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November 19, 2024

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NERC Urges Preparedness Ahead of Weekend Storms

NERC is urging electric stakeholders to take preparations ahead of a winter storm system that the National Weather Service expects to “hammer much of the eastern half of the” U.S. this weekend and next week. 

In a statement earlier this week, the ERO said the coming weather “has the potential to create significant challenges, especially in major metropolitan areas.” Predictions by the NWS include blizzard conditions with 6-12 inches of snow from eastern Nebraska to central Michigan, and potentially more than a foot of snow in northern lower Michigan.  

Much of Montana and North Dakota is expected to see temperatures fall below zero degrees Fahrenheit Jan. 12, with single-digit temperatures likely in the Central Plains, Iowa and Minnesota. These conditions will likely persist “well beyond the end of the week,” the NWS said. 

Additionally, high winds are expected in the Deep South and Southeast U.S. with the possibility of tornadoes. While rainfall totals are expected to be relatively light compared to earlier this week, parts of the Mid-Atlantic and Northeast, already saturated by heavy rain, may experience floods. NWS is also forecasting “unsettled weather conditions” in the West, with the Oregon Cascades, along with the coasts of Oregon and northwestern California, predicted to receive several feet of snow. 

In a video posted Tuesday, NERC CEO Jim Robb said that “while forecasts do not indicate that this polar air mass will dip as far south as it did during Winter Storm Uri in 2021, the concerning pattern shows a much colder and broader area of impact.” He asked industry to “take this upcoming weather system extremely seriously and be prepared for extreme temperatures and wind chills.” 

NERC said stakeholders will need to pay “prudent attention throughout the long holiday weekend” to winterization and fuel supplies. The ERO encouraged generator owners and operators, reliability coordinators, balancing authorities, transmission operators and fuel suppliers to evaluate energy adequacy, and load-serving entities to “review their demand projections to ensure the highest levels of reliability.” 

NERC’s release mentioned the ERO’s “comprehensive approach” to preparing for and mitigating the impacts of severe weather events, including the new cold weather standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) approved by FERC last February. (See FERC Orders New Reliability Standards in Response to Uri.) 

Work on additional cold weather standards continues at NERC: The organization’s Board of Trustees voted in October to send EOP-011-4 and TOP-002-5 (Operations planning) to FERC for approval. NERC’s board also warned last month that it is prepared to unilaterally approve the proposed standard EOP-012-2 — which FERC ordered the ERO to submit for approval by February 2024 — if it fails its next ballot round this month. (See NERC Board May Force Action on Cold Weather Standard.) 

NERC warned in its 2023 Winter Reliability Assessment that much of North America faces elevated or high risk of energy shortfalls during extreme weather conditions this winter. A common theme in multiple regions was that generation has not kept pace with demand growth, with the added concern in New England that using natural gas for both home heating and electric generation could place unsustainable burdens on the gas delivery infrastructure. (See NERC: Grid Risks Widespread in Winter Months.) 

This week’s statement also mentioned NERC’s 2023 Long-Term Reliability Assessment, which advised that “integrated planning and effective coordination [are] imperative” in light of the growing interdependence between North America’s gas infrastructure and electric grid and the risks posed to both systems by extreme cold temperatures. 

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Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP

MISO stakeholders this week pushed MISO to publish sooner rather than later a new deadline for accepting aggregators of distributed resources into its markets.

MISO hopes to file for a new implementation date and clear up other aspects of its Order 2222 compliance with FERC by May 10. While the RTO plans to discuss several aspects of its revamped compliance multiple times between now and early spring, it plans to devote only one final April 11 meeting of its DER Task Force to discussing the new target date. After that, it will present a final, reworked Order 2222 compliance proposal to the MISO Market Subcommittee at its April 18 meeting.

In October, FERC told MISO it had to achieve a more timely Order 2222 compliance, striking down the RTO’s originally proposed plan to accept aggregators’ offers beginning in the first quarter of 2030. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

Clean Grid Alliance’s Rhonda Peters asked MISO not to wait to hold discussions on its new implementation until spring.

“The implementation date is a topic of great importance to many stakeholders,” she said during a Jan. 11 teleconference of MISO’s DER Task Force.

MISO’s Marc Keyser said landing on a new implementation date will be relatively “straightforward” when compared to the other outstanding Order 2222 compliance directives FERC ordered MISO to resolve.

“Multinodal aggregations are a pretty complex topic…we think we’ll need multiple discussions there,” Keyser said.

However, Sierra Club’s Justin Vickers said the implementation date is a “big deal.”

“I think not being able to talk about that until the very end will affect how we will discuss other issues,” he said, adding it would be “prudent” for MISO to share its revised go-live date with stakeholders expeditiously.

Organization of MISO States Executive Director Marcus Hawkins said MISO’s 2030 finish date was revealed belatedly in its first round of compliance work, which led OMS to reassess MISO’s compliance plan. OMS last year filed comments with FERC that a 2030 implementation date was too gradual.

Advanced Energy Management Alliance’s DeWayne Todd asked MISO to consider a staged implementation to the order, where it works in DER aggregators’ participation as it’s able.

Otherwise with the Order 2222 compliance edits, MISO is reaching out to its stakeholders for advice on how it should best coordinate with regulators, distribution companies and aggregators to solve FERC’s directive to establish cybersecurity and customer data privacy protections for meter data management.

The RTO also is seeking stakeholder reactions on how it should set up dispute resolution when disagreements arise between aggregators, LSEs, distribution companies and/or regulators over meter data or settlements. MISO is proposing that it become involved and review an aggregator’s participation in its markets when its settlements are successfully disputed more than 10% of the time by an LSE and the financial impacts of successful disputes exceed $7,500 for an individual dispute or average at least $100,000 across all successful disputes.

MISO will hold two workshops with distribution companies on Order 2222 compliance: a Jan. 22 teleconference to discuss a 60-day timeline and process for reliability reviews to monitor DER aggregations’ impact on the distribution system and a Feb. 27 teleconference to hash out operational coordination.

MISO also plans to discuss how it might handle DER aggregations across multiple pricing nodes at DER Task Force meetings beginning in February.

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DOE Seeks Proposals to Build out HALEU Supply Chain

The U.S. Department of Energy is putting $500 million from the Inflation Reduction Act into the buildout of a domestic supply chain for the high-assay, low-enriched uranium (HALEU) needed to deploy and power advanced nuclear reactors, according to a request for proposals released Jan. 9. 

HALEU is uranium that is enriched 5 to 20% with U-235, the isotope needed to sustain a chain reaction that can produce energy, versus low-enriched uranium (LEU) that is enriched only up to 5% and is used in the existing light-water reactors in the U.S. The higher enrichment levels allow for reactors with “smaller and more versatile designs with the highest standards of safety, security and nonproliferation,” according to the RFP announcement. 

The RFP is the second of two focusing on the key processes involved in HALEU production: mining, milling, enrichment and deconversion, which is the process of converting enriched uranium into usable fuel. The previous RFP, issued in November, will provide funding for deconversion facilities, while the current request will offer contracts for enrichment, which will include mining and milling. 

Focusing on the domestic enrichment part of the process, DOE will award one or more contracts that will run for at least 10 years, with a minimum order valued at $2 million. While the RFP says that mining and milling activities may occur in North America at large or in “allied or partner” nations, actual enrichment and storage of the HALEU must be located in the U.S. 

Also, the RFP specifically notes that any HALEU produced under these DOE contracts must not “negatively impact the existing baseline uranium production capacity currently supplying the U.S. domestic nuclear industry.” 

Proposals are due March 8. 

“Nuclear energy currently provides almost half of the nation’s carbon-free power, and it will continue to play a significant part in transitioning to a clean energy future,” Energy Secretary Jennifer Granholm said in the RFP announcement. “A robust HALEU supply chain” will strengthen “our national and energy security.” 

At present, the only commercial source of HALEU is a state-owned company in Russia, and lack of a domestic supply threatens DOE’s Advanced Reactor Demonstration Program, which is supporting the development of two advanced reactors with $2.5 billion in funding from the Infrastructure Investment and Jobs Act. 

Both projects will need HALEU, and the lack of a domestic supply has already been cited as potentially causing a two-year delay in the completion of one, the Natrium reactor being developed by the Bill Gates-founded TerraPower. 

A DOE-funded demonstration project in Ohio began producing small amounts of HALEU in October, but the department estimates that the U.S. could need up to 40 metric tons by 2030, with more than that required each subsequent year. 

The RFP is one more piece of the U.S. commitment to reviving the domestic nuclear industry and ending its dependence on Russian uranium in the wake of the war in Ukraine. At the 28th Climate Change Conference of the Parties (COP28) in December, the U.S. and more than 20 other countries pledged to triple nuclear power around the world by 2050. 

In a second COP28 announcement, the U.S. joined Canada, France, Japan and the U.K. in plans to mobilize $4.2 billion in public and private funds over the next three years “to establish a resilient global uranium supply market free from Russian influence and the potential to be subject to political leverage by other countries.” 

The announcement also encouraged “nuclear electricity generating utilities or direct nuclear energy industrial end-users of like-minded nations to develop [a] long-term supply strategy that signals and provides confidence to the industry to make the relevant investment to increase their capacity.” 

Building Confidence

However, building private sector confidence in the emerging HALEU market may take more than DOE’s initial $500 million commitment, according to a recent analysis from the nonprofit Nuclear Innovation Alliance (NIA). 

A successful buildout may require between $1.5 billion and $2.9 billion, said co-author Patrick White, NIA’s research director. 

“The $500 million is a really, really good down payment,” he said. “But if you want to create a market signal [that] the federal government could support or help ensure that there’d be sufficient demand — let’s say 10 metric tons per year for a period of 10 years … that’s where you start getting appropriation needs on the order of a couple of billion dollars.” 

One key to establishing a domestic supply chain while driving down costs might be leveraging existing, commercially produced LEU as feedstock for HALEU. “Use of lower-cost LEU enrichment services as part of the HALEU production process significantly reduces the overall cost of HALEU,” the report says. 

White argues that using LEU as HALEU feedstock could be done without affecting the fuel supply for the existing U.S. nuclear fleet, especially if mined and milled uranium can be obtained from other North American or partner nations, as allowed in the RFP. 

He also said that smart program structuring could “both protect the taxpayer and lower the total amount of money [needed] upfront.” A revolving fund, for example, could allow the government to “purchase HALEU and use that as kind of a guaranteed market signal and then sell [it] back to companies that are going to need it,” he said. That revenue could then be used to purchase more HALEU. 

White sees the RFP providing DOE with a flexible framework “so they can work with different companies out there to determine what’s going to be the best pathway forward to really kind of get new … capacity brought online.” 

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Newsom Budget Would Trim Calif. Climate Spending

California Gov. Gavin Newsom (D) on Jan. 10 proposed a fiscal 2024/25 budget that further shrinks the $54 billion California Climate Commitment to $48.3 billion, while spreading the climate spending over seven years rather than five.

At the same time, the state’s climate efforts will be bolstered by $10 billion of federal funding, Newsom said during a press conference. “That’s helped supplement some of the modest cuts we’re making in this space,” he said.

The proposed budget would maintain about $6.6 billion of the $7.9 billion of energy investments included in the state’s 2022 budget act. That money is intended to fund critical grid reliability projects and speed the state’s transition to clean energy.

The governor’s release of a proposed budget in January is just the first step in the budget process. The governor and legislature will spend several months haggling over the budget before it is finalized.

Newsom’s budget proposes $291.5 billion in spending, including about $208.7 billion from the state’s general fund. It grapples with an expected shortfall of $37.9 billion, following a $31.7 billion shortfall for fiscal 2023/24.

The governor attributed the deficits to wide swings in state tax revenue from capital gains. Before the recent budget shortfalls, the state had two years of surpluses totaling about $176 billion. Now, he said, the state is “going back to what we have traditionally seen … after a period of unprecedented distortion.”

Another issue, Newsom said, is that last year’s extension of tax-filing deadlines to November, because of severe winter storms, masked the full extent of the state’s revenue decrease. “Now that the receipts are in, we must bring our books back into balance,” Newsom said in a budget message. Newsom’s projection of a $37.9 billion deficit differs from the state Legislative Analyst’s Office prediction last month of a $68 billion deficit.

The California Climate Commitment received $54 billion in funding through the budget acts of 2021 and 2022. But the 2023/24 state budget cut the investment to $51 billion, while sparing $10 billion for electric vehicle infrastructure and incentives. (See Newsom Expresses ‘Sense of Urgency’ on Energy Buildout.)

The fiscal 2024/25 proposal maintains the $10 billion for EV programs but spreads it out over seven years rather than five.

The budget proposal includes $2.9 billion in cuts to climate programs and $1.9 billion in spending shifted to future years. An additional $1.8 billion in spending will be shifted from the general fund to other funds, mainly the greenhouse gas reduction fund (GGRF), which is money from the state’s cap-and-trade program.

As a result, some programs set to receive GGRF money will see a delay in funding. That includes $45 million earmarked for equity programs such as the Clean Cars 4 All electric vehicle incentive and $120 million for ZEV fueling infrastructure grants.

The governor’s budget proposes cuts to some programs, such as a $40 million reduction to the Carbon Removal Innovation program at the California Energy Commission. That would leave $35 million for the program. Similarly, $22 million would be cut from the CEC’s Industrial Decarbonization Program, leaving $68 million.

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SERC, Duke Agree to $40K Penalty for Reliability Violations

Duke Energy will pay $40,000 to SERC Reliability for violations of NERC reliability standards at multiple renewable energy generators, according to two agreements reached between the utility and the regional entity last year.

NERC submitted the settlements to FERC on Nov. 30 in its final spreadsheet Notice of Penalty of 2023 (NP24-3). On Dec. 29, the commission said in a filing that it would not further review the agreements, leaving the penalties intact.

SERC sorted the Duke settlements into two overall violations, each carrying a $20,000 penalty. The first involved infringements of MOD-032-1 (Data for power system modeling and analysis) at eight Duke facilities:

    • Conetoe II Solar in North Carolina;
    • Cimarron Windpower II and Ironwood Windpower in Kansas;
    • Frontier Windpower I and II in Oklahoma;
    • North Allegheny Wind in Pennsylvania;
    • North Rosamond Solar in California; and
    • Top of the World Windpower in Wyoming.

Because the issues span the footprints of multiple regional entities, SERC will split the penalty with the Midwest Reliability Organization, ReliabilityFirst and WECC based on net energy load.

According to the settlement, Duke discovered while gathering evidence for an upcoming audit that the facilities in question had not submitted modeling data to their transmission planners and planning coordinators in some of the previous years, as required by the standard. Most of the facilities were missing their steady-state, dynamics and short-circuit data; Frontier 2 was missing only its dynamics data, SERC said.

After learning of the failure to submit the data, Duke conducted an extent-of-condition review across its other business areas. (The initial discoveries were all in the Duke Energy Renewables division.) No other MOD-032-1 infringements were discovered.

SERC and the other regions classified the violations as a minimal risk to grid reliability, noting that failing to submit required data “could have resulted in inaccurate data being used in planning models and studies” but adding that in nearly all cases, there were no changes in the relevant data during the period of noncompliance. The facilities’ mitigating activities included submitting the missing data; defining the roles and responsibilities of all those involved in producing and submitting MOD-032-1 data; and implementing a tool to track upcoming modeling requirements.

The second Duke settlement involved violations of MOD-025-2 (Verification and data reporting of generator real and reactive power capability and synchronous condenser reactive power capability). Conetoe II Solar also was involved in these infringements, along with the Los Vientos and Notrees wind facilities in Texas; SERC will split the fines with the Texas Reliability Entity.

Once again, Duke discovered the MOD-025-2 violations while gathering evidence for an upcoming audit. The facilities had failed to submit information when they performed their five-year staged verification of real and reactive power capabilities in 2021.

The REs determined that the root cause of the infringement was “an inadequate fleetwide compliance management approach to MOD-025-2.” According to the settlement, the staff responsible for overseeing compliance activities lacked training, and the utility’s MOD-025-2 procedure lacked clearly defined roles and responsibilities for all groups involved in producing and submitting the data.

Mitigating activities by the facilities included defining the responsibilities involved in the MOD-025-2 procedure and implementing an organizational approach for model data evidence that defines how the evidence is to be structured and named. The company also trained the impacted groups on updates to the procedure “to ensure new processes are understood and implemented.”

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FERC Permits Elliott to Buy up to 20% of NRG Stock amid NOI

While an inspection into its approval process plays out, FERC has allowed another investment firm to purchase a sizable chunk of a public utility.

With Jan. 8’s decision, New York-based Elliott Investment Management is free to bump up its current 2.36% ownership of NRG Energy common stock to a maximum 20% through direct or indirect purchases (EC23-112).

FERC allowed the transaction over extensive protest from Public Citizen, which warned that the investment firm was seeking to control the utility. Elliott said it eventually may exercise voting rights depending on NRG’s financial and operation performance.

The approval follows FERC initiating a Notice of Inquiry last month on its practice of issuing blanket authorizations for investment companies seeking a stake in public utilities. (See FERC Reconsidering Blanket Authorizations for Investment Companies.)

In this case, FERC said the transaction won’t harm competition because Elliott doesn’t currently own or control generation in the markets where NRG operates. The commission also noted that the transaction doesn’t involve any handover of generation facilities and doesn’t disturb market concentration or operational control.

Elliott does, however, own a 15% ownership interest in Peabody Energy Corp., which supplies coal to some NRG plants in PJM and ERCOT. Elliott pledged that it doesn’t involve itself in Peabody’s day-to-day operations.

Public Citizen protested that assertion. The group pointed out that two Elliott executives, Samantha Algaze and Dave Miller, serve on Peabody’s board of directors. Public Citizen argued that Peabody’s management is “directly accountable” to the board and that board members have “unfettered access to influence management.”

Nevertheless, FERC rejected Public Citizen’s request for a hearing to probe how Peabody’s coal supply contracts with NRG would affect competition.

The Elliott executives included sworn affidavits that they do not oversee Peabody’s day-to-day operations, nor do they set pricing, negotiate contracts with customers or “seek to influence Peabody management decisions concerning to whom or what Peabody sells coal or the markets in which they sell coal.”

Public Citizen further argued that FERC couldn’t authorize the deal because it couldn’t allow Elliott executives to simultaneously serve on the NRG and Peabody boards. That would violate the Clayton Act, the organization reasoned.

Elliott argued that FERC is not tasked with enforcing the Clayton Act and that Peabody isn’t a competitor of NRG because it doesn’t mine coal.

FERC said Elliott’s board control and representation at either Peabody or NRG was “irrelevant” to its evaluation of the transaction. It also agreed that its jurisdiction doesn’t extend to Clayton Act enforcement.

Additionally, Public Citizen said it was troubled that prior to seeking FERC approval, Elliott attained indirect control of more than 10% of NRG through acquiring derivatives that “likely convey indirect voting control.” It said the Securities and Exchange Commission is similarly uneasy over the use of derivatives to covertly control public companies and has proposed a rulemaking to treat holders of cash-settled derivatives as owners for reporting purposes.

Public Citizen claimed that Elliott has a history of acquiring derivatives to “amplify their indirect control over a target company.” The consumer group said Elliott follows a playbook of using their economic interests to exert corporate control and then switch out board members and executives. Public Citizen said Elliott’s use of derivatives to control voting rights means Elliott meets FERC’s definition of an affiliate company.

FERC, however, decided it wouldn’t address the allegations of investor activism. It also said any existing affiliation between Elliott and NRG wouldn’t affect its competition analysis. FERC said though it wasn’t making a finding of affiliation now, it wasn’t foreclosing on the possibility of determining it later.

Elliott said Public Citizen’s concerns were “speculative” and its use of derivatives “merely [confers] economic interest and [does] not permit the holder to ‘force’ any change at such companies.”

Public Citizen warned FERC that “this is a proceeding of first impression for the commission, and therefore requires careful consideration, as it will likely establish precedent for both hostile takeovers of public utilities and affiliation treatment of cash-settled swaps.”

It said FERC should curb Elliott’s ability to enter into cooperation agreements and ban it from appointing board members at other public utilities. Public Citizen alleged that “at least once a year,” Elliott appears to scoop up direct and indirect interests in jurisdictional utilities and then pressure personnel and investment changes. The group said cooperation agreements allow Elliott access to nonpublic material of other utilities while simultaneously serving as a de facto affiliate of NRG, posing a risk to competition.

Public Citizen asked FERC to force Elliott to disclose how many arrangements it has with utilities and limit its ability to enter into future cooperation agreements.

Finally, Public Citizen further alleged that Elliott is collaborating with Bluescape Energy Partners to force operational changes at NRG. It said Bluescape and Elliott have enjoyed “a yearslong relationship of successfully conspiring to bend target companies to their demands.” According to Public Citizen, this is the sixth time Elliott and Bluescape have “joined an effort to usurp management of a public utility without first securing” a FERC order through a combination of cash-settled derivatives, acquisition of NRG stock and coordination with Bluescape.

FERC said any possible collusion with Bluescape was beyond the scope of the proceeding.

Commissioner Mark Christie said though he concurred with FERC’s decision to allow the stock purchase, Public Citizen’s allegations regarding Elliott and its investments in public utilities are of interest to the commission.

“To that end, in future proceedings, interested entities should continue to file information they believe may be of interest to the commission in its review, including, as Public Citizen has done here, information regarding investment practices in jurisdictional utilities commenters believe may suggest indicia of influence as they relate to affiliation and control,” Christie wrote.

He said such information on investment firm behavior led FERC to publish the notice of inquiry on its policy in the first place.

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Md. Emission-reduction Plan: High Ambitions, No Funding

To meet its ambitious goals of reducing greenhouse gas emissions 60% by 2031 and getting to net zero by 2045, Maryland should adopt a Clean Power Standard (CPS) ― 100% carbon-free by 2035 ― increase state rebates for electric vehicles to $7,500 for low-income buyers and quadruple the installation of heat pumps for HVAC and water heating, according to the state’s Climate Pollution Reduction Plan. 

The state also will have to come up with an extra $1 billion per year in public funding to pay for those proposals and the dozens of other initiatives laid out in the plan, even as it faces increasing budget shortfalls over the next few years. 

Released by the Maryland Department of the Environment (MDE) on Dec. 28, the plan lays out emission-cutting recommendations for every sector in the state’s economy, and to-do lists for the General Assembly and the administration of Gov. Wes Moore (D). 

“The policies in this plan, if fully implemented … will nearly put an end to the fossil fuel era and accelerate the transition to a clean energy economy,” the report says. 

The plan also stresses that a major portion of that $1 billion in new public spending each year “would focus on providing financial support to Maryland’s low-, moderate- and middle-income households and small businesses,” with the primary goal of improving equity and affordability. 

The state’s energy transition will be “intentional but also practical and methodical,” the report says, laying out “a sustainable path where incentives are provided at key decision points to consumers.” For example, when a furnace needs to be replaced, state incentives ― added to federal tax credits from the Inflation Reduction Act ― could cover up to 100% of the cost of installing a heat pump for low- and moderate-income households and 50% for middle-income households. 

Clean energy advocates have mostly praised the plan but cautioned that the nitty-gritty details of implementation remain to be worked out. 

The plan is “scientifically sound; it’s technically strong,” said Kim Coble, executive director of the Maryland League of Conservation Voters. “Where we are disappointed is that … there isn’t a plan to implement it. There’s [no] action. There’s not a funding source. There’s not even a discussion about how we are going to determine a funding source.”  

Rather, she said, the plan lays out an extensive list of tasks for lawmakers and different state agencies, without providing concrete next steps. 

    • The Maryland Energy Administration (MEA) would determine a legal framework for the CPS and whether the needed regulations could be implemented under its existing statutory authority.  
    • The MDE would begin drafting new regulations to establish zero emission standards for heating equipment, with final regulations to be released by the end of 2025.  
    • Responsibility for providing new point-of-sale incentives for EVs and EV chargers would be split between the Department of Transportation and MEA, respectively.  
    • The Public Service Commission would have the role of initiating a proceeding this year “to require natural gas utility companies to develop plans to achieve a structured transition to a net-zero economy in Maryland.”  
    • As a first step toward the CPS, the General Assembly would update the state’s existing Renewable Portfolio Standard specifically to exclude solid waste incineration, which is currently defined as renewable power. 

The Elephant in the Room

People’s Counsel David S. Lapp, the state’s top consumer advocate, likes the plan’s focus on building electrification, which “is the least-cost path forward for customers, including residential customers,” he said. Heat pumps can replace both home heating and cooling equipment, Lapp said. 

PSC action on gas utility planning is critical, but not enough, he said. “The legislature at some point, the sooner the better, will need to get involved.” 

By continuing to approve long-term investments by the gas utilities, “the state is effectively subsidizing fossil fuel infrastructure investments that are entirely contrary to virtually everything you see in the MDE report,” Lapp said. 

Even before the plan came out, the Maryland Chamber of Commerce raised concerns that any new regulations and fees could result in businesses moving “their operations to other states with less restrictive carbon emissions reduction regulations to avoid the high costs of compliance. Businesses in those states can also emit greenhouse gases then import their products into Maryland, creating an unfair playing field for Maryland businesses,” it said in an October letter to MDE. 

But Stephanie Johnson, founder of the newly formed Maryland Renewable Energy Alliance, countered that “the plan does a really good job of identifying the problems the state is facing, and it provides an overview of the potential solutions.” 

“The elephant in the room is the cost and timeline,” Johnson said. “I think there’s a political disconnect between the desire to move towards clean energy and the political will to make that happen, and I don’t think the plan gets at that problem.” 

Getting to 60%

The passage of the Climate Solutions Now Act (CSNA) in 2022 put Maryland on the map as a state with some of the most aggressive GHG emission reduction goals in the nation ― 60% below 2006 levels by 2031 and net zero by 2045 ― making it a potential model for other states. 

The law also required MDE to formulate a plan ― to be submitted to the governor and the General Assembly by the end of 2023 ― to reach those targets while creating jobs and economic benefits for the state. Moore upped the ante with his commitment to decarbonize the state’s electric power system by 2035. 

MDE released a preliminary plan laying out multiple options for implementing the CSNA in June ― also required by the law ― followed by a comment period that included a series of public meetings across the state. (See Maryland Climate Report Lays out Pathways to Achieving Goals.) 

Maryland is already halfway to the 2031 goal, according to MDE, and existing policies could get the state to 51%. In the past year, the state has adopted the Advanced Clean Cars II rule, requiring all new light-duty vehicles sold in the state to be zero emission by 2035. The General Assembly also passed a bill making the state’s community solar pilot a permanent program. 

Getting to 60% could be achieved by a mix of policies focused on specific sectors ― like the CPS and zero emission heating standards ― as well as economywide initiatives, such as a carbon fee or statewide cap-and-invest program, the report says. 

On the benefit side, MDE estimates that reaching net zero by 2045 could generate $1.2 billion in public health savings while creating 27,400 jobs and increasing personal incomes by a total of $2.5 billion. Factoring in heat pumps, EVs and other energy-saving measures, individual households could save as much as $4,000 per year, the report says. Statewide GHG emissions would drop by 646 million metric tons by 2050. 

Such dramatic cuts in emissions will not keep Maryland and its residents from experiencing the potentially catastrophic impacts of climate change. “Maryland’s climate will get warmer, wetter and wilder,” the report says. 

In 50 years, the state’s climate could be more like Mississippi’s, and by the end of the century, “islands throughout the Chesapeake Bay and much of Dorchester County will be lost to the sea,” the report says. Located in the middle of Maryland’s Eastern Shore, Dorchester is considered “ground zero” for sea-level rise in the state, according to a 2018 report. 

Money

Beyond the impacts of climate change, the greatest challenge ahead for Maryland is money. The ambitious targets in the CSNA did not come with any funding, and figures from the state’s Department of Legislative Services show budget gaps expanding to $418 million in 2025 and to as much as $1.8 billion by 2028. 

Maryland lawmakers must not only raise an extra $1 billion per year for clean energy and emissions reductions but do so without leaving consumers to pick up the tab through higher electricity rates or other expenses, the report says. 

“I don’t know that everybody’s figured out how to budget for climate change yet,” said Del. David Fraser-Hidalgo (D), pointing to impending budget cuts for the state’s Department of Transportation. The state also needs to increase teacher pay and hire more police officers, he said. 

“These are things that have been a known issue for a while now,” Fraser-Hidalgo said. “So, to come with a report and say, ‘Hey, we need another billion dollars for the next 10 years’ … is a challenge for the General Assembly, and the governor to find creative ways to come up those monies to make those changes.” 

Lapp said, “It’s going to take a variety of state policies to support what needs to happen, [and] that should not be subsidized, in effect, by ratepayers. It should be supported through other government policies because paying for a lot of the policies through rates is regressive.” 

“A key approach should be taxing polluters … getting money from fossil companies,” said Del. Lorig Charkoudian (D). She points to the plan’s recommendations for a carbon fee or a statewide cap-and-invest program, with some of the money raised used to offset the effects of any price increases on low- and moderate-income consumers. 

Maryland already participates in the Regional Greenhouse Gas Initiative (RGGI), a consortium of 11 East Coast states that sets ever-decreasing caps on emissions from power plants that burn fossil fuels and holds quarterly auctions to sell allowances to plants to offset their emissions. 

At the last auction of 2023, on Dec. 6, Maryland received more than $50 million from allowance sales, according to figures on the RGGI website. Now, it is pushing the other states in the consortium ― many with their own emission-reduction goals ― to set the emission caps even lower in their upcoming program review, expected this year. 

A statewide cap-and-invest program would go beyond power plants to cap emissions and sell allowances to other major industrial or commercial GHG emitters. 

Other recommendations in the plan include green revenue bonds and pollution mitigation fees for both interstate and in-state drivers. Interstate drivers would pay a “clean air toll” by mail to help mitigate the emissions their vehicles produce while traveling in the state. 

For Maryland residents, the report envisions a pollution mitigation fee paid as part of the registration process for vehicles that burn fossil fuels. The state is considering joining the growing number of states that have increased registration fees for EVs to make up for lost gas taxes, used for highway maintenance. 

If the EV fees are established, the pollution mitigation fee and clean air toll for gas-burning cars should be set at comparable amounts, the report says. 

Maryland also must go after federal funding available from the Infrastructure Investment and Jobs Act and the IRA. The report calls for all state agencies to “work closely with local governments, nonprofits and community-based organizations to ensure Maryland is competitive for federal climate action implementation funds and build capacity for local-level implementation.” 

The General Assembly

As the General Assembly opens its 90-day regular session Jan. 10, it must pass several laws before agencies can implement the plan’s top priorities. 

For example, before Maryland can set up a cap-and-invest program, the legislature would need to pass a new law that would allow the state to regulate emissions from the manufacturing sector, something it is currently prohibited from doing. 

The plan also calls for legislative action to update the state’s energy efficiency program, known as EmPOWER Maryland, to allow the PSC to set emission-reduction goals for electric and gas utilities and “require the utilities’ programs to facilitate beneficial electrification of fossil fuel heating equipment.” 

Another proposed bill would require new multifamily housing to be built either with EV chargers already installed or with the wiring necessary for installation. A new law would also be needed to allow state EV rebates to be paid at the point of sale. 

Charkoudian sees low-hanging fruit in a bill that would remove waste incineration as an eligible form of renewable generation in the RPS as a first step toward the CPS. Although previous efforts to update the RPS have failed, she said, “that absolutely can be done this year. … The idea that we are subsidizing trash incineration as a renewable source … is absurd, and it’s unjust, and it flies in the face of everything we’re trying to do with our environmental justice policies.” 

Both Charkoudian and the Chesapeake Climate Action Network (CCAN) are hoping for progress on a bill called the Responding to Emergency Needs from Extreme Weather (RENEW) Act, which was introduced by Fraser-Hidalgo last year but did not get past an initial hearing. The bill proposes that major fossil fuel companies pay a series of annual, fixed fees to compensate the state for the impacts of extreme weather events exacerbated by climate change.  

“It requires every company that has emitted more than a billion tons of greenhouse gas emissions cumulatively between 2000 and 2020 to pay [fees] to the state of Maryland,” said Jamie DeMarco, CCAN’s Maryland director. If passed, the bill could raise close to $1 billion per year for 10 years, he said. 

Fraser-Hidalgo plans to reintroduce the bill this session, and both he and DeMarco said they are going to make a major effort to get the bill to the governor’s desk. 

The LCV’s Coble says the General Assembly should approach funding with a two-step strategy, beginning with green bonds as a short-term solution. The second step would be a cap-and-invest program, which she said, “is going to take some time because it has to go through a whole regulation and rulemaking process. I would like to see the administration start that effort now because it probably wouldn’t be effective for several years.” 

Both Coble and DeMarco said direct support from Moore could be essential in getting the needed laws through the legislature. The governor has not yet released a public statement on the MDE plan. 

Fraser-Hidalgo said the funding issue could be holding Moore back from a full commitment to the MDE plan. 

“I think he would like to do that. I think he will do that,” he said. “These are expensive transitions ― electrification and decarbonization. They’re very expensive [and] haven’t really been done before and not in the way we’re talking about.” 

“We want to see Gov. Moore do three things,” DeMarco said. “One is [to] speedily and effectively implement all the executive actions … in this report. Then we also want to see him pick specific revenue raisers and fight for [them], and we also want to see him support specific legislation in Annapolis that aligns with the legislative goals” in the plan. 

Coble has a similar challenge for the governor and the legislature. “We’ve got a strong base to work from here; and we need leadership, and we need a sense of urgency, and then it will happen,” she said. “I mean, we’re the state of Maryland. Of course, it will happen.” 

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NYISO Finds No Need for New Capacity Zones

NYISO will not need to create any new capacity zones to ensure grid reliability over the next four years, the grid operator told stakeholders Jan. 9. 

That was the conclusion of NYISO’s quadrennial new capacity zone (NCZ) study, the results of which the ISO presented to a meeting of the Installed Capacity/Market Issues working groups (ICAP/MIWG). The study found that none of New York’s six “highway interfaces” — the transmission links between capacity zones — are constrained, eliminating the need to establish an NCZ. 

The NCZ study’s deliverability tests assess whether each highway interface can accommodate additional power flows and has an “additional transmission capacity” (or deliverability “headroom”) or cannot support more power and has “bottled generation capacity” (a deliverability “constraint”). The results showed, however, that each interface has additional transmission capacity, negating the need for new zones. The finding aligns with the 2019/20 NCZ study, which also identified no constraints. 

NYISO performs the NCZ study in conjunction with its demand curve reset (DCR), another quadrennial process to review and adjust the demand curves in its capacity market to ensure they accurately reflect the current costs and market conditions for providing reliable electric service in New York. 

NYISO must share the NCZ study with its Market Monitoring Unit for review and commentary and submit the study’s results to FERC as an informational filing by March 31. 

Final LCR Results

At the ICAP/MIWG meeting, NYISO also presented the final locational minimum installed capacity requirements (LCR) for the 2024/25 capability year, which were based on the 22% installed reserve margin (IRM) approved by the New York State Reliability Council’s Executive Committee (NYSRC EC) late last year. (See NY Reliability Council Approves 22% IRM for 2024/25.) 

The IRM determines the additional amount of capacity New York load-serving entities must maintain as a precaution against unexpected outages or demand surges. 

Final locational minimum installed capacity requirements (LCR) for the 2024/25 capability year | NYISO

Stakeholders raised questions about future discussions on transmission security limits (TSLs) and the assumptions contained within them, highlighting their growing relevance in LCR determination. TSLs define the maximum power capacity that can be safely transferred over the transmission network in a particular area, directly influencing the LCR and IRM by indicating the minimum generation required to maintain grid reliability within transmission constraints. 

NYISO staff confirmed it is engaged in ongoing discussions with the NYSRC and its subcommittees to refine TSLs and their assumptions and indicated those talks are expected to continue throughout 2024. 

The ISO intends to seek stakeholder approval for the final LCR results at the Jan. 18 Operating Committee meeting. 

Capacity Accreditation

NYISO staff also told ICAP/MIWG meeting attendees that the second set of informational capacity accreditation factors (CAFs), derived from the base case that produced a 23.1% IRM, will soon be published online. 

The IRM was derived from a technical study produced by both NYISO and the NYSRC’s Installed Capacity Subcommittee, which concluded that, under base conditions, a 23.1% IRM would satisfy the resource adequacy criteria without violating a loss-of-load expectation of no more than 0.1 event-days/year in the next capability year. 

The ISO said this second set of materials will include emergency assistance updates not captured in the first set of CAFs and must be posted by March 1. 

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New Jersey Broadens Public Solar Remote Net Metering Rules

New Jersey has enacted new remote net metering rules that increase the size and scope of solar projects eligible for the program but are less ambitious than lawmakers sought because Gov. Phil Murphy limited the expansion to protect ratepayers.

The Senate and Assembly voted unanimously Dec. 21 on a bill, S2848, that incorporated changes required by Murphy (D) when he conditionally vetoed the legislation.

Murphy, explaining his reasoning for the changes in a Nov. 27 veto statement, applauded the bill’s intent to “make solar energy more accessible to municipalities, schools and other public entities throughout New Jersey.” But he added that “the bill as currently drafted could prove extremely costly for New Jersey ratepayers.”

The Legislature, concurring with the veto, limited the size of remote net metering projects to 5 MW in the final bill, down from 10 MW initially sought by lawmakers. The final bill also placed remote projects under the state’s small solar facility incentive, in which the New Jersey Board of Public Utilities (BPU) sets the size of incentives through the Administratively Determined Incentives (ADI) program. The small solar facility program also limits the total annual capacity for all projects it awards each year to 50 MW.

In addition, the final version of S2848 allows eligible remote net metering projects to serve multiple public entities as subscribers without the need for a single host entity, which current rules require, and allow several hosts. The bill also allows public utilities to recover costs related to the remote net metering program in the same way they are able to do under the Community Solar program.

Sen. Bob Smith (D), a bill sponsor, said that despite the veto, the program will nevertheless “allow for more opportunities” for remote net metering.

Growth and Costs

The legislative tussle is part of the ongoing effort to stimulate the development of remote net metering projects that can help the state reach its solar capacity installation goals while also ensuring those developments don’t cost ratepayers too much. (See NJ Steps up Remote Net Metering Approvals.)

Remote net metering allows for the energy to be generated in a different place than where the energy is consumed. It enables an entity, such as a company or a government agency, that does not have space to erect a solar array to generate power at its main location to site a solar project at one or more separate sites and use the energy at the first location. State rules also allow a public agency to generate electricity that can be used remotely by other public bodies.

New Jersey implemented the state’s remote net metering program to create a solar option for municipalities and other public bodies that could meet several requirements of the state’s community solar program but could not match that program’s requirement to have a large number of subscribers.

State officials see remote net metering as part of the solar package that can help the state reach its goal of zero emissions by 2050, with solar reaching 12.2 GW of solar capacity installed by 2030 and 17.2 GW installed by 2035.

Smith said the aim of S2848 was to broaden the use of remote net metering beyond the private sector, which accounts for a large proportion of remote net metering projects installed to date.

“Why shouldn’t schools or school boards or county governments or township governments also be involved in net metering?” he said. “So it increases who can do net metering pretty significantly.”

One way the bill does that is by allowing the size of a remote net metering project to be set by the size of the aggregated energy use of the participating entities, not the average energy use, as has been the case up to now. The bill also allows the solar project and the energy receiving customers to be located on any property within the electric distribution company’s service territory, rather than requiring it to be on the public body’s own property.

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DOE Planning up to $70M in Energy Resilience Investments

The Department of Energy is preparing to invest up to $70 million in technology to reduce risks to energy infrastructure from cyber and physical threats, natural disasters and extreme weather events as part of the All-Hazards Energy Resilience Program, according to an announcement issued last week.

Funding will be provided competitively through DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER), the department said. As many as 25 projects will receive grants of between $500,000 and $5 million. Groups associated with universities; national laboratories; nonprofits; companies; and state, local and tribal governments are eligible to apply.

CESER’s cyber and physical security investments will focus on addressing threats from “the growing digital landscape” and vandalism, sabotage and ballistic damages like the substation shootings of December 2022 in Moore County, N.C., which knocked out power for 45,000 customers. (See House Energy and Commerce Examines Moore County Attack.)

FERC has praised NERC’s Critical Infrastructure Protection (CIP) reliability standards, which govern cyber and physical security for electric utilities, as an “effective technical baseline” for the industry and even held them up as a model for other energy sectors following the 2021 ransomware attack on Colonial Pipeline. (See Colonial Hack Sparks Competing Recommendations at FERC.) But DOE said in its release that “today’s approaches to prevent these attacks” — physical attacks in particular — don’t go far enough to “minimize intrusions and damage.”

University-based research and development into cyber and physical security is a particular focus of the program. DOE said applicants in this area must be from historically Black colleges and universities, and research teams must include participants from the energy sector such as utility owners and operators or service providers.

In addition, CESER is seeking projects that will address climate and wildfire mitigation, including “opportunities to harden infrastructure against wildfires” and reducing the impact of extreme weather on energy transmission resources.

Climate change and the expected increase in severe weather have become standard topics of conversation among FERC, NERC and electric industry stakeholders, with the ERO’s 2023 Long-Term Reliability Assessment released last month highlighting the issue as a significant threat in the coming decade.

CESER said successful applicants should “span all types of energy delivery infrastructure,” including electric utilities, gas pipelines and renewable energy sources. The program is seeking “innovative and unique solutions that are not ‘one size fits all.’” According to the projects’ funding opportunity announcement, the department hopes to identify “next-generation tools and technologies … that will become widely adopted throughout the energy sector to reduce an incident disruption to energy delivery.”

Funding applications are due by March 4. CESER will notify selected recipients in May to begin award negotiations, with the amounts of the final awards to be announced in September.

“Making smart investments in America’s energy systems today is essential to ensuring they’re more reliable and resilient against tomorrow’s threats,” Energy Secretary Jennifer Granholm said. “As we build our clean energy future, these investments will help save money in the long run by identifying and developing innovative solutions that ensure our nation’s energy infrastructure can withstand emerging threats and the challenges of a changing world.”