Search
`
November 12, 2024

Posted on

Ameren Files to Recoup Rush Island Closure Costs from Customers

Ameren Missouri appears to be making good on a two-year-old announcement to close its Rush Island coal plant, which has racked up multiple Clean Air Act violations over the years.

Last week, Ameren Missouri filed for permission with the Missouri Public Service Commission to use securitization to finance the closure of the plant through ratepayers (EF-2024-0021). The utility said it wants to wind down operations by mid-October next year to avoid installing sulfur dioxide scrubbers per a court order.

The financing option Ameren seeks is possible through a two-year-old Missouri law that allows utilities to securitize outstanding debt on their facilities to further the energy transition. If approved, Ameren would be free of Rush Island debt and free to invest in other generation, while investors paying the bonds would be guaranteed a return of 2% to 4%. The securitization would result in a new line item on monthly bills of $1.71 for the average residential customer for the next 15 years.

Ameren estimates it has more than $475 million of undepreciated investment in Rush Island today.

Despite the request for ratepayer-backed bonds to recoup plant investment, Ameren pledged customer bills would decrease with the earlier-than-anticipated retirement. It estimated customers would save $120 million over 15 years.

In its filing, Ameren said “costs of securitization are lower than traditional ratemaking” and concluded that “retirement of Rush Island instead of retrofitting the plant with expensive pollution control equipment is clearly in customers’ best interest.”

In testimony to the Missouri PSC, Ameren Missouri President Mark Birk said by the time the order from the U.S. District Court for the Eastern District of Missouri to scrub Rush Island became final, “circumstances had made the continued operation of coal-fired plants extremely challenging.”

He said EPA’s proposal to limit carbon emissions from existing coal plants poses “serious risks to the continued viability of these assets,” so installing hundreds of millions of dollars’ worth of scrubber equipment is unwise.

“Faced with these realities, the only prudent option was to shut down Rush Island instead of adding scrubbers,” Birk said.

For resource planning purposes, Ameren long assumed the 1.2-GW plant would retire sometime in 2039.

The embattled coal plant has been at the center of a yearslong legal battle over its emissions. In 2007 and again in 2010, Ameren replaced boiler components at Rush Island that upped output without completing a new source review as required under the Clean Air Act, triggering a lawsuit from the Sierra Club and an eventual court order to install pollution controls or shut down.

Birk said the securitization of the cost of retirement for Rush Island is appropriate because Ameren made “prudent decisions” when making investments in the plant. He argued that at the time, the boiler upgrades were viewed as routine and completed by other utilities without a new source review.

The District Court in late September approved Ameren’s decision to retire the plant in October 2024. It previously said the plant should cease operations in March.

Whether Rush Island can retire by October is unclear. Ameren itself cautioned in its filing the new retirement date could change.

The plant has been operating for more than a year under a MISO-designated system support resource (SSR) agreement, used to keep generation operating past planned retirement dates for the sake of system reliability.

MISO last year deferred Ameren Missouri’s planned retirement of Rush Island to keep the grid reliable. The utility pulls in a FERC-approved $8.3 million monthly payment to keep the two-unit Rush Island Energy Center operating (ER22-2721). (See FERC Approves Lower MISO Reliability Payments to Ameren Coal Plant.)

In early summer, MISO said it likely will require the assistance of Rush Island for nearly two more years to avert voltage violations until members complete transmission upgrades and bring wind, solar and battery storage projects proposed in Illinois and Missouri online. The RTO previously said it plans to renew the SSR once more in 2024. (See MISO Poised to Extend Missouri Coal Plant’s Life.)

However, MISO spokesperson Brandon Morris said MISO’s tariff cannot override a federal court order; “therefore, Rush Island must cease operation on this date.”

“MISO will follow its tariff in determining if the existing SSR contract can be extended or if a new SSR contract can be issued for the period between Sept. 1, 2024, when the existing SSR contract expires, and this Oct. 15, 2024, date,” Morris said.

MISO declined to comment on whether it sees a need to request an extension of the SSR and didn’t elaborate on whether it expects enough new generation and system upgrades in place by the third quarter of 2024 to take the two coal units’ place.

The Missouri Public Service Commission has set a Dec. 15 deadline for those wishing to intervene in the case.

Posted on

Lamont Withdraws Connecticut’s 2035 EV Mandate

In a setback for Connecticut’s electric vehicle goals, Gov. Ned Lamont (D) has withdrawn regulations that would have required all new vehicles sold in the state to be non-emitting by 2035, in line with California’s emissions standards. 

The regulations were facing rejection from the legislature’s Regulation Review Committee, with members of the committee expressing concern about affordability and the development of adequate charging infrastructure. 

In a press conference following the withdrawal of the regulations, Democratic leaders expressed their disappointment with the “speed bump” while vowing to work to find a workable solution that would satisfy concerns about cost and infrastructure while maintaining strong electric vehicle goals. 

“We do not want to be left behind as a state,” said Sen. Christine Cohen (D), co-chair of the joint Transportation Committee. She added that there is “no plan to do away with the ban altogether.” 

Lamont stressed the importance of the regulations and said he will work with members of the legislature to address their concerns. 

“Is Connecticut going to be the first state to renege on a commitment we made on a strongly bipartisan basis just two years ago, and on a unanimous basis back about 20 years ago?” Lamont said. The state first aligned its emissions regulations with California in 2004. 

Lamont added that predictable regulations combined with incentives and economies of scale will continue to bring down the costs associated with EVs. 

“This is how you make it affordable,” Lamont said. “Changing our minds will take us in the wrong direction.” 

Katie Dykes, commissioner of the Department of Energy and Environmental Protection, highlighted the air quality benefits of rapidly reducing vehicle emissions. 

“Connecticut has some of the worst air quality in the country,” Dykes said. “Our kids and our vulnerable communities — especially environmental justice communities living near highways and industrial zones — are disproportionately experiencing asthma and respiratory illness, disrupted lives and high medical bills because of it.” 

Dykes noted that the majority of the air pollution generated in the state comes from vehicles, along with 40% of the state’s carbon pollution. 

“It will be nearly impossible for us to meet the state’s Global Warming Solutions Act targets of reducing greenhouse gas emissions 45% by 2030 without vehicle emissions standards in place,” Dykes said. EVs now make up about 10% of vehicle sales in the state, while charging port availability has increased by 30% over the past year, she said. “A pause in this momentum will make it harder to purchase an EV in Connecticut.” 

The move comes after a concerted lobbying campaign by the state’s oil industry to push legislators on the Review Committee to kill the regulations. At a press conference earlier in November, Chris Herb of the Connecticut Energy Marketers Association called the regulations “too much, too soon.” 

“These regulations will increase the cost of gasoline, diesel, electricity and virtually every product and service across the state,” Herb said. 

Looking forward, legislative leaders said they are hoping to work quickly with lawmakers to come to an agreement on new legislation setting strong vehicle emissions mandates. 

Lamont said the legislature could give itself more oversight and the ability to review and change the regulations in the future if the state proves to be unable to support the transition to EVs under the proposed timeline. 

“I think that may get us over the finish line,” Lamont said. 

Senate President Martin Looney (D) spoke in favor of “a review process every few years” to account for the pace of technology improvement and the development of EV infrastructure. 

“We will be having caucuses and move forward with what we hope will be a consensus bill that can pass both chambers and that the governor will sign,” Looney said. 

Beyond the emissions mandates, Looney said the state needs to take significant steps to address affordability and infrastructure concerns. He said the state will need to allocate more funding for chargers and tax breaks for vehicle purchases. 

“That has to be factored into our revenue structure,” Looney said. He added that the state will need “additional revenue in order to do that, as well as to meet all of the other existing needs. … This becomes part of an overall discussion on overall policy.” 

Posted on

PJM Restructuring Executive Team

PJM is restructuring its executive team, the RTO announced Nov. 28, promoting Stu Bresler to executive vice president of market services and strategy and creating two new positions.

“Over the years, Stu has helped build many of PJM’s markets and has made sure all of PJM’s markets are supporting the mission of reliability at the least cost for consumers,” CEO Manu Asthana said in a statement. “PJM and its stakeholders have come to rely on his expertise, diligence [and] leadership and his willingness to listen to all viewpoints that can help PJM ensure a reliable energy transition.”

Bresler started at PJM as a professional engineer in 1994 and was subsequently responsible for implementing its demand response program. He now oversees the operations of all PJM markets.

“I have seen the power of competitive markets to reinforce grid reliability while controlling costs for consumers and attracting investment in cleaner and more cost-effective generation technologies,” Bresler said in the statement. “It is a real honor and privilege to be able to help PJM ensure the reliable delivery of electricity through the current transition as our region moves toward a lower-emitting generation fleet.”

PJM has also established a new chief security officer position, which Steve McElwee, a 15-year PJM veteran who currently serves as chief information security officer, will fill Jan. 10. Along with his current responsibilities for cybersecurity, McElwee will have oversight of business continuity, facility services, physical security, and identity and access management.

PJM Chief Information Security Officer Steve McElwee | © RTO Insider LLC

“Steve’s cyber experience in his current role, coupled with his experience supporting business continuity and recovery, physical security tactics and NERC [Critical Infrastructure Protection standards] compliance, will add tremendous value to the PJM security program,” Asthana said. “He has put his stamp on the industry for his ability to heighten awareness and educate employees and stakeholders on security risks and practices.”

“The landscape of threats aimed at the electrical grid continues to increase exponentially, and I’m committed, along with PJM, to meeting this challenge with the resources necessary to keep power flowing for the 65 million people we serve,” McElwee said.

McElwee will report to another new position, the RTO said: the executive vice president of operations, planning and security. The hiring process will be handled by Preng & Associates, with the goal of having the position filled by the second quarter of next year. Until then, McElwee will continue to report to Chief Information Officer Thomas O’Brien.

“This important role will continue to focus on reliability, planning for the grid of the future and operational excellence. In addition, it combines physical security, cybersecurity, enterprise information security, IT compliance, business continuity, and security engineering and architecture in a new division,” PJM said.

The changes are the latest in a series to PJM leadership. This month, the RTO named Paul McGlynn to replace Ken Seiler as vice president of planning following Seiler’s retirement April 1, 2024. McGlynn will report to Seiler until then. Seiler will remain with PJM through the end of next year in a consulting role “to transition his duties in a seamless manner,” the RTO said.

Posted on

Salton Sea Could Supply Lithium Needs for Decades, Study Finds

The Salton Sea region of Southern California could produce enough lithium for more than 375 million electric vehicle batteries, potentially releasing the U.S. from its dependence on foreign sources of the key mineral, according to a new report. 

In fact, the region, which has been dubbed Lithium Valley, may have enough lithium to allow the U.S. “to meet or exceed global lithium demand for decades,” according to the Department of Energy, which funded the study. 

The analysis was led by researchers from Lawrence Berkeley National Laboratory. DOE called it the most comprehensive assessment so far of the area’s lithium potential. 

“This report confirms the once-in-a-generation opportunity to build a domestic lithium industry at home while also expanding clean, flexible electricity generation,” Jeff Marootian, DOE’s principal deputy assistant secretary for energy efficiency and renewable energy, said in a statement. 

Imperial County, Calif., is the site of the Salton Sea Known Geothermal Resource Area (KGRA). Geothermal brines that are a byproduct of geothermal electricity generation in the area have been found to be rich sources of lithium. 

Lithium is a key component of EV batteries and is also used in battery energy storage systems, which are playing an increasingly important role in decarbonizing electricity production. But currently, the U.S. must import nearly all the lithium it needs. 

The 11 geothermal power plants now within the KGRA have a combined capacity of about 400 MW. That’s just a fraction of the estimated 2,950 MW in potential geothermal capacity in the area, “leaving extensive room to increase geothermal electricity generation while accessing more of the region’s available lithium resources,” according to DOE. 

The Berkeley Lab researchers projected that the geothermal brines in the area could yield 3,400 kilotons of lithium — enough for 375 million EV batteries, which is more than the number of vehicles now on U.S. roads. 

Those findings assume the entire Salton Sea geothermal reservoir could be accessed for electricity production and that lithium could be fully extracted from the resulting geothermal brines. 

Three companies that are building or operating power plants in the area — Berkshire Hathaway Energy Renewables, EnergySource and Controlled Thermal Resources — are planning to use direct lithium extraction technology to recover lithium from the geothermal brine, the report said. 

The Berkeley Lab analysis also looked at potential impacts of geothermal power plants and lithium extraction on air quality, water resources and seismic activity. 

“The analysis illustrates that if these things are done properly, lithium development is not likely to create significant negative environmental impacts,” the researchers said. According to DOE, direct lithium extraction from brine requires 99% less water per ton of lithium than current mining procedures and emits almost no CO2. 

But the researchers acknowledged that the impacts of lithium extraction on waste production “will require attention moving forward.” 

For example, they said, the role of battery recycling in a potential battery supply hub is a topic that could be further evaluated. 

“Recycling these batteries could complement and perhaps ultimately replace raw material extraction as a source of lithium, making the industry more sustainable in the longer term,” the report said. 

The Berkeley Lab analysis comes after the California Energy Commission convened a panel known as the Lithium Valley Commission, which met during 2021 and 2022 to consider issues related to lithium extraction in the state. Assembly Bill 1657 of 2020 called for formation of the commission. 

The commission made several recommendations in a final report released in December 2022. Those included increased state funding for research and development, support for start-up companies and public-private partnerships to promote development of a circular lithium economy in California. 

Another recommendation was to accelerate investment and upgrades in transmission for geothermal power plants in Imperial Valley to be online starting in 2024. 

Posted on

Western RTO Group Seeking $800K in DOE Funding

The group working to lay the foundation for an independent Western RTO is seeking $800,000 in federal grants to support its administrative and outreach needs.

The West-Wide Governance Pathways Initiative (WWGPI) explained its need for the money in a concept paper accompanying the application it submitted in response to a Department of Energy Funding Opportunity Announcement (FOA). The group is applying for $400,000 in annual funding over two years.

“This funding is necessary for major Pathways support functions — development of informational materials; outreach to key stakeholders; regular convenings through virtual and in-person gatherings; and facilitation to ensure meaningful participation by those who wish to engage,” the group said in the concept paper, which it distributed to stakeholders Nov. 22.

The Washington State Department of Commerce submitted the DOE application on behalf of the WWGPI on Nov. 17, Kathleen Staks, executive director of Western Freedom and co-chair of the group’s Launch Committee, told RTO Insider. Regulators from that state, along with Arizona, California, Oregon and New Mexico, proposed the initiative in July. (See Regulators Propose New Independent Western RTO.) The grant application process closes Jan. 19, 2024, Staks said.

The concept paper describes other uses for the grants, including “leadership, staffing, virtual meetings and administrative support;” four in-person meetings per year; and funding for 50 people to attend those quarterly gatherings.

The FOA funding will be “essential to performing outreach to states and groups not yet aware of, or able to participate in, the new nonprofit independent governance entity envisioned by” the founders of the initiative and make its processes more accessible to a broader set of stakeholders, the group said.

The federal dollars also would support creation of an independent website, “which is a critical component of communication and success,” the group said. The WWGPI website currently is being hosted by the Western Interstate Energy Board. The concept paper notes that grants also could pay for other “in-kind resources” now provided by the group’s Launch Committee and other stakeholders.

“It is impossible to overstate the importance and impact of DOE funding for the essential work of the Pathways Initiative; without these resources, broad-based engagement efforts will not be viable,” the paper states. “Funding is necessary for a complete range of activities that can contribute to an increased degree of agreement that can offer lasting success.”

‘Keep Cranking’

The Launch Committee discussed the WWGPI’s financial needs during a Nov. 17 virtual public meeting.

Critics say the initiative lacks transparency, especially around its sources of funding. (See Idaho PUC Declines to Join Western RTO Governance Effort.)

During the meeting, Jim Shetler, general manager of the Balancing Authority of Northern California and co-chair of the committee’s Administrative Work Group, acknowledged the need for an “unbiased” source of funding for the group as it seeks to create an entity to oversee an independent RTO that pointedly includes the West’s largest consumer of electricity, California, and leans on the services of the state’s biggest grid operator, CAISO. (See West-Wide Governance Pathway Group Digs into its Work.)

Shetler said any DOE awards likely would arrive in the middle of 2024 at the earliest, requiring the WWGPI to seek other interim sources of funding.

“We do know that there are some participants within the sectors that have indicated a willingness to consider offering some dollars to help seed some of the early efforts for this group. And then we’ve also done looking at outreach to foundations,” Shetler said.

Despite the WWGPI’s current lack of funding, the concept paper shows the group plans to proceed on an ambitious timeline as it moves to outpace SPP’s efforts around Markets+, the day-ahead market offering directly competing for members with CAISO’s Extended Day-Ahead Market. The Launch Committee expects to establish a nominating committee for a foundational board of directors in January 2024; identify, interview and seat members of the board in March; and establish a nonprofit entity in April.

The group is “committed to keep cranking on the work that we’re doing,” Staks said during the Nov. 17 meeting.

Posted on

FERC Wants More Detail on MISO Sloped Demand Curve Plan

FERC last week said it needs more description behind MISO’s plan to adopt sloped demand curves for its capacity auctions before it decides the matter.

Among the commission’s questions in its deficiency letter: a request that MISO better explain how its opt-out provision would work (ER23-2977).

MISO’s provision to allow utilities to opt out of the auction for three years at a time drew the most criticism based on stakeholders’ mixed reactions to the filing. (See MISO Stakeholders Split on Sloped Demand Curve Proposal.)

FERC ordered MISO to justify how its plan to impose a “X% adder” on load-serving entities that opt out constitutes comparable treatment between utilities. The adder would require load-serving entities (LSEs) to secure more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The adder would be based on how much excess capacity is procured through the auction using the sloped demand curve in previous years. FERC asked exactly how MISO would calculate the adder beyond the 2025/26 planning year, because MISO included detailed calculations only for the first planning year the sloped curve would be in play.

The commission asked MISO to shed more light on why LSEs electing to opt out of the auction would completely forgo the auction and not a portion of their resource adequacy requirements.

FERC was left curious as to how MISO would handle establishing planning reserve margin requirements (PRMRs), considering some LSEs would opt out and affect the remaining capacity requirements.

The commission also asked how MISO would establish PRMRs for LSEs in states that have overridden MISO’s planning reserve margin and how the opt-out provision would interact with the final figure. The commission said MISO’s tariff was silent regarding such circumstances and whether an LSE’s final PRMR would depend on its opt-out status.

FERC inquired after several other details around MISO’s proposal. It asked whether MISO would forgo an annual price cap or use a replacement annual clearing price cap for local resource zones. MISO proposed to remove its existing cost of new entry multiplied by 1.75 cumulative price cap on local resource zones when zones are in shortage or near-shortage conditions.

FERC also asked how MISO would line up the calculation of its cost of new entry with the calculation of the sloped demand curve.

The commission said it needed to know which components of MISO’s sloped demand curve would change every three years and which would be subject to change annually. MISO proposed to produce an entirely new sloped demand curve every three years after performing an analysis to see what’s changed in auction supply and demand.

Finally, FERC asked MISO what unit of measure it would use to express marginal reliability impact curves.

MISO’s sloped demand curve shape relies on marginal reliability impact curves, or the depiction of the diminishing reliability value of incremental capacity during abundant supply and the increasing importance of incremental capacity during scarce supply. FERC said it needed to know MISO’s schedule for determining both its marginal reliability impact curves and the resulting sloped demand curves.

Posted on

McAdams Says He Will Resign from Texas PUC

DFW AIRPORT, Texas — Public Utility Commissioner Will McAdams made public his intention to resign before next year during an SPP stakeholder meeting Nov. 28. 

Adams, whose departure has been rumored for several weeks, said his family and his health both became factors in his decision to step down. 

“This has been a challenging duty. I’ve enjoyed it, it’s been meaningful, but there were considerable pressures on both the family and the health,” McAdams told RTO Insider during a break in the SPP meeting. “None of those pressures looked to resolve themselves in the near term. I have a young family and I need to be more attentive to them.” 

McAdams and his wife have three children less than 10 years old. In addition to his responsibilities for the PUC, he also has chaired the Resource and Energy Adequacy Leadership (REAL) Team addressing SPP’s resource adequacy challenges and was elected last month to serve as president of the RTO’s Regional State Committee (RSC) in 2024. 

In his spare time, McAdams has taken on a greater role in managing his family’s ranch in Southeast Texas. 

“It’s multiple things all converging at the same time,” he said. “This decision has not been and was never going to be easy, but it’s been some of the most meaningful work of my life.” 

McAdams’ term on the PUC expires Sept. 1, 2025. His resignation will leave the five-person PUC with two vacancies. Peter Lake resigned as chair in June and has been replaced by Kathleen Jackson as the commission’s interim chair. 

Gov. Greg Abbott (R) appoints the PUC’s commissioners. Appointees must be confirmed by the Senate, which is in a fourth consecutive special session. 

McAdams also leaves a sizeable hole in SPP’s initiative. His leadership of the REAL Team has been praised by the RTO’s CEO, Barbara Sugg, and members of the team. 

Omaha Public Power District’s Colton Kennedy, chair of SPP’s Supply Adequacy Working Group and a key player on the REAL Team, said McAdams is a “pivotal force” in setting the direction of policy. 

“Chairman McAdams has had an exceptional ability to steer discussions forward amidst uncertainty,” Kennedy said. “His leadership comes at a crucial time in the evolution of the electric grid.” 

“I appreciate his leadership. He is very structured, he keeps people motivated, he keeps the conversation going and he keeps the issues moving forward,” Evergy’s Denise Buffington, the REAL Team’s vice chair, said. “I like the pace at which he does it. He does keep things moving and sets targets. It’s complex work, but the objective is not to spin out.” 

McAdams said the RSC, composed of SPP state regulators, will “recompute” both the committee’s and the REAL Team’s leadership. A state commissioner will take over the REAL Team’s chairmanship; South Dakota’s Kristie Fiegen and Nebraska’s Chuck Hutchinson hold two of the three commissioners’ slots. 

Buffington said McAdams was instrumental in setting the team’s work plans. “Now, it’s executing on that and making sure it stays on the rails. It’s constant monitoring, making sure we’re on track and not getting overwhelmed,” she said. 

SPP said the RSC’s vice-president elect, Minnesota’s John Tuma, will serve as the group’s president in 2024. The committee will hold an election next year to fill the vice president’s open position. 

“As we move into the spring, you’ll have a more defined outlook on how this organization will proceed forward,” McAdams told the REAL Team. 

He said he will continue to chair the group’s final 2023 meeting. He said he wants to close out the team’s objectives for the year before turning the chairmanship over to his replacement. 

“I’ve appreciated the work and effort that everybody’s put into this. I think everybody realizes that this is an important time in our industry and in our history,” McAdams said. “I was able to help guide part of that, but this was never going to be up to any one person, any one organization. It’s going to require a repeat rotation of good people into these jobs to help prepare for the next winter, to help prepare for the next summer, to help prepare for the next need, especially as those needs continue to grow.” 

Abbott appointed McAdams to the PUC in April 2021, part of the commission’s overhaul after the deadly winter storm that killed hundreds of Texans and nearly imploded the ERCOT grid. The three incumbents all resigned or left the PUC, with McAdams and Lake appointed as the first two new commissioners. Texas lawmakers also increased the PUC’s membership from three to five commissioners. 

“I am grateful to the governor for giving me the opportunity,” McAdams said. “It’s just that everybody comes to a time where they need to turn it over to fresh blood. And it’s that time.” 

McAdams previously served as president of the Associated Builders and Contractors of Texas after spending more than 10 years in state government. He was an adviser to House Speaker Dennis Bonnen and held several senior staff positions within the Senate.  

Following graduation from Texas A&M University, McAdams served four years as an infantry officer in the U.S. Army, retiring as a captain. 

Posted on

Overheard at CHESSA Solar Focus Conference

BALTIMORE, Md. ― Maryland officials like to point out the state now has the country’s most ambitious greenhouse gas emissions reduction goal — 60% by 2031 — and is also aiming for 100% clean power by 2035, with 14.5% coming from in-state solar.  

Hitting those targets is doable, but hard, they say. 

“It’s going to be incredibly complicated,” said Josh Tulkin, director of the Maryland Sierra Club, speaking at the Solar Focus conference sponsored by the Chesapeake Solar and Storage Association (CHESSA) on Nov. 16. “There’s a desire to often say because we have to do it, let’s also make it sound super easy. It won’t be super easy. We have 100 years of … using one particular system weighted toward a particular type of power generation.” 

“There’s a lot of hard stuff we’ve got to face,” agreed Del. Lorig Charkoudian (D). “If we roll up our sleeves, we can do it, but it does mean we have to be willing to acknowledge the challenges along the way and be willing to be creative and be willing to sit down a lot of times with folks that we’re not usually sitting down with to sort through and find solutions together.” 

As detailed in panel discussions at the conference, the obstacles to a decarbonized electric system include the siting and permitting problems many solar developers face, Maryland’s dependence on out-of-state wholesale power — still about 60% fossil fuels — and the need for grid modernization to interconnect the clean power coming online.  

On the plus side are Maryland’s Democratic Gov. Wes Moore and Democratic control of both houses in the General Assembly, as well as a new Democratic majority on the state’s Public Service Commission.  

But, Charkoudian cautioned, having political majorities may not translate into the policies or the market forces the state will need. 

“Markets are … not real things in and of themselves,” she said. “They are things we created from policy; so, whatever we want the market to do, we can make the market do. So, if we’re saying the market’s not working, it’s our fault, our policy and results,”  

The bigger question for Charkoudian is not if, but “how do we get [to 100%]? … How do we set up the market so there’s a regulatory framework that allows us to get there?” 

Kristen Harbeson, political director of the Maryland League of Conservation Voters, said that incorporating environmental justice strategies into policymaking from the start will be critical and likely uncomfortable for many. Like Charkoudian, Harbeson called for expanding the stakeholder voices sitting at the tables where legislative and regulatory priorities are set and compromises forged.  

“Even if your table is full … figure out who’s not at the table, who needs to be at the table, making sure any community that your project or your effort touches is being engaged,” she said. 

“If you’re comfortable, you’re probably not doing it right,” Harbeson said. “You need to be ready to be uncomfortable because progress happens in the space between discomfort and sheer panic.” 

Community Solar

Maryland’s Climate Solutions Now Act (CSNA), passed in 2022, set the 60% emissions reduction goal.  As mandated in the law, the Department of the Environment will roll out its implementation plan before the end of the year. Speaking at a conference in October, Environment Secretary Serena McIlwain hinted the plan would focus on transportation, buildings and exploring options for expanding renewable energy. (See Chasing Goals, Facing Obstacles at Md. Clean Energy Summit.) 

In Maryland, policymakers and project developers appear to be focusing on in-state initiatives, aimed at growing the local solar market, as they wait for PJM to clear its backlog of utility-scale solar and storage projects, which could take until 2026, (See Solar Developers Sing Mid-Atlantic Interconnection Blues.) 

The state imports about 40% of its power through PJM, according to the U.S. Energy Information Administration. 

Maryland is behind on its efforts to reach the 14.5% solar target, according to former state Sen. Paul Pinsky, sponsor of the CSNA and now director of the Maryland Energy Administration. The passage of H.B. 908 in April, making Maryland’s community solar pilot program permanent, could help the state make up lost ground, he said, speaking at the two-day Solar Focus conference on Nov. 15. 

Del. Luke Clippinger (D), a sponsor of H.B. 908, sees the law as a first step. Making the program permanent has raised public interest in community solar, which could in turn lead to “creative opportunities for businesses and nonprofits to come together and work with individual neighborhoods and work with individual communities so that we can expand this program, especially in low- and moderate-income communities across the state,” Clippinger said.  

The law requires that 40% of the output of community solar projects in the state goes to low- and moderate-income subscribers. 

“The greatest potential for expanding the growth in renewable energy is in our low- and moderate-income population because they don’t generally have the ability to do this otherwise,” he said. 

V2G, VPPs and TOU

Looking toward the 2024 legislative session beginning in January, Del. David Fraser-Hidalgo (D) is working on a new bill to promote the development of residential solar and storage, electric vehicle-to-grid (V2G) systems and virtual power plants (VPPs).  

The Distributed Renewable Integration and Vehicle Electrification (DRIVE) Act will “encourage the PSC to craft incentives and reduce barriers for consumers hoping to participate in V2G charging and those who wish to participate in a VPP,” Fraser-Hidalgo said in an email to RTO Insider.  

Del. David Fraser-Hidalgo (D) previews the DRIVE Act, aimed at promoting virtual power plants in Maryland. | © RTO Insider LLC

The PSC will also be authorized “to identify the most cost-effective way to roll out VPPs in coordination with FERC, PJM and other stakeholders” and to explore the introduction of default time-of-use rates at a future, not-yet-determined date, he said.  

With V2G, an electric vehicle’s battery can be tapped to put power on the grid at a time of emergency or high demand. Similarly, VPPs are combinations of distributed energy resources — such as solar and storage — that either can connect to the grid when needed or operate off-grid in emergencies to keep the power on at community centers, hospitals or other critical facilities.  

Time-of-use rates provide price signals to consumers to manage their energy use by charging increased rates during times of peak demand and lower rates in off-peak hours.  

Previewing the bill at Solar Focus, Fraser-Hidalgo said the DRIVE Act would use a term like “discounted rates” rather than time-of-use. “I think everybody [at the conference] probably knows what time-of-use is … but when you’re trying to get people to change behavior, probably something like discounted rates makes a lot more sense.” 

The bill aims to address questions about “how do we work with utilities and how do we diversify where we get electricity from, how we store electricity and how we distribute electricity,” he said, while also creating “a lot of resilience and redundancy we currently do not have.” 

Charkoudian agrees that distributed resources, like V2G and VPPs, will be “a huge piece” of Maryland’s march to 100% clean energy, but she cautions that policy, regulation, technology and markets have to be aligned. “Storage is a perfect example of the mismatch,” she said.  

“Precisely because storage can do so much … it’s not just generation and it’s not just ancillary services; it’s not just a balancing of load; but [because] it’s all those things … none of the markets really work for it,” she said. 

“We’ve got to find a way to get the conversation happening in a way that allows us to really head in the right direction or else we could have all the technology, all the brilliant people and not get our policies right and miss the opportunity,” she said. 

Posted on

CISA Releases AI Security Guidelines

With artificial intelligence systems undergoing a rapid pace of development and deployment in recent years across multiple industries, and security often “a secondary consideration,” developers must be active in preventing “novel security vulnerabilities” from taking root in their software, cybersecurity agencies from multiple countries warned in new guidance issued over the weekend.

The “Guidelines for secure AI system development” document was published Nov. 26 by the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) and the U.K.’s National Cyber Security Centre (NCSC). Similar organizations in other countries also signed on, including Australia, Canada, Chile, France, Germany, Israel, Japan, Poland, South Korea and Singapore. In addition, multiple technology companies and groups contributed to the document, many with their own AI initiatives, such as Amazon, IBM, Google, OpenAI and Microsoft.

“We are at an inflection point in the development of artificial intelligence, which may well be the most consequential technology of our time. Cybersecurity is key to building AI systems that are safe, secure and trustworthy,” Homeland Security Secretary Alejandro Mayorkas said in a press release. “Through global action like these guidelines, we can lead the world in harnessing the benefits while addressing the potential harms of this pioneering technology.”

CISA and the NCSC’s goal with the document was to provide a framework for developers to “build AI systems that function as intended, are available when needed and work without revealing sensitive data to unauthorized parties.” The guidelines can be used by developers of AI systems created from scratch or by those adding AI to existing tools or systems, with a focus on machine learning applications that can detect patterns in data that are not explicitly programmed by humans and can generate predictions, recommendations or decisions based on statistical reasoning.

New Vulnerabilities in Software Stack

Along with known cybersecurity threats, the addition of AI and machine learning elements to a system introduces new vulnerabilities that malicious actors can exploit. Attackers’ strategies can include prompt injection attacks, which involve manipulating large language models to produce unintended responses and actions, or corrupting the system’s training data or user feedback. If successful, such actions may allow users to perform unauthorized actions, extract sensitive information about the model or alter the model’s classification or regression performance.

Complicating the security picture is the fact that modern software products, including AI applications, integrate components from third parties such as data, models and remote services, making it “harder for end users to understand where responsibility for secure AI lies.” CISA and the NCSC said component providers “should take responsibility for the security outcomes of users further down the supply chain” and, when known risks cannot be mitigated, inform users of the risks and advise them on how to use the components securely.

The agencies arranged the guidelines into four key areas with the aim of covering the entire life cycle of AI system development and ensuring a “secure by default” approach: secure design, secure development, secure deployment, and secure operation and maintenance.

The authors sought to align the guidelines to the NCSC’s “Secure development and deployment guidance” and the National Institute of Standards and Technology’s Secure Software Development Framework.

Secure design covers identifying risks and threat modeling, along with “specific topics and trade-offs to consider on system and model design.” Recommendations in this section for managers include ensuring staff members are aware of the risks facing AI and that threats to the system are understood and adequately modeled. Project leaders should ensure developers consider security as important as functionality and performance, judging the security benefits and trade-offs of elements as fundamental as the choice of AI model.

Under secure development, the authors grouped guidelines relating to supply chain security, documentation and asset management. Developers must identify, track and protect both their in-house assets and those from outside parties, ensuring third-party software is sourced from “verified commercial [and] open-source … developers” and prepared to switch to alternate solutions for mission-critical systems if outside components are compromised.

Technical debt management also falls in the second category; this concept applies to the practice of making engineering decisions for short-term results that fall short of best practices. The document’s authors acknowledged that “like financial debt, technical debt is not inherently bad, but [it] should be managed from the earliest stages of development” so numerous small decisions over rapid development cycles do not add up to major vulnerabilities.

Responsibilities Continue After Release

Secure deployment guidelines apply to the stage in which the AI system has been released to end users. Recommendations in this phase include releasing software only after subjecting it to thorough security evaluations; securing the infrastructure, such as application programming interfaces, models, data and the training and processing pipelines; and developing incident-management procedures.

Finally, once the system has been deployed, developers enter the secure operation and maintenance stage. A developer’s responsibility at this point is to monitor the system’s behavior in order to detect changes that could affect security, including malicious intrusions and natural data drift. Update procedures should be secure, the updates themselves must be tested before they are released, and developers should continue to participate in information-sharing communities to share lessons learned and best practices.

“As nations and organizations embrace the transformative power of AI, this international collaboration … underscores the global dedication to fostering transparency, accountability and secure practices,” said CISA Director Jen Easterly. “This joint effort reaffirms our mission to protect critical infrastructure and reinforces the importance of international partnership in securing our digital future.”

Posted on

Connecticut Issues Storage RFI Aimed at Vehicle Electrification

The Connecticut Department of Energy and Environmental Protection (DEEP) Nov. 20 issued a request for information regarding the state’s solicitation of energy storage to help electrify its diesel vehicle fleets. 

The RFI is connected to a DEEP request for proposals aimed at replacing fossil generation and facilitating the interconnection of vehicle charging infrastructure. From the RFP, the state will select storage projects in three categories: projects that enable the electrification of vehicle fleets; projects that are co-located at the site of an existing fossil steam unit; or projects that are connected to the grid without co-location. 

The RFI concerns the diesel fleet category of projects and is intended to “build [DEEP’s] understanding of the expected locations, charging profiles, fleet size and other pertinent information from potential bidders proposing to install an energy storage system supporting diesel fleet electrification.” 

It is part of the state’s efforts to deploy 1 GW of energy storage by the end of 2030, a goal set by state legislation passed in 2021. The state has emphasized the need for projects that reduce emissions in designated environmental justice communities. 

“The RFP will provide ratepayer support to cost-effective storage projects,” DEEP wrote. “Cost effectiveness will include health effects from displaced emissions.” 

Along with the RFI, the state announced the allocation of nearly $1 million of federal Diesel Emission Reduction Act (DERA) funding to replace old diesel engines with electric alternatives or cleaner combustion engines. 

“Diesel-related air pollution continues to harm public health in Connecticut, especially in the low- to moderate-income communities across the state that have borne a historic and disproportionate impact from air pollution,” DEEP Commissioner Katie Dykes said in a statement. 

Dykes called the new storage and vehicle opportunities “important tools to cost-effectively and reliably reduce air pollution, support healthier communities and encourage further electrification of the heavy-duty vehicle sector.”   

DEEP is aiming to release a draft RFP “shortly” that will select up to 450 MW of nameplate storage capacity, capped at 250 MW for any individual project. One point of contention that has emerged in the RFP stakeholder process is the co-location of storage with existing fossil generators. 

For RFP applications of storage co-located with existing fossil generation, DEEP is “tying the category to amending the air permits to significantly reduce the plants running in the summer when emissions from the plants are most harmful,” a DEEP spokesperson told NetZero Insider. DEEP will also require projects to provide a date of the fossil fuel plant’s retirement, “so EJ communities benefit without hurting reliability.” 

In comments following a July technical session, Cary Lynch, climate and energy policy manager for the Connecticut chapter of the Nature Conservancy, argued that incentivizing storage that is paired with existing fossil generation “will not help the state meet its decarbonization target and will only delay the retirement of older, dirty fossil fuel generation plants. … Pairing storage with Class I renewables should be prioritized. … Building and strengthening our renewable energy portfolio is critical to creating a clean, reliable and affordable electric grid.” 

In other public comments after the meeting, several battery storage companies noted the difficulty of assessing and establishing fair and cost-effective compensation for co-located storage facilities within the context of ISO-NE market rules and the capacity commitments of fossil fuel generators. 

Commenters including BlueWave, FirstLight Power and RENEW Northeast expressed concern about whether supporting co-located storage facilities would meaningfully decrease the site’s fossil generation beyond already existing policies and trends. 

“We are concerned the current proposed structure may ask ratepayers to subsidize more expensive storage than is needed under the guise of emissions benefits when co-located storage is electrically indistinguishable from standalone storage,” RENEW wrote in July. 

In BlueWave’s July comments, the company encouraged DEEP “to focus this solicitation on the deployment of cost-effective energy storage that will prepare the electric grid for the retirement of fossil plants and erode the economic rationale for all fossil generation in the state.” 

Potential bidders for the diesel-fleet category of the RFP will need to submit responses to the RFI by Jan. 5 to be eligible for the RFP. Applications for the DERA funding are due by Dec. 15.