be framed as an opportunity to become one of the early experts in a new economy.

Also, Big Tech is currently laying workers off by the thousands, while clean energy is hiring by the thousands, Lawrence noted.

Andreini pointed to the optics of recruiting young adults to help save the planet. “We’re cooler,” he said. “At the end of the day, you’re talking about an energy revolution right now. That’s really what’s going on. I tell adults that, and they get excited. It’s got to be about more than just money.”

Major Projects

Houtan Moaveni, executive director of New York’s Office of Renewable Energy Siting, was interrupted by the only spontaneous round of applause during the summit when he said his office — a recently created entity — has issued more final siting permits in the last two years than were issued in the preceding nine years. Each took only six months on average.

Darren Suarez of Boralex later qualified that record: ORES, which works with projects rated at no less than 25 MW, moved much of the review process outside the formal permitting procedure. Including pre-permitting work, the overall time involved is still lengthy.

But that procedural standardization and streamlining has been the beneficial result of the Section 94-c law under which ORES operates, he said.

“It has the appearance of being faster, but I think the big thing for developers is it’s more certain. You know spending the money — if we do the right thing; we meet the objectives; we meet the standards — we’ll get the permit.” That was not always the case with Article 10 permitting, which 94-c supplemented, he said.

One of the biggest initiatives in New York is not in the state, but in federal waters off its coast.

Gregory Lampman, director of offshore wind at the New York State Energy Research and Development Authority, said the state’s goal for offshore wind is 9 GW of installed capacity by 2035, but the OSW program folds in much more than the flow of electrons from ocean to land: It seeks to create a local manufacturing supply chain and the supporting infrastructure; develop a workforce; and coordinate transmission needs with NYISO while striking a blow for environmental justice and benefiting disadvantaged communities.

The goal is a new ecosystem with spinoff benefits.

“We’re trying to empower the whole of manufacturing capacity in the state of New York,” while simultaneously competing with neighboring states for finite resources and collaborating with them to expand availability of those resources, Lampman said.

And how is that working out with the 27 OSW leases up and down the Atlantic Coast?

“We probably are far short of where we need to be, but we are moving forward because there are economic pressures to develop that supply chain,” said Jim Bennett, a senior adviser at the U.S. Bureau of Ocean Energy Management.

He said BOEM’s focus is now transitioning from leasing to project review and approval.

“In the past three years, we’ve doubled the number of people we have on board, which for a federal agency is pretty impressive, but during that same time, our workload has increased fivefold,” Bennett said.

With the expansion of variable wind and solar power generation, New York needs a large amount of energy storage capacity: It has set a near-term goal of 6 GW, the most of any state, but eventually will need significantly more, some of it the long-duration type that is not yet technologically mature.

This, along with the domestic manufacture incentives of the IRA, could create a new industry sector in New York, said William Acker, executive director of the New York Battery and Energy Storage Technology Consortium.

“This is going to be a real catalyst to grow the economy in New York state,” he said.

In the wake of the supply chain disruptions of 2020 and 2021, there has been great interest in domestic manufacturing, said Michael Slattery of Agilitas Energy. “I can’t speak to the precise amount of batteries that will come into New York, but I think New York is very well positioned — as is any state that has a large industrial base and a hefty demand for the output.”

Slattery said he might be more pessimistic than most on the subject, but he expects domestic demand to outstrip domestic production for three to five years.

“It is a huge, huge logistical challenge to get these factories built,” he said.

Acker touched on a subject he has raised before: The present structure of New York’s electricity market makes large-scale energy storage uneconomical.

“The new programs that the state is bringing forward might level that playing field, but right now there isn’t really much traction,” he said. “It was mentioned earlier: We have great goals in this state, but actual deployed projects at the bulk level have been pretty minor.”

Hurdles and Hiccups

Tens of thousands of megawatts of clean energy capacity is on the drawing board in New York state, but many projects will never advance beyond that stage. This divide was a frequent topic at the summit.

Panelists touched on the long and winding road that connects inspiration and execution in New York state government, as competing interest groups delay or reshape the laws and regulations needed to bring grand goals such as decarbonization to reality.

New York’s landmark Climate Leadership and Community Protection Act — which set many of the goals the state and its energy sector must now reach — was signed into law nearly four years ago but is still mired in planning and sometimes heated debate.

State leaders are fond of pointing out that the CLCPA mandates 70% of the state’s power come from renewable energy by 2030, and that the project already in NYISO’s interconnection queue would bring the state to 66%. But some of those projects will never break ground.

“Projects haven’t been built for a variety of reasons. One of those certainly is interconnection,” Boralex’s Suarez said.

“We look at what’s in the queue now, [and] we actually see all the projects the state would need to meet, basically, its objectives. A lot of those projects won’t come to fruition for a variety of reasons, some of them as a result of timing or economics, or sometimes they’re purely speculative. Sometimes some developers may have more than one project that they’re putting in multiple interconnection queues.”

NYISO is trying to speed up the process and reduce some of the speculative activity, Suarez said, but the volume of applications is unprecedented, and the ISO is not set up for it. The most recent Class Year was one of NYISO’s largest ever, he added, and many projects had to go to FERC to seek additional time to get into it.

Moderator Ingo Stuckmann, of the Zero Emission Think Tank, asked his panel about those economic challenges, such as triple-digit price increases for substations and multiyear wait times for transformers.

Suarez said the long lead time between contracts being signed and work starting on projects proved harmful in 2022. “There is a real disconnect at this point between what the expectations were three years ago and what the reality is now, and unfortunately we’re confronted with that reality.”

Marguerite Wells of Invenergy said, “I think you see that too in the conclusion of the last [NYISO] Class Year, where half of the projects rejected their cost allocations, which means they’re out of the Class Year, and they’re either going to shut down or going to have to go through a new Class Year and hope for a better cost allocation.

“I think that’s a really significant indicator of how … these costs are impacting project economics,” she added.

Moving Forward

New York has a strong home rule tradition, and while some authority to approve renewable energy projects has been moved to the state level, local support remains important to the clean energy transition.

Winning hearts and minds is apparently something many of the panelists have put a lot of thought into; they offered the audience numerous suggestions on building community support.

Job creation is often touted by energy developers, but that is not a compelling argument to the local residents who stand up at a town hall meeting and say they just do not want to look at a solar array, said Amy McDonough of New Leaf Energy — particularly given that most of the jobs created are temporary construction positions.

“The bigger picture — what this renewable energy economy means to the state, not just this project in their town, but this project and the next project and the next project — that kind of messaging and education could potentially be helpful,” she said.

White Plains Mayor Thomas Roach said building that city’s large community solar program relied on the help of organizations trusted in the community, such as El Centro Hispano.

“They actually had volunteers entering people into the system so they could take advantage of the discounted electricity because a lot of people are intimidated by the process,” he said.

That type of outreach can be important with something like community solar, which may sound suspiciously like a scam to someone who receives a cold call solicitation, said Sandhya Murali, co-founder and COO of Solstice.

Suarez threw in a plug for expanding New York’s transmission grid, which would make it possible to site renewable energy in more of the state, and not overwhelm a relatively small number of communities with solicitations just because interconnection is possible there.

“Increased transmission can actually increase social acceptance to some of those projects,” he said.

Wells suggested focusing locally instead of globally, emphasizing economic development rather than climate change, “in terms of the renewable energy industry committing to the communities in which it works.”

As is often observed, there are two New Yorks: New York City is densely populated, heavily Democratic and unable to host a meaningful amount of clean energy generation. Beyond the New York City suburbs, most of the state is more conservative, less densely populated and has a much lower median income.

The open space upstate is ideal for solar farms and wind farms spread across thousands of acres, but many upstaters resent having to look at power lines, wind towers and solar arrays.

“In a lot of these communities, climate change doesn’t exist in the minds of many constituents,” Wells said. “So, I don’t talk about climate change as a driver for my work; I talk about economic development. Because it is the other half, and the money that these projects generate is very significant in terms of making a difference in the lives of upstate communities that don’t have a lot of other revenues.”

April 10, 2023

Public Service Co. of New Mexico Joins WRAP

Public Service Company of New Mexico (PNM) said Friday it has joined the Western Resource Adequacy Program (WRAP), expanding the reliability program’s footprint in the Desert Southwest and bringing the number of participants to 22 across the Western Interconnection.

WRAP also received formal participation agreements last week from two Washington utilities, Seattle City Light and Snohomish County Public Utility District. Both are participants in the program’s current non-binding phase, a precursor to a binding phase in which member utilities can be penalized for falling short of their reserve requirements.

In contrast, PNM is a new participant in WRAP, a first-of-its-kind reliability effort started by the Northwest Power Pool, which changed its name to the Western Power Pool in February 2022 to reflect its expanding reach across the West.

“One of the things that makes the WRAP so beneficial is the ability to share in the diversity of the entire Western region,” Western Power Pool CEO Sarah Edmonds said in a news release. “Bringing in PNM adds to that diversity, in terms of geography, resource mix and seasonal loads.”

PNM’s generation fleet includes solar, wind, natural gas and coal resources. It has said it will meet the state’s clean energy mandate five years before the compliance date. The mandate requires utilities to have a zero-carbon power supply by 2045.

The company serves its 525,000 customers in Albuquerque, Santa Fe and 19 smaller cities, villages and tribal communities with 55% carbon-free energy.

It has participated in CAISO’s Western Energy Imbalance Market since April 2021, allowing it to buy and sell energy in the interstate real-time market.

“We continue to ensure our customer needs are met through innovative solutions to our power resources, participation in energy markets and strengthening our resource adequacy framework,” PNM CEO Pat Vincent-Collawn said in a statement. “We see WRAP as another tool to continue to enhance PNM’s system reliability.”

WPP has been developing WRAP since 2020, initially to address concerns that Pacific Northwest utilities had been unknowingly drawing on the same shrinking pool of reliability resources. Interest in the effort quickly spread to other parts of the West; its footprint now covers all or part of 10 Western states and British Columbia.

FERC approved WRAP’s tariff in February, saying the program “has the potential to enhance resource adequacy planning, provide for the benchmarking of resource adequacy standards and more effectively encourage the use of Western regional resource diversity compared to the status quo.” (See FERC Approves Western Resource Adequacy Program.)

The ruling allowed WRAP to move forward with a binding phase that will include penalties for members that fail to meet their resource-sufficiency obligations. WPP has the option to initiate the binding phase of the program during any season between 2025 and 2028, per the commission’s order. (See WPP CEO Looks to ‘Earliest Possible’ Binding Season for WRAP.)

The program involves two “time horizons” — a forward-showing program requiring participants to show they have sufficient capacity months in advance of summer and winter peaks, and an operational program, focused on the allocation of resources in the real-time and day-ahead time frames.

“PNM is expected to participate in WRAP’s forward showing later this year ahead of the summer 2024 operational program,” WPP said in its news release. “The forward showing component of the WRAP is where participants demonstrate they have secured their share of the region’s energy needs. The operational component, in the winter and summer seasons, is when utilities with a deficit can tap into the pool of shared resources if needed.”

WRAP participants in the Southwest include Arizona Public Service, Arizona’s Salt River Project and NV Energy.

April 9, 2023February 7, 2024

Texas Legislature Moves Bills Remaking the ERCOT Market

Texas lawmakers have advanced several bills that, while revised, still threaten to upend the ERCOT market and punish renewable energy.

Introduced last month, the bills would fund the construction of 10 GW of gas-fired plants that would only be used to prevent load shed; place limits on how much renewable generation can be built; institute a firming requirement for all resources and load-serving entities; and mandate that generation be built closer to load to reduce transmission costs. (See Texas Senate Lays out Changes to ERCOT Market.)

The Texas Senate approved four bills Wednesday, three of which cleared the Business and Commerce (B&C) Committee earlier in the week. They include Senate Bill 6, which has drawn widespread opposition over its proposed Texas Energy Insurance Program. Under the program, interest-free loans from state funds — Texas has a $32.7 billion budget surplus — would be used to build break-glass-in-case “reliability assets,” defined as gas plants in ERCOT’s footprint with on-site fuel storage.

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Sen. Charles Schwertner, author of SB 6 and SB 7, explains his legislation to the Texas Senate. | Texas Senate

The bill’s detractors include Grover Norquist’s Americans for Tax Reform (ATR) conservative advocacy group. It said SB 6 and other legislation “all seek to impose arbitrary restrictions on energy producers or authorize superfluous subsidies.”

“While the motivation behind them is well-meaning, such misguided intervention is likely to produce barriers to entry that reduce competition and raise consumer prices,” the organization added.

SB 6 is similar to Berkshire Hathaway Energy’s proposal during the 2021 legislative session to fund $8.3 billion to build 10 GW of gas fired generation for “blackout insurance.” The proposal never made it into legislation. (See Stakeholder Soapbox: Berkshire’s Proposal Will Prevent Another Texas Power Catastrophe.)

The current legislation is expected to cost about $10 billion. However, the costs could be as high as $18 billion, according to a Lower Colorado River Authority document recently obtained through an open records request by Austin’s NPR radio station, KUT. In the document, LCRA says it could build about 5.6 GW of reliability assets for $10 billion in capital costs and about 10 GW for $18 billion.

State Sen. Nathan Johnson (D) reminded the B&C Committee Monday that stakeholders have raised concerns for several years over an off-market backup system that could have “damaging, perhaps destructive effects” to the ERCOT market.

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Sen. Nathan Johnson (right) questions the legislation. | Texas Senate

“To the extent we’re going to preserve our competitive market, I’m concerned that the scope of this is too large and it ought to be brought down considerably in size and work in conjunction with other elements,” he said. “It seems to wag the whole system at this size.”

“This bill … speaks to the concerns of millions of Texans regarding what do we do when there is anticipated extreme heat or extreme cold. Do we have enough backup electricity to make sure our grid doesn’t go down?” B&C Chair Charles Schwertner (R) said during Monday’s committee meeting. “This is just like a generator at your house. It is an insurance electricity backup system that stands behind the energy-only market here in Texas.”

Schwertner, who drafted the bill, said he had added several revisions after further input from 20 “major stakeholders” and hours of discussion with members and stakeholders. The modifications include weakening the thresholds project developers must meet to establish “financial stability” by reducing the applicant’s ownership of existing capacity from 15 GW down to 2.5 GW and not requiring total assets of $10 billion for every GW of capacity applied for.

However, applicants will be required to have an investment grade credit rating.

The substitute bill’s biggest revision keeps the program’s plants from entering the competitive day-ahead and real-time markets for 40 years and clarifies that Texas regulators should continue to work on market design fixes that address the state’s reliability issues.

That could satisfy some market participants who have said the temptation would be too great not to use the plants sitting on the sidelines.

“The concern is that you’re going to be paying for these resources and they’re going to be sitting there,” South Texas Electric Cooperative General Manager Clif Lange said during a legislative hearing last week. “It’s going to be extremely tempting when we come back in two years or four years to want to make sure that the [Public Utility] Commission uses these a little bit more frequently. I think you’re going to get pressured to try to make sure that those are deployed at a lower price level.”

Lange said that should the gas units enter the ERCOT markets, they could start displacing competitive resources and lead to price distortions.

“You start to see more pressure on the existing portfolio of assets and as a result, you potentially start flushing out more dispatchable generation,” he said, warning that lower-cost renewable generation will continue to replace inefficient thermal resources.

Energy producer WattBridge has spent $2 billion in adding 4 GW of fast-start gas generators since 2018. In testimony before both legislative bodies, CEO Mike Alvarado said his company is one of those that would be affected.

“The market we invested in over the last 36 months is not the market that exists today,” he said. “We do not anticipate investing any further in ERCOT; the current market conditions simply do not allow it, and the current legislation considered by the Senate makes it that much more challenging for our business.”

Other provisions in the substitute bill would cap the sidelined gas plants’ regulated rate of return at 10%. Independent research firm Clearview Energy Partners said the revised legislation would also ensure that a generator with one or more participating plants does not receive more than $100 million a year in revenue per gigawatt of installed generation capacity.

Should the state not provide sufficient funding for the program, the bill directs the PUC to set a nonbypassable charge to all transmission and distribution utilities, municipally owned utilities and electric cooperatives in ERCOT.

The Senate, controlled 19-11 by Republicans, passed SB 6 by a 22-9 margin, with one Republican and four Democrats crossing the aisle. Johnson and the other two Democrats on the B&C Committee all voted “present” Monday in sending the bill to the floor.

Another ‘Legislative Priority’

Senators also unanimously approved SB 7 Wednesday. Along with SB 6, it has been designated a “legislative priority” by Lt. Gov. Dan Patrick, who controls the Senate.

The bill creates a new “firming” ancillary services program that directs load-serving entities to purchase “dispatchable” reliability reserve services on a day-ahead basis. Revisions to the bill mandate that resources offering the service be capable of running for at least 10 hours, up from four hours as originally drafted. That would essentially lock out energy storage, which ERCOT considers dispatchable.

Americans for Tax Reform said SB 7 would subsidize energy capacity instead of compensating firms for electricity they sell and would create an “adverse incentive structure wherein energy producers would become more reliant on taxpayer subsidies.”

“This would hamper the Texas energy industry and likely lead to increased prices on consumers as well as producers,” Americans for Tax Reform said.

In testimony before lawmakers last month, ERCOT CEO Pablo Vegas called the concept a “tax” and said it could lead to increased generation retirements.

“We would lose energy resources in the short term,” he said. “Resources that cannot be economic under the new cost burden that’s put in place [by SB 7] would pull out of the market, so we would have an energy deficit from that.”

The Senate has already sent several other bills to the House of Representatives. They include:

SB 2012, which would establish policy guardrails should the PUC implement the performance credit mechanism. Lawmakers have thrown cold water on the construct, advising the regulators that they can’t go forward with it without legislative input.
SB 2014, which would make renewable energy credits voluntary instead of mandatory.
SB 2015, which would mandate that 50% of generating capacity installed in ERCOT after this year be sourced from dispatchable resources.
SB 1287, which would require developers to pay for some of the interconnection transmission costs, adding more hurdles for renewable resources that are built far from the grid.

Renewable generation already accounts for a bit more than half of ERCOT’s capacity and for most of the projects in ERCOT’s interconnection queue. According to a study by Joshua Rhodes, a University of Texas researcher, wind and solar resources saved Texas consumers $11 billion in just 2022.

“I worry that some of the bills come across as anti-renewable,” Sen. Judith Zaffirini (D) said Monday. “And so, we want to make sure that we have the dispatchable energy that we have but not necessarily hurt, not punish, renewables.”

April 9, 2023

EPA Proposes Tougher MATS Regs on Coal Power Plants

EPA last week took the next step in its campaign to clean up coal-fired power plants, proposing to strengthen the Mercury and Air Toxics Standards (MATS).

The changes would impose stricter limits on emissions of mercury and other metals, fine particulate matter, sulfur dioxide, nitrogen oxides and carbon dioxide.

EPA said in a news release Wednesday that the proposal would reduce by 67% the emissions of filterable particulate matter (fPM) from existing coal-fired plants. The proposal contemplates even lower emission limits for fPM and seeks comment on whether EPA should finalize a more stringent standard.

It would also require operators to run continuous fPM emission-monitoring systems; EPA estimates about two-thirds of existing coal-fired units do not currently use such a system. It also seeks to revise requirements to assure better emissions performance during plant start-up.

Finally, the proposed changes would bring plants that burn the lowest-grade coal, lignite, up to the same standards as other coal-fired plants. A fact sheet indicates lignite plant emissions limits would be slashed by 70%.

When issued in 2012, MATS required significant reductions of mercury, acid gases and other harmful pollutants from coal- and oil-fired power generation, framing them as a health threat. EPA called the proposal the most significant update to MATS in the 13 years since.

The agency had undermined the legal basis for MATS during the Trump administration but promptly moved to restore it after President Biden took office in January 2021. In February, EPA reaffirmed the scientific, economic and legal underpinnings of the regulations. (See EPA Reaffirms Power Plant Mercury Regulations.)

That move had little immediate impact, as U.S. coal plants were already in compliance, having reduced their mercury emissions by 90%. But it set the stage for further regulatory steps to limit the impact of a fossil fuel long blamed for pollution and climate change. EPA estimates its proposal would result in about 500 MW of coal-fired capacity retirement by 2028 but cause only minimal increases in the cost of electricity and natural gas.

After EPA reaffirmed MATS in February, it announced two other moves to limit emissions. In early March, it proposed tighter rules on wastewater emissions from coal plants. The Effluent Limitations Guidelines and Standards have followed a trajectory similar to the path of MATS: They were instated under President Barack Obama, weakened under President Donald Trump, then reinstated and expanded under Biden. (See EPA Proposes Tighter Coal Plant Wastewater Regs.)

In mid-March, EPA announced final details of its Good Neighbor Plan to slash emissions of smog-forming nitrogen oxides from power plants and industrial facilities in 23 states that contribute to ozone formation in downwind states. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.)

Collectively, the changes and proposals may hasten the trend away from coal as a source of fuel for power generation in the U.S.; EPA’s wastewater proposal, for example, offers smaller decreases in emissions limits at power plants whose operators agree to stop burning coal by 2028.

Advocates for public health and the environment have cheered the moves, while those connected to the coal industry have criticized them. Others worry that the policy of speeding the pace of fossil fuel generation retirements while simultaneously pushing to electrify large swaths of society could result in shortages of power.

The divide was on clear display Wednesday between leaders of the U.S. Senate Environment and Public Works Committee after the MATS proposal was announced.

“The Mercury and Air Toxics Standards continue to be a remarkable, cost-effective success in reducing mercury and other toxic air pollution,” Chair Tom Carper (D-Del.) said. “Thanks to MATS, children and families are breathing cleaner air, and there is less pollution in our nation’s waters. EPA’s proposed rule would build on the progress made to better protect communities. This science-based rule will ensure that power plants use modern pollution-control technology, which will help save lives and support a healthy economy.”

Ranking Member Shelley Moore Capito (R-W.Va.) blamed the original MATS for closure of many coal-fired plants. “The Biden administration continues to wage war on coal and affordable, reliable energy by issuing unnecessary regulations intended to drive down electricity production from our nation’s baseload power resources,” she said. “With one job-killing regulation after another, the EPA continues to threaten the livelihoods of those in West Virginia and other energy-producing communities across the country.”

The American Lung Association said it would advocate for the more stringent options EPA is considering beyond its initial proposal. “EPA’s statutory requirement is to protect individuals from the maximum exposure to hazardous air pollutants, and the Mercury and Air Toxics Standards must be strengthened so that they adequately protect health from power plant pollution. The American Lung Association will work during the public comment process to strengthen the final rule to maximize health protections from power plant toxic pollution.”

The Union of Concerned Scientists hailed the benefits of the original MATS and bemoaned delays to its rollout a decade ago. “For all the good that MATS has brought, we must also reckon with the fact that all these towering benefits could and should have happened sooner, and lives were harmed in the time between. EPA cannot repeat that same delay today. While MATS has driven enormous benefits to date, the fact remains that coal- and oil-fired power plants still release pollution that hurts people and the environment, and it is incumbent on EPA to act.”

April 9, 2023

FERC OKs Partial Settlement in Entergy Grand Gulf Row

FERC last week approved a partial settlement that resolves some city and state commissions’ longstanding allegations of overcharging at Entergy’s (NYSE:ETR) Grand Gulf Nuclear Station.

Under the agreement approved April 4, Entergy subsidiary System Energy Resources Inc. (SERI) will pay an $18 million refund and commit to rate reductions that go back to October 2022 (ER23-435).

SERI operates and owns 90% of the 1,400-MW Grand Gulf plant in Port Gibson, Miss. It sells the plant’s output under a unit power sales agreement (UPSA) to Entergy’s Arkansas, Louisiana, Mississippi and New Orleans affiliates.

The refund will be split among the Louisiana (26.86%), New Orleans (32.87%) and Arkansas (40.27%) subsidiaries. Mississippi regulators last year accepted a separate settlement offer from Entergy that resolves the state’s complaints about Grand Gulf’s performance and billing. (See Entergy Offers Regulators $588M to End Grand Gulf Complaints.)

The partial settlement also contains provisions that reduce the Entergy companies’ monthly UPSA bills’ base rate.

Louisiana, New Orleans, Arkansas and Mississippi regulators have for years accused Entergy and SERI of mismanaging the nuclear plant, massaging accumulated deferred income tax numbers to overcharge customers, overbilling ratepayers for Grand Gulf’s sale-leaseback arrangement, and recovering the costs of lobbying, image advertising and private airplane use in the sales agreements’ rates.

The UPSA bills will now exclude recovery of executive bonuses, restrict advertising cost collections to only safety-related advertising, and limit the recovery of employees’ air travel costs to those directly linked to SERI.

Revised SERI UPSA bills will also include a line item that reduces the base rate for the advanced collection of Grand Gulf’s semiannual lease payments. FERC trial staff argued that the management company should “return to its customers the monthly lease payments’ time value that is held until SERI makes the lease payment.”

As part of the deal, SERI will include money pool borrowings in its short-term debt, which is used to work out its cost-of-capital calculation used in the UPSA.

SERI has also committed to making additional refunds, with interest, in UPSA bill credits to the Entergy companies for a 15-month period dating back to September 2020. Those refunds will reflect UPSA formula rate reductions.

The partial settlement does not address city and state officials’ complaints over SERI tax maneuvers related to Grand Gulf. That dispute is ongoing. (See Regulators File Emergency Motion in Ongoing Grand Gulf Battle.)

April 7, 2023December 10, 2023

Complaints to FERC over PJM Performance Penalties Multiply

Additional generator companies have filed complaints with FERC alleging that PJM violated its governing documents during its response to the December 2022 winter storm in its assigning of nonperformance penalties.

Independent power producer Nautilus Power filed one of the first complaints March 30, arguing that PJM did not follow the correct process for initiating an emergency, depriving gas generators of notice that they could be called on and to procure fuel. (See IPP Asks FERC to Dismiss PJM Performance Penalties over Elliott Outages.)

Nautilus’ filing was followed by several more in the following week, alleging that PJM violated its tariff by exporting energy during emergency conditions, failing protocols for declaring an emergency and penalizing generators not scheduled.

ComEd Generators: Region was not in Emergency

Several independent power producers within the ComEd zone filed a joint complaint arguing that conditions in the region throughout most of the performance assessment interval (PAI) during the storm, also known as Winter Storm Elliott, did not warrant emergency conditions and that the penalties faced by generators there should be eliminated (EL23-54).

The companies argued that PJM was exporting as much as 6,000 MW to the Tennessee Valley Authority and the SERC Reliability footprint during emergency conditions, in violation of the Operating Agreement and suggesting that emergency procedures were not warranted. It argued that there was not a capacity shortage by pointing out that LMPs were below the rest of PJM throughout much of the assessment intervals.

“Simply put, no emergency conditions existed in the ComEd zone: There was no capacity shortage in the ComEd zone, prices were low, and constraints precluded the generation in the ComEd zone from helping the rest of PJM and, if anything, signaled to PJM to back down in-zone generation. Further, PJM committed several tariff, OA and manual violations, such as failing to curtail exports,” the IPPs said.

Prior to the declaration of the Dec. 24 PAI around 4:30 a.m., PJM’s net exports to TVA and SERC were approximately 5,000 MW. Exports had fallen to under 1,000 MW by 6 a.m. but began to increase three hours later and had reached 4,000 MW by noon.

Drawing off an affidavit supplied by Scott Harvey of FTI Consulting, the complaint said that reserve shortages “disappeared” when exports were cut and argued that that shows they were the driver of the shortages leading to the emergency declaration.

“Dr. Harvey concludes that the effect of the increases in exports on PJM prices and reserve levels suggests that emergency actions in other regions of PJM may have been needed (though not needed in ComEd) precisely because of the exports that were supposed to be curtailed before emergency actions were invoked,” the IPPs said.

Solar Developer Argues Penalties Run Contrary to Purpose

SunEnergy1, which operates about 1 GW of solar generation, filed a complaint arguing that the nonperformance charges and the overall Capacity Performance construct are unjust and unreasonable by creating penalties that do not incentivize a change in behavior for solar units that have no capability to operate at night. The company said that 87% of the charges it has been assigned were accrued during evening hours (EL23-58).

The company argued that both PJM and FERC discussed the need for incentives for capacity resources to invest in performance during emergencies as one of the justifications for creating CP following the 2013/14 polar vortex. PJM’s effective load-carrying capability (ELCC) structure already accounts for solar resources’ output fluctuations in class accreditations, the company argued, and imposing penalties could drive resources out of the capacity market.

Because PJM staff are aware of and plans around the limitations of solar, the company argued that nighttime operations should be treated similarly to planned outages.

“How does it further the goals of PJM’s capacity market, and how is it just and reasonable, to excessively penalize such resource for nonperformance during times when such resource is physically incapable of performing ― particularly when PJM’s operators know such resource cannot operate during such times, and do not rely upon it to operate during such times in order to maintain the reliability of the bulk power system?” SunEnergy1 said.

The complaint asks FERC to “direct PJM to explore more holistic and comprehensive reforms to its capacity market design to specifically ensure that the risks of participating in PJM’s capacity market do not materially outweigh revenue opportunities for solar resources in PJM’s capacity market moving forward.”

Generator Coalition Files Complaint

Several companies representing 27,500 MW of generation jointly filing as the Coalition of PJM Capacity Resources argued that PJM should be required to determine which resources would not have been dispatched had the RTO curtailed non-firm exports during the PAI and excuse them from penalties. The group also recommended that FERC require PJM to recalculate the balancing ratio to include all exports and to use those figures to reassess penalties (EL23-55).

The coalition said PJM’s low load forecast resulted in insufficient capacity being procured, which the RTO was slow to make up for through reliability assessment and commitment (RAC) runs that did not secure any systemwide capacity on Dec. 22 and less than a third of the forecast error the next day.

It also argued that PJM continued exporting throughout emergency declarations, constituting a tariff violation and effectively holding generators to the capacity needs of outside regions.

“To be clear, complainants do not object to PJM providing assistance to neighboring regions when that assistance is needed and when PJM has available resources to assist (as PJM apparently did during Winter Storm Elliott),” the coalition said. “Rather, complainants object to PJM declaring emergency operations and imposing penalties on PJM resources to support other systems.”

Talen Generators not Dispatched

In addition to joining the coalition’s complaint, Talen Energy filed its own, arguing that PJM is seeking to improperly assign penalties against several of its generators that were available to operate but were not dispatched (EL23-56).

“These generators had available staffing, access to fuel and start times that would have allowed them to provide power during the Dec. 23 and Dec. 24 PAIs had PJM scheduled them in a timely manner,” Talen said. “Assessing nonperformance charges against the Talen PJM generators in this circumstance would amount to penalizing them for following PJM’s instruction, which was to remain ready to operate if dispatched.”

Talen argued that generators are normally excused from CP charges if they are not dispatched or are scheduled down by PJM, with an exemption to allow penalties for units not scheduled solely based on their operating parameter limitations or market-based offers that are higher than their cost-based offers. This was not the case for at least two of the company’s generators, as similarly configured facilities in its fleet were dispatched, it said.

“Simply put, PJM made a judgment call, or perhaps even a mistake, at the time of the PAIs and did not dispatch Martins Creek,” Talen said referring to its 1,719 MW gas-fired generator. “PJM must take responsibility for its own management of the grid during Winter Storm Elliott — including its decision not to dispatch the Martins Creek units.”

Lincoln Power Declares Bankruptcy Because of Penalties

Delaware-based Lincoln Power declared bankruptcy on March 31 because of about $39 million in nonperformance penalties assigned to two of its combustion turbine generators: the 480-MW Elgin Plant and the 330-MW Rocky Road Plant, both in Illinois. Like Nautilus, the company is an affiliate of Cogentrix Energy Power Management.

In an affidavit filed with the U.S. Bankruptcy Court in Delaware, Chief Restructuring Officer Justin Pugh stated that PJM has been withholding $350,000 weekly from the company’s revenues and demanding about $2 million in collateral. While it has been disputing the validity of the penalties with PJM, Pugh told the court that the company cannot continue to operate through the withholdings.

Lincoln has been experiencing a liquidity crunch because of low clearing prices in recent capacity auctions, Pugh said, but the company likely would have otherwise remained profitable.

“While such liquidity constraints are substantial, the debtors could have sustained their current debt load had their business not been subjected to numerous issues caused by a severe winter storm that struck and inflicted record cold temperatures across most of the United States, from Dec. 22, 2022, through Dec. 27, 2022,” he said.

April 7, 2023

NJ Proposes Modest Community Solar Capacity Hike

New Jersey’s permanent community solar program should approve projects with a combined capacity of at least 750 MW in its first five years, according to a straw proposal released by the state’s Board of Public Utilities (BPU) last week.

The proposal resists the effort by some legislators to dramatically ramp up capacity in light of what the plan calls the “tremendous market response” to two pilot programs in 2019 and 2021. Instead, it calls for much the same capacity allocation of 150 MW per year discussed in the past, with a 50% hike in available capacity suggested in the third and fourth years of the program to make up for any shortfalls in earlier years.

The much anticipated straw proposal limits the maximum size of projects eligible to participate in the program to 5 MW. It also requires eligible projects to be developed on rooftops, carports and canopies over impervious surfaces, contaminated sites and landfills and man-made bodies of water.

The proposal rejects the selection strategy used in two pilot community solar programs of awarding capacity through a competitive process. Instead, projects will be picked on a first come, first served basis, providing they meet heightened requirements to ensure readiness for development.

The release of the proposal, which will be the subject of a public hearing on April 24, provides insight into how the state wants to push forward a market sector that state officials regard as among the most successful in the state’s renewable energy portfolio.

In his push for New Jersey to reach 100% clean energy by 2050, Gov. Phil Murphy (D) has set a goal for the state to have 32 GW of solar by 2050, about 34% of the state’s generating capacity. The state had 4.36 GW of installed solar capacity at the end of February, according to the latest BPU figures available, and agency leaders see community solar as a potential growth driver.

“It is important to highlight the tremendous market response and overall interest in developing community solar projects,” the proposal states, noting that the board received more than 650 applications for the two temporary pilot programs.

Chasing Solar Goals

Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage.

The BPU approved 45 projects totaling 75 MW in the first community solar pilot in 2019, and two years later approved 105 community solar projects totaling 165 MW in the second pilot. Both solicitations were substantially oversubscribed, with 412 applicant projects in the second phase and 252 applications in the first. (See NJ Selects 165 MW in Community Solar Projects.)

The interest in the program prompted two lawmakers to introduce a bill, S3123, that would have more than tripled the size of the planned permanent community solar program to 500 MW a year. The BPU had set an early target of 150 MW a year for the permanent program, for a total of 750 MW over five years. Some stakeholders also suggested that the program should award 300 MW of capacity in the first year of the program, to make up for the fact that the BPU had initially planned to have three pilot programs but abandoned the final pilot to create the permanent program.

But the BPU opposed the bill, saying the sector and grid could not handle such a rapid expansion. In fact, only 25 community solar projects in the two pilot solicitations have been installed so far, according to recent BPU figures. (See NJ BPU Opposes Community Solar Program Expansion.) And the agency has stuck to its original plan — albeit increasing the goal slightly by saying it will allocate “at least” 150 MW a year — and making some changes to program rules and requirements.

Encouraging LMI Participation

The straw proposal suggests that the state maintain the pilot program requirement that 51% of the subscribers to each community solar projects be reserved for low- and moderate-income households. That system has so far resulted in projects signing up more than 6,000 subscribers who have received more than $6 million in bill credits and saved more than $1 million, according to the proposal.

But it recommends that the agency relax pilot rules that required consumers to provide documentation of their income if they wanted to subscribe as low- or moderate-income participants.

In response to concerns from solar developers over the difficulties of getting documentations, the BPU recommends that such participants be allowed to self-attest to their income through the use of a standardized form.

“Staff believes that potential community solar subscribers should not be dissuaded from participation by having to produce a tax return, EBT card, or other documentation of income,” the proposal says. “Individuals may feel uncomfortable providing this personal information to subscriber organizations, and there is concern about subscriber organizations retaining such data.”

Replacing Competitive Selection

The proposal also changes the selection process by which projects are picked for the program. The agency concluded that the competitive process used in the two pilots, in which applicants were evaluated and ranked by the BPU staff, though effective, was also too time-consuming and so complicated that it took nine months to complete the process. During that time, some projects withdrew because the lease on the proposed project site expired, the proposal said. (See Slow Progress of NJ Community Solar Pilot Draws Fire.)

The proposal instead suggests that projects be picked on a first come, first served basis, and that the quality of the projects would be ensured by raising “minimum maturity requirements” — such as having applied for certain permits and being viable for interconnection. Those details would ensure the selected projects had not been rushed too quickly into the application process and would be likely to succeed if picked.

That raising of the bar might help alleviate the scenario in the pilot programs in which only 44% of selected projects reached commercial operation before the BPU’s conditional approval expired, the proposal suggested.

“All projects would be required to meet certain criteria … to ensure key policy preferences are met,” the proposal says. “With strict prerequisites for application, the potential pool of applicants will be limited to those that are considered to be most beneficial from a policy perspective and are most mature and able to make progress toward completion soon after awarding.”

“An open enrollment process fairly allows for a diversity of projects to participate without being constrained by a scoring process that may favor certain types of project elements or developers,” the proposal states. “This procedure is more sustainable for a permanent program and limits the administrative burden associated with a competitive solicitation process.”

The proposal also offers a solution to a two-year-old discussion about how best to bill subscribers so that the program is simple and attractive to ratepayers. The proposal rejects the option that ratepayers receive separate bills for electricity from the utility and a community solar subscription from the developer, noting the confusion and increased risk of non-payment. (See Billing Key to NJ Community Solar Growth.)

Consolidating those elements into a single bill handled by the electric distribution company would be simpler, and “customers would be better served having only a single bill,” the proposal says.

April 7, 2023December 10, 2023

LBNL: Interconnection Queues Grew 40% in 2022

Interconnection queues around the country are filled with over 2,000 GW of new generation, dominated by solar, storage and wind, according to updated analysis from the Lawrence Berkeley National Laboratory released Thursday.

The 2,000 GW number is up 40% from a year earlier, according to LBNL, which studied the seven ISO/RTOs and 35 additional utilities outside organized markets that altogether serve 85% of total electric load in the country. Over 10,000 projects representing 1,350 GW of generation and 680 GW of storage are in the queue.

The zero-carbon generation in the queues alone totals about 1,260 GW, which would be about equal to the total amount of generation operating around the country today.

The growth in projects reflects the real interest in transitioning the industry to a cleaner future, but it also represents growing backlogs as projects take five years to get through the processes, the lead author of the study, Joseph Rand, an energy policy researcher at LBNL, said in an interview.

“The queues illustrate both the opportunity and the challenges of rapid electric sector decarbonization in the United States because we see this unprecedented development interest in new clean energy,” Rand said. “But then, on the other hand, we do see the backlogs and delays and high withdrawal rates.”

Some of the trends in the queue are worthy of concern, but others represent a real opportunity, he added.

The continued growth in the queue reflects the reality that the industry wants to build a lot of renewables, which is because of demand from state mandates and commercial customers, Brattle Group Principal Johannes Pfeifenberger told RTO Insider. But only a fraction of those projects will ever lead to steel in the ground — and the fact that it is so hard to get through the queue contributes to that growth.

“You never know which location on the grid is a good location, or which is a bad location,” Pfeifenberger said. “So, if a developer hopes to develop 1,000 MW of renewables, they might submit 3,000 MW of interconnection requests, hoping to find a good location where it is cost-effective to interconnect.”

While the overall amount of capacity continued to rise in the year, the number of new requests fell from 2021, which LBNL said was caused by both CAISO and PJM pausing new applications as they dealt with significant backlogs that led to new rules in both markets. CAISO’s pause ends this year, but PJM will not take any new requests until 2025.

“The interest in solar, storage and wind is so widespread across the country that even if these two leading markets dip down or pause for a year, it’s surging everywhere,” Rand said.

PJM had the largest number of active projects in its queue at 3,042, followed by the non-ISO West at 1,879, MISO at 1,734, ERCOT at 902, and the Southeast (outside of ISO/RTOs) at 830. By total capacity the numbers are different — with the non-ISO west at 598 GW, MISO at 339 GW, and PJM at 298 GW.

Queue requests by technology type from around the country | Lawrence Berkeley National Laboratory

Solar represents the largest technology by volume in the queue, with 947 GW of the total, followed by storage at 680 GW. Both figures include hybrid projects made up of both technologies.

Solar is widespread across the country, but LBNL noted that both the Northeast and SPP had less of the resource type waiting to connect to the grid. Most of the wind is in the West, or offshore from the East Coast, while storage is centered around the CAISO and the West — although it is rapidly expanding to the east as well.

Offshore wind makes up 113 GW, which is more than enough to meet the Biden administration’s goal of 30 GW by 2030.

Most Projects Drop Out

While the capacity in the queues would be enough to decarbonize the power sector if everything were built, that is not going to happen. For all the projects in queues between 2000 and 2017, just 21% (and 14% of capacity) entered service, LBNL said. The success rate of more recent proposals cannot be determined yet.

More recent projects are dropping out later in the queue process, which exacerbates delays for those left behind as grid operators must do significant restudies to determine who must pay for the transmission upgrades required to reliably interconnect generation.

FERC is working on a couple proposed rules meant to help the process. One would update the pro forma queue rules (RM22-14) to include revisions such as giving priority to projects farther along their development paths, and another on regional planning that would require planners take into account future sources of generation (RM21-17).

FERC’s reforms should help to streamline the queues a little bit, but they are far short of progress in Europe, which is generally farther along in its grid transition, Pfeifenberger said. He said ERCOT has a similar system to that of the United Kingdom and some other European countries, which can move renewables through the queue at a much quicker rate than the current FERC-regulated processes, which were designed over 20 years ago to connect natural gas plants to the grid.

Rand believes that, together, FERC’s NOPRs can have an impact on the queue and its backlog, but they both need to become final rules for that to happen.

“Either one of them in isolation just wouldn’t be sufficient to make a big dent in this problem,” Rand said. “But combined, they might they definitely have real potential to unlock this queue.”

‘Connect and Manage’

The interconnection NOPR would adopt on a national basis changes that some organized markets and individual utilities have already made to speed up their queue and minimize speculative projects, but it will not lead to new transmission being built to resource-rich areas. The transmission planning NOPR would handle that second part, but one key issue remains, Rand said.

“That’s cost allocation: Who pays?” Rand said. “If you’re a generator, trying to interconnect to the grid system, how much do you pay for the interconnection upgrades? And what determines what fraction that you pay? And what types of upgrades you pay for? That’s not really addressed in those two NOPRs, and it’s a very sticky issue that I think leads to a lot of projects ultimately withdrawing from the queue.”

The U.K. and ERCOT both use a process called “connect and manage,” compared with the “invest and connect” process used in FERC-regulated RTOs, and when the British adopted that system their queue times were cut from five years to one year, Pfeifenberger said.

“The idea is you let people interconnect. It might be non-firm, they might get curtailed, but then use … congestion management or proactive transmission planning, where congestion makes it worthwhile to upgrade the transmission system,” Pfeifenberger said.

Enel North America, a subsidiary of the Italian utility that develops renewables and is a major player in demand response, has written a whitepaper endorsing the basics of connect and manage, and it has made similar arguments to FERC as it weighs reforms, he added.

ERCOT does not have the regular, proactive transmission planning process to compliment the “connect and manage” process, Pfeifenberger said. The process has not been adopted elsewhere in the U.S. because it represents a major change from the normal of doing business.

“It’s very hard for an ISO to change it in the connection process,” Pfeifenberger said. “First of all, the ISO may not want to because they think the interconnection process is what is necessary. But even if they wanted to, they have to go through the stakeholder processes; they have to change the tariff; they have to get FERC approval. But I think it’s mostly a mindset issue, that the ISOs just like the way they’re doing it.”

ERCOT does have a record of more quickly connecting resources to the grid, but Rand said it was not a silver bullet because projects there face higher risks of curtailment as the Texas grid operator just offers energy-only service as opposed to the network interconnection service in other markets.

“You can connect without paying those upfront, interconnection upgrade costs,” Rand said. “But you face a curtailment risk. You face a lot more curtailment risk, perhaps, than you might get in MISO if you have a network interconnection service.”

April 6, 2023

Western EIM Expands to Texas

CAISO’s Western Energy Imbalance Market pushed into a small part of Texas on Wednesday with the addition of El Paso Electric, which occupies the westernmost corner of the Lone Star State.

The Western Area Power Administration’s (WAPA) Desert Southwest Region and Avangrid (NYSE:AGR) also joined the WEIM on Wednesday, with the latter becoming the first generation-only participant in the interstate market.

The latest additions mean the WEIM now encompasses approximately 80% of electricity demand in the Western Interconnection and has a presence in every state in the West except Colorado. (Three Colorado utilities that had planned to join the WEIM instead joined SPP’s Western Energy Imbalance Service last year.)

“Because of their varied resources and location, these new WEIM partners further strengthen regional collaboration and coordination in the West,” CAISO CEO Elliot Mainzer said in a news release. “It’s been a pleasure to work with them in support of their effort to achieve enhanced operational efficiencies while providing cost savings to their customers.”

WAPA’s Desert Southwest Region, based in Phoenix, “sells power in Arizona, Southern California and portions of the Southwest to wholesale customers such as towns, rural electric cooperatives, public utility and irrigation districts; federal, state and military agencies; Native American tribes; and U.S. Bureau of Reclamation customers,” WAPA says on its website. It operates transmission lines to deliver power from the Hoover Dam and the Parker-Davis Project, which includes two other hydroelectric dams on the Colorado River.

EPE is a regional utility that operates generating resources — including wind, solar and natural gas plants — and transmission and distribution systems that serve more than 460,000 customers in a 10,000-square-mile area of the Rio Grande Valley in West Texas and southern New Mexico.

Avangrid has operations that sprawl across 24 states. Avangrid Renewables, the arm of the company that joined the WEIM, operates a generation-only balancing authority area in Oregon and Washington that connects to the Bonneville Power Administration’s transmission system.

“Avangrid owns and operates 18 generation facilities and provides balancing services for one third-party generator, which are made up of primarily wind resources within the BAA,” CAISO wrote in a June 29, 2022, letter to FERC that accompanied Avangrid’s agreement to join the WEIM. “The total nameplate capacity is 2,763 MW, with an additional four facilities under construction.

“Also sitting within the BAA are pseudo-tied contracted hydro facilities and the Klamath Falls Cogeneration (535 MW) and peaking (100 MW) facilities,” it said.

In a news release Wednesday, Avangrid said that as a WEIM participant, it “will support and strengthen the energy system of 11 Western states with almost 2 GW of installed emissions-free capacity from facilities that the company operates in the region.”

“Joining the WEIM as the first generation-only entity represents a meaningful milestone for the CAISO and for us,” Avangrid CEO Pedro Azagra said in the news release.

Since it began in late 2014, the WEIM has generated more than $3.4 billion in benefits for its participants, including $1 billion in 2022, by supplying lower cost energy and avoiding curtailment of renewable resources.

CAISO has been working to add a day-ahead component to the real-time market. Its Board of Governors and the EIM Governing Body approved the extended day-ahead market (EDAM) proposal on Feb. 1. (See CAISO Approves Day-ahead Market for Western EIM.)

The ISO is developing tariff language that it plans to send to FERC before the end of June.