CAISO’s Western Energy Imbalance Market topped $4 billion in cumulative benefits for its participants in the second quarter of 2023, just six months after it topped the $3 billion mark at the end of 2022, the ISO said this week.
The WEIM generated nearly $799 million in benefits in the first half of this year, including $380 million in Q2, bringing its total benefits to $4.2 billion since it began in 2014. It reached $3.4 billion in cumulative benefits in the fourth quarter of 2022.
The market’s benefits come primarily from transfers of lower-cost energy between Western entities, as well as operational efficiencies and increased uptake of solar and wind power.
The benefits of the WEIM, a real-time interstate trading market, grew rapidly as more participants joined in recent years. It now includes 22 entities in 11 states and British Columbia that collectively represent about 80% of load in the Western Interconnection.
Those with the most benefits in Q2 were CAISO, with $70 million in benefits; NV energy, with $46 million; and PacifiCorp, with $37.5 million.
The second-quarter results were notable for the large quantities of exports from California. CAISO had net exports of 2,758,377 MWh, nearly five times as much as the next-highest exporter, Arizona’s Salt River Project, which had 564,023 MWh. NV Energy came in third with 531,979 MWh. Net exports for all other WEIM participants fell well below those figures.
Inexpensive solar energy flowing from California in the middle of the day was a likely cause of CAISO’s vast net exports. The state has been adding utility-scale solar arrays at a fast pace as it tries to meet its 100% clean energy goal by 2045.
California’s ample spring sunshine and moderate temperatures combined to produce an excess of solar energy in the second-quarter months from April to June.
CAISO statistics show that solar output peaked May 23 at more than 15,000 MW, exceeding a 14,000-MW peak in May 2022. Then, on June 13, the ISO again broke its record for solar production with 15,718 MW.
With the latest numbers in, CAISO is hoping the proven benefits of the WEIM will convince participants to sign up for its planned extended day-ahead market (EDAM). The WEIM EDAM is likely to face stiff competition from SPP’s Markets+ offering, which is planned to include real-time and day-ahead markets.
CAISO expects to file its EDAM tariff language with FERC this month. It recently announced a public EDAM Forum on Aug. 30 in Las Vegas, which it will co-host with PacifiCorp, NV Energy, Southern California Edison and the Balancing Authority of Northern California.
WEIM cofounder PacifiCorp has already committed to join the EDAM and several other entities are nearing a decision, CAISO said.
“The forum’s panel discussions will allow a broad spectrum of utility and thought leaders to delve into the potential benefits and outstanding questions regarding EDAM participation, its evolution, and how it could transform and optimize energy delivery in the future,” CAISO said in its announcement.
Virtual power plants can economically replace many of the country’s 217 GW worth of peaking power plants, which emit pollution like nitrous oxide and are often located in population centers, the Clean Energy Group (CEG) said in a webinar Thursday.
VPPs are portfolios of distributed energy resources that include resources like demand response, rooftop solar, smart water heaters, plugged-in electric vehicles, batteries and other resources that are controlled by utilities or independent aggregators, said Brattle Group Principal Ryan Hledik. He authored a study released earlier this year finding VPPs were the cheapest option for resource adequacy. (See Brattle Group Finds VPPs Cheapest Alternative for Resource Adequacy.)
“The idea with a virtual power plant is that a utility or an aggregator will control those distributed energy resources,” Hledik said. “And then ultimately, the control of those resources is done in an orchestrated, managed way to provide benefits to the power system.”
Using the pre-existing resources is cheaper up front than installing peaking power plants or energy storage systems, and it helps cut emissions. Those benefits are split between the firm running the VPP program and its customer participants, Hledik said.
VPPs are gathering momentum because many of the costs of the DER technologies they rely on are coming down, and the expectation is that this will continue over the long run. The Inflation Reduction Act provides incentives for many of the resources, while policies like FERC Order 2222 require markets be open to aggregations of DERs.
The industry spent $120 billion on capacity that was needed to maintain resource adequacy in the last decade, and most of that went to natural gas plants, though in recent years batteries have seen an uptick in investment, said Hledik.
Brattle’s analysis found that a utility with about 1.7 million customers could use a 400-MW VPP to maintain reliability. The VPP in that scenario would help lower load in both summer and winter, and be dispatched in seven months for a total of 63 hours, up to seven hours at one time, said Hledik.
While some utilities have adopted VPPs already, with the Upper Midwest’s Otter Tail Power and Vermont’s Green Mountain Power being listed as examples on the webinar, others are more cautious about relying on VPPs for the same level of reliability as power plants or grid-scale batteries.
“A lot of times we do encounter utilities or system operators who don’t yet trust the ability of VPPs to operate and perform the way a gas peaker might or utility-scale battery might,” Hledik said. “Just pushing the button and getting it to run is a little different when you think about the fact that there are customers on the other end of this.”
That kind of resistance can be overcome by doing pilot programs and seeing other utilities already successfully relying on VPPs, he added.
The shift to VPPs from gas-fired peakers can have major health benefits because some 154 GW of the power plants are in urban areas, and 32 million Americans live within three miles of one and their NOx emissions, said CEG’s Shelley Robbins.
“Because of the way they run, you pretty much can’t capture that NOx,” said Robbins. “Because they don’t run at a baseload level, the systems that capture pollutants don’t work on these plants.”
NOx is a small particle that easily gets into the entire body through the lungs and is associated with conditions such as asthma, inflammation, cognitive decline, Parkinson’s, Alzheimer’s, premature birth and other medical conditions.
The peaking power plants are often located in urban areas, with a map CEG produced showing their locations overlaid on the most populous areas of the country. New York City is home to about 6 GW of peaking capacity, including some plants that are more than 55 years old, said CEG President Seth Mullendore.
To grow VPPs going forward, one policy that states could adopt is what CEG calls the “Connected Solutions Model,” said its senior project director, Todd Olinsky-Paul.
“Through this mechanism, homes and businesses with batteries and other types of renewable resources can supply capacity and energy to the grid during peak demand times and also retain the use of those batteries for resilience and other needs,” said Olinsky-Paul. “And in return, they get paid by the utility; whereas the utility would ordinarily pay a peaker plant, now they’re paying participating customers for these services.”
Customers would purchase distributed resources and sign multiyear contracts with utilities to be able to dispatch them using a VPP model, he added. It is important that such programs offer some upfront equity because often the people who want to participate the most and save on their monthly bills can least afford the upfront payments for DERs.
Constellation Energy championed its nuclear fleet as being ready to match clean energy load when and where it’s needed during the company’s second-quarter earnings call Thursday.
“Our businesses are essential to addressing the climate crisis, and our assets are endurable. The Inflation Reduction Act provides unique opportunities for Constellation and its investors. We believe that we will be able to use nuclear energy to produce hydrogen. We will be able to re-license our nuclear fleet to run at least 80 years without needing to replace it, and the [Inflation Reduction Act] provides, at long last, a long-term commitment that nuclear energy is part of the national security of this great nation,” CEO Joseph Dominguez said.
He said value already is being realized through an hourly carbon-free matching agreement with Microsoft to use nuclear power sourced from Constellation to reduce the carbon footprint of the company’s Boydton, Va., data center. Under the agreement, announced last month, Microsoft will receive up to 35% of its clean energy attributes from Constellation’s nuclear capability, allowing the company to procure almost the entirety of its energy from carbon-free sources when combined with other renewables.
The two companies also partnered in March to develop an hourly carbon-free energy matching program, which Microsoft will use to track its performance for the new procurements.
Dominguez said he expects more wholesale price volatility and shrinking RTO reserve margins over the foreseeable future, but he believes the company’s generation portfolio, helped by the value of its clean energy attributes, positions it well to manage the changing grid.
“Reserve margins are about as thick as they’re going to be in these markets, and as you see fossil generation being replaced with renewable generation, the underlying markets are going to be very volatile and it’s going to take a special kind of company with a special balance sheet to cover that. I think sustainability solutions also allow us to enter into longer deals with customers that really want that sort of product support,” he said.
While wholesale energy revenues were down this year, Executive Vice President Dan Eggers said Constellation thinks that will be offset by the incentives included in the IRA. He also credited the production tax credits with contributing to the company’s increased credit rating outlook from Moody’s, which went from stable to positive.
“Lower prices were offset by an increase in expected PTCs from plants without existing ZEC [zero-emission credit] programs, reinforcing the downside protection the PTC provides against declining power prices,” he said.
In New York, an agreement the company has with the New York State Energy Research and Development Authority (NYSERDA) to receive ZECs for its three nuclear generators in the state stipulates that the company will return a portion of the revenue from those credits when federal incentives are available. Gov. Kathy Hochul (D) said the tax credits provided by the IRA will reduce electric rates while maintaining incentives for nuclear production in the state.
Eggers said the company saw significant year-over-year gains in the last quarter, leading it to increase its guidance range from $3.3 billion to $3.7 billion, up from $2.9 billion to $3.3 billion, raising the midpoint by $400 million.
Dominguez said nuclear generation meets all the attributes sought for green hydrogen production and he’s confident Constellation’s existing nuclear fleet will be eligible for federal incentives for green hydrogen.
“We’re having very productive conversations with the administration about means of addressing this from a regulatory standpoint so that existing nuclear can be used to make hydrogen and re-licensed nuclear plants would effectively count too,” he said.
Existing generators will be needed to meet the upcoming hydrogen demand, he said, particularly under EPA rules that require gas-fired generators to begin blending hydrogen into their fuel.
Questioned on how the company will prioritize nuclear generation for clean energy credits and producing green hydrogen, he said both can be accomplished at once. For industrial customers looking to decarbonize with hydrogen electrolyzers at their sites, he said they can buy the company’s carbon-free certifications and be eligible for federal tax credits for clean hydrogen production.
Executive Vice President Kathleen Barrón said Constellation has been encouraging onshore nuclear fuel production and pushed for the Nuclear Fuel Security Act to be included in the National Defense Authorization Act (NDAA). The U.S. Senate overwhelmingly voted to approve both the amendment and the NDAA on July 27.
Constellation’s 21-GW nuclear fleet also is to grow following a deal to buy a 44% stake in the 2,645-MW South Texas Project nuclear generator announced last month. The announcement says the company anticipates Nuclear Regulatory Commission and Department of Justice approval of the transaction by the end of the year.
Dominguez said the company views natural gas as an important bridge fuel as the nation decarbonizes and it is making investments to reduce emissions from its gas-fired generators, including blending hydrogen into its fuel and developing carbon capture technology. Constellation announced in May that it had set an industry record by operating on a blend of 38% hydrogen at its Hillabee gas generator.
High-level energy officials from Connecticut, Maine, Massachusetts, Rhode Island and Vermont asked ISO-NE to establish an executive-level environmental justice position, in a letter on Tuesday.
“At the highest level, this position would provide an EJ and equity lens to ISO-NE’s management and staff, inform the development of ISO-NE initiatives, rules and operations and engage EJ communities and stakeholders,” the letter says.
The officials said responsibilities of the position could include advising the ISO-NE Board of Directors and senior management on market rules, transmission planning, operations and new initiatives, along with performing outreach to environmental justice communities and facilitating internal training.
The environmental justice needs at ISO-NE may require multiple positions, the commissioners and energy officials said.
“As community engagement and responsibilities grow, this executive position could build out and manage additional team members providing EJ expertise to ISO-NE and enhancing community, government and industry engagement,” the letter says.
All the states represented in the letter have environmental justice provisions written into law intended to protect communities that disproportionately face the negative effects of energy infrastructure. These communities frequently are lower-income, non-white and non-English speaking. New Hampshire, which did not sign the letter, is the only New England state that does not have an environmental justice statute.
The state officials’ request came in response to ISO-NE’s presentation to the New England states in June on the preliminary operating and capital budgets. ISO-NE proposed a 21.5% budget increase for 2024 in its presentation to the NEPOOL Participants Committee. The RTO framed the budget increase in part as “ramping up its capabilities” to help facilitate the transition to clean energy resources. (See ISO-NE Considers Major Capacity Market Changes.)
“There is a gap in ISO-NE’s budget proposal and its current management team without a position reflecting EJ experience,” the letter says. “A successful clean energy transition cannot happen without community engagement and a meaningful role for EJ communities in helping to shape decisions that impact wholesale power and transmission rates and affect how the benefits and burdens of our electric system are apportioned.”
The letter acknowledged that such a position may be unprecedented at RTOs across the country.
“We understand that if ISO-NE creates a dedicated EJ position, it may be the only independent system operator or regional transmission organization in the country that has established such a role,” the state officials wrote. “We encourage ISO-NE to be first in this critical area.”
In response to the letter, ISO-NE said it is open to input from the states on environmental justice issues.
“We’ve received the letter and look forward to continuing our conversations with the New England states and stakeholders on issues related to environmental justice and the clean energy transition, both in the context of our annual budget and beyond,” ISO-NE said in a statement to RTO Insider.
Mireille Bejjani, co-executive director of the environmental justice organization Slingshot, applauded the state’s proposal, saying it’s an important step.
“ISO New England doesn’t have a track record on environmental justice; it hasn’t been something they have taken into account,” Bejjani said, noting that ISO-NE’s main considerations have been limited to cost and reliability. “The potential creation of the position is really exciting because it could change the conversations that are happening so that when reports are being put together and decisions are being made, we’re taking into account the human side of the grid.”
Bejjani said it is important to give the position real authority and decision-making power, and not to use it as justification for a business-as-usual approach. She also echoed the need to expand the role beyond a single position.
“It’s too much work for one person to manage all of the environmental justice concerns for an entire grid operator,” Bejjani said.
Susan Muller, senior energy analyst for the Union of Concerned Scientists, said it’s especially important to give environmental justice communities representation in the NEPOOL process, which was not specifically mentioned in the letter.
“The NEPOOL stakeholder process is where most of the decisions are made,” Muller said. “The person in this position should be thinking about how to make the NEPOOL process accessible to the impacted communities … right now, it would be almost impossible for most communities to participate in the NEPOOL committee process.”
Muller added a distinction must be made between outreach to energy infrastructure host communities and energy consumers. ISO-NE’s Consumer Liaison Group meets to engage with energy consumers four times a year. She added that ISO-NE is not alone among the country’s ISOs and RTOs in its historical lack of consideration of environmental justice.
In June, a coalition of climate and environmental justice organizations (including the Union of Concerned Scientists) submitted to MISO a set of “equitable grid principles,” calling on the organization to prioritize human rights, accessibility, and climate resilience in its decision-making processes. (See MISO Stakeholder Activists Propose Equity Principles.)
MISO responded by acknowledging the importance of the principles but argued that their members and state regulators were better situated to address the issues.
A group of renewable energy developers lodged a complaint at FERC last week over MISO’s pursuit of a smaller system impact threshold on interconnecting generation, which will induce more network upgrades.
The group of eight developers, including National Grid Renewables, Invenergy and NextEra Energy, said MISO’s new rule — which halves some interconnecting generation’s allotted distribution factor (DFAX) to 10% — means the RTO is making “sweeping” cost allocation decisions while circumventing FERC approval (EL23-85). The grid operator did not run the change past FERC, entering the stricter cutoff into a Business Practices Manual (BPM) rather than its tariff. (See MISO, Stakeholders Debate Lower Congestion Limit.)
The new rule applies to MISO’s basic and unguaranteed level of interconnection service, called energy resource interconnection service (ERIS). The DFAX, which represents how much a generator impacts transmission congestion, is used to assign the costs of transmission upgrades to ERIS customers. The RTO is applying the more stringent DFAX threshold to customers within certain subregions and at certain transmission voltage levels.
The developers argued that MISO’s tariff is unjust and unreasonable because it is silent on cost allocation criteria for interconnection customers. They asked FERC to order MISO to revise its tariff to incorporate the previous 20% DFAX standard and only allow a smaller threshold if the RTO makes a formal proposal before the commission with evidence that the change is reasonable and necessary.
The developers argued that the Federal Power Act and FERC policy require that MISO keep its cost allocation criteria for interconnection customers on file with the commission.
“Should a public utility be permitted to change the cost allocation criteria that it uses to assign interconnection customers hundreds of millions of dollars in costs each year without commission oversight and without complying with the filing requirements of the FPA?” the developers asked rhetorically in their July 25 complaint. “MISO’s use of a BPM to make drastic changes to its cost allocation criteria reflects a fatal defect in MISO’s tariff: The tariff does not include the cost allocation criteria applied by MISO to determine the rates that a customer must pay to obtain interconnection service.”
MISO has said the lower tolerance on congestion contributions will allow upgrade costs to be shared among more interconnection customers and result in fewer unaddressed reliability issues passed on to later queue cycles or turning up in the RTO’s annual transmission expansion plans.
But the developers contended MISO has flouted statutory requirements by dodging the filing process on a proposal that will “materially affect the costs that customers are required to pay to obtain interconnection service and access the wholesale markets.” They said it didn’t respond to stakeholders’ requests that it justify its proposal.
“Although MISO may believe that a selectively applied 10% standard represents an improvement over prior practice, the only standard that has been shown to be within the range of reasonableness is the longstanding 20% standard. MISO has not provided any empirical data that shows the 20% DFAX standard is unjust, unreasonable or unduly discriminatory,” the developers said.
They also charged that MISO’s goal is reducing congestion for the sake of economics, not supporting reliability. The RTO should also employ a DFAX threshold uniformly, the developers argued.
Assuring consumers that the government is not “coming to take your gas stove,” New Jersey’s Board of Public Utilities (BPU) opened a two-day conference Tuesday into the contentious issue of how to dramatically reduce the use of natural gas and promote alternatives in pursuit of cutting carbon emissions.
Representatives of government, environmental groups, ratepayer advocates and utilities mapped out scenarios, challenges and potential pitfalls on how to manage the transition away from gas while protecting ratepayers and overburdened communities.
BPU President Joseph L. Fiordaliso began by dismissing what he sees as widely circulated misinformation that the state planned to mandate the use of electricity for heating, hot water and other appliances.
“Natural gas is not going anywhere anytime soon,” Fiordaliso said. State officials say a transition away from gas will be adopted voluntarily by consumers.
That switch will be difficult, complicated and unpredictable, and require extensive planning and investment, speakers said. Key to success will be balancing support for the declining natural gas sector and its users, while boosting the capacity of clean energy to handle the influx of former gas users, speakers said.
“We’re talking about a fundamental transformation of two important energy systems in the state in a relatively short amount of time,” said Bob Brabston, the BPU’s executive director, near the end of a 90-minute panel Tuesday morning on the cost impact and challenges of the shift.
“What does that mean for us as a state from an economic competitive standpoint? What does it mean to the businesses that operate here? And what are some of the things that we as policymakers should be thinking about as we talk about some of this stuff?”
‘Flat’ Building Emissions
The BPU convened the conference, which ran Tuesday and Wednesday, after Gov. Phil Murphy (D) signed an executive order requiring the agency to solicit stakeholder input and draft recommendations by August 2024 on how to shrink the natural gas sector. The state is seeking by 2030 to cut greenhouse gas emissions to 50% below 2006 levels.
State policy does not mandate a shift to electrify building water and heat systems, but a series of policies introduced by the Murphy administration heavily promote the shift, including rules approved by the BPU on July 26 that would create a series of “startup” building electrification programs backed by incentives. (See NJ BPU Backs Building Decarbonization Plan Despite Opposition.)
A separate executive order signed by Murphy calls on the state to electrify 400,000 dwelling units and 20,000 commercial spaces or public facilities by 2030.
Opponents of the plans, including business groups and fossil fuel interests, say electrification is expensive and the state’s strategy is heavy handed and doesn’t take into account alternative fuels. Meanwhile, some environmental groups say the state is electrifying too slowly.
Eric Miller, New Jersey energy policy director at the Natural Resources Defense Council, speaking on the same panel as Brabston, said the need for a solid strategy to cut emissions from natural gas use in buildings can be seen in the history of the energy generation and building sectors, which are the second- and third-largest generators of carbon emissions. While emissions from energy generation have been about halved in the past two decades, building emissions — which account for 26% of state emissions — “are about flat,” because of the lack of a policy, he said.
The solution is a Clean Heat Standard, under which the state sets a steadily increasing goal for the percentage of clean energy used by buildings, he said. Such an initiative would be flexible enough to “allow a broad range of technologies” to replace fossil fuels, he said.
Abe Silverman, former BPU general counsel who now runs a clean energy policy program at Columbia University, echoed Miller’s call for a standard, which he described as “bringing in a competitive, technology-agnostic standard for the natural gas sector.”
“That has really profound implications for how we drive investment in the sector and how we think about things going forward,” Silverman said. “When we see this in other states, we largely see this as negotiated political settlements, where you establish the benchmarks upfront, and then you use the competitive market to achieve those standards.”
Adopting such a system likely would trigger “a very difficult, contentious discussion” over the levels at which the standard is set, he said. Other thorny issues include what entities and institutions are covered by the standard, which fuels are considered clean and who will ensure compliance, he said.
Even more complicated is how to assess the “cost effectiveness” of the strategy, he said.
“We’re talking about switching people off of the natural gas system to electrification, or otherwise decarbonizing the natural gas they’re using,” he said. “You have to think about both the costs of moving customers off the gas system onto the electric system, that’s one set of costs. But then you also have to think about the cost of maintaining the natural gas system.”
Planning Future Electricity Demand
A key issue as customers leave the gas sector is whether the electricity sector has the capacity to handle the increase with clean energy rather than electricity created with fossil fuels, said Michael A. Schmid, vice president for asset management and planning at PSE&G.
“We need to be talking with our RTOs. We need to be looking at how they’re doing their planning, what they’re estimating load forecast to be compared to what the utilities are estimating currently,” he said. One example of the challenge, he said, is how to plan for the rise in electric heating, which at some point — likely 20 years or so from now — will mean the winter electricity peak will exceed the summer peak. That planning task will be further complicated by the unpredictability of the rise in electric vehicles, which PSEG expects to reach about 800,000 vehicles in New Jersey in 10 years, he added.
Silverman said utilities that serve gas and electricity customers will lose a gas customer but add an electricity customer. But utilities that serve only gas customers, or only electric customers, will see a different impact, he said.
Maintaining the natural gas distribution system will be key to big gas users, such as industrial customers, Schmid said. Utilities will continue to improve the gas system and ensure it doesn’t harm the environment, such as through methane leaks, he said.
“How do we balance out the cost of the of the gas distribution system to the costs that are going to come in on the electric system?” he asked. As utilities like PSEG continue to invest in both sides, “we have to sit there and say: Are we ready for the future?”
Customer Impact
Utilities also will have to carefully manage the effects on customers, Silverman said. He cited a section of the natural gas grid that — from an “operational perspective” and for financial reasons — should be shut down even though there are gas customers in the area that don’t want to shift to electricity.
“How do we reach a consensus as a society about shutting down that little piece of grid because there are cost savings?” he asked.
David S. Lapp, of People’s Counsel in Maryland, which advocates for ratepayer interests, said it’s important to consider the impact of the shift away from gas falls heavily on low- and moderate-income consumers.
Lapp, speaking on a panel Tuesday afternoon about ratepayer costs of the energy transition, said a study by his office of the impact in Maryland found that initially, some customers would switch away from gas. Then, as their departure pushed up gas rates because the user base was smaller, that encouraged even more users to flee rising gas prices.
“So the customers who are … capable of leaving the system will,” he said. “So, then we will have people who can’t get off the gas system, whether it’s because they’re low-income, they can’t afford switching over the appliances or they’re renters, and they don’t have that ability.”
“What we saw is really a risk of rapidly spiraling, increased gas rates for customers,” he said. One solution, he said, is to slow the pace of infrastructure spending on the gas side, to “mitigate the possibility of stranded cost.”
A new analysis quantifies how setback ordinances are affecting wind and solar energy development.
The National Renewable Energy Laboratory said these local laws are multiplying but their broad effects typically have not been measured in large-scale assessments because of the extensive amount of data that is needed and the detailed modeling that must be built from it.
As a result, NREL said, previous assessments likely have overestimated the amount of land available for renewable development and underestimated the cost and difficulty of development.
If the most restrictive setback rules were imposed nationwide, the potential for wind development would drop almost 90% and solar nearly 40%, compared with a scenario in which no restrictions were in place.
It’s important to include these setbacks in resource assessments, the authors say, to accurately estimate the actual potential.
The NREL study — “Impact of Siting Ordinances on Land Availability for Wind and Solar Development” — was published Thursday in Nature Energy.
Reviewing state and local zoning laws and ordinances, the authors found 1,853 local wind rules in effect in 2022, compared with 286 four years earlier. They also found 839 local ordinances affecting utility-scale solar construction in 2022; no comparable data tally was made in previous years.
The most common types of regulations are minimum setbacks from roads, property lines and structures; noise level restrictions; and wind turbine height limits.
Setback distances typically are greater for wind turbines than solar arrays and often are calculated with some multiple of the turbine’s height.
Looking nationwide at land suitable for energy development — with no legal protections, wetlands, high elevations or other major limits — the study found the potential for construction of 147 TW of solar capacity and 14 TW of wind capacity if no setback restrictions were imposed.
This falls to 121 TW and 4 TW under the median distance among setbacks imposed nationwide and falls to 91 TW and 2 TW under the most restrictive setback rules — a decrease of as much as 38% for solar and 87% for wind.
“The increase in local zoning ordinances is a sign that the renewable energy industry is maturing,” lead author Anthony Lopez said in a news release. “Ordinances can provide a structured approach to thoughtfully weave clean energy infrastructure into society and our natural environments.”
A key takeaway, he said, is the importance of understanding the impact of renewable development on communities, and of providing communities with information to help them balance regulation of those impacts with the benefits of constructing renewable resources.
Other findings and caveats in the report include:
The impact of setback restrictions varies greatly depending on the nature of the community; Albany County, Wyo., and Erie County, Pa., have similar setback requirements for wind turbines, but Erie County is so much more densely developed that nearly the entire county is excluded from wind power installation.
Factors not examined in the report — such as environmental, ecological and security considerations — also influence land availability.
The report incorporates only zoning ordinances that had been posted online.
Energy developers sometimes can obtain exemptions from setback standards.
A few counties’ information is missing, so data was simulated for them.
There was no attempt to factor in local circumstances — such as when owners of two adjacent parcels agree to host wind turbines, and the setback requirements are canceled along the property line between them.
Setback data were combined with wind and solar data to model the renewable energy potential of a given area and the local ordinances’ impact on it.
The Tennessee Valley Authority’s plan to swap a retiring coal plant with a new natural gas facility is making progress despite opposition from environmental groups.
The Tennessee Department of Environment and Conservation (TDEC) in late July issued an Aquatic Resource Alteration Permit to Tennessee Gas Pipeline Co. The Kinder Morgan subsidiary is proposing to build a new methane gas pipeline across three counties in Tennessee to supply TVA’s proposed 1,450-MW Cumberland gas plant. (See Nonprofits Urge TVA to Reconsider Gas-fired Options.)
The newest permit paves the way for the Army Corps of Engineers to issue a Section 404 permit under the Clean Water Act and for FERC to move forward with its own permitting. On June 30, FERC issued a favorable, final environmental impact statement (EIS) for a natural gas pipeline to supply the plant.
Angela Mummaw of Appalachian Voices said she thought TDEC’s permitting process was rushed.
“They did not take the time to seriously consider the detailed comments they received. Community members and subject experts submitted hundreds of pages of concerns, and they made a decision just five days after the comment period ended,” Mummaw said in a statement. “There was no response about the new species of crayfish we discovered, or the stream that would be crossed three times in short succession, compounding the negative impacts of the open-trenching method that Tennessee Gas Pipeline Co. plans to use. Despite all the reasons we gave them not to, TDEC issued the permit anyway.”
Assuming the pipeline is fully permitted, TVA will be a customer for its proposed plant.
TVA plans to retire the first of two coal burning units at the 50-year-old Cumberland plant by the end of 2026 and expects to have the planned gas plant operating before then to replace production. The Cumberland Fossil Plant failed during the December 2022 winter storm, contributing to the rolling blackouts TVA was forced to authorize.
“Natural gas is an important part of our energy system of the future. It offers flexibility to meet load demand as we add more generation, like solar power, to the mix without risking reliability and grid stability,” TVA spokesperson Elizabeth Gibson said in an emailed statement to RTO Insider.
The Sierra Club, Appalachian Voices and the Center for Biological Diversity, represented by the Southern Environmental Law Center, filed a lawsuit in mid-June in U.S. District Court in Nashville hoping to stop TVA’s plans to substitute one fossil fuel for another.
The lawsuit claims TVA defied the National Environmental Policy Act by committing to a new natural gas plant too early in the process, failing to seriously consider carbon-free alternatives and ignoring the climate harms and volatile fuel costs the community will bear. The groups allege TVA signed a contract with the pipeline company before completing the requisite review.
“We know that renewables with battery storage and robust energy efficiency continue to beat out fossil fuels in cost around the country, so a federal agency should be held accountable when it fails to meet the most basic requirements of the National Environmental Policy Act,” Sierra Club’s Amy Kelly said in a statement at the time.
The groups have said if the Cumberland replacement plant is allowed to proceed, it will emit an estimated 2.8 million tons of greenhouse gases annually. They also said TVA didn’t consider the cost of mitigating air pollution from the plant in its analyses.
Appalachian Voices’ Brianna Knisley said TVA struck “an early deal with an international corporation and then produced a faulty study of alternatives that was designed to favor that backroom agreement.”
When TVA retires Cumberland’s second coal-burning unit by the end of 2028, it may supplant the output with a separate, 900-MW gas plant in Cheatham County, Tenn., and a 400-MW battery storage system.
TVA insists it “has not yet made any decisions about replacement generation for the second unit at Cumberland Fossil Plant,” according to Gibson.
However, TVA has filed a notice of intent to prepare an environmental impact statement for the smaller, gas-fired plant.
Entergy said Wednesday it is expanding its clean energy portfolio by adding 6 GW of renewable capacity through 2026.
CEO Drew Marsh said the company has almost 2.4 GW of renewable capacity either in construction, permitted, under regulatory review or in negotiations.
“We’ve been limited by a smaller development pipeline,” Marsh told financial analysts during Entergy’s second-quarter conference call. “We have been successful with the projects we’ve been able to put forward. We are finding success in building out our portfolio somewhere in the neighborhood of 4 GW in the pipeline.
“We expect the growth to continue to be very strong, given where we are competitively,” he added.
Entergy reported earnings of $391 million ($1.84/share), more than double last year’s second quarter of $160 million ($0.78/share). Last year’s second quarter included operating and shutdown costs for the Palisades nuclear plant, which was sold during the same period a year ago.
Zacks Investment Research analysts had expected earnings of $1.69/share.
“We had a successful second quarter with meaningful progress on key regulatory and legislative fronts,” Marsh said in the New Orleans company’s press release.
Entergy plans to take advantage of the Texas Resiliency Act, which allows utilities to submit resiliency plans and defines cost recovery options. It plans to file once the Public Utility Commission’s rulemaking is complete.
Entergy’s Texas subsidiary has filed for approval to increase its annual nonfuel retail base-rate revenue requirement to $1.2 billion — an increase of about $131.4 million (11.2%). Management was hopeful the Texas commission will approve an order during Thursday’s open meeting.
The company’s share price gained more than a dollar during the day’s trading before closing at $101.40, a gain of 23 cents.
FERC on Tuesday accepted CAISO’s proposed tariff revisions designed to help it deal with the overwhelming number of interconnection requests it received in 2021 and again this year (ER23-2058).
During the filing window for Cluster 14 in April 2021, the ISO saw a 241% increase above its previous record for interconnection requests, and 20% more projects than expected stayed in the queue for the second phase of the cluster study.
“CAISO notes that the increase required CAISO to revise its interconnection study deadlines for Cluster 14, which the Commission approved in September 2021, shortly after Cluster 14 began,” FERC said.
The ISO received 544 interconnection requests totaling more than 350 GW in its Cluster 15 window this year, “a 45% increase above the Cluster 14 interconnection requests and a new record-high,” the commission noted.
CAISO contended that studying Clusters 14 and 15 at the same time was unworkable for the ISO and its transmission owners. It asked FERC to approve changes to its tariff that extend remaining Cluster 14 deadlines by two months and to pause Cluster 15 studies until it finishes with Cluster 14, “which effectively puts Cluster 15 on hold until September 26, 2024,” FERC said.
“CAISO represents that the unprecedented volume of interconnection requests in both Clusters 14 and 15 require additional time and process to complete,” it said.
Intervenors did not object, and FERC said it found the new timelines reasonable.
“CAISO explains why it is not possible to process Clusters 14 and 15 under the existing time frame in its tariff and proposes revisions that establish a transparent and reasonable approach for addressing the unprecedented challenges raised by Clusters 14 and 15,” FERC said. “Accordingly, we agree with CAISO that its proposal to extend the interconnection study deadlines for Cluster 14 will help ensure that, under the circumstances, CAISO and its transmission owners have sufficient time to study these interconnection requests.”
‘Unbearable’ Delays
Commissioner Allison Clements concurred, saying the time extensions sought by CAISO made sense to allow the ISO to deal with its “massive Cluster 14 interconnection queue cluster and to pause its even more massive Cluster 15 interconnection queue cluster.”
She added that the issues CAISO faces “are emblematic of the unbearable queue delays and costs that interconnection customers and utilities are facing around the country.”
“Order No. 2023, ‘Improvements to Generator Interconnection Procedures and Agreements,’ includes reforms that will improve interconnection processes across the country,” Clements said. “However, as I noted in my concurrence, while the rule ‘can be expected to improve matters, more will be necessary to solve the problem.’ Therefore, I urge all transmission providers to consider the additional reforms and improvements to generator interconnection processes that I discuss in detail in my concurrence to Order No. 2023.”
She appended her concurrence to Tuesday’s CAISO decision.
“The final rule is one of the largest in FERC’s history,” Chair Willie Phillips said in a press conference after FERC’s monthly open meeting last week. “It represents the largest and most significant set of interconnection reforms since the pro forma interconnection procedures were created two decades ago.”
“Our country has a severe interconnection backlog. Currently there are 2,000 GW of resources in interconnection queues, the largest backlog in history,” he said.
Clements concurred in Order 2023.
“As of the end of 2022, a staggering 10,000 projects representing over 2,000 GW of potential generation and storage capacity are stuck in line to connect to the grid,” she wrote. “That is nearly double the 1,250 GW of total installed capacity in the United States today.”
Order 2023 will improve the situation, but more is needed, she said.
Her 23-page concurrence discussed “deeper reforms that get at some of the remaining fundamental challenges with interconnection processes.” It also addresses “additional nuts and bolts changes that could enhance the effectiveness of a variety of interconnection processes, but which were not part of the proposal giving rise to this final rule,” Clements said.
