The EPA is proposing tighter standards on wastewater discharge from coal-fired power plants.
The revised Effluent Limitations Guidelines and Standards would restore and build on standards set under President Obama in 2015 but weakened under President Trump in 2020. The EPA estimates the changes would block the release of 584 million pounds of toxic pollutants per year via three separate waste streams.
Use of coal as a fuel for steam electric generating stations has been steadily decreasing in the U.S., and the proposed changes appear to encourage additional decommissioning, with an exit option for plant operators planning or considering a shutdown or a conversion to a different fuel.
Operators will be eligible for less-stringent wastewater pollution limits if they agree to permanently stop burning coal by 2028. And those that have already complied or are in the process of complying with the 2015 or 2020 requirements will get a pass on some of the new regulations if they plan to stop burning coal by 2032.
The original deadline for the 2028 opt-in has already passed, but the EPA said in a fact sheet that it is aware that additional plant operators would opt in if the deadline were extended as it proposes and said the extension might give some operators the flexibility to cease burning coal earlier than they might otherwise.
Announcing the proposal Wednesday, EPA Administrator Michael S. Regan called it an ambitious step to protect communities from harmful pollution.
Coal-fired plants discharge large amounts of wastewater laced with mercury, other toxic pollutants, nutrient pollution and dissolved solids, the EPA said.
The proposal would address three waste streams from combustion — flue gas desulfurization wastewater, bottom ash transport water and combustion residual leachate — and pave the way for potentially stricter discharge standards on surface impoundments such as ash ponds.
The EPA offers four sets of options in its proposal. It estimates the total social costs of its preferred option at $200 million and total monetized benefit at $1.56 billion, plus unquantifiable benefits such as habitat improvement for aquatic life.
In its impact analysis, the EPA projects a 0.1% nationwide reduction in generating capacity and 0.1% increase in production costs by 2030 as a result of plant slowdowns or shutdown under its preferred option. Depending on the region, that could mean a residential bill increase anywhere from 9 cents to $1.31 per household per year, the EPA estimates.
The rule was originally issued in October 1974. It was amended four times through 1982, then not again until 2015. After two legal challenges, EPA in August 2020 revised it again, changing limits on the flue gas desulfurization and bottom ash transport wastewater discharge.
Five months later, on his first day in office, President Biden issued Executive Order 13990, ordering the EPA to review all regulation and policy actions taken under President Trump and to revoke or revise any that did not protect public health and the environment.
The EPA’s move to reaffirm Mercury and Air Toxics Standards for power plants was one result of that order. (See EPA Reaffirms Power Plant Mercury Regulations.) The new wastewater regulations proposal announced Wednesday is another.
The EPA will soon post details on virtual public hearings planned April 20 and 25.
A federal jury in Cincinnati on Thursday found former Ohio House Speaker Larry Householder (R) guilty of racketeering conspiracy in connection with nearly $61 million FirstEnergy paid a dark money group controlled by him to win passage of legislation authorizing a $1.1 billion public subsidy for the utility’s two uncompetitive nuclear power plants in northern Ohio.
Also found guilty as a co-conspirator was former Ohio Republican Party Chairman Matt Borges for his role in lobbying lawmakers to approve H.B 6 in 2019 and to help defeat a referendum petition overturning the legislation in 2020.
Two other co-conspirators pled guilty to lesser charges and testified against Householder and Borges. A fifth defendant and top Ohio lobbyist died by suicide in 2021.
The jury deliberated about nine hours following the seven-week trial that included hundreds of documents.
FirstEnergy in July 2021 agreed to pay a $230 million fine in a deferred prosecution agreement that included its willingness to assist federal prosecutors. (See DOJ Orders $230 Million Fine for FirstEnergy.) The company fired its CEO and up to half-dozen others following internal investigations in the last two years.
In March 2021, Ohio lawmakers reversed the nuclear bailout subsidy with passage of a bill that continued a public bailout of two aging coal-fired power plants owned by the Ohio Valley Electric Corp. (See Ohio Lawmakers Repeal Nuclear Subsidy for Energy Harbor.)
After the FBI arrested Householder and his four associates in July 2020 pre-dawn raids, the office of the U.S. Attorney for the Southern District of Ohio called the months-long investigation the largest public corruption case in the state’s history.
Following the verdict Thursday, U.S. Attorney Kenneth Parker said in a prepared statement Householder “illegally sold the state house, and thus he ultimately betrayed the great people of Ohio he was elected to serve. Matt Borges was a willing co-conspirator, who paid bribe money for insider information to assist Householder.”
The Justice Department said that, beginning in March 2017, Householder began receiving quarterly $250,000 payments into the bank account of Generation Now, a 501(c)(4) he controlled, from FirstEnergy and its subsidiary FirstEnergy Solutions, operator of the power plants at the time.
Both defendants plan to appeal the conviction and remain free on bond. A sentencing hearing has not been set.
The West Virginia Public Service Commission has filed a complaint with FERC alleging that PJM is violating its tariff by not granting the PSC access to the RTO’s Member Liaison Committee (EL23-45).
“PJM’s refusal to allow the PSC access to discussions with the PJM Board that can be observed by electricity producers, transmission companies and other market participants is wrong,” PSC Chair Charlotte Lane said in a press release announcing the complaint.
“This compromises the PSC’s ability to understand the full range of underlying factors and special interests driving PJM decisions so that it can be fully armed to protect the West Virginia electric customers in grid decisions, as well as in decisions we make in regulating West Virginia electric utilities,” Lane said.
Along with other state regulators, the commission had been permitted to attend LC meetings from 2011 through 2018. But in September 2018 the Members Committee voted to enforce the LC’s charter to restrict attendance to members of the RTO and PJM’s Board of Managers, locking out state commissions, FERC staff, the Independent Market Monitor and the Organization of PJM States Inc. (OPSI). (See PJM Stakeholders Table WVa PSC Attendance at Liaison Committee.)
“We are disappointed that PJM has required the PSC to take this extraordinary step in filing a complaint to access information needed to protect West Virginia electric customers,” Lane said in the release.
The PSC complains that PJM’s tariff and past FERC transparency rulings require that ex officio, nonvoting members must be allowed to observe the LC meetings and that prohibiting their attendance violates the non-discrimination provisions of the Federal Power Act sections 205 and 206. It notes that PJM continues to allow other ex officio members, namely state consumer advocates, to attend the LC given their status as voting members of PJM’s standing committees and makes the case that there is no reason to not allow state regulators as well, as the LC is not a voting committee.
After being told that it was not allowed to register for LC meetings in August 2018, the PSC attended two MC meetings in September and November 2021 to make the case for its right to attend. While a motion was made during the Nov. 17 meeting, stakeholders narrowly voted to indefinitely postpone voting on the matter.
“Indeed, the Liaison Committee Charter makes clear that the Liaison Committee does not ‘vote’ on matters, but rather exists to improve transparency between the Board and the members. There is thus no reason to distinguish between voting and non-voting ex officio members of PJM regarding their rights to attend and observe the Liaison Committee meetings,” the complaint states.
PJM spokesman Jeff Shields responded that the RTO “is fully compliant with its governing documents on this issue. Participation on the Liaison Committee is determined by members, who did not support participation by the West Virginia Public Service Commission when it was brought before the Members Committee in November 2021.”
The PSC argued that knowledge of the meeting’s proceedings is necessary to allow it to fulfill its mandate to protect consumers’ interests, since FERC-regulated utilities operating in West Virginia may participate in the meetings and have an opportunity to advocate before the PJM board for market rules that are not in the state’s interests.
“The statements made by those utilities to the PJM Board and the positions they take before the Board are matters of unique and critical interest to the PSC WV given the state regulatory commission’s obligation to oversee the actions of those West Virginia-jurisdictional utilities and the positions they take in discussions with an entity charged with overseeing the markets and transmission operations for their utility operations in West Virginia,” the PSC wrote. “Absent the right of the PSC WV to attend those meetings, it would be unable to discern what the West Virginia jurisdictional utilities were telling the PJM Board of Managers regarding issues of critical importance to regulation of utility operations in West Virginia.”
The PSC said attending the LC meetings “is critical to its ability to ensure service reliability and affordability in West Virginia, especially during the market’s transition to renewable energy resources.”
Struggling to deal with an overwhelming number of generator interconnection requests, CAISO has launched a new stakeholder initiative to overhaul its interconnection process to prioritize projects that serve the state’s resource requirements in areas that already have transmission.
The revamp is vital to help the state add the gigawatts of renewable resources and storage it needs to meet its 100% clean energy mandate by 2045, CAISO said in an issue paper and straw proposal it published this week to start the “Interconnection Process Enhancements 2023” initiative. The first stakeholder meeting is scheduled for Monday.
“With the ISO’s interconnection application queue inundated with applications, current processes need to be reimagined to ensure resource procurement and queuing are effectively shaped and informed to take advantage of transmission and interconnection capacity that exists or is already planned and under development, and to align with the transmission upgrades necessary for longer-term resource development,” the paper says.
CAISO received 359 interconnection requests totaling more than 105 GW during its Cluster 14 window in April 2021, quadruple the number of prior years, with 205 projects totaling 65.5 GW proceeding into phase 2 of the interconnection study process.
“When the schedule for the Cluster 14 supercluster was developed, the ISO assumed that the unprecedented number of projects studied in phase 1 would … result in a large percentage of projects withdrawing,” the issue paper says. “That would have made for a much more reasonable number of projects needing to be studied in Cluster 14 phase 2.” But the “high project withdrawal rate … did not materialize. In fact, the percentage of projects proceeding into phase 2 is higher than normal.”
The window for Cluster 15 requests is scheduled for April 3-17. CAISO said it expects to receive 279 to 308 interconnection requests based on an informal survey of developers late last year.
“Simply layering a massive influx of new Cluster 15 interconnection requests on top of the existing queue and the Cluster 14 projects in the queue is not an effective way to advance interconnection proposals,” the paper says. “To do so would exacerbate an already unworkable situation.”
Refinements to CAISO’s interconnection process over the past two years have not sufficiently reduced the number of requests to the manageable level needed to “support the pace of new resource development that must be sustained in the years ahead,” it says. (See CAISO Approves More Interconnection Enhancements.)
“Simply put, without transformational changes to the [Generator Interconnection and Deliverability Allocation Procedures] in the 2023 [Interconnection Process Enhancements] initiative, we will not be able to accommodate the rapidly accelerating pace of new resources that must be connected to the grid to achieve SB100 goals in a reliable and cost-effective fashion.”
The new initiative has two tracks. The first involves adjusting the schedule for processing Cluster 15 requests by postponing request validation and scoping meetings until the Cluster 14 phase 2 studies are finished by Nov. 24 and the results meetings are complete by Feb. 22, 2024.
“As such, the ISO does not anticipate resuming Cluster 15 until 2024,” the straw proposal says.
Track 2 of the initiative is meant to prioritize projects that would use available transmission capacity and that are in zones where the ISO’s transmission planning process identifies the need for additional capacity based on state resource planning. It also seeks to limit the number of requests studied within those zones according to the state’s resource procurement needs.
Track 2 “will focus on the transformative changes to the interconnection process needed to achieve the strategic direction” agreed to in a December memorandum of understanding between CAISO, the California Public Utilities Commission and the California Energy Commission. (See CAISO CEO Lauds Transmission Planning Agreement.)
‘It Just Doesn’t Work’
The MOU was meant to better coordinate the CPUC’s Integrated Resource Planning process, the ISO’s transmission planning process and the CEC’s Integrated Energy Policy Report, which identifies the state’s energy needs and its activities under Senate Bill 100, the 2018 measure that that established the state’s clean energy mandate.
Long-term resource planning and procurement by the CPUC and CAISO’s transmission planning process “requires just exquisite coordination and synchronization of those different processes,” CAISO CEO Elliot Mainzer said in a speech to the Energy Bar Association Western Chapter on March 2.
The MOU “defines the order of operations to make sure that the CEC-CPUC-CAISO processes are much more tightly coordinated and synchronized,” Mainzer said. The ISO needs “to start getting out of this traditional reactive mode of transmission planning” and a “dysfunctional” queuing process.
“I think running 60,000-MW cluster studies just prevents transmission planners from doing actual transmission planning,” Mainzer said.
CAISO’s annually updated transmission plan will be released soon and will take a more proactive “zonal approach,” he said.
“It will let the transmission plan shape the queuing and shape the procurement so that we’re queuing up and running competitive solicitations on the buy side of places where we’re actually going to be building transmission capacity, as opposed to running fictional studies that give you useful insights or coming out with studies that say, ‘Sure I’ll interconnect you. It will cost you $850 million.’ It just doesn’t work.”
‘First-ready, First-served’
Long interconnection queues have plagued other RTOs and ISOs in recent years.
The number of generation projects entering PJM’s interconnection queue nearly tripled between 2018 and 2022 as more renewable projects were proposed. The RTO started 2022 with nearly 2,500 projects under study in its queue, with 95% of the more than 220 GW of requests from renewables, storage or a combination of the two.
It estimates it will take until 2026 before it can clear the backlog. New interconnection requests will not be studied before then, PJM said.
In a Notice of Proposed Rulemaking in June, FERC proposed similar changes by replacing the serial “first-come, first-served” study procedure with “first-ready, first-served” cluster studies (RM22-14). The commission also proposed more stringent financial commitments and readiness requirements for interconnection customers, which it said would discourage speculative interconnection requests. (See FERC Proposes Interconnection Process Overhaul.)
In calling for a switch to a “first-ready, first-served” study process, the commission endorsed rules it had already approved for MISO and SPP. Even with the rule changes, MISO faces scrutiny over whether it can deal with 170 GW of new generation requests that were added to its interconnection queue in September. (See MISO Insists it can Handle Record-setting Interconnection Queue.)
CAISO has fast-tracked its new interconnection initiative and plans to seek approval from its Board of Governors in May.
DENVER — EPA official KC Becker last week presented renewable industry stakeholders with new opportunities to access funding from the Bipartisan Infrastructure Law and the Inflation Reduction Act.
Becker, the agency’s administrator for the Mountains and Plains region, spoke at the Colorado Solar & Storage Association’s Mountain West Conference on March 1, breaking down EPA programs to fund decarbonization. She said that between the two “historic” pieces of climate legislation, the EPA will be distributing $100 billion in a variety of forms, but she focused on two programs equaling about $32 billion that aim to reduce emissions.
“[The] theme through all of these is that they’re really focused on cleaning up dirty sources of energy and replacing them with clean sources,” she said.
The Greenhouse Gas Reduction Fund makes up $27 billion of funding and is broken into two parts:
the green bank portion, which aims to leverage private capital by distributing $20 billion to 15 private entities to disperse to emissions-reducing projects; and
the Zero-emission Tech Fund, which is awarding 60 competitive grants totaling $7 billion to “states, tribes, municipalities and eligible nonprofit entities … directed specifically and almost exclusively at solar and storage.”
In selecting winning grants, the EPA will focus heavily on those deploying rooftop and community solar in environmental justice communities.
“This is a big climate effort; it’s also a big environmental justice effort,” Becker said. “The people who are most impacted by the climate crisis tend to be the most burdened with pollution, the least [able] to adapt to a changing climate, and that’s really where we want to be making our investments.”
The other $5 billion of funding will go to pollution-reduction grants to encourage states to decarbonize. Becker was especially excited to talk about those, saying “we were embargoed on [speaking about] this until this morning at 7:30, so this conference is very timely.”
The EPA plans to give states up to $3 million in non-competitive grants to create and submit their climate plans. The other $4.7 billion is slated for implementation of those climate plans, which will be dispersed through competitive grants. Becker again stressed the importance of considering disadvantaged communities when applying for the grants.
“The president has said in the deployment of all this new money … [that] whoever might have a little slice of this Inflation Reduction Act really has to meet the Justice40 goals. And that’s putting 40% of our investments or benefits to serve marginalized, underserved, overburdened communities,” she said.
Despite the deluge of federal funding, Becker has run into some policy makers who are resistant to the changes this money could bring. She said that after leaving the conference she would be calling the lawmakers in her region to encourage them to take advantage of this opportunity.
“Just in Colorado alone, through the Inflation Reduction Act, we estimate that it’s going to bring $13.2 billion of investment to large-scale clean power generation and storage,” Becker said, adding that “if they don’t want to call it climate pollution reduction money or greenhouse gas reduction money, it is economic development money.”
“One thing that I’ve been saying to the states in my region that tend to be more conservative is: If you don’t take this money, it’s going to go somewhere. It’s probably going to end up in California,” she said, drawing a laugh from the audience.
Agriculture contributed more than 11% of U.S. greenhouse gas emissions in 2020, and the Biden administration has allocated nearly $20 billion in new funding authorized by the Inflation Reduction Act to expand local and regional soil and water conservation programs, as well as reduce emissions.
The Natural Resources Conservation Service, an agency of the U.S. Department of Agriculture, last fall announced the first competitive grants would be available in six separately funded programs. The initiatives are designed to foster sustainable agricultural practices under the rubric of “climate smart” harvests.
Proof of sustainable practices will also be a key component in low-carbon ethanol for aviation and in numerous other agricultural-based chemicals and products.
Carrie Pearson, Cargill Corp. | AURI
Federal mandates on carbon are coming in one form or another, say agricultural and food-marketing experts.
“I think it’s coming,” Carrie Pearson, product sustainability lead at Cargill, said of federal rules requiring agribusiness to provide evidence about the environmental impact of food products.
“If you look at the Inflation Reduction Act, there are incentives for products that have lower footprint and environmental product declaration data available,” she said last month during a webinar produced by the Minnesota-based nonprofit Agricultural Utilization Research Institute (AURI).
Kate Barry, Chainalytics | AURI
Kate Barry, an expert on food packaging and senior consultant with Atlanta-based supply chain consulting firm Chainalytics, agreed, but she added that she did not expect federal rules immediately. “I see them coming in five to 10 years. I think we are a long way from being able to control at the farm level.”
The road to lower carbon in food and fuel begins on the land, whether a few hundred acres in a small farm or thousands of acres in a corporate farm.
“IRA provides unprecedented funding levels targeted to improve soil carbon; reduce nitrogen losses; [and] reduce, capture, avoid or sequester carbon dioxide, methane or nitrous oxide emissions associated with agricultural production,” NRCS said in an initial request for comments.
Partnerships for Climate-Smart Commodities
Key to the success of the new programs is a long-practiced NRCS “ground up” approach to encourage buy-in from small farmers and ranchers.
USDA describes its existing Partnerships for Climate-Smart Commodities as an effort to help farmers and ranchers in 30 states align agricultural conservation practices with the growing market demand for food grown or raised in a climate-friendly environment. NRCS has awarded $2.8 billion in initial grants to 70 projects through the program.
The broad initiatives — including the availability of new climate-smart financing, new efforts to reduce livestock methane emissions, an emphasis on increasing individual farm participation in carbon sequestration techniques and the overarching emphasis on local involvement — have already caught the attention of existing trade organizations, as well as entrepreneurial farmers and ranchers.
Jared Knock, AgSpire | AURI
One such entrepreneur who has embraced sustainable practices and won initial USDA funding is Jared Knock, a college-educated, 25-year South Dakota farmer and rancher and employee at Millborn Seeds, the nation’s largest supplier of cover crop and grass seeds.
Knock and his associates at Millborn created a second company, AgSpire, three years ago to promote cooperation between farmers and ranchers to improve grazing land, encourage growth in cover crops and reduce the over-reliance on synthetic fertilizers.
In a January webinar produced by AURI, Knock said AgSpire’s team includes agronomists and grazing specialists to advise ranchers about soil-building management and the best seed mixture of regenerative grasses and cover crops for fields temporarily taken out of grazing.
The company also has developed a program to assist farmers who want to produce low-carbon corn as a feedstock for low-carbon fuel, Knock said.
The impact of corn production on the environment could be sharply reduced by replacing diesel fuel, using renewable nitrogen fertilizer and replacing the fuel used to dry the harvest. | AURI
AgSpire is a partner in five projects receiving initial USDA grants, including one focused on improving ranch grazing lands with extensive use of rotating cover crops; one to produce low-carbon aviation fuels; another to sell climate-smart, low-climate-impact feed corn; and a project to expand the production of low soil-impact seed grains.
“We are a segue between the farmer and rancher and helping them to understand what opportunities they have,” he said. “We are also working with [food] companies to understand how to engage with the farmers and put programs into practice. The Climate-Smart Commodities application process was a good opportunity.”
The program is also focused on engaging food retailers.
Cameron Wallace, Land O’ Lakes | AURI
Cameron Wallace, an executive at Land O’Lakes subsidiary Truterra, said the company’s new climate-smart partnership with USDA will enable it to dramatically scale up its already extensive programs connecting farmers with retailers.
“Today we have over 2 million acres in our platform and over 53 local retailers. We feel like we are uniquely positioned to operate on a national scale and to help provide support and capabilities to ensure that growers can implement climate-smart practices, sustainably and in a profitable way that helps them improve their yields and their productivity as well,” Wallace said.
“Our goal through our climate-smart partnership with USDA is to continue to scale those programs to increase the capabilities and [market] access across the country, both in row crop operations, as well as livestock and dairy operations, to increase financial support and technical support [to farmers] … to enable the scaling of markets as more and more food companies are trying to meet their sustainability goals,” he said.
Scott Herndon, Field to Market | AURI
Field to Market, a D.C.-based alliance of growers, conservation groups, universities and agribusiness organizations, is already working on a national scale to create an agricultural supply chain based on sustainability. It has won a $70 million Climate-Smart grant.
“Our premise is that no one sector can achieve sustainability on their own,” said Scott Herndon, president of the alliance. “That is why we bring all sectors of the value chain together.”
He said the alliance’s financing programs — the basis of the USDA grant — have been designed “to incentivize the adoption of sustainable agriculture,” including “blended financing models or green bonds” offering reduced interest rates for sustainable production.
Ashley McDonald, National Pork Board | AURI
Ashley McDonald, assistant vice president for sustainability at the National Pork Board, which has also been awarded a Climate-Smart grant, said the pork industry is aiming to reduce its GHG emissions by 40% by 2030.
Reaching that goal involves enrolling as many of the nation’s hog farms as possible in an analytical study to develop best practices across the industry, using data from participating members, she said, adding that the board intends use its USDA grant in new financing programs to assist farms adopt sustainable practices.
Measuring the Carbon Impact of Sustainable Practices
The underlying assumption that adopting sustainable practices will reduce carbon dioxide and other GHGs will have to be measured, and agronomists are already trying to figure out how to do it.
Joel Tallaksen, University of Minnesota | AURI
One analytical tool that has been used is a life cycle assessment (LCA), a kind of accounting methodology designed to look at the environmental impact of a manufactured product, said University of Minnesota scientist Joel Tallaksen.
“LCA is very holistic, going from the extraction of resources all the way through production and end of life,” Tallaksen said. “Now, the nice thing about LCA is that it can examine multiple environmental issues. So, you can look at things like fossil energy greenhouse gases, but you can get very specific and look at some detailed topics.
“The biggest challenge in LCA work is getting data on different systems, especially in agriculture. Once you have all that data, then you can begin to model how that data is going to fit together. LCA is really an accounting methodology, and it focuses on noneconomic issues. So, we can gather a lot of data and use that data to look at environmental impacts and some of the other impacts the system might have,” he said.
Analytical tools used by manufacturers to calculate environmental impact are being used cautiously to as first step to estimate agriculture’s climate impact. | AURI
That is the way the tool is used in manufacturing. Agriculture is a bit trickier, Tallaksen said. “Agriculture deals with biological systems, and they’re very different from going into a factory that’s making staplers. …
“But when you start dealing with biological systems, there are complex interactions that you must think about. In agriculture, you’re talking often about soil type, moisture [and] temperature,” factors that will determine how fast reactions occur, he said.
Another complexity in figuring agricultural emissions is that often the impact of a crop must be allocated to a number of commodities that are ultimately marketed,” he said. “If you find out there’s a certain amount of greenhouse gas being produced, but it’s going into two different products, you have to figure out how to divide that impact between the two products,” he said.
New Jersey regulators on Monday cut the incentive for residential solar and increased incentives for some non-residential projects after a report on the first year of the program showed that non-residential installations had failed to meet agency targets even as residential projects surged.
The state’s Board of Public Utilities (BPU) approved a $5 reduction in the incentives for net-metered residential projects, to $85/MWh, after the report found that registrations in the segment were on track to far exceed the 150 MW of capacity allocated to the program, which is part of the Administratively Determined Incentive (ADI) program. BPU staff concluded that all the capacity allocated to the program would be subscribed by the end of January, four months before the end of the program year, leaving plenty of demand unsatisfied.
The board voted to increase the incentives in four segments on the non-residential side after the report found that by mid-February only 55% of the 287.8 MW of capacity allocated had been subscribed.
To stimulate development, the board increased the incentive for small net-metered rooftop, carport, canopy and floating solar projects from $100/MWh to $110/MWh and raised incentives on net-metered ground projects from $85/MWh to $90. The agency also increased the incentive on net-metered non-residential rooftop, carport, canopy and floating solar projects of size between 1 MW and 5 MW from $90/MWh to $100/MWh. It increased the incentive for non-residential ground projects in the same capacity size category from $80/MWh to $85/MWh.
Before the unanimous vote, BPU President Joseph L. Fiordaliso expressed hope that the changes would help “maintain the level of activity for our solar industry.”
“I view this as an initiative that will maintain the robust activity of our solar industry,” he said. “And I think it’s extremely important to do that. We saw one segment not doing as well as we would like, and therefore (that led to) the increase in the incentive.”
Solar Stimulants vs. Cost
The incentive restructuring is the latest effort by the state to shape a solar incentive that will boost development of new solar without placing an excessive burden on ratepayers. The BPU in 2020 closed its more than decade-old program amid criticism that the incentives were too generous. In June 2021 it created the Solar Successor Incentive Program (SuSI).
It had two parts: the ADI program, with incentives set by the BPU for residential and smaller projects; and the Competitive Solar Incentive (CSI), with incentives for grid-scale and larger projects set by competitive solicitation process.
The state’s ambitious solar goals, set out in Gov. Phil Murphy’s Energy Master Plan, call for New Jersey to install 5.2 GW of solar capacity by 2025, add another 7 GW by 2030 and reach a total of 17.2 GW by 2035. In 2021, Murphy signed the Solar Act, which directed the BPU to create a new program that would generate 3,750 MW of new capacity by 2026, or 750 MW a year.
Reaching that goal is still a way off. The sector had a strong year in 2022, adding 432,241 kW of new capacity, the second highest total in the last eight years, after 453,217 kW in 2019, according to BPU figures. The state, with 4.29 GW of solar capacity installed at the end of 2022 — in 160,375 projects — would hit the 2025 target if it continues at the same pace of installation as in 2022, but it would need a dramatic increase to reach the 2030 goal.
In the review of the first year of the ADI, the BPU order concluded that “without action, the ADI program is likely to fail to meet the targets established by the Solar Act of 2021.”
While BPU officials believe the figures show the sector is ramping up capacity installation, solar developers have argued that the surge in installation in 2022 was set in motion in 2021, before the ADI program was put in place. The state at that time offered incentives through the temporary Transition Incentive (TI) program, which closed when ADI opened. Developers have argued that some of the increase in capacity in 2022 stemmed from developers rushing to register projects in 2021 under the higher TI incentives before the program closed. (See Solar Industry Pushes for Bigger Incentives from NJ Program.)
The ADI program included a requirement that the BPU conduct a review of the program’s first year, which showed the residential sector was oversubscribed. The BPU reallocated 100 MW of available capacity from the non-residential segment to the residential segment to “avoid impending oversubscription” of the latter, the board order said.
Inflationary, Supply Chain Pressures
Solar sector representatives at a hearing in December urged the BPU not to respond to the oversubscription of capacity in the residential market by reducing the incentive levels. Several industry trade groups argued that “apparent increases in the pace of registration in the residential sector have more to do with a catch-up in processing a backlog in applications than a real increase in activity,” according to the BPU summary of the December meeting that is part of the board order approved Monday. Reducing incentive levels would harm the residential sector, they argued.
On the non-residential side, trade associations said they believe that “the relatively slow uptake in the non-residential net metering market segment is a direct indication that current incentive levels need to be increased, particularly in light of rising costs,” according to the board order. A representative of the Solar Energy Industries Association told the December meeting that costs for commercial installations have increased 15% while residential costs have gone up 12%, largely due to shipping constraints and other supply chain issues stemming from the pandemic and trade instability.
The BPU, in its order, agreed that rising costs were an issue and that something had to be done to assist the sector.
“The non-residential market segment is tracking at approximately two-third of the board’s target,” the board order said.
“The board sees clear evidence that the inflationary and supply chain pressures of 2021 and 2022 have depressed participation in the non-residential market segments of the ADI program,” the order added. “The board attributes this fall off to the fact that reported costs for installed solar facilities have increased significantly over the past 18 months since the board established the ADI program, largely driven by the record high levels of inflation.”
LANSING, Mich. — Community solar projects would be legal and regulated by the Public Service Commission under a bipartisan package of two bills introduced in the Michigan Senate this week.
Enacting a community solar system in Michigan, where local projects would be open to both homeowners and businesses, has been a major goal for many environmental and energy activists in the state. With Democrats in control of both the Senate and House for the first time in 40 years, and with solar projects winning favor in rural, mostly Republican areas of the state, observers believe the legislation has a good chance of passing and being signed into law by Gov. Gretchen Whitmer (D).
SB 152 was introduced by Republican Sen. Ed McBroom, who represents the Upper Peninsula, where home solar projects have been growing in popularity. SB 153 was offered by Sen. Jeff Irwin (D), who represents Ann Arbor, a college town that has led many alternative energy and climate change issues in the state.
While solar home projects have been growing in interest and popularity in the state, Irwin said many people still cannot access them because of cost, home design or other issues.
The bills were assigned to the Senate Energy and Environment Committee, but no hearings have been scheduled.
McBroom said utility customers should be able to “choose where their electricity is guaranteed.” The idea of guaranteed power is particularly sensitive to many state residents given the number of major outages electricity customers across Michigan have endured following several major ice and snow storms. (See related story, Consumers, DTE Energy on the Hot Seat over Michigan Outages.)
“These small-scale, local solar projects will be particularly useful to residents, providing an opportunity to independently produce energy for themselves and their neighbors and providing savings on energy bills for those who subscribe,” McBroom said.
Irwin said community solar projects will give businesses, homeowners, schools and churches the ability to connect to more affordable, locally produced electricity. According to the U.S. Energy Information Administration, electric bills in Michigan jumped by 15% from 2020 to 2022.
The bills are tie-barred, meaning one cannot take effect unless the other also passes.
The bills give the PSC one year to create community solar rules, after which projects could be established and set up with financing.
The bills also would bar utilities from eliminating community solar customers from a utility’s customer base and require them to connect projects to the grid. Utilities will be permitted to recoup “reasonable” interconnection costs.
NEW ORLEANS — MISO and SPP said Wednesday the Department of Energy has signaled that the grid operators and their state commissions can move forward with a full application for funding from the agency’s Grid Resilience and Innovation Partnerships (GRIP) program.
MISO Vice President of System Planning Aubrey Johnson said DOE urged the RTOs and their regulators March 3 to move forward in seeking funding for the $1 billion Joint Targeted Interconnection Queue (JTIQ) transmission projects.
“We were ‘strongly encouraged’ to bring a full application forward,” Johnson said during a panel at the Gulf Coast Power Association’s MISO/SPP Regional Conference.
MISO and SPP are collaborating on the DOE application that is led by the Minnesota Department of Commerce. The Great Plains Institute (GPI) is organizing stakeholders and coordinating the multistage GRIP application process. The organizations sent a concept letter to the DOE in mid-January that served as a preliminary application.
Matt Prorok, the Institute’s senior policy manager, said in an email that the organizations will begin working on a full application.
“We were excited to receive encouragement,” he said. “GPI, the Minnesota Department of Commerce, MISO, SPP and a number of other partners have been hard at work since January, and we look forward to submitting a full application in May.”
David Kelley, SPP’s vice president of engineering, said as soon as the first JTIQ is approved and its process memorialized, the RTOs will begin analysis creating a “JTIQ 2.0” portfolio. He said the second effort will focus on the southern portion of the grid operators’ seam, where MISO South meets SPP’s Arkansas and Louisiana footprint.
MISO has said DOE funding will not affect its and SPP’s plan to lay out a 90%/10% cost allocation methodology for interconnecting generation and load, respectively, for the JTIQ projects. (See “DOE Funding for JTIQs Won’t Affect Cost Allocation,” MISO, SPP Update Stakeholders on Joint Tx Planning.)
The first JTIQ portfolio is expected to support 28.6 GW of new generation on either side of the seam.
Johnson said he and Kelley “bristle” when they hear stakeholders question whether generation developers will bring forward enough projects to fund the first collection of JTIQ facilities.
“We’ve got over 100 GW in their queue,” Johnson said, pointing to Kelley and referring to SPP’s generator interconnection queue. “And we’ve got more than 200 GW in our queue. … We think this is going to fill up rapidly.”
Kelley said once-obvious regional differences between grid operators are shrinking. He said all are experiencing renewable energy growth, baseload generation retirements, rising electrification and green hydrogen developments. “The pace of change is absolutely incredible,” he said.
While utility commissioners are concerned about variable energy generation when it comes to resource adequacy, it’s extreme weather that’s really keeping them up at night, speakers said during a webinar hosted by WECC.
During the March 2 webinar, part of WECC’s monthly resource adequacy discussion series, panelists explored myths and realities of resource adequacy. The first potential myth discussed was whether the rising volume of variable generation is playing a major part in resource adequacy concerns.
California’s duck curve, in which solar energy drops off at the same time electricity demand is peaking in the evening, was cited as an example of variable generation.
For panelist Eric Blank, chair of the Colorado Public Utilities Commission, the problem of variable generation is increasingly “understood, quantifiable and capable of solution.”
But extreme weather events, ranging from heat waves to winter storms, haven’t been consistent with past weather patterns and are a “new world,” he said.
“I think it’s less a variable generation problem and much more an extreme weather and correlated outage problem,” Blank said. “That’s what keeps me up at night.”
Panelist Mary Throne, a commissioner on Wyoming’s Public Service Commission, said variable generation does play a role in RA. Combined with extreme weather, she said, the two issues keep her up at night.
Another issue is to what extent extreme weather events, previously considered to occur with low probability, should be factored into resource planning.
Branden Sudduth, vice president of reliability planning and performance analysis at WECC, explained that in the past, planning revolved around determining the hour of peak demand in a given year. The thinking was that if demand in that peak hour could be met, resources would be adequate the rest of the year.
Now, Sudduth said, planners are starting to change their approach.
“People are recognizing the need for more of the stochastic planning,” Sudduth said. “Looking at a wide range of generator availability conditions and then coupling that with a wide range of demand conditions as well. And then using those stochastic models to help us identify specific hours of the year when demand might be at risk.”
But cost is also a consideration when planning for extreme conditions.
“We have to ask the questions, … see what happens in extreme conditions and correlated unit outages,” Blank said. “But the question, ‘Do we incur the cost to manage to those scenarios?’ is a much more difficult question [without] obvious answers.”
Electrification is another piece in the puzzle.
“You have to consider it in terms of changing weather patterns and increasing demand as we attempt to move toward more electrification,” Throne said, although she noted that electrification of vehicles and buildings was likely to occur slowly in Wyoming.
Another potential misconception panelists discussed was whether an organized market, such as a Western RTO, will be the solution to resource adequacy issues.
Throne said the impact of an organized market is still unknown.
“We are going to move incrementally, and whether we ever get to a full RTO remains to be seen,” Throne said.
Blank said an organized market isn’t going to solve every problem, but it has the potential to accelerate transmission expansion and lead to better regional planning.
“If it’s done right, it could produce a lot of benefits,” he said. “And if we screw it up, it could create a mess.”
