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November 24, 2024

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AEU Report Shows Major Economic Benefits from Quicker Queues

Fixing the interconnection process to speed up the development of new generation could add $100 billion in economic benefits, according to an analysis released Nov. 21 by Advanced Energy United.

Improving interconnection processes around the country could lead to $57 billion in economic benefits and 667,000 job-years from increased solar energy deployment and $42 billion and 376,000 job-years from increased onshore wind deployment, according to the report, “How Interconnection Reform Can Accelerate Clean Energy Deployment.”

“Our nation’s electricity demands are growing, and these broken interconnection processes are standing in the way of Americans building the energy projects we need to thrive,” AEU CEO Heather O’Neill said in a statement. “Fixing interconnection would unleash job-creating energy projects and deliver an economic boom in states across America. If states can more quickly build the poles and wires needed to connect new electricity resources to the power grid, they will unleash their economic potential, lower electricity bills for residents and improve energy reliability for all.”

Generators coming online in 2023 averaged five years in the queue, from when they requested interconnection to commercial operation, compared to an average of just two years from 2000 to 2007.

FERC has attempted to address the issue with orders 2023 and 1920, and the report argued that states can support and build on those efforts by engaging in implementation and pushing for supplemental reforms.

“In the United States, almost 2,500 GW of non-emitting power generation and energy storage capacity are seeking to interconnect, equivalent to double the capacity of all generation sources currently online in the United States,” the report says. “Legacy interconnection processes were established decades ago to individually evaluate a small number of large, predominantly coal and natural gas power plant proposals, and these processes are ill-suited to evaluate thousands of more geographically distributed wind, solar and energy storage projects.”

The precise impacts of speeding up the queues will take years to play out, but the report offers an illustrative analysis showing how accelerating them can benefit the economy.

Under one of the scenarios, attrition of projects initially increases by 25% this year, which reflects a “purging” of the queues prompted by Order 2023’s higher financial requirements. But as additional improvements play out, project attrition is expected to fall by 50% from historic rates, while a business-as-usual case would see a 10% increase.

The report includes state projections (for the Lower 48 except Texas) for projects getting through the queue quicker and what benefits that would bring to their economies.

“Results vary between states, which is to be expected, as interconnection requests reflect renewable energy resource potential, state policy support and local project development considerations such as land availability, perceived permitting complexity, local construction costs and more,” the report said. “Nonetheless, each state sees incremental renewable energy deployment with interconnection reform.”

For most states, implementing changes will lead to an appreciable increase in renewable projects, with California, for instance, seeing 147 TWh in additions by 2030, compared to 112 TWh under business as usual.

One clear group of exceptions are those states banking on large offshore wind contracts — Connecticut, Delaware, Maryland, Massachusetts, New Jersey and Rhode Island — for most of their incremental renewable growth. The successful deployment of offshore wind depends on other factors, the report says.

“In a few states, successful interconnection reform leads to a significant increase in renewable generation such that generation in 2030 exceeds state [renewable portfolio standard or clean energy] requirements,” the report says. “New Mexico and Arizona show renewable energy generation increases that outstrip state requirements, showing that each state is well positioned for exporting first-rate solar and wind-generated electricity.”

The report suggests states advocate for transmission providers to build trunk lines that aid interconnection and fast-track interconnection requests that are proposed for areas with available grid capacity.

It also suggests tailoring analyses to requested levels of interconnection (capacity- or energy-only), standardizing study assumptions, evaluating alternatives to traditional transmission upgrades, using automation, and using independent monitors to oversee the process and recommend improvements.

Another suggestion is to expedite construction of needed upgrades by adopting industry best practices and proactively addressing supply chain constraints.

“By engaging directly with FERC, pursuing available federal funds and calling on their regional grid operator to fulfill their responsibility to provide reliable and low-cost electricity, states can maximize economic opportunities made possible by more abundant solar and wind projects,” O’Neill said.

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CAISO Kicks off ‘Workshop’ to Update RA Mechanisms

CAISO on Nov. 18 kicked off a Resource Adequacy Modeling and Design “workshop” designed to reevaluate and refine several mechanisms the ISO uses to ensure resource adequacy.

The workshop builds on the ISO’s RA Modeling and Program Design working group, in which staff and ISO stakeholders highlighted problem statements associated with the RA program. It aims to continue refining solutions to the problems identified and develop policy responses.

The main goal of the effort is to update the default counting rules and planning reserve margin (PRM), evaluate the need for the Resource Adequacy Availability Incentive Mechanism (RAAIM) or an unforced capacity mechanism (UCAP), and reevaluate outage and substitution rules and the capacity procurement mechanism (CPM), also referred to as the “backstop.”

The issues will be addressed in the three different tracks, but ISO staff noted the tracks can be combined or changed based on stakeholder feedback.

Track one addresses modeling, default rules and accreditation, while track two deals with outage substitution and availability and performance incentive mechanisms. Track three tackles visibility and backstop.

The workshop will be further divided into three “packages” that outline workflow. Package one identifies minimal changes needed to take the first step in addressing the topic, package two outlines forward planning and package three covers operational measures.

The packages are “illustrative” and not representative of CAISO’s preferred or final approach, said Partha Malvadkar, principal of RA and infrastructure policy at the ISO.

“What we’re looking for as we work towards policy development is packages of changes that make sense together and that are achieving the goals and objectives that came out of the working group process in a comprehensive and consistent manner,” Malvadkar said.

PRM and Default Counting Rules

Another central aim of the initiative is to evaluate how well PRMs and counting rules set by local regulatory authorities (LRAs) reflect forced outage rates, performance and availability. Evaluating the need for UCAP, which was discussed in the prior initiative, fits into this area. (See CAISO Considers Replacement of RA Incentive Program.)

“In response to potentially changing regulatory structures at the CPUC (including the scoping of UCAP), CAISO has an opportunity to establish alternatives to the current resource counting design and eliminate/redefine availability and performance incentives while acknowledging LRA authority to establish counting rules,” according to a presentation from the meeting.

The ISO also identified the need to update the PRM based on changes in the RA resource mix and evolving reliability needs within the CAISO balancing authority area (BAA). CAISO policy developer Ansel Lundberg identified that qualifying capacity values, also referred to as “counting rules,” should reflect the relative contribution of different resource types to maintain BAA-wide and local reliability and to meet at least a 0.1 LOLE.

The initiative also addresses the need for capability testing to account for seasonal resource availability. According to Lundberg, the availability of resources based on varying seasonal ambient derates is not consistently reflected in resource net qualifying capacity (NQC), which poses challenges for grid operations. CAISO thinks it should adopt minimum requirements so it can rely on capacity to perform consistent with accreditation in a given season. Such requirements could minimize partial forced outages that derate resources below their NQC value during critical periods.

Outages and Substitution

CAISO also intends to work to establish a more efficient process for outages and substitution. Central to that is developing a voluntary planned outage substitution pool, where scheduling coordinators can make capacity available and pay for it if needed. SCs could also procure from the pool.

The ISO is also considering developing a planned outage buffer provided by each LRA, as well as moving to annual or seasonal showings, CAISO lead policy developer Anja Gilbert said.

The final intent of this track is to remove planned outage substitution requirements and replace them with strong incentives and better information about periods of risk.

RAAIM Reform

RAAIM is one such incentive mechanism that could help remove planned outage substitution requirements. But the ISO is considering revising RAAIM to become a “pay-for-performance” mechanism for capacity to respond and non-capacity resources to be available during scarcity conditions.

That model, which has been implemented in PJM and ISO-NE, acts as both a reward and penalty relative to a resource’s obligation during scarcity events. If a supplier’s poor performance contributes to reliability risk, it could face “strong consequences,” according to Lundberg’s presentation.

Backstop and Visibility

A central component of the prior and current RA initiatives within the ISO is the need for more visibility into RA and non-RA resources. (See CAISO’s Capacity Procurement Mechanism Inefficient, Stakeholders Say.) CAISO’s lack of visibility into the “not-shown” RA fleet makes the backstop mechanism less efficient, but regular reporting on the status of RA capacity could improve the system, said CAISO lead policy develop Hilary Staver.

The ISO suggested options for policy reform, including updating CPM authority to accommodate the backstop based on an assessment of energy sufficiency and/or net peak needs.

“We’re looking to provide visibility into RA and non-RA resources in order to allow for efficient decision making in CAISO operations, obtaining capacity with the right attributes when and where it’s needed, and trying to be efficient and effective in our backstop approach,” Staver said.

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Consumer Advocates File Wide-ranging Complaint on PJM Capacity Market

Several state consumer advocates filed a complaint at FERC on Nov. 18 alleging that PJM’s capacity market is failing to mitigate market power, overestimating future load and producing high clearing prices that generation owners cannot act on. 

The complaint asks the commission to find that the 2025/26 Base Residual Auction (BRA) failed to produce appropriate rates, require a host of changes to the auction design and establish a refund with replacement rates. The complaint was jointly submitted by the Illinois Attorney General’s Office, Illinois Citizens Utility Board, Maryland Office of People’s Counsel, New Jersey Division of Rate Counsel, Office of the Ohio Consumers’ Counsel and D.C. Office of the People’s Counsel. 

“From one auction to the next, the total capacity cost to consumers jumped from $2.2 billion to $14.7 billion. Worse, continuing to run BRAs using the current design promises the possibility of future auction clearing prices that are even higher. Absent changes to fix the PJM capacity market’s flawed auction rules, some have predicted that the 2026/2027 BRA could clear at the new, higher offer cap ($696/MW-day) regionwide, ballooning charges to PJM ratepayers to $37 billion,” the advocates said. 

One of the market changes they advocated for is already the topic of a separate complaint filed by a group of public interest organizations: PJM’s practice of not modeling the expected output of generators operating on reliability must-run (RMR) agreements (EL24-148). The retirement of Talen Energy’s 1,273-MW Brandon Shores and 702-MW H.A. Wagner generators outside of Baltimore have been credited as one of the drivers of the BGE zone reaching the $466.35/MW-day price cap in the 2025/26 auction. 

While the RTO plans to submit a proposal under Federal Power Act Section 205 that would add the output of two generators running on RMR agreements to the supply stack beginning with the 2026/27 auction, the advocates want that change to be made for the prior auction as well. (See “Insight into Upcoming Filing,” FERC Approves PJM Capacity Auction Delay.) 

In addition to requiring that RMR units offer into the capacity market, they requested that the commission extend the advance notice that generation owners must provide PJM ahead of deactivating resources, empower the RTO to delay deactivations for reliability, base RMR compensation on a cost-of-service rate and require that RMR resources participate in all relevant PJM markets. 

The advocates wrote that market power protections are incomplete so long as intermittent generation and storage are exempt from the requirement that all resources must offer into the capacity market and demand response resources are not subject to the three-pivotal-supplier (TPS) market power test. Citing analysis from the Independent Market Monitor on the auction, they said the tight balance between supply and demand led to all capacity resources having market power, underscoring the need to ensure that no resource classes are able to exercise market power. In that analysis, the Monitor has argued that DR and intermittent resources did exercise market power in the auction, a claim PJM has said is unsubstantiated. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.) 

“The primary cause of the BRA price spike is not the interplay of supply and demand. It is the byproduct of a market power problem endemic to the PJM design that the existing mitigation protocols are unable to address,” the advocates wrote. 

They requested that DR resources that fail the TPS test be limited to offer caps akin to generation resources; be required to offer their maximum dispatchable demand reduction into the markets; and have their performance measured as a function of the actual metered reduction in load before and after the resource is dispatched. 

They also asked that the commission implement the Monitor’s recommendation that the capacity ratings for gas generation be applied seasonally to align with PJM’s risk modeling. Accreditation for gas resources is capped at their summer ratings, a practice the advocates said is inconsistent with PJM’s risk modeling skewing toward the winter. Aligning the two would more accurately reflect their potential contribution to high-risk winter periods. 

New supply is unlikely to offer a remedy, the advocates wrote, because of the confluence of a compressed auction schedule and backlogged interconnection queue that make it unlikely that developers can construct resources in response to high prices. In testimony supporting the complaint, Daymark Energy Advisors CEO Marc Montalvo said the high prices serve no benefit for consumers and allow generators to collect windfall revenues. Prioritizing interconnection studies for resources that would be built in constrained locational deliverability areas would allow the resources with the highest impact to be accelerated through the queue, Montalvo recommended. 

“Under current market conditions, capacity prices are being driven by the barriers to entry of new supply — including constraints on the time it takes to study interconnection requests and build new transmission to interconnect new resources in the queue — which add to the market power of incumbent suppliers,” Montalvo wrote. “High prices cannot bring new generation into the market more quickly than it can be interconnected, and while such prices might retain existing generation, they are substantially above any just and reasonable measure of the net going forward costs that existing resources must cover to deliver capacity.” 

He went on to argue that the sudden jump in BRA clearing prices — from $28.92/MW-day in the 2024/25 BRA to $269.92/MW-day in the following auction — calls into question whether the underlying fundamentals reflect an abrupt shift from surplus to shortage or a flawed market design. 

The advocates also called for FERC to direct PJM to open a stakeholder process to make several changes to the capacity market in the longer term. It singles out the calculation of the net cost of new entry parameter and shifting the capacity market to a prompt or staggered auction to alleviate inflated load forecasts. They argued that PJM has a track record of over-forecasting load, a trend that could be exacerbated by rapidly accelerating estimates of data center load. 

“These clearing price outcomes do not match the market facts on the ground. Yes, load is increasing — but PJM has historically overestimated load and appears poised to do so again by exaggerating the likely additions of massive data center loads without firm power supplies,” they said. 

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Most Stakeholders Support Special Interconnection Rules for Tribes

Most stakeholders support a proposal before FERC to exempt energy projects developed by federally recognized Native American tribes from deposits and other fees in the generator interconnection process.

The Alliance for Tribal Clean Energy filed a petition for an expedited rulemaking to exempt tribal energy projects from fees designed to discourage speculative development, which won widespread support in comments filed ahead of a Nov. 18 deadline (RM24-9). (See FERC to Consider Special Interconnection Rules for Tribal Energy Projects.)

Tribes and their representatives from around the country were supportive of the policy, arguing that commercial readiness deposits and withdrawal penalties, which are meant to discourage speculative projects, do not make sense for the developments that tribal entities pursue.

The Inflation Reduction Act effectively opened up tax credits for tribal energy projects, but some of FERC’s rules still offer regulatory barriers to that development, said the Midwest Tribal Energy Resources Association, which represents 27 tribes from the region.

“We have witnessed firsthand the unique challenges tribes face due to current regulations that require commercial readiness deposits and impose withdrawal penalties,” the association said. “These requirements, while intended to manage speculative interconnection requests, disproportionately impact tribal nations who often lack access to the same financial resources and capital as traditional energy developers.”

The Navajo Transitional Energy Co. (NTEC) is a Tribal Energy Development Organization (TEDO) owned by the Navajo Nation, which controls 17 million acres of “trust lands” in the Four Corners area in the Southwest and includes 300,000 members, including 170,000 at the reservation. NTEC owns the Navajo Mine, which serves the Four Corners Generating Station, a 1,540-MW coal plant in which it owns a 7% stake with plans to add a carbon capture and storage demonstration project to the site.

NTEC is also pursuing renewable energy projects, including a 1,200-MW solar plant that will be built in several stages with ENGIE North America.

“The federal government has recognized it has a trust responsibility to protect tribal sovereignty, economic security and Tribal Energy Development Organizations’ energy development on tribal lands,” NTEC said. The commission has, likewise, stated it endeavors to “work with the tribes on a government-to-government basis.”

TEDOs have historically been structurally excluded from capital markets and are unable to use traditional tax equity or debt financing, NTEC said. “Instead of traditional financing available to other transmission developers, Tribal Energy Development Organizations secure much of their financing through philanthropy and federal grants only available once a project has secured interconnection rights.”

The sovereign nature of tribes can discourage private parties from entering into contracts with them, but they have land with often good resources to develop.

“Land, without an interconnection, cannot support a generating facility,” NTEC said. “The commission can make tribal energy development more attractive to development partners by modifying the pro forma interconnection procedures to increase Tribal Energy Development Organizations’ chances of being able to offer a favorable position in the interconnection queue.”

The Environmental Defense Fund, National Wildlife Federation, Earthjustice, Natural Resources Defense Council, Sustainable FERC Project and Center for Biological Diversity filed joint comments in support of the petition. They said the process leading to Order 2023 involved insufficient input from federally recognized tribes and that led to a rulemaking that does not work for them, which is a potential violation of FERC’s “trust responsibility” to tribes.

“The United States government holds a trust responsibility toward tribes, rooted in Article I, Section 8 of the Constitution, shaped and defined by 375 treaties, hundreds of laws and countless executive orders,” the groups said. “This fiduciary duty requires the government to honor treaty obligations, manage resources for tribes’ benefit and act in their best interests. Federal agencies are mandated to actively consult and engage with tribes on matters impacting tribal lands, resources and cultural heritage, ensuring respect for tribal sovereignty and upholding commitments to promote tribal self-determination and wellbeing.”

Energy projects developed by tribes are not speculative because tribes always have direct control of the land and limited points of interconnection, which means they cannot file speculative projects in search of the best one, the environmentalists said. Tribal lands on average have 70% fewer kilometers of transmission and 43% less high-voltage transmission than the rural U.S.

The environmentalists agreed that tribes often face issues with financing in part because lenders are unfamiliar with their legal systems, their lands have little pre-existing infrastructure, and it is hard to secure financing.

“Much of tribal land is held in trust by the federal government, restricting lenders’ ability to claim an interest in land as collateral if a borrower defaults,” they added.

The Choctaw Nation of Oklahoma urged FERC to also give deference to tribes when they oppose jurisdictional energy projects being built on their lands.

“These projects provide benefits to non-tribal entities while imposing most of their costs on the tribal nations, which is the definition of environmental injustice,” the tribe said. “The proposed Pushmataha County Pumped Storage Project is a textbook example of this.”

The tribe was referring to a project proposed by Southeast Oklahoma Power Corp. on lands and waters within the Choctaw reservation that derive profit by generating electricity to be sold to Texas (P-14890). Despite opposition from the Choctaw and Chickasaw Nation, it is moving forward.

While most of the intervenors in FERC’s docket were supportive of the petition, it did run into opposition from Idaho Attorney General Raúl Labrador (R).

“Instead of following the same requirements as everyone else, the tribes would get a blanket waiver from paying commercial readiness deposits at the same time as other requesters and from paying the full withdrawal penalties,” he said. “This exception would give the tribes an easier path to connecting their generators to the grid, giving them an unfair advantage.”

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SPP Has ‘Positive Outlook’ Heading into Winter

SPP says it expects to have enough generation to meet demand this winter following an assessment that indicated an increase in operational certainty over the previous two assessments.  

The grid operator’s staff told stakeholders Nov. 18 during its annual Winter Reliability Forecast and Emergency Communications webinar that they project a 98.5% probability of SPP having sufficient resources to meet the projected peak demand this winter season. That probability increases further when operating reserves are added to the mix. 

Weather forecasts, peak demand projections, expected generation availability and other trends suggest the region will have a greater margin between electricity demand and generating capacity than in the previous two peak seasons, staff said. 

“While this forecast presents a positive outlook for electricity customers throughout the SPP footprint, we must continue to be vigilant and plan for growing power demands in the future,” SPP COO Lanny Nickell said in a statement. “We can never say for sure when extreme weather events, such as what we have experienced in recent years, may materialize. SPP is doing everything it can to be prepared to meet customer needs.” 

Winter storms in February 2021 and December 2022 stretched the footprint’s available reserves, forcing the RTO to shed load in 2021 and import power. 

SPP has projected demand to peak at 46.92 GW in its 14-state footprint. It has a total winter capacity of 63.88 GW, resulting in about a 40% reserve margin. The capacity values do not include the effect of accreditation policies filed at FERC. The grid operator’s resource adequacy requirements for the winter season (December-March) are not effective until the 2024/25 winter season. 

The La Niña weather pattern is forecast to return during the upcoming season, bringing with it the potential strong polar jet stream that led to the 2021 and 2022 winter storms. Temperatures are expected to be lower than normal in the northern plains and higher in the South. 

SPP annually assesses historical and predicted future electricity use, weather forecasts, wind energy’s variability, drought conditions, and generation and transmission outages to identify and address threats to energy reliability during the winter. 

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Corporate Solar Development Continues to Grow

Large corporations trying to green their operations continue to expand their solar generation capacity, with Meta, Amazon and Target among the leaders. 

In its latest “Solar Means Business” report, the Solar Energy Industries Association reports nearly 40 GW of on-site and off-site corporate capacity installed by March 2024. 

It finds that Meta Platforms leads on overall capacity (5,177 MWDC); Amazon led on capacity addition in calendar year 2023 (2,930 MWDC) and has the largest self-reported pipeline (13,591 MWDC); and Target has the largest on-site capacity (319 MWDC). 

Additionally, the 2024 edition of the report is the first to tally corporate installed battery storage. Google tops the rankings by a wide margin, with 312 MWAC. 

Solar and storage are a reliable and low-cost way to power operations, SEIA President Abigail Ross Hooper said in a Nov. 20 news release announcing the report.  

It is not a one-size solution, she said: “These industry giants are investing in solar through a diverse range of applications, including on-site and off-site installations, on carports, paired with storage, or even as an anchor tenant for a community solar project.” 

Most of the companies surveyed for the report cited Inflation Reduction Act incentives as a driver of their expanded procurement of renewables. Most said they had no problem finding partners or institutional support for their plans. 

About half said high or volatile prices, expensive capital and internal financial constraints have limited procurements.  

About half said interconnection reforms, new community solar legislation and simpler tax credit monetization would help drive further investments. 

The report also indicates: 

    • Corporate procurement represents more than 18% of U.S. solar capacity. 
    • In 2023, 20% of solar installations had a corporate offtaker. 
    • Corporate involvement has become increasingly diversified, with growing interest in community solar, tax equity investment and microgrids. 
    • Expectations of increased demand and rising cost for electricity — and a desire to lock in supply and price — drive solar investment decisions. 
    • Big-box retailers and the largest tech firms dominate the rankings, but a range of other sectors are making inroads, including automaker General Motors, fast food icon McDonald’s and packaging manufacturer Smurfit Westrock. 
    • Rooftop commercial solar capacity has grown at a 12% compound annual growth rate for the past five years. It is an obvious choice for Target, Walmart, Amazon and other companies with large, flat-roofed facilities, and growth has continued despite rising costs, supply chain disruptions and other headwinds. 
    • Battery storage will be a key trend for corporate buyers, as states and utilities seek to add storage capacity to their grids. It is a versatile solution — No. 2 Kaiser Permanente, for example, is using its 115.6 MWAC of installed storage to form microgrids to make its medical facilities more resilient to outages, while No. 5 Starbucks is using its 10.5 MWAC for customer EV charging. 
    • Procurement plans are huge: The top 10 corporate buyers alone report a pipeline of 27.8 GWDC of solar, and the actual total is likely higher, as some pending projects are not disclosed. 
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NJ Scrutinizes Solar Net Metering Strategy

New Jersey has launched a yearlong process to evaluate the effectiveness of its solar net-metering system and generate possible alternatives amid developer concerns that potential changes could hinder future project installation rather than stimulate it. 

The state Board of Public Utilities (BPU) outlined the evaluation plan in a two-hour online forum Nov. 19, during which consultants reviewed the state’s current system, evaluated options for change and provided insights into net-metering reform strategies adopted in New York, California and Illinois. 

The evaluation was triggered by the expansion in the amount of electricity produced by net metering. The state’s 2018 Clean Energy Act allows that when 5.8% of the total annual kilowatt-hours (KWh) sold in the state is net metered, the state can “cease offering net metering to customers that are not already net metered.” The state reached the threshold in the energy year that ended May 31, 2024. 

In response, the BPU launched a “robust stakeholder process” to develop an updated net-metering mechanism, according to the BPU announcement of the plan. 

The goal is partly to “provide certainty on compensation mechanisms going forward” and to “encourage economic efficiency and fair allocation of costs and benefits,” Sawyer Morgan, a project manager in the BPU’s clean energy division, said in the online forum. The policy also should “integrate with grid modernization, energy storage and demand response technologies” and provide support for a “strong solar industry.” 

Net metering refers to the way solar projects designed to generate electricity only for the user can send electricity into the grid if they create more power than the customer needs. With a utility paying for the electricity, the strategy can help the customer pay off the project investment. 

The agency seeks stakeholder policy proposals that will be presented and compared at a technical conference Jan. 21, 2025. From these, three policy options will be developed and a straw proposal released in June 2025, with a final report expected in November 2025. 

Solar Sector Goals

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, said the state needs to better define its vision for the new policy. 

“These are not really complimentary goals,” he said. “A lot of these are in conflict with one another, and I really think it’s important for the state to give us more specific guidance in terms of what’s more important in those goals, maybe ranking them or scoring them.” 

While the residential solar market is “doing well,” the “commercial sector is underperforming somewhat” and the state needs to give clarity in what its priorities are and evaluate the impact of any policies “based upon the anticipated consequences,” he said. 

“Because I think those consequences could be very, very significant,” he said. “Take a wrong step here and we could really undermine a lot of the good that’s been done.” 

Some of the handful of solar developers who spoke in the meeting expressed concern that the contribution of solar to the state would get lost in discussions on policy, especially if cost is emphasized. 

“This process shouldn’t be seen as a ‘let’s sharpen our pencils and figure the exact value of solar to the grid,’” said Andy Wall, a board member of the Mid-Atlantic Solar and Storage Industries Association. 

“We can’t lose sight of that fact. The purpose of net metering is to promote the willingness of New Jersey residents and businesses to host solar for the rest of us,” he said. 

Net Metering Reimbursement Calculations

New Jersey at present has 197,000 residential net-metered installations and 9,500 non-residential net metered installations, totaling 2,305 MW, with an annual generation of 4,600 GWh, according to the BPU. The state had a total installed solar capacity of 4.95 GW, in September as it aims for a goal of 12.2 GW of solar energy by 2030. 

The state’s focus on drafting a new program comes seven months after new compensation rules for solar net metering in California — known as Net Energy Metering 3.0 (NEM) — took effect. The rules cut the payments for net metered electricity from solar-only projects, in favor of solar and storage projects. A study by the California Solar and Storage Association (CALSSA) found that even before the rules took effect, they had triggered 17,000 solar sector job losses. (See Can US Maintain Record Solar, Clean Power Growth? ) 

Abe Silverman, a former BPU general counsel who now runs the Ralph O’Connor Sustainable Energy Institute at Johns Hopkins University, said New Jersey’s program is designed to bring order to the sector now that the 5.8% threshold has been reached. 

“I read this new proceeding as an opportunity for the board to hear from folks in an organized manner, rather than waiting for the utilities to come in and make a filing to change the net-metering rules, which could be chaotic and create uncertainty for solar developers,” he said in an interview with NetZero Insider. “It’s significantly better for developer certainty to have an active proceeding.”    

BPU officials said they’re considering three net metering mechanisms, the methods by which the amount of electricity sent to the grid is calculated and its value — and the payment by the utility — is established. 

In the first method, similar to traditional net metering, the customer’s electricity generation “rolls the meter back, offsets their consumption, regardless of when it occurs, and excess generation, and all generation, is basically compensated at the customer’s retail rate,” said Akhilesh Ramakrishnan, a project manager for The Brattle Group, which is working on the issue for the BPU. 

Under the second method, called Net Billing and the most commonly used of the three, the amount of electricity sent to the utility — exported — is measured. So too is the amount of additional electricity imported because the customer at a particular time hasn’t generated enough by solar, Ramakrishnan said. The electricity imported and exported each has its own rate, and the difference between the two is either charged or credited to the customer, he said. 

In the third method, Buy All, Sell All, the cost of all the electricity used by the customer is calculated, as is the cost of all the electricity generated, he said. Either the difference is paid by the customer, or they receive a credit if the amount generated exceeds the use. 

Consultants who studied the net metering reform efforts used by other states told the hearing that New York and California use a form of the Net Billing method, with different rates for electricity imports and exports. New York also added a surcharge to “attempt to reduce the amount of cost that’s being shifted from these customers to non-solar customers,” Ramakrishnan said.  

Preliminary studies show rooftop installations are lower in California after the state introduced NEM 3.0, but there were other factors at play — such as a rise in interest rates — that mean the impact of NEM 3.0 is unclear, he said. 

Illinois has developed a Buy All, Sell All system, he said. 

Ratepayer Costs

In New Jersey, the BPU said customers who already are net metered likely could continue as they are, but the agency still is studying the issue.   

Andrew Gold, assistant deputy rate counsel with the New Jersey Division of Rate Counsel, expressed concern about the burden on ratepayers. He said the state’s achievement of the 5.8% threshold “signals both the success of prior net-metering policy initiatives as well as the need to carefully consider next steps that could reform the net metering process in ways that continue to promote behind-the-meter solar generation, but at a much lower ratepayer cost.” 

Ratepayers have to pick up some of the costs of buying net-metered electricity, and also some generation, transmission and distribution fixed costs, which are not paid by the customer generating the power, he said. 

“This rate design often results in under recovery of these capacity costs by net metering residential ratepayers at other residential ratepayers’ expense,” he said. Reform can bring “tremendous opportunities for creating greater efficiencies and reducing ratepayer financial support costs for net metering systems, both legacy and new installations,” he added. 

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Texas Now Wants to be No. 1 in Nuclear Power

AUSTIN, Texas — Not content with having the world’s eighth largest economy — bigger than Russia’s — along with being a global leader in crude oil production and home to more wind and solar energy than any other state, Texas has set its sights on dominating nuclear energy production as well.

Texas officials released a report Nov. 18, titled “Deploying a World-Renowned Advanced Nuclear Industry in Texas,” that lays out a path for the state to become a “global nuclear energy hub.”

”Texas is the energy capital of the world, and we are ready to be No. 1 in advanced nuclear power,” Texas Gov. Greg Abbott said in a statement. “By utilizing advanced nuclear energy, Texas will enhance the reliability of the state grid and provide affordable, dispatchable power to Texans across the state.”

The report was shepherded by Jimmy Glotfelty, a Public Utility Commission of Texas member and chair of the working group tasked with studying and planning for the use of advanced nuclear reactors (ANRs) in Texas. The report became public just before Glotfelty sat down for a fireside chat at the Nov. 18 Texas Nuclear Summit.

“The governor wants us to be No. 1. We’re No. 1 in wind, we’re No. 1 in solar, we’re No. 1 in oil production and gas production,” Glotfelty told his audience. “What’s next? Nuclear. That’s our challenge. That’s our challenge for the industrial sector. That’s our challenge for the power sector. That’s our challenge for the manufacturing sector, to be a part of this industry going forward.

“We hope this is a springboard to greater, bigger, better things in the nuclear space in Texas, and this is just the beginning,” Glotfelty said. “This is the end of the beginning, and we’ve got a lot more work to do in the future.”

Texas Nuclear Alliance President Reed Clay, the summit’s host, said the state’s leadership has laid the groundwork for “immense, unmatched nuclear potential to chart a bold path forward.”

“The importance of nuclear energy to the state’s future energy needs and for the continuation of the Texas miracle cannot be overstated,” Clay said.

Texas has only four reactors at two sites, Comanche Peak near Fort Worth and the South Texas Project south of Houston, which provide over 5 GW of energy between them. However, both plants each have room for two more reactors.

But the interest in nuclear power is there, given the projections of 8% load growth. Texas A&M University has asked the Nuclear Regulatory Commission for an early site permit that would allow up to five 10- to 200-MW reactors to be built on its campus, making it the country’s first higher education institution with a commercial nuclear reactor site license.

The NRC in September gave Abilene Christian University approval to build and test a 1-MW ANR that will be cooled by molten salt. Along the Gulf Coast, Dow Chemical and X-energy plan to develop four gas-cooled ANRs at a large chemical plant; it has already been selected for up to $50 million in federal funding but does not yet have regulatory approval.

‘Not Chernobyl’

In a message to Abbott included in the report, Glotfelty said economics and federal licensing timeframes — “neither of which the state can directly change” — are the “fundamental challenges” to achieving the state’s objectives. However, he said the working group made seven recommendations to “prove up the state’s role as a regulatory and economic leader in this new innovative technology.”

The recommendations target critical industry issues in Texas, and most will require legislative solutions:

    • Advanced nuclear authority.
    • Nuclear permitting officer.
    • Workforce development program.
    • Advanced manufacturing institute.
    • Nuclear public outreach program.
    • Nuclear energy and supply chain fund.
    • Nuclear energy fund.

The group foresees the advanced nuclear authority as a state agency to be the “tip of the spear” in providing a voice for the nuclear industry. The nuclear permitting officer would guide interested companies through the permitting process while workforce programs would train the next generation of nuclear employees, from the engineer down to the “most important welder,” Glotfelty said.

“Our state has the ability to do it,” he said. “We do it for other types of projects, and we will do it for the nuclear space as well.”

The team also proposed a nuclear energy fund that would offer low-interest loans to developers, similar to the $10 billion Texas Energy Fund. Glotfelty said while he wishes the government didn’t have to help fund the industry, state money will be involved “because we’re competing with 50 other states.” He said the state’s $20 billion surplus, fueled by its oil and gas industry, provides an opportunity.

“We’re helping reduce the front-end cost by putting state dollars at work,” Glotfelty said.

The Texas Legislature’s biennial session runs from Jan. 14 to June 2.

Then comes the hard part, Glotfelty said. While public opinion has softened on nuclear power since the 1980s, it hasn’t reached the acceptance that wind and solar energy have.

“We’ve got to have coordinated effort to help people understand that Texas is not Chernobyl, that nuclear is not Three Mile Island and Fukushima,” Glotfelty said.

“This end of the beginning is the report. Writing is done. Now it’s the communicating,” he added. “It’s communicating with everybody at the local level. It’s communicating with everybody in the legislature. It’s communicating with your supply chain. It’s communicating the fact that we want to build things here in Texas.”

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NYPA Urged to Do More in New Renewables Role

ALBANY, N.Y. — The New York Power Authority should do more with its new ability to develop renewable power, clean energy advocates say. 

NYPA in October issued a draft strategic plan to develop or partner on development of 40 new solar, wind and storage projects totaling 3.5 GW of capacity, and said the early stage projects among this first tranche likely would experience an 80 to 85% attrition rate. (See NYPA Enters Renewable Development with 3.5-GW Plan.) 

Advocates who fought for years to secure the new powers of development have been disappointed. They want a 15-GW road map with less attrition. They have been mounting a campaign to sway public opinion and are speaking out at hearings as NYPA conducts a statewide listening tour before finalizing its strategic plan. 

The final plan must be delivered to the governor and Legislature by Jan. 31, 2025. 

Public Power NY plans a demonstration outside a Nov. 20 hearing in Manhattan, and members of the coalition spoke at a Nov. 18 hearing in Albany. 

Public Power NY Co-Chair Patrick Robbins remarked about the recent wildfires in the Hudson Valley — a region whose woodlands usually see abundant rainfall but now are experiencing an extended drought and a wave of fires, which are rare in living memory. 

“In a few months, we’re looking at a reactionary federal administration,” Robbins said. “We need the New York Power Authority to come up with a plan that meets this moment. 

“The plan contains just over 3 GW of renewable energy capacity when we know that NYPA would need to build five times this amount in order for New York to meet our legally mandated renewable energy electricity targets.” 

Mark Schaeffer is a longtime advocate who helped push for the state’s Climate Leadership and Community Protection Act — the CLCPA, the landmark 2019 law that codified many of the carbon-reduction targets the state now is trying to meet.  

He keyed in on one word in the law’s title: “I emphasize the word ‘leadership’ because the state must lead,” he said. “This is an affluent, progressive state in a wealthy country disproportionately responsible for greenhouse gases, and the federal government has now become part of the problem.” 

State Assemblywoman Sarahana Shrestha (D), whose Hudson Valley district includes areas affected by wildfires, floods and other problems blamed on climate change, also called for NYPA to aim higher — at least 15 GW. 

The state has been relying on private sector development to reach its renewable development goals and has seen extensive attrition due to local and global cost escalation, delays and New York’s cumbersome regulatory and permitting processes. 

The state now projects 43% renewable energy by 2030, Shresta said — far short of the 70% mandate in the CLCPA. (See NY Expects to Miss 2030 Renewable Energy Target.) 

“NYPA was supposed to fix this,” she said to audience applause. “Only a public entity like NYPA can absorb the risks and costs that would help smaller projects go online — projects that may not make a profit but greatly help to meet people’s needs.” 

This is at the center of the vision behind the Build Public Renewables Act, the measure that empowered NYPA to take a role in development: Democratize electric power, cut out the profit motive, push fossil fuels out of the picture and let the people of New York enjoy the ecological and financial rewards. 

But the enabling legislation also directed NYPA to take on added costs: expand its workforce training efforts, retire its gas-fired peakers and help fund a new utility bill rebate for low-income New Yorkers. 

The law did not change the fact that New York is one of the slowest and most expensive states to build electric infrastructure and has a strong home-rule tradition that can delay or kill projects.  

Two stalwart renewable energy supporters representing the Capital Region in the state Assembly, Democrats Patricia Fahy and John McDonald, both voiced support for NYPA and for its expanded mission at the hearing. But both also raised a warning about costs. 

“Let’s be clear — and unfortunately, the recent elections demonstrate that — there are concerns [among] the public with [regard] to affordability, which should not be lost on anybody,” McDonald said. 

Clean, sustainable, reliable, resilient and affordable are the guiding principles, he added. “Sounds easy, but it is not. But I am confident.” 

If a strong vision by the state’s leaders and hard work by the state government managers were all that mattered, the state might be much closer to its clean-energy goals, and it might not have to create a new mission for the power authority Gov. Franklin D. Roosevelt signed into existence in 1931. 

But a slow interconnection queue, a long review process, local opposition and global macroeconomic factors have caused a high rate of attrition in proposed or contracted projects. 

NYISO’s 2024 Load & Capacity Data Report offers a sobering view: After a decade of promoting solar and wind power development, New York ended 2023 with 255 MW of solar and 2,454 MW of wind capacity installed in front of the meter out of a total statewide capability ranging by season from 37.4 to 39.7 GW. 

Further, front-of-meter solar and wind respectively contributed just 230 and 4,893 GWh of the state’s 124,153 GWh net energy production in 2023.  

(Distributed solar is faring better in New York, surpassing 6 GW installed capacity in October, but it, too, has a low capacity factor.) 

‘Learning Curve’

So the advocates are right: New York has a long way to go in its clean energy transition. 

In 2023, NYPA created a new position to lead the new role it was given — vice president of renewable project development — and appointed Vennela Yadhati to the role. (See NYPA Names Exec to Head New Renewable Development Effort.) 

She has been opening NYPA’s hearings with an overview of the draft plan and the larger picture it would fit into. She does not take questions or respond to comments, as it is a listening tour rather than a discussion, but she spoke to NetZero Insider about some of the concerns raised. 

The 2023 law expanding NYPA’s role — which was opposed by private-sector developers — does not shift the task of decarbonizing New York’s grid from the private sector to the public sector, Yadhati said. Rather, it adds NYPA as another piece of the solution. 

“We do realize our position to be now one of the several hundreds of players in a very mature market,” she said. “So that’s where we have a learning curve. But we’re learning from our partners as we develop this.” 

She added: “The legislation does not have a minimum threshold or anything for the capacity or time frame goal that we need to be hitting. It is for NYPA to participate and continue to support the state’s goals, as we have been doing.” 

Yadhati pushed back on the suggestion that NYPA — an entity under state control but self-funded separately from the state budget — has extensive access to cheap capital to build 15 GW of renewables at low cost thanks to its high bond rating. 

NYPA’s strong rating is based on it choosing its projects carefully, she said. “That’s where our approach needs to be very balanced and very strategic.” 

NYPA does have a history of achievement: It is the largest state entity of its kind, it operates more than 1,550 circuit-miles of transmission, it built some of the nation’s largest hydropower and pumped hydro storage plants, and it built one of the state’s nuclear power plants. 

The draft renewables plan calls for 10 solar projects totaling 200 MW that NYPA would develop on its own and 30 solar, storage and wind projects totaling 3.2 GW that NYPA would partner with private developers to build. 

This first tranche does seem modest, particularly given the 80 to 85% attrition rate expected for early-stage proposals and the 30 to 60% rate projected for more mature proposals. 

But it is only the first tranche, Yadhati said. 

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ISO-NE Details Regional Energy Shortfall Threshold Metrics

ISO-NE’s Regional Energy Shortfall Threshold (REST) will rely on a pair of metrics intended to capture the intensity and duration of energy shortfall risks in extreme weather scenarios, the RTO told the NEPOOL Reliability Committee on Nov. 19. 

The REST project is an effort to define an acceptable threshold for ISO-NE’s seasonal risk modeling, which will use the RTO’s newly developed probabilistic energy adequacy tool (PEAT). ISO-NE plans to use the REST to evaluate whether additional actions will be needed to support system reliability ahead of winter and summer seasons. 

The modeling features a “multiday rolling-horizon economic dispatch,” which includes both preventive and corrective measures from the RTO and incorporates generator opportunity costs. (See ISO-NE Boosts Energy Adequacy Modeling Capabilities.) 

In the seasonal outlook for the upcoming winter — which marks ISO-NE’s first time using the PEAT in a seasonal analysis — the RTO’s modeling found manageable shortfall risks. (See ISO-NE Sees Manageable Shortfall Risk for Upcoming Winter.) In the future, the REST and its associated metrics are intended to help standardize this evaluation. 

To assess the magnitude of shortfall risks, ISO-NE plans to calculate the normalized unserved energy (NUE), defined as total shortfall relative to demand, over the most extreme 72-hour cases identified by the model. This will indicate what percentage of load would experience shortfall in the low-probability events identified. 

To evaluate shortfall duration, the RTO will calculate the length of the most extreme scenarios, looking beyond the 72-hour window used to calculate intensity. 

Mike Knowland, manager of operations forecast and scheduling for ISO-NE, said the duration and magnitude metrics will complement each other and are both “critical metrics for assessing energy adequacy risk under extreme conditions.” He added that ISO-NE “is still evaluating how best to incorporate these two metrics into its REST proposal.” 

ISO-NE still is taking feedback on the proposed metrics, and it plans to continue stakeholder discussions on the proposal through January or February of 2025. Once the metrics are established, the RTO plans to present an initial proposal on risk thresholds in March or April. 

The establishment of the REST directly relates to how much the region is willing to spend to limit the potential reliability effects of low-probability weather events, and it could raise tough questions about the tradeoffs between reliability, affordability and decarbonization. ISO-NE has indicated it expects the states to play a major role in establishing this threshold. 

NECEC Agreements

Also at the RC, ISO-NE reviewed the Transmission Operating Agreement and Interconnection Operators Agreement for the New England Clean Energy Connect (NECEC) transmission line.  

The 1,200-MW line was solicited by Massachusetts and would facilitate additional imports from Hydro-Québec. Avangrid, the project developer, recently indicated the line has a best-case in-service date of January 2026. (See Avangrid Sues NextEra over ‘Scorched-earth Scheme’ to Stop NECEC.) 

ISO-NE plans to file the agreements with FERC in the first half of 2025 and seeks an advisory vote from the RC on the interconnection agreement, as well as a vote from the NEPOOL Transmission Committee on the transmission agreement.  

The TOA between ISO-NE and NECEC would give the RTO operating authority over the line, which includes responsibility for generation dispatch, real-time balancing, establishing operating limits and exchanging transmission security information to the relevant parties. 

The agreement also includes “a standard ‘grandfathered agreements’ provision,” which includes rights of Massachusetts’ electric distribution companies to receive power from the line, ISO-NE said. These rights can be overridden by “short-term reliability actions.” 

The interconnection agreement between Hydro-Québec and ISO-NE governs the “coordinated operation and scheduling of energy and ancillary services,” emergency energy exchanges, outage scheduling and the “treatment of inadvertent interchange.” 

While the NECEC contracts between Massachusetts’ EDCs and Hydro-Québec are intended to facilitate the one-way flow of power from Canada to the U.S., the line will be capable of sending power in both directions, ISO-NE said. This will allow for emergency south-to-north transmission, although the system impact of these flows still needs to be studied, the RTO added. 

The RC is scheduled to vote on the interconnection agreement in January 2025. 

Planning Procedure for Data Collection

Steven Judd, ISO-NE manager of resource adequacy and accreditation, outlined the RTO’s proposal for a new planning procedure (PP-14) focused on generator data reporting requirements, which is intended “to provide structure and guidance for lead market participants responsible for reporting monthly data.” 

“This procedure will describe the data submission timelines, reporting requirements and validation processes for the required data,” Judd said. He added that standardizing the reporting requirements and guidelines will help ensure system reliability. 

The RC will vote on the proposal in January 2025.