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November 7, 2024

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NJ Hikes Non-residential Solar Incentives After Registration Lags

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.”

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Bipartisan Community Solar Package Introduced in Michigan Senate

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.

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DOE Clears JTIQ Projects to Proceed with Funding App

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.”

Full GRIP applications are due May 19. Approved projects could potentially be awarded a 50% project match. (See DOE Opens Applications for $6B in Grid Funding.)

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.

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Extreme Weather a Key RA Concern, Western Commissioners Say

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.”

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Consumers, DTE Energy on the Hot Seat over Michigan Outages

Lansing, Mich. — After a month’s worth of weather-related outages that affected as many as 1 million customers across Michigan, the state’s two largest utilities are facing inquiries into why so many of their customers were left in the dark and why it took so long to restore power.

The Michigan House Energy, Communications and Technology Committee will hold a hearing March 15 looking into massive outages that primarily struck utility customers of Consumers Energy (NYSE:CMS) and DTE Energy (NYSE:DTE) over two consecutive weeks in February and the first days of March.

The Senate Energy and Environment Committee also is planning a hearing on the outages, but a list of witnesses has not been completed nor has a date been set, according to an aide to Chair Sean McCann (D).

In addition, the Public Service Commission soon will issue a request for proposals from third-party outlets to audit CMS and DTE regarding their ability to handle storms and respond to outages. The audits, ordered in October, could take a year to complete.

While customers of other utility systems — including the Lansing area’s municipal utility — also lost power during the series of storms, most of the affected residents were customers of Michigan’s two largest utilities, CMS and DTE.

As many as 1 million customers were left without power after a major ice storm hit the state on Feb. 22. Another ice storm hit on Feb. 27, knocking out power to some who had earlier lost service and had it restored; it also affected a new batch of customers.  A week later, a major snow and windstorm knocked out power to another 200,000 customers, most of those DTE customers in the Detroit area.

Social media accounts across the state were filled for several weeks with outrage over the delays in having service restored. Many customers went more than a week without power, a situation that drew national attention. Affected customers complained that they pay some of the highest utility rates in the Midwest while enduring some of the worst service in the nation.

DTE Energy Line Workers (DTE Energy) Alt FI.jpgDTE Energy called on more than 3,500 field workers to restore power from damage caused by a storm that had 15 cities in Southeast Michigan declare snow emergencies in early March. | DTE Energy

 

Michigan ranked 46th among the states and the District of Columbia in reliability, according to a 2022 report by the Citizens Utility Board of Illinois that compared the average duration and frequency of outages along with average time to restore power.

The winter outages especially infuriated DTE customers who for several years have suffered blackouts following major wind and rainstorms during the summer.

In Ann Arbor, which along with the rest of Washtenaw County was hard-hit by outages, a city council member introduced a resolution calling on the legislature to help local communities be better prepared and more resilient against outages. The resolution, introduced by Ayesha Ghazi Edwin, urged the legislature to approve bills creating community solar systems as well as letting communities invest more in renewable energy and electric storage systems. The council has not yet acted on the proposed resolution.

Rep. Helena Scott (D) told the Detroit News that the House hearing will look into what needs to be done to prevent future outages.

“We cannot and will not simply accept that this is our new normal,” Scott said. “The power grid and associated infrastructure must be reinforced, updated and improved so that residents are safe, warm and receive the services they pay for.”

PSC Chair Dan Scripps will be one of the witnesses expected before the House committee hearing. The committee has not yet released a list of witnesses, but a spokesperson for CMS said the company’s senior vice president of engineering and vice president for electric operations will be speaking.

PSC spokesman Matt Helms said the audits are needed because “over the last couple of years, the commission has been aware that Michigan’s electric utilities are facing significant new reliability challenges as the state sees increasingly severe and frequent storms.”  

Helms said the audits were the first time the PSC had undertaken such a comprehensive review of the utilities’ systems.

CMS spokeswoman Katie Carey said the utility is spending $5.4 billion over five years to strengthen its grid and reduced customer outages by 20% last year. “We understand the frustration that people are feeling after the historic ice storm, and this strengthens our resolve to do better,” she said. “We are open to ideas from the Michigan Public Service Commission, policymakers and others.”

DTE spokesman Peter Ternes said the company has spent more than $5 billion rebuilding its grid over the last five years and plans to increase its spending to $9 billion over the next five years. “DTE looks forward to appearing before the House and Senate energy committees to discuss our shared goals of improving reliability, delivering cleaner energy and maintaining affordability for our customers,” he said. “Our customers deserve a reliable electric grid, powered by cleaner energy.”

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Co-op Leaders Share Reliability Concerns

Supply chain issues, the trend toward electrification and cyber and physical security all weigh on the minds of the nation’s electric cooperatives, CEOs of several co-ops said in a media call Tuesday.

The CEOs were gathered in Nashville, Tennessee, for the annual meeting of the National Rural Electric Cooperative Association (NRECA), whose members say they supply energy to 42 million consumer-members across 48 states. NRECA CEO Jim Matheson said that the co-ops’ member ownership model gives them “a particularly consumer-centric view on how we do our jobs” and a unique incentive to ensure reliable service.

Attendees acknowledged that many reliability challenges are common across all types of utilities, but said the issues are often more acute for co-ops, which can have limited resources compared to larger investor-owned utilities. The growing wait time to obtain spare parts is one such area. Pointing to the spread of electric vehicles and the increased use of electricity for heating and cooking, Electric Cooperatives of Arkansas CEO Buddy Hasten warned that shortages could cripple operations just as the grid is needed most.

“We’ve always been responsible — all utilities, not just co-ops — about keeping spare inventory. But we’re chewing through that spare inventory, and we can’t restock it fast enough,” Hasten said. “I think there [are] starting to be some real chinks in the reliability wall, where [if] the right storm, the right set of conditions comes in, all of a sudden, you may go to the cupboard, and it’s bare.”

Matheson added that the rising consumer demand, paired with the ongoing replacement of conventional generation sources with renewable energy, has also made it essential to install new electric infrastructure as quickly as possible to deliver the intermittent power rapidly to where it is needed. Yet that the permitting process for new construction still does not move as quickly as utilities need, he said.

“I think the electrification push in this country, and retirement of existing assets, shines a much brighter light on the challenges of the permitting delays we face as a sector,” Matheson said. “For decades, people thought that we need streamlined permitting, we need permitting that works better. This time we really do. We need a predictable process — not that we want to skirt any rules, but something that’s predictable and that’s reasonable.”

The conversation also touched on preparations for cyber and physical security in light of recent high-profile incidents involving electric infrastructure, such as the Moore County, North Carolina, substation attacks in December that left 45,000 customers without power for days. (See Duke Completes Power Restoration After NC Substation Attack.) Matheson acknowledged that hardening infrastructure can be daunting because “there’s not a one size fits all.”

Duke Energy substations (FBI) Alt FI.jpgThe Duke Energy substations in Carthage (left) and West End, N.C., that unidentified attackers shot on Dec. 3, 2022, leading to the loss of power for around 45,000 customers in Moore County. | FBI

 

“Every location is different, and for physical security, a substation in location A, compared to B, compared to C, there may be different mitigation efforts you could deploy to create greater physical security at that particular location,” Matheson said. “So, the advice that we’ve heard — and this is the investor-owned [utilities], the [municipals], the co-ops … is you really have to do a thoughtful, asset-by-asset inventory of your system, and determine in each case what the relative risk is and what the potential opportunities are to mitigate risk at that physical location.”

Chris Jones, CEO of Middle Tennessee Electric, said that while his organization has made substantial investments in cybersecurity, there’s no way to know if it was enough. He said that one of the benefits of trade organizations like NRECA is the opportunity to collaborate and share approaches to common problems.

“There’s no end to the amount of money you could spend, [so] we’ve got to weigh this out — what’s the risk, versus how much can we reasonably invest to mitigate those risks?” Jones said. “I think one of the great benefits of the electric cooperative network is our ability to share information and ideas with each other. … These are very difficult and challenging questions, but I take comfort in the fact that I have peers across the country that I can share notes with, and we’re going to do our best to figure it out.”

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DOE Announces $6B for Industrial Decarbonization

The U.S. Department of Energy on Wednesday announced $6.3 billion in funding to decarbonize energy intensive industries such as aluminum, steel and cement plants, with the White House calling the new grant program the “largest investment in industrial decarbonization in American history.”

The funding is intended to “accelerate decarbonization projects and provide American industry a once-in-a-generation ‘first mover’ advantage in the emerging global clean energy economy,” a White House fact sheet published Wednesday said.

“Widespread demonstration and deployment of decarbonization projects within these industries is key to achieving [President Biden’s] goal of a net-zero carbon economy by 2050 and will help strengthen and secure America’s global leadership in manufacturing for decades to come,” it said.

The new Industrial Demonstrations Program, funded by the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, will “focus on the highest emitting industries where decarbonization technologies will have the greatest impact,” DOE said in a news release.

Other industries that will be eligible for awards include chemicals and refining, food and beverage, and forest products and paper, the agency’s Office of Clean Energy Demonstrations, which will administer the grants, said on its program page. In addition to industry, grant recipients can include technology developers, universities and state and local governments, among others, OCED said.

In its funding notice, the office said it expects to make up to 55 awards of $35 million to $500 million each, with a minimum 50% cost-sharing by awardees. Priority will be given to projects that “offer deep decarbonization, timeliness, market viability and community benefits,” it said.

“Industrial emissions account for roughly one third of the nation’s carbon footprint, and the industrial sector is considered one of the most difficult to decarbonize due to the diversity of energy inputs, processes, and operations,” OCED said. “The sector’s emissions result not just from fuel for heat and power, but also from feedstocks and processes that are inherently carbon intensive.”

The latest effort is part of the Biden administration’s push to reduce emissions from “across the industrial sector, including by demonstrating decarbonization projects at scale in this decade — solutions that had previously seemed decades away,” DOE said in a news release.

“Widespread demonstration and deployment of decarbonization projects within these industries is key to achieving the President’s goal of a net-zero economy by 2050 and will help strengthen and secure America’s global leadership in manufacturing for decades to come,” it said.

Buy Clean

The Biden Administration is also trying to build a larger market for low-emissions products. It published updates Wednesday to its Buy Clean Policy, including the start of a new federal-state partnership.

The administration launched the Federal Buy Clean Initiative last year to “leverage the $630 billion of annual purchasing power” by the federal government — the “largest direct purchaser in the world and a major infrastructure funder” — to increase the use of American-made, low-carbon materials in federal construction projects, it said.

Twelve states have joined that effort, it said.

“Today, the Biden-Harris Administration is launching the Federal-State Buy Clean Partnership with commitments from … leading states,” including California, Illinois, Michigan, New Jersey, New York, Oregon and Washington, it said. “These states have committed to prioritize efforts that support the procurement of lower-carbon infrastructure materials in state-funded projects, and to collaborate with the federal government and one another to send a harmonized demand signal to the marketplace.”

The Natural Resources Defense Council praised the administration’s moves in a news release Wednesday.

“With this $6 billion funding stream and other federal incentives like Buy Clean, American manufacturers have the opportunity to produce the world’s most competitive low and zero-carbon industrial materials,” Sasha Stashwick, NRDC’s director of industrial policy, said in the release. “These are the products buyers around the world will be seeking in the clean economy.”

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Washington’s 1st Cap-and-Trade Auction Nets Nearly $300M

Washington’s first cap-and-trade auction pulled in nearly $300 million in revenue, according to a summary report issued by the state’s Department of Ecology Tuesday.

All 6,185,222 allowances offered in the Feb. 28 auction were sold, clearing at a settlement price of $48.50. That was well above the floor price of $22.20 and “in the range” of an independent analysis commissioned last summer, the agency said in a statement after results were released.  Each allowance entitles a holder to emit one ton of greenhouse gases.

The auction summary showed that 56 companies, utilities and public institutions bid into the auction, but it did not indicate which bidders were successful. 

The Ecology Department is required to provide a final revenue report by March 28.

“This is truly historic for Washington and for the global movement toward a low-carbon future,” Gov. Jay Inslee said in the statement. “This cap-and-invest system is crucial to our approach to addressing climate change, and we are very encouraged to see this program starting off so well.”

“With the cap-and-invest program now fully underway, we can begin providing critical support for reducing emissions in our state and helping communities deal with and prepare for the effects of climate change,” said Ecology Director Laura Watson. 

Washington’s Democrat-controlled legislature in 2021 passed the law establishing the nation’s second cap-and-trade program — behind California — along party lines. Last year state agencies hammered out regulations to put that law into effect. 

The Feb. 28 auction was the first of four quarterly auctions to be held this year by the Ecology Department. 

In January, Washington officials told the state Senate Transportation Committee that the cap-and-trade auctions could raise almost $1.5 billion through fiscal 2024 and reiterated their view that a new low-carbon fuel standard will raise gas taxes by about one penny per gallon. (See Washington Estimates $1.5B in Cap-and-Trade Revenue Through 2024.) 

Later this legislative session, the state Senate and House plan to allocate revenue from the first cap-and-trade auction. The Ecology Department estimates $484 million in cap-and-trade revenue will be raised in fiscal year 2023 (July 1, 2023 to June 30, 2024) and $957 million in FY 2024.

The revenue from the auctions is expected to shrink over time as the number of emission allowances is reduced. Estimates are considered less reliable as they are projected farther into the future. The agency currently estimates $901 million in revenue for FY 2025, $730 million in FY 2026 and $592 million in FY 2027.

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MISO Reports Loss of Control Room Capabilities

MISO said it experienced a “complete loss of monitoring or control capability” at its control center last week, setting off short-lived energy imbalances.

According to the grid operator, the March 1 incident lasted about 41 minutes. It said it was administering routine quarterly maintenance on its energy management system (EMS) at midnight to update modeling. However, “issues with the update” sent incorrect dispatch signals to generation through the RTO’s automatic generation control tool.

MISO said the glitch led to an imbalance in its balancing authority and a Balancing Authority ACE Limit (BAAL) event. It said its area control error (ACE) reached as high as 2,000 MW, resulting in a 17-minute BAAL event.

The ACE then swung as low as -4,285 MW, resulting in a second BAAL event for 11 minutes, MISO said. It said it used “backup tools and processes” to regain the control room’s monitoring and control capability.

The grid operator said it reported the disturbance to the Department of Energy through the agency’s electric emergency incident and disturbance report (form DOE-417), which is used to collect information on incidents and emergencies. 

MISO said its backup plan included reverting temporarily to its earlier December model. It said the model worked as intended.

“We were able to address the incident in less than 15 minutes and move to our new model within a couple of hours, spokesperson Brandon Morris said in an emailed statement to RTO Insider. “We are reviewing the situation and will improve the processes under our new model manager and EMS systems.”

MISO is working to deploy a new EMS and a one-stop model manager that will serve as a single record for maintaining members’ modeling information. The RTO said it experiences redundant data entry and review because it lacks a unified modeling process for reliability, markets and planning. (See MISO Pivots to Models, Market Engines in New Platform Replacement.)

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DERs in Wholesale Markets Still Years Away

FERC has been working through compliance filings on Order 2222, but none of the ISOs or RTOs have yet to have aggregations of distributed energy resources actually participate in their markets.

The commission defines DERs as any resource located on the distribution system or behind a customer meter, or any subsystem thereof, said David Kathan, a former FERC staffer who worked on the issue and now runs his own consulting firm. Speaking on a webinar hosted Wednesday by the United States Energy Association, Kathan listed rooftop solar, community solar, electric vehicles, cogeneration facilities, distributed storage, demand response and others as potential DERs.

Load management and solar were the dominant DERs from 2015 to 2020, and they are expected to continue growing at a healthy clip but will be joined by additional resources ramping up deployments this decade such as EVs and storage, Kathan said.

Hawaii is ahead of most states on renewable deployments with a goal of getting to 100% renewables by 2045, and DERs will play a key role there, he said.

“I know Hawaii is not exactly, you know, the normal state in the United States; it’s islands,” Kathan said. “It has a different set of resources and challenges. And they like to call themselves a postcard for the future.”

Across the entire state, DERs could make up 15% of electricity by 2045, but they could be as high as 23% on the island of Maui. It is important for grid operators to have visibility into those resources, but that requires changes to how they have operated in the past.

“Many DERs, especially behind-the-meter resources, are too small to participate in wholesale markets,” Kathan said. “Most RTOs and ISOs have set a minimum offer size requirement of at least 100 kW.”

Individual DERs often do not have the capability, nor the interest, to participate in the markets, but they are happy to have aggregators do much of the work so they can get paid, he added.

“At present, no DER aggregations participate in wholesale markets … and will mostly have to wait until implementation of 2222 by the RTOs and ISOs,” Kathan said. “Most plan for effective dates for their participation between 2024 and 2026.”

MISO has proposed an implementation date of 2030, but that is still pending FERC approval. CAISO enacted its DER aggregation rules back in 2016, and many of the elements it set up then informed Order 2222. But even there, no DERs have participated in the wholesale markets yet.

“It is not necessarily a problem with the rules, and more having to do with issues that are still not resolved at the state level,” said Kathan. “And in particular, whether various resources, like DERs and demand response, are able to see resource adequacy credits has been a major issue on why there has not been as much participation.”

Getting the rollout of DERs and how they work on the grid right is going to be important when it comes to decarbonization efforts, said Omar José Guerra Fernández, of the National Renewable Energy Laboratory.

Much of the discussion has been on how to decarbonize the power sector, “but then we also need to decarbonize the industrial transportation and building sectors,” said Guerra Fernández. “And, in my opinion, this is the place where the DER group will play a significant role.”

DERs will help ensure that cars are charged up when the grid is producing clean power, providing a key cross-sectoral role in decarbonization, he added. It will also help decarbonize the building sector in ways that central station renewables are not capable of by adding distributed generation, heat pumps and other technologies that can ensure buildings do not produce greenhouse gases.

“DERs are a variety of technology that will allow us to do this cross-sectoral integration of the energy systems to help achieve net zero by 2050, or maybe before,” Guerra Fernández said.