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December 27, 2024

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Stakeholder Soapbox: The Prevalence of Rent-seeking in Public Utility Regulation

By Kenneth W. Costello

Public utility regulation falls within the lexicon of economic regulation with its main objective to protect consumers from the monopoly power of a utility. The presumption is that public utilities provide essential services that require strong service obligations and price controls. It also is inferred that a single private firm would be preferable to allowing the entry of a number of potentially competing firms.  

In recent years, state utility regulators have exhibited much more political posturing that deviates from their original mission, often mandated or coerced by the legislature and governor. For example, we have seen regulators approving higher utility rates to advance the agendas of politically influential interest groups like social justice activists. Many regulators have become advocates of the environmental, social and governance (ESG) movement that has spread widely across the corporate and political worlds.   

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Kenneth W. Costello |

The upswing in special-interest demands afflicting most states comes from clean air advocates, vendors and others who are not utility customers. Their presence in the regulatory arena has proliferated to squeeze out public interest goals. Some interest groups regard anything less than a maximum effort to tackle climate change and a net-zero carbon future as a social injustice. But an obsession with these objectives has threatened long-held policy objectives, like reasonable and stable utility rates, economic growth and reliable utility service. California and several other states have gone down this primrose road.  

Politicization of utility regulation — that is, using regulators to gain favors — means many things, mostly bad; that is, more special-interest influence with the potential to jeopardize the public interest by:  

    • further emphasizing myopic effects;
    • making more difficult execution of the “balancing act” long held by regulators, with the addition of new interests and social objectives;
    • parting from the charge of regulation to serve the long-term interest of utility customers;
    • escalating rent-seeking costs and increasing the likelihood of subsidies and mandates; and
    • spreading the cost and risk for uneconomical, politically driven investments onto utility customers.  

Although politicization does not inevitably mean a negative outcome for society, it typically ends up with one interest group unduly affecting governmental actions that harm the public good.  

The culprits are politicians and bureaucrats who envision utilities as “social agencies” by extending their domain beyond a for-profit commercial enterprise. Utilities have had to offer special rates and other concessions to low-income households; accommodate, facilitate and even subsidize their competitors (e.g., net metering) and renewable energy; invest in uneconomic new technologies where cost is subordinate to other factors (e.g., the effect on carbon emissions); subsidize energy efficiency; and achieve clean-air targets beyond federal and local mandates. These demands on utilities, which are costly, have complicated their ability to operate in their proper role as profitable entities providing basic services reliably and economically.  

Public utility regulators, like other government entities, are susceptible to rent-seeking efforts by advocates with different agendas to achieve self-serving outcomes paid for by utility customers. The electricity industry in particular has several features that make it highly visible and disposed to politics and interest-group lobbying. The major ones are a substantial environmental footprint, a large user of energy (e.g., fossil fuels), provision of an essential service and high social cost from service interruptions.  

As pressures intensified for more new social investments, driven largely by politics and other outside forces, utility regulators have had to wrestle more with the economic inefficiencies of cost socialization and subsidies. Subsidies are especially socially damaging, typically the product of increased politicization; they are:  

    • unfair to funding parties (namely, utility customers);
    • economically inefficient by conveying false price signals; and
    • unfair to competing energy sources like natural gas.  

One common bizarre practice is for electric utilities to subsidize their customers to use less of their service via EE initiatives; and to subsidize their competitors like rooftop solar. Overall, subsidies almost always fail a cost-benefit test when viewed as a public good.  

Because of these developments, regulatory failures and capture have magnified. Historically, capture referred to undue influence by utilities at the expense of their customers and the public interest. More recently, capture has encompassed new stakeholders with the same effect of harming utility customers and the public interest.  

This modern-day capture has sprung from the progression of certain interests with utilities protected against financial concerns. We are seeing utility customers being “taxed” with surcharges and “innovative rate mechanisms” guaranteeing that utilities recover their investments directed at the general public, rather than just utility customers.  Think of subsidies to clean technologies that reduce carbon emissions, which benefit the whole world. One must ask, why should utility customers alone pay for those investments?  

Much of what we see today that passes for the public good really is rent seeking, which benefits a distinct minority at the expense of the majority. Overall, regulators need to think hard about distinguishing truth from virtue. We know from experience that government often rationalizes its actions as morally unobjectionable when in fact it bequeaths handouts to a narrow group at the expense of the public good. 

Skepticism is called for when government officials declare, for example, that we would all be better off if we consume less electricity and other fossil fuels and produce more renewable energy. Such claims may be out of sync with what is best for society.  

Regulators should ask themselves whether utilities’ primary customers are on the short end of the stick. Are customers funding the advancement of social objectives through inflated electricity rates and even lower service reliability without compensatory benefits? These actions are likely to have a regressive effect by disproportionally burdening below-average income households. For example, the beneficiaries might mostly include high-income households while the payers are households of lower incomes. Think of subsidies funded by utility customers for advancing rooftop solar, electric heat pumps and electric vehicles.  

What we see is politics and interest groups driving change toward a clean, lower energy-consumption future, whereas utilities are not necessarily opposed, but demand changes in rate-making and other regulatory practices to protect their financial interests. Regulators, pressured by utilities and advocates of clean energy, have acquiesced and even exhibit zeal about this development. They commonly pass through cost increases and revenue losses to utility customers. Regulators should ask: What are the benefits to the majority of utility customers from “footing the bill” for subsidizing clean energy technologies and EE?  

We can make one glaring observation: Special-interest groups are the true catalysts of change, with government cultivating their agendas. Either for ideological or monetary reasons, these groups want to shape the future, and the sooner the better. Their interest encompasses only themselves — not the broader public interest. Their vision of the future entails filling up their pockets or satisfying their favorite doctrine.  

Yet the job of utility regulators is to balance the interests of different groups to best serve the public good. That places extreme urgency on state utility regulators, to enforce the “balancing act” that trades off different legitimate interests for the common good — a difficult task, yes, but one that society expects regulators to do.  

That naturally leads to the question of whether society requires too much from electric utilities. We expect utilities to maintain financial viability, provide reliable and resilient service, make electricity affordable to all customers, adopt and accommodate new technologies that compete with their core business, decarbonize their generation portfolio, and promote less usage of electricity by their customers. No other private business comes to mind in which society expects firms to tackle such a wide range of social issues.   

As an illustration, take the case of utility subsidies for EE. While government officials and utilities won’t admit it, the best evidence shows that their ratepayer-subsidized EE programs are likely to fail a cost-benefit test.   

The plain question policymakers should ask is whether the market for EE technologies is free of major “market failures.” If so, one can conclude the marketplace is providing energy consumers with the right incentives to “purchase” EE when it is in their self-interest, and energy consumers are rational and unobstructed in making decisions by market barriers. After all, if society feels consumers are rational in making decisions on what other goods and services to buy, what would cause the same consumers to be irrational when they decide on EE investments for their homes and businesses?     

Regretfully, the best evidence has had little effect on utility EE programs because the public is unaware of the transfers; EE is widely popular; and politicians, bureaucrats and utilities can enjoy their support. Utilities gain, for example, goodwill with their regulators without suffering any financial consequences or even profiting as a consequence because of new rate mechanisms like revenue decoupling and a premium rate of return for complying with EE mandates.    

We should be mindful of the words of Milton Friedman: “One of the great mistakes is to judge policies and programs by their intentions rather than their results.” For many observers, utility (government-subsidized, as well) EE programs transmit good feelings (i.e., virtual signaling) about using less energy. Instead of expanding the subsidies for EE — which many today advocate for — we should give serious consideration to phasing them out or, preferably, eliminating them all together.  

Another example of a misdirected policy is the recent efforts to artificially induce energy consumers to switch from fossil fuels for home use and transportation to electricity, which observers call electrification. Proponents of electrification — notably politicians, bureaucrats, electric utility companies and environmentalists — prefer it to happen sooner than later and be accelerated by subsidies and other governmental enticements. Some even advocate mandated electrification or natural gas bans to prevent hyperbolic climate catastrophes. Many view electrification as essential to combat climate change or even as a free lunch.   

As with most things, there are two sides, and electrification is no exception. Most champions of electrification fail to consider, or intentionally ignore, its downsides. A major one is the high cost to households and businesses of converting from natural gas and other fossil fuels to electricity — a cost that can amount to thousands of dollars for an individual home. Another downside stems from the efficiency losses in energy markets from prematurely advancing electrification with subsidies (sometimes funded by utility customers with the approval of state utility regulators) and governmental mandates.  

Instead of artificially bolstering electrification with subsidies and mandates, policymakers should allow electric technology to evolve on its own without government support. Technology will determine the ultimate success of electrification — not subsidies and other governmental actions that largely are politically driven to serve special interests.  

To conclude, one philosophical inquiry is whether bad policies descend from society’s ignorance of their effects, or do strong-armed and self-interested politics always prevail, regardless of the public interest?   

An optimist would say truth will prevail. One perception of truth relates it to policymakers’ decisions that rely on impartial information to balance the interests of different stakeholders for the public good. Yet such optimism appears far from compelling when one observes the myriad policies adopted by society and their consequences for the public good. 

Kenneth W. Costello is a regulatory economist and independent consultant.  

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FERC Allows Dominion’s FRR Resources to Shift to PJM Capacity Market

FERC on July 5 granted a complaint from Dominion Energy to allow planned capacity resources to shift their participation from the Fixed Resource Requirement (FRR) alternative to the Reliability Pricing Model (RPM) capacity market without being subject to a newly instituted notification requirement (ER24-2197). 

Dominion argued there’s a disparity between the Dec. 12, 2023, deadline for planned resources — those still in development, but expected to begin operation prior to the start of the delivery year — to notify PJM of their intent to offer into the 2025/26 Base Residual Auction (BRA) and the May 17, 2024, deadline for entities to terminate their participation in the FRR alternative. The utility included 80 MW of planned resources in its 2025/26 delivery year FRR plan prior to notifying PJM it planned to terminate its FRR election April 30, after which the RTO told Dominion those planned resources had missed the BRA participation notification deadline and could not submit offers. (See PJM MIC Briefs: Nov. 1, 2023.) 

The company asked FERC to either grant it a waiver from the notification requirement or rule that PJM’s Reliability Assurance Agreement (RAA), when read together with tariff Attachment DD, impinges on FRR entities’ ability to enter the RPM. 

The commission determined the notification deadline does not apply to planned resources being constructed by an FRR entity when the deadline passes and that Dominion’s planned resources can be entered into the 2025/26 auction, which is scheduled to be conducted July 17. (See FERC Approves PJM Capacity Auction Delay.) 

“As an initial matter, we find that the plain language of Section 5.5 of Attachment DD does not expressly address whether FRR entities at the time of the notice-of-intent deadline are subject to the requirements, including the notice-of-intent deadline, provided for therein,” the commission said. “However, we find that under a sensible reading of the tariff and as a practical matter, the provision did not apply to Dominion’s planned generating capacity resources, as Dominion was an FRR entity, not a capacity market seller, as of the relevant deadline.”  

Subjecting FRR resources to a deadline in December would not comport with transitional process the commission approved in PJM’s Critical Issue Fast Path (CIFP) proposal to overhaul its approaches to risk modeling, accreditation and Capacity Performance penalties, FERC said. Recognizing that insufficiency and capacity deficiency penalties were increased in the changes, FERC also greenlit a process for FRR entities to shift to the RPM with at least two months’ notice ahead of the 2025/26 auction. (See FERC Approves 1st PJM Proposal out of CIFP.) 

In that order, “the commission explained that PJM proposed to allow FRR entities and their resources to transition from FRR to the auction on only two months’ notice,” FERC said. “PJM’s interpretation of Section 5.5 would prevent former FRR entities from transitioning resources planned in accordance with their FRR obligations to the BRA.” 

PJM agreed with Dominion’s argument that the deadlines were misaligned and resulted in unintended consequences for FRR entities seeking to enter the RPM. But it said it could not resolve the issue unilaterally without a commission order. 

“More particularly, the mismatch of the deadlines prevent FRR entities, such as Dominion, from effectively participating in RPM auctions by excluding their planned generation capacity resources from participation in the RPM auctions when terminating the election of the FRR alternative, which could result in adverse consequences to Dominion and its ratepayers,” PJM wrote in a June 17 filing. “Additionally, this could also produce inaccurate market signals by not properly reflecting actual demand and supply.” 

Dominion stated that its decision to return to the capacity market was in part driven by the increased FRR penalties, as well as the short timeline to adjust to the new requirements following the commission’s approval of the CIFP changes. 

“Taking into account the difficulty in satisfying this requirement due to the delivery year being roughly one year away, as well as the significant capacity accreditation reforms and increased penalties for FRR entities approved by the commission and detailed above, Dominion notified PJM on April 30, 2024, that it was terminating its FRR alternative election,” Dominion said in its complaint, filed June 4.

Commissioner David Rosner, who joined FERC last month, participated in the order. The newest commissioner, Lindsay See, did not. 

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Stakeholders Battle over Battery as Proxy in NYISO Demand Curve Reset

NYISO stakeholders are divided over consultants’ proposal to use a two-hour battery as the peaking plant in the ISO’s capacity market demand curve, as part of its quadrennial demand curve reset for 2025-29. 

Comments on the draft report, produced by Analysis Group and 1898 & Co., were due last week. Generators generally were opposed to the proposed proxy unit, while state agencies were in support. 

To set the curve, NYISO looks at the gross cost of new entry, the cost of a hypothetical new peaking plant and the likely revenues the plant would earn from participating in the capacity market. The difference between likely cost and likely revenue illustrates what the hypothetical peaking plant would need to earn from the capacity market to support entering the market. 

The current curve uses General Electric’s H-class frame gas turbine as the peaking plant. (See FERC Approves NY Demand Curve Reset, Rejects 17-Year Amortization.) 

The consultants found that a two-hour battery energy storage system (BESS) “represents the highest variable cost, lowest fixed-price peaking plant that is economically viable,” the report said. “To be economically viable and practically constructible, a BESS would use lithium-ion technology and a modular purpose-built enclosure form-factor.” 

The cost of the two-hour BESS assumes a 15-year amortization period and additional costs for capacity augmentation over the life of the battery system to “ensure consistent performance.” 

The Independent Power Producers of New York wrote that they strongly oppose the selection of a two-hour BESS as the proxy unit in all locations of the New York Control Area. The IPPNY wrote that two-hour BESS has an inherent limited operating capability, which means it “cannot meet transmission security-based requirements.”  

“The Hochul administration says we need 10-hour batteries and up. The NYISO System & Resource Outlook … says we need long-duration storage of four hours and up,” said Richard Bratton, director of market policy and regulatory affairs for IPPNY. “I think that we agree that on a foundational basis that a two-hour battery can’t meet reliability needs for the system, and yet we’re seeing a push for it just because it is the cheapest option.” 

Luminary Energy, an energy market consulting firm, recommended the Analysis Group consider “no less than a four-hour BESS or the simple cycle gas turbine” as the proxy unit. 

“A two-hour BESS would not be able to mitigate the reliability risks and needs outlined by the NYISO’s Comprehensive Reliability Planning process,” Luminary wrote. “A two-hour BESS would not provide sufficient energy optionality for grid operators to manage volatile and uncertain real-time conditions and presents a high risk to grid operators of depleting the energy from the asset before the most critical systems present themselves.” 

The New York Battery and Energy Storage Technology Consortium commented that choosing the two-hour unit would contribute to volatility in the capacity market. The selection potentially would result “in an abrupt drop in capacity prices as the demand curve is determined on a new, lower-cost proxy unit.” 

Others questioned the Analysis Group’s appraisal of site leasing costs in New York City. Jones Lang LaSalle Americas, a commercial real estate services and investment firm, commented that the methodology used in the draft demand curve “underestimates the expected site leasing costs.” It recommended using the required rate of return of 7.2 to 7.45%. This would cover the higher site leasing costs for industrial uses required by new generation. 

Support, with Some Caveats

The New York Department of Public Service supported the selection of the two-hour BESS as the peaking unit, saying the draft demand curve supported the policy goals of the Climate Leadership and Community Protection Act requirements and the state’s goal of 6 GW of energy storage statewide by 2030. 

The DPS did ask that the consultants include revenues and incentives from outside the wholesale market when calculating the net cost of entry for a new peaking plant. The department cited numerous state programs that would compensate clean energy resources for their clean attributes in meeting the state’s CLCPA goals. 

Comments submitted on behalf of New York City were more ardently supportive of the draft demand curve and agreed with the selection of the two-hour BESS as the peaking unit of choice.  

“Frankly, based on ‘the numbers,’ selection of a two-hour BESS as the proxy peaking unit technology is the clear-cut choice with no close or even obvious alternative,” the city commented. “Moreover, it is beyond rational dispute that a two-hour BESS based on lithium-ion technology is in fact a viable technology.” 

The New York Transmission Owners wrote that they agreed with the consultants that the two-hour BESS required less capacity revenue than the other technologies to support its entry to the market and that it had the lowest fixed costs. But they urged the consultants to shift the amortization period to 20 years as opposed to 15, citing the industry’s increased experience with battery storage units. 

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Google: AI, Data Centers Drive 13% Rise in GHG Emissions

The introduction to Google’s 2024 Environmental Report begins with a list of the company’s efforts to cut energy consumption and greenhouse gas emissions at its data centers worldwide; for example, Google’s sixth-generation Trillium computer chip is 67% more efficient than its fifth-generation predecessor. The company also has “matched” or offset 100% of its global energy use with renewable energy purchases for seven years in a row and in 2023 signed contracts for an additional 4 GW of renewable power, more than in any previous year. 

Such milestones notwithstanding, Google reported a 13% year-over-year increase in greenhouse gas emissions last year, driven primarily by its supply chains and the voracious power demands of the artificial intelligence programs now chewing up electrons at its data centers, the report says.  

The company’s 2023 emissions totaled the equivalent of 14.3 million tons of carbon dioxide, up 48% over its 2019 base year, and the report says Google expects further increases “before dropping to our absolute emission reduction target” — net zero by 2030. 

The report explains the difference between Google’s assertions of 100% clean energy and its increased emissions in terms of global versus regional accounting: Google tracks its clean energy purchases on a global, annual basis, but the Greenhouse Gas Protocol ― which the company and many other corporations use to track emissions ― monitors on a regional basis.  

“In some regions, we purchase more clean energy than our electricity consumption (such as in Europe), while in other regions, we purchase less (such as in the Asia-Pacific region) due to significant regional challenges in sourcing clean energy,” the report says. 

Such discrepancies reflect the complicated tradeoffs and uncertainties that Google and other tech giants ― including Amazon, Microsoft and Meta ― now face as AI becomes ubiquitous across almost every sector of the economy and every aspect of daily life. Like Google, Microsoft and Meta have committed to cutting their GHG emissions to net zero by 2030, while Amazon Web Services (AWS) has set a 2040 deadline. 

These companies often argue for AI’s potential to cut emissions by optimizing the operation of energy systems, from raising efficiency and cutting electric bills in individual homes to streamlining permitting and interconnection processes to improving visibility across the grid itself. 

But realizing that potential comes with a cost: A single AI search can use up to 10 times more power than a standard, non-AI search, which could lead to a doubling of power demand from data centers by 2030, according to a recent report from the Electric Power Research Institute (EPRI). (See EPRI: Clean Energy, Efficiency Can Meet AI, Data Center Demand.) 

In the past, increases in data center power demand have been mitigated largely by advances in chip, software and data center efficiency, the EPRI report said. But even with new efficiency measures, like Google’s, the industry is struggling to offset the exponential growth in demand from AI. 

Google estimates that in 2023, its data centers used 24 TWh of electricity, or about 7% of the power demand of the world’s data centers, which the International Energy Agency has estimated at 240 TWh to 340 TWh. Overall, cloud and AI data centers represent between 0.1 and 0.2% of global electricity use, the Google report says. 

The impact of this increased demand in the United States has become a point of intense discussion across the high tech and electric power industries as more and more states compete to draw in “hyperscale” AI data centers. Historically, power demand for individual “enterprise” data centers has varied from 5 MW to 50 MW; hyperscale centers start at around 100 MW and can exceed 700 MW.  

Northern Virginia’s “Data Center Alley” — home to an estimated 150 hyperscale data centers — accounts for 25% of total U.S. power demand from data centers, and a recent study predicted the area would need to add 11 GW of new power by 2030 to meet predicted growth. (See Report Shows Wide Range of Data Center Demand Scenarios for Virginia.) 

A list of new load additions in development in the MISO service territory includes a pipeline of nine data centers ― including two Google facilities in Indiana ― totaling 5.7 GW.  

Getting to 24/7 CFE

Google’s ambitious targets for using carbon-free energy (CFE) make its net-zero goals even more daunting. The company has pledged to power all its facilities with 24/7 CFE ― matching supply and demand on an hour-by-hour basis ― again by 2030. It also is committed to buying clean power that comes “bundled” with energy attribute certificates (EACs), similar to renewable energy certificates (RECs), to ensure it is adding new carbon-free projects to the grid.  

Microsoft and other companies, including utilities, sometimes supplement their purchases of clean energy by buying unbundled EACs, which typically come from existing renewable energy projects and may not add new clean power to the grid. 

Google now averages 64% CFE at its data centers worldwide, with varying levels of clean energy going to facilities in different grid regions, the report says. Data centers in 10 grid regions — including MISO — are running on 90% or more CFE, while those in the Middle East, Africa and Asia are well under 20%. Total electricity demand at the company’s data centers increased by 3.5 TWh, or 17%, in 2023, the report says. 

Beyond making its data centers more efficient, Google also has developed a “carbon-intelligent computing platform” that allows the company to shift computing tasks to other times or locations with more available CFE. 

Familiar roadblocks to faster procurement and deployment of CFE have proved harder to shift, including interconnection delays, higher interest rates and development costs, and supply chain backlogs, according to the report. But Google also has become an active partner working with developers and utilities to pilot new business models aimed at untangling some of these problems. 

The company partnered with LevelTen Energy, an online energy marketplace, to develop a streamlined process for issuing requests for proposals and negotiating power purchase agreements through standard PPA terms included upfront in the RFP. The new approach has cut the time from RFP to signed PPA from 10 to 12 months to about 100 days, allowing Google to finalize contracts for 1.5 GW of power, according to an announcement on the LevelTen website. 

Similarly, the company is looking for ways to de-risk and accelerate the commercialization of emerging technologies that can provide the clean, dispatchable power its data centers need. In June, Google and NV Energy unveiled a “clean transition tariff,” now pending approval by the Nevada Public Utilities Commission. Under the proposed tariff, Google would pay a fixed premium for locally generated CFE ― from an enhanced geothermal project developed by Fervo Energy ― to match demand hour for hour at a Nevada data center. 

Google has framed both initiatives as replicable models that can be used in other U.S. or global markets. 

Looking to the future, an emerging theme in industry discussions is the need for the responsible use of AI, both socially and environmentally.  

Defining “responsible use,” however, will be an evolving and intensely debated target. The Google report notes that the speed of technological transformation driving AI means “historical trends likely don’t fully capture AI’s future trajectory.” Further, as AI is integrated across global economies, “the distinction between AI and other workloads will not be meaningful.” 

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Calif. Lawmakers Send $10B Climate Bond Measure to Nov. Ballot

California lawmakers voted July 3 to send a $10 billion climate resilience bond measure to voters in November, and clean energy advocates are hailing the measure’s investments in offshore wind and transmission projects. 

With a 33-6 vote in the state Senate and a 66-6 vote in the Assembly, the legislature passed Senate Bill 867, known as the Safe Drinking Water, Wildfire Prevention, Drought Preparedness and Clean Air Bond Act of 2024.  

Lawmakers had worked over the weekend to hammer out the measure’s final language. (See Calif. Lawmakers Consider $10B Climate Resilience Bond.) 

Senate President Pro Tem Mike McGuire (D), serving as acting governor, signed the bill the same day it was passed, just hours before the deadline for the Nov. 5 ballot. 

McGuire said in a statement that the funds would help communities protect themselves against wildfires, floods and extreme heat. 

The $10 billion measure includes $3.8 billion for safe drinking water and drought, flood, and water resilience, as well as $1.5 billion for wildfire prevention and forest resilience. There’s also funding to address sea-level rise, promote nature-based climate solutions and encourage climate-smart farms. 

At least 40% of the funds must go to projects that benefit vulnerable residents or disadvantaged communities.  

The bond measure allocates $850 million to clean energy projects, including $475 million for offshore wind — primarily building, expanding and upgrading port facilities. 

Adam Stern, executive director of trade group Offshore Wind California, called the funding “an important down payment” toward achieving the state’s offshore wind targets of 5 GW by 2030 and 25 GW by 2045. The California Energy Commission’s offshore wind strategy estimates that $11 billion to $12 billion will be needed to upgrade ports to meet the 2045 goal. 

“If the Golden State wants to go big on offshore wind, we must make the necessary investments to upgrade our ports to assemble and deploy these floating wind turbines,” Stern said in a statement following the Legislature’s votes. 

Advanced Energy United, a national business group, said it worked with lawmakers to allocate $325 million for clean energy transmission projects, which may include reconductoring and other grid-enhancing technologies. An additional $50 million is designated for long-duration energy storage and distributed energy resources, including virtual power plants.  

Edson Perez, the group’s California policy lead, called the funding for DERs and VPPs “crucial,” though he said more money would be needed to maximize the technologies’ benefits. 

“This investment will strengthen our electricity grid’s reliability, flexibility and affordability, which is critical for preventing blackouts during extreme heat and wildfires,” Perez said in a statement. 

The climate resilience ballot measure will need a majority vote to pass. The measure would authorize the state to sell up to $10 billion in bonds, which would be paid back with interest from the state’s general fund. 

A legislative analyst estimated that principal and interest costs for the bonds would be $19.3 billion, assuming a 30-year term and a 5% interest rate. 

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NJ EV Incentives Target Low-income Buyers

New Jersey soon will reopen its $30 million Charge Up electric vehicle (EV) incentive program for a fifth year with new rules that offer the top incentive — $4,000 — only to low- and moderate-income buyers. The just-passed state budget also tops up the program with an extra $20 million. 

The New Jersey Board of Public Utilities (BPU) on June 27 approved the $30 million as part of a package of $82.5 million in EV-related expenditures in the agency’s clean energy budget, among them incentives to support charger installation at tourist sites and in multiunit dwellings, as well as local government EV purchases and charger installations. 

The BPU has not released a date for the start of the Charge Up program, which will include the $20 million in additional funds put in the state budget by Gov. Phil Murphy (D), for a total of $50 million. But the launch is expected in two phases: The first one — offering a $2,000 incentive to all vehicle buyers — will start early this month, and the additional $2,000 for low- and moderate-income buyers will be available in the fall. 

The shift in incentive strategy comes as New Jersey seeks to continue its recent relatively strong EV sales amid signs they are weakening in other states. The state also is considering how the program can have the deepest impact in a market in which buyers now can access much larger $7,500 federal incentives under the Inflation Reduction Act. (See Will Final Rules on EV Tax Credits Help or Hurt US Market Growth?) 

EV sales also face new headwinds in New Jersey after Murphy on June 28 ended an exemption from sales tax for EV buyers, and the legislature added a fee that can add $1,000 to a purchase. 

Launched in 2020, the Charge Up program in recent years has offered incentives of up to $4,000 for buyers of vehicles priced less than $45,000, with up to $1,500 awarded for vehicles priced between $45,000 and $55,000. BPU officials developed the strategy after most of the incentives in the early years of the program went to buyers of Tesla models, the higher-priced vehicles on the market. 

In setting the $45,000 threshold for the maximum incentive, BPU officials said they wanted to target “incentive-essential” buyers, those with lesser economic means who opt for a cheaper vehicle and might not buy an EV without the subsidy. (See NJ Ramps up EV Purchase, Charger Installation Programs.) 

That level of incentive now will be open only to lower-income buyers. 

“We’ve restructured the program for vehicle incentives to help better ensure that incentives are going to support people who otherwise wouldn’t be able to switch to electric,” BPU President Christine Guhl-Sadovy said before the board approved the 2025 clean energy budget. 

Explaining the new program structure at a May 31 public hearing, Cathleen Lewis, e-mobility program manager for the BPU, said “incentives for EVs with an MSRP of $55,000 or less will have a fixed incentive of $2,000.” Income-qualified applicants then will be eligible for an additional incentive in the amount of $2,000.  

To be eligible, single tax filers who buy an EV must have incomes below $75,000, and joint tax filers must earn no more than $150,000, she said. The median household income for EV owners in New Jersey was $89,703 in December 2023, according to Atlas Public Policy. 

To date, Charge Up has awarded $120 million, supporting the purchase of more than 36,000 vehicles. Funding in the Charge Up program historically has been exhausted within months of its opening. In a June 14 letter to the board, the New Jersey Division of Rate Counsel argued that demand is so strong that a maximum incentive of $2,500 would stimulate sales and allow the funds to last longer.  

EV Sales Escalation

The shift comes after EV sales in New Jersey increased dramatically in 2023, even as some analysts say EV sales are slowing across the country. 

New Jersey added 62,426 new EVs on the road in 2023 – up 68% over the 2022 figure, based on figures from the Department of Environmental Protection, according to ChargEVC-NJ. ChargEVC called the increase the “largest year-over-year growth ever recorded based on DEP figures in the state,” and the organization, which promotes EV adoption, and other EV supporters say the figures show New Jersey is in reach of its goal of having 330,000 EVs on the road by the end of 2025.

Yet supporters say that trajectory may be undercut by several measures adopted by the state this year, which could slow the uptake of EVs.  

Murphy’s signing of the bill, A4702, that ended the exemption from state sales tax for EV buyers followed the enactment of a law, A4011, that added a $250-to-$290 fee to the price of an EV that was designed to help pay for road repairs the way the registration on gas-fueled vehicles does. Because the fee will be paid at purchase for four years at once, critics say it will add more than $1,000 to the price of an EV from July 1, the start of fiscal 2025. (See New Jersey Lawmakers Back $250 Annual EV Fee.) 

The two measures followed the state’s adoption of California’s Advanced Clean Cars II rule, which will require all new light-duty vehicles sold in the state to be zero emission by 2035. The rule requires manufacturers to make zero-emission vehicles (ZEVs) a steadily increasing portion of their car sales, starting with 35% for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. (See New Jersey to Adopt Advanced Clean Cars II Rule.) 

Aside from funding for the Charge Up program, the state budget adopted by the legislature on June 30 included $10 million to help local governments buy EVs and chargers, $9 million to help install chargers in multiunit dwellings and $15 million to help school districts buy electric buses. An additional $2 million will go to a pilot program to use EV school buses for vehicle-to-grid energy storage and $6 million for a pilot depot to provide chargers for medium- and heavy-duty vehicles. 

Consumer Charging Concerns

ChargEVC calls the EV fee and the phaseout of the sales tax exemption “unforced errors” that could slow the state’s upward trajectory of EV sales. The organization says the number of light-duty electric vehicles increased by 66% in 2023, to 151,827, and the number of plug-in hybrids grew by 91%. Still, EVs in 2023 made up only 2.2% of all vehicles in New Jersey, ChargEVC said in April. 

The state added roughly an additional 18,000 vehicles in the first three months of 2024, up 11%, according to figures compiled by the DEP. EVs accounted for about 2.6% of all vehicles in the state, the DEP figures show. 

“We certainly hope the $4,000 incentive for low-income buyers will help” boost sales, said James Appleton, president of the New Jersey Coalition of Automotive Retailers (NJCAR). “The sad truth is that the State of New Jersey is giving with one hand and taking away with the other.” 

He said he does not believe New Jersey’s EV demand is as robust as ChargEVC thinks, and added that the Advanced Clean Cars II rule requires car companies to sell 110,000 EVs in 2024, well above what the state achieved in 2023. 

“Consumers are kicking the tires on EVs, but dealers tell me that price and the absence of clear and consistent state and federal incentive programs make it hard to get and keep consumers interested in actually pulling the trigger to buy,” he said. One reason EVs are selling in New Jersey is that “car buyers in [New Jersey] are generally more affluent and the higher price for most EVs isn’t as serious a barrier in [New Jersey] as elsewhere.” 

But the state’s shortfall in charging stations is affecting sales, he said in an email. PHEVs are selling well because “consumers are going into dealerships looking for an EV and driving away with a PHEV because of price and because of concerns about publicly available, reliable charging infrastructure.” 

New Jersey ranked fifth in the nation by number of electric vehicles, not including PHEVs, according to figures for 2023, the latest figures compiled by the U.S. Department of Energy’s Alternative Fuels Data Center (AFDC). New Jersey had 125,317 all-electric vehicles, compared to 1.178 million for top-ranked California, 231,518 for second-place Florida and 210,433 for third-place Texas.  

But New Jersey lags in charging ports. The state is 14th in the nation, with 3,834 ports, compared to California with 46,501 ports, according to AFDC figures. New York is third, with 10,048 ports. New Jersey has one port for every 32 vehicles, compared to one for every 25 vehicles in California and one for every 10 vehicles in New York, the agency’s figures show. 

Doug O’Malley, director of Environment New Jersey, said the state policy is “schizophrenic.” 

“EV sales have been increasing tremendously over the course [of] the last two years. We’re really starting to see … the EV market take off,” he said. “And we’d expect to see that sales will continue to increase because of the lowering [of] prices and because of, you know, the expansion of charging infrastructure.” 

But the removal of the tax exemption and the addition of the EV fee “essentially cut the knees off that program unnecessarily,” he said. “You’re literally basically putting up a stop sign for people that are on the fence on whether they’re buying an EV.” 

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2 New California Bills Could Accelerate Decarbonization

The California Assembly Utilities and Energy Committee on July 2 advanced two new bills that could accelerate the state’s decarbonization goals by helping residents and multimeter customers transition to renewable energy.  

Senate Bill 1221, introduced by Sen. Dave Min (D), would advance efforts to retire gas-fired power plants, requiring gas companies to submit a map of all potential distribution line replacement projects by July 2025.  

The bill also directs the California Public Utilities Commission (CPUC) to designate priority neighborhood “decarbonization zones” that consider the concentration of gas distribution line replacement projects outlined in the maps by January 2026. The commission would then be required to establish a voluntary program to implement pilot projects within each zone to facilitate cost-effective decarbonization with an emphasis on equity.  

“The pilot projects enabled by SB 1221 will engage neighborhoods, support residences with zero-emissions appliances and create quality jobs, paving the way for disadvantaged communities to access clean homes and indoor air,” Edson Perez, policy lead at Advanced Energy United, said in a press release. “SB 1221 presents an opportunity to meaningfully and thoughtfully advance the state toward its climate goals and help residents transition away from a system destined for cost increases.”  

The legislation adds to the portfolio of other efforts led by the California Energy Commission and the CPUC to retire gas generation, including the CEC’s targeted electrification and strategic gas decommissioning, which involves transitioning whole neighborhoods to electric power instead of using a mix of services. (See Targeted Electrification ‘Promising but No Silver Bullet’ for Gas Cost Dilemma.) 

Additionally, SB 350, signed into law in 2020, requires the CPUC to focus utility energy procurement decisions on reducing greenhouse gas emissions by 40% by 2030. In January 2020, the commission opened the Long-Term Gas Planning Rulemaking procedure, which helps chart a course through the energy transition with an emphasis on gas infrastructure retirement.  

A second bill moving through the Legislature, SB 1374, focuses on rooftop solar and could reverse the CPUC’s controversial decision to block schools, farms and apartment buildings from using the solar power they generate to offset their utility bills. The legislation, written by Sen. Josh Becker (D), would amend the CPUC’s law, allowing schools and apartments in California to fully use the solar energy generated on their property.  

The first iteration of the bill included churches and farms, but following the committee’s recommendation, it was narrowed down to just schools and apartments. The amended legislation would require the CPUC to ensure that any contract or tariff related to customer-generators with a renewable electrical generation facility meets certain requirements, including allowing customers to elect to aggregate load.  

“Enabling more distributed energy resources like solar and storage will help grid reliability and affordability by keeping power close to consumers and making investments in transmission and distribution as efficient as possible,” Perez said in the press release. “By enabling schools and other multimeter customers to take full advantage of their solar and storage investments and save money on energy costs, SB 1374 saves everyone money. We must think about affordability at a systemwide level and with a long-term vision to ensure an energy transition that works for everyone.”  

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NYISO Studying How to Update IRM Calculation to Account for Offshore Wind

The New York State Reliability Council’s mathematical model for calculating the state’s installed reserve margin (IRM) every year will need to be updated as more offshore wind and major transmission lines come online, NYISO told stakeholders last week. 

“That would be a reasonable expectation as we get further along,” said Dylan Zhang, manager of resource adequacy for NYISO. “We’re seeing the curve dynamics fall apart, so the methodology isn’t maybe as robust.”  

During the June 26 meeting of the NYSRC’s Installed Capacity Subcommittee, members discussed the breakdown of the model in possible future scenarios where 9,000 MW of offshore wind, with accompanying transmission, would be available to New York City and Long Island.  

The IRM is the minimum amount of capacity beyond the forecasted peak demand that must be procured to satisfy the loss-of-load expectation. For the 2024/25 capability year, which began May 1, the council set the IRM at 22%. 

The rather complex method for setting the IRM is known as “Tan45.” Hypothetical IRMs are plotted against possible minimum locational capacity requirements (LCRs) for New York City (zone J) and Long Island (zone K), based on how much generation from upstate zones is “shifted” into them. The low point of the curve (representing the lowest possible IRM and highest possible LCR) for each zone is determined by simply excluding generation from certain upstate zones from the total amount of statewide capacity. 

An anchor point of each curve is then selected by applying a tangent of 45 degrees at its sharpest bend, and then another formula using the values where the tangents intersect the curves determine the Tan45 inflection points. The final IRM is calculated by averaging both curves’ Tan45 points and rounding up to meet the LOLE.

OSW Tan45 curve comparison | NYISO

But in future scenarios with the addition of significant amounts of generation flowing into the city, NYISO “observed that the current process to establish the low point no longer appears to operate as intended,” the ISO’s Lucas Carr told the subcommittee. 

With less generation needing to be shifted over to zones J and K, the curves flatten. Under one scenario studied, the “low point” of the IRM on the curves reached as high as 39.99%. 

“In the older system, when we had more transmission limitations, if you had capacity down in New York City load centers, that provided more reliability than a given megawatt in Buffalo,” said Mark Younger, president of Hudson Energy Economics. “Not surprisingly, it has problems when you start to add a whole bunch of transmission because now the reliability value of an additional megawatt in New York City is not nearly as much as it was before.” 

Members of the Installed Capacity Subcommittee said they would need to develop an alternative model before the current methodology breaks down. “Rather than waiting to drive off the edge of the cliff to figure out what to do next, let’s figure it out now,” one member said. “This is trying to do some forward planning. … But we’re good, for now.” 

“When the subject was first brought up about [dropping Tan45], that was not well received,” another committee member said. “But it’s not a matter of, ‘Oh we don’t like Tan45.’ It’s a matter of there are issues … coming up.” 

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Wildfire Prompts CAISO’s 1st Transmission Emergency of Summer

CAISO declared its first transmission emergency of the summer July 2 as a fast-spreading Northern California wildfire forced Pacific Gas and Electric to de-energize transmission lines near one of the state’s key hydroelectric facilities.

By the morning of July 3, the Thompson Fire had burned more than 3,000 acres in Butte County, prompting the California Department of Forestry and Fire Protection (Cal Fire) to request PG&E de-energize circuits from the Wyandotte Substation that were in or near the fire, as well as several transmission lines, leaving about 4,200 residents without power.

Paul Moreno, a spokesperson for PG&E, told RTO Insider the utility was able to repair a few transmission lines, including one serving Lassen Municipal Utility District. The remaining three were expected to be restored July 4, but Moreno was unsure when staff will be able to re-energize the Wyandotte circuits.

“We’ve been closely tracking the weather forecasts and have geared up on staffing and are ready to respond to any heat-caused power outages,” Moreno said.

PG&E also announced a public safety power shutoff (PSPS) that went into effect the morning of July 2, leaving 2,200 Northern California residents across eight counties without power. While the utility hoped to restore power July 4, it was unsure of the timeline because of wildfire danger and dry winds.

The transmission emergency, which the ISO extended into July 3, comes at the start of an extended heat wave that will bring soaring temperatures to cities across much of the West, including Sacramento, Portland, Las Vegas and Phoenix.

While the ISO assured its power grid is stable and supply shortfalls weren’t forecast through July 3, high heat in the interior of the state could set temperature records.

“We are continuing to closely monitor long-duration extreme heat in California, with triple-digit temperatures forecast in the valley over the next several days,” an ISO spokesperson said. “We are also watching wildfire activity across the state. While fires are not currently affecting the bulk electricity system, wind direction can change quickly and impact generation and our transmission system.”

CAISO also issued a restricted maintenance operation (RMO) alert effective midnight July 3 through midnight July 10 to caution utilities and transmission operators to avoid taking equipment offline for routine maintenance. The RMO can help assure all generators and transmission lines are available to supply higher loads, according to the ISO spokesperson.

Hyatt Hydro Plant Taken Offline

The Thompson Fire started outside Oroville the morning of July 2. By late afternoon on July 3, the fire had grown to more than 3,500 acres and was 0% contained, according to Cal Fire. The agency has issued mandatory evacuation orders for many zones in Butte County and evacuation warnings were in place for others. The cause of the fire remains unknown, and there have been no reports of fatalities.

In a statement posted on X on July 2, the California Department of Water Resources (CDWR) said the fire ignited just north of its Oroville Field Division facilities and that “several” state water project facilities were under evacuation orders from the Butte County sheriff.

Among those was the Hyatt Powerplant, a 645-MW hydroelectric facility near Oroville Dam that CDWR temporarily shut down because of de-energized PG&E transmission lines. Plant staff were relocated to the nearby Thermalito Pumping-Generating Plant, the agency said.

The department was able to resume Hyatt’s operations on July 3, it said in a follow-up post. Staff found minor damage to nonessential infrastructure at the dam, but “there was no damage to the dam or spillway structure, and Oroville Dam remains safe,” it said.

No Alarms on West Coast, but EEA 2 Declared Inland

Despite the forecast for extended heat, utilities across the region have not expressed alarm about energy shortages, likely in part because of the lower demand seen during holiday weekends.

The Sacramento Municipal Utilities District, which is not part of CAISO but participates in the ISO’s Western Energy Imbalance Market, said this week it was prepared to meet electricity demand, “barring a grid or other emergency such as wildfire or unexpected significant power shortfall.”

Portland General Electric noted on its website that it too is prepared for “high temperatures and high electric use.” Portland-based Pacific Power urged its customers to take steps to conserve power during peak periods between 3 and 7 p.m. to reduce strain on the grid.

Nevada-based NV Energy hasn’t issued calls for conservation, but the utility did alert customers about its newly implemented PSPS policy in the event of high fire danger.

But in New Mexico, according to a source, the El Paso Electric balancing authority area in the SPP reliability coordinator footprint on July 2 was placed into an Energy Emergency Alert 2, in which the RTO requests emergency energy from available resources, activates emergency energy programs and calls for conservation from consumers.

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PURPA Case Offers FERC Early Glimpse of Post-Chevron World

FERC is getting an early taste of life without Chevron deference after the Supreme Court remanded a case involving the Public Utility Regulatory Policies Act (PURPA) back to an appeals court. 

In a brief order issued July 2, the Supreme Court granted a petition for writ of certiorari in Edison Electric Institute v. FERC, remanding it to the D.C. Circuit Court of Appeals for further consideration in light of Loper Bright Enterprises v. Raimondo. (See Supreme Court Ends Chevron Deference to Administrative Agencies.) 

The case involves a solar plant Broadview Solar developed in Montana that FERC certified as a “qualifying facility” under PURPA, which are supposed to be rated at 80 MW or less. The power plant can produce up to 160 MW, but it can only deliver up to 80 MW to the grid. 

FERC certified the facility as a QF under PURPA over the protests of EEI and its member NorthWestern Energy, the utility required to buy its output. The complainants argued that a plain reading of PURPA indicates that any resource that generates more than 80 MW cannot be a QF and that FERC exceeded its authority in the approval. 

The D.C. Circuit previously upheld the decision, finding that PURPA was unclear on the exact meaning of “power production,” so it deferred to FERC’s interpretation. (See DC Circuit Upholds FERC on Montana PURPA Project.) 

In their petition to the Supreme Court, EEI and NorthWestern argued that the lower court misapplied Chevron by rushing to agency deference while ignoring the plain language of PURPA. 

“But if Chevron is properly understood to condone the result reached here, then this case is further evidence that the time has come to reconsider Chevron by, at the very least, clarifying its limits,” they said in the petition filed last June. 

FERC based its approval on its “sendout approach” for PURPA qualifying facilities that measures how much power they can ship out to the grid, it said in a response filed with the Supreme Court in September. The commission has been using the sendout approach since 1981. 

“The net power that a qualifying facility sends out to the grid is also the amount of power that is ‘capable of being avoided on the [purchasing utility’s] system,’ i.e., the amount of power that the purchasing utility need not get from elsewhere,” FERC said. 

While the solar array at the Broadview facility can produce up to 160 MW, and a co-located battery can discharge up to 50 MW for four hours, it has to convert that direct current electricity into alternative current through an inverter connected to NorthWestern’s grid that is just 80 MW. 

The facility as a whole can supply no more than 80 GW of grid-usable alternating current to the grid at any one time. 

“The battery does not permit the facility to supply more than 80 MW to the grid at any time,” FERC said. “But the array-and-battery design does mean that the Broadview facility can more consistently deliver 80 MW of power to the grid than the facility would be able to deliver using only a 160-MW solar array with the same inverters.”