Utility Business Model Reform

The Federal Energy Regulatory Commission on Aug. 20 rejected a proposal from Basin Electric Power Cooperative to establish rate schedules for cryptocurrency operations and other large loads.

Basin failed to show that its proposal to treat cryptocurrency mining loads differently from other loads of similar size is just and reasonable and not unduly discriminatory or preferential, FERC said in its potentially precedent-setting decision.

“Specifically, Basin has not provided adequate evidence to support its assertion that all crypto loads pose a greater stranded asset risk than other loads of similar size,” FERC said.

Basin Electric argued that cryptocurrency mining operations can quickly come and go because they don’t require significant investments in infrastructure or a workforce.

However, FERC said Basin Electric failed to show that crypto operations are more likely than other types of customers to cause stranded assets by packing up shop and moving elsewhere after the cooperative invests in transmission and generating assets to serve them.

“We acknowledge that there are increasing utility and stakeholder concerns related to the growing number of large loads seeking electric service,” FERC said. “We are sympathetic to Basin’s concerns regarding its ability to serve expected load growth reliably and economically. Therefore, our rejection herein is without prejudice.”

Basin Electric, based in Bismarck, North Dakota, is a wholesale generation and transmission cooperative with 140 utility members that serve about 3 million customers.

In March, Basin Electric asked FERC to approve three rate schedules for crypto and blockchain loads as well as a schedule for new non-crypto loads larger than 75 MW. The proposal marked the first time FERC had considered specific rates for cryptocurrency operations, according to Basin Electric.

Under the proposal, for crypto loads in Basin Electric’s service territory in the Southwest Power Pool and Midcontinent Independent System Operator footprints, the cooperative intended to buy energy to serve the loads at market prices and then pass the costs to its members, which would recoup those expenses from the crypto loads, according to FERC. Basin planned to negotiate a rate with its members for crypto loads in the Western Interconnection.

Basin Electric told FERC that it had 200 MW of crypto load in 2023, and it expected more than 1,000 MW in crypto operations to come online in its service territory in the coming years.

In support of adding a “large load” rate schedule, Basin Electric said its members are in discussion with 22 potential projects totaling nearly 5,000 MW, close to the cooperative’s peak load in 2022, according to FERC.

Some of those projects include direct air capture plants, hydrogen hubs and green ammonia factories driven by federal and state legislation, FERC said.

Based on the PJM Interconnection’s last two capacity auctions, it appears the grid operator’s capacity market isn’t up to the task of providing adequate power supplies for its 13-state footprint, according to Brian Tierney, FirstEnergy president and CEO.

Tierney’s comments came during an earnings conference call on July 31, a day after PJM released the results of its most recent capacity auction. The auction produced record-setting prices — with consumers set to pay $14.7 billion for capacity in the 2025/26 delivery year, up from $2.2 billion in the last auction — but only drew in 110 MW of new generation, down from 330 MW in the previous auction.

“I'd call yesterday's print, the canary in the coal mine and the canary didn't make it,” Tierney said. “If you look at what's happened with the [independent power producer] prices over the course of the year, they are all anticipating higher prices in the years going forward.”

The new generation that cleared in the auction was “essentially nil,” Tierney said. “Same in the auction prior to that, it was about 300 MW, again, not the right amount. If people were to respond to yesterday's print and say, ‘Yes, I think it's a good idea to invest in baseload dispatchable generation in PJM,’ it would be six years before that capacity would come online.”

Tierney said he doubts PJM’s capacity market will attract significant power plant investment into the region. “So it’s something we need to figure out,” he said. “I just don't think the PJM construct is going to fix the issue even if it sends some positive price signals.”

FirstEnergy is “actively engaged” in talks on alternative ways to build power supplies, Tierney said. The company is allowed to own generation in West Virginia, but has “wires only” utilities in Maryland, New Jersey, Ohio and Pennsylvania.

“We're open to any construct that would allow us to invest in capacity on something that looks like a regulated basis,” Tierney said. States like Pennsylvania and Ohio could create an agency akin to the New York State Energy Research and Development Authority that could procure power supplies, he said.

“If it looked like a regulated basis and we could offer at a price that would allow us something that looked like a regulated return and allow us to recover on a pass-through basis, fuel and energy, those are things that we'd be willing to do,” Tierney said.

That framework could exist alongside energy markets and retail choice, according to Tierney.

“I also think you could have constructs like NYSERDA or [the New York Power Authority] where they could buy on behalf of the state's residents, and that doesn't have to be an end to competition,” Tierney said. “They can even have auctions where all people could participate in that, utilities, independent power producers, and others.”

Here are three other takeaways from FirstEnergy’s earnings call.

FirstEnergy nears bribery scandal settlements. The Akron, Ohio-based utility company has reached an agreement in principle with U.S. Securities and Exchange Commission staff to settle allegations related to FirstEnergy’s role in the H.B. 6 bribery scandal, according to Tierney. FirstEnergy has set aside $100 million for the potential settlement, the company said.

Also, FirstEnergy is in the final stages of a resolution with the Ohio Organized Crime Investigations Commission, Tierney said. The company set aside $19.5 million for the resolution, which is expected to also resolve the Ohio Attorney General’s civil case against FirstEnergy.

“We're making real progress on putting those legacy issues behind us and focusing on the future,” Tierney said.

Data centers under development in all FirstEnergy states. Compared to 2023, FirstEnergy is studying more than twice the number of data centers over 500 MW this year, according to the company. FirstEnergy has excess transmission capacity to service data centers and other new customers, Tierney said.

However, FirstEnergy’s utilities are experiencing only “modest, steady” load growth, partly driven by a growing number of electric vehicles in Maryland and New Jersey, Tierney said. Weather-adjusted residential sales increased 0.4%, commercial sales jumped 1.3% and industrial sales climbed 1.1% in the last 12 months, according to FirstEnergy’s earnings presentation. 

Earnings plunge on one-time charges. FirstEnergy’s second-quarter income plummeted to $45 million, or 8 cents/share, down from $235 million, or 41 cents/share, in the same period last year, the company said in a press release. Second-quarter revenue grew to $3.3 billion from $3 billion a year ago.

FirstEnergy’s earnings were dragged down by 28 cents/share because it recorded a $207 million “asset retirement obligation” in response to new Environmental Protection Agency requirements for coal ash disposal sites, according to the company’s earnings report filed with the SEC. The company also took a 4 cent/share charge related to the H.B. 6 investigations.

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By BlinkUX

When customers can’t solve a problem on their own, utilities pay the price. 

A typical utility company (with two million customers) receives two to three million customer service calls annually, costing nearly $20 to $40 million, with most calls centering around common customer tasks, such as confirming a bill, restoring power, setting up service, or updating an account. 

Many of these call center experiences are a lose-lose for customers and employees across the industry. Customers become frustrated with never-ending phone trees that lead to various departments, and service representatives lack the supportive technology that makes it easy to manage customer accounts.

A surge in calls, paired with inefficiencies in the call center process, places a significant financial burden on the companies.

Many utility leaders already know that improving the call center is necessary to improve ROI, but are saddled with outdated and aging technology infrastructure  supporting their customer-facing platforms and internal processes.

How can utilities squeeze more value out of the technology they’ve already invested in while building digital experiences that alleviate this outsized burden on call centers?

Unlocking efficiency: The self-service solution

Digitizing the customer journey with a user-centered, logged-in experience gives customers easy access to their most sought-after information, empowering them to resolve issues independently and spend less time on the phone. On the internal side, improving the technology call center employees use (i.e., better dashboards and data retrieval) allows them to resolve customer concerns quickly and lower the average handle time.

By integrating these two experiences into a single platform, customers and employees can seamlessly share real-time data and improve efficiency. Take a power outage for example:

When the power goes out, a customer logs into their self-service portal to report an issue; through automated information retrievals, the customer sees an updated status on the estimated time of restoration without ever having to pick up the phone to call customer service.

This seamless communication between systems reduces the need for follow-up calls, taking pressure off the call center employees and improving customer satisfaction by keeping them informed.

Decreasing call center volume by 10% — Avangrid’s user-centered transformation

Prominent utility company Avangrid noticed significant challenges with its customer experience, leading directly to high operational costs. Customers often needed to call multiple times to activate a service, and over half implied they had never visited the company’s website. 

Avangrid turned to Blink to reevaluate its customer and employee experiences and revamp the processes underpinning the high call center costs. Through in-depth user research, employee interviews, and process mapping, we found key inefficiencies in the internal workflow: manual tasking, back-and-forth communication between siloed teams, and error-prone technical limitations.

To better serve customers, Blink created personalized and responsive mobile and web experiences that allow customers to complete tasks in 10 minutes or less. We also provided a strategic roadmap for technological upgrades and a new marketing strategy to increase awareness around their new digital solutions.

Less than a year after launching these improvements for just one channel in one user journey, Avangrid saw a 10% decrease in call center costs, a 30% increase in app utilization, with 85% eBill adoption and automated account setup.

Getting started: How to improve customer and employee experiences and kickstart cost savings

Digital transformation is unique for each company, depending on the maturity of its current self-service and internal systems. To pinpoint the best opportunities for self-service, consider three key aspects: At what point in the customer journey are customers calling the most (e.g., account changes, payment issues, or outages), and which of these has the highest handling time and lowest IVR containment?

Leaders should prioritize improvements by identifying which parts of their tech stack are likely to break and impact crucial customer interactions. At the same time, implementation teams can also improve operational efficiency in areas unhindered by technology limitations through tools like design systems, customer-centered thinking, and better omni-channel communication.

By improving the experiences that matter most to customers, utilities can build trust, increase customer satisfaction, and lower business overhead costs.

Vertically-integrated electric utilities can benefit from data center demand growth but will also face credit risks unless contractual safeguards and other cost recovery mechanisms are put in place, according to a July 22 report from Moody’s Ratings.

The report names Dominion Energy subsidiary Virginia Electric and Power Co., Pinnacle West Capital subsidiary Arizona Public Service, and Southern Co.’s Georgia Power as utilities well positioned to benefit from higher revenues associated with serving cloud computing, artificial intelligence and other digital services.

Data center electricity demand could double by 2030 to consume 9% of U.S. electricity generation, according to analysis published by the Electric Power Research Institute in May. Some experts, however, doubt that all of the anticipated load growth will materialize as AI-enabling chips and algorithms become more efficient.

After years of stagnant electricity demand, many utilities see opportunity in the rapidly-increasing energy requirements of data centers. But Moody’s report warns that without proper safeguards, utilities will face credit risks in the event new demand does not materialize as hoped.

“The complications of serving new, large-scale data centers leaves utilities exposed to two fundamental risks,” analysts at Moody’s said. “On the demand side, utilities could overbuild system capacity for load that never materializes or that serves the new load for a period of time that is shorter than the useful life of the new power asset. On the supply side, utilities could promise capacity to a data center customer that is not actually available by the time the customer requires it.”

“Cost allocation and rate design are key for financial stability and to avoid cross-customer subsidization,” Moody’s said. “If a data center ceases operations or simply does not use as much power as originally envisioned, some of the infrastructure costs incurred to serve this expected demand could be socialized to other customers.”

Data center demand is rising rapidly, driven in part by AI applications that EPRI says require 10 times or more the electricity of traditional internet searches. Cloud services and crypto currency mining are also contributing to the increase.

But whether high-end demand forecasts materialize is an open question, say some experts, as the technology becomes more efficient. Jim Robb, president and CEO of the North American Electric Reliability Corp., said he doubts all of the load growth being forecast today will materialize, as both AI-enabling chips and algorithms become more efficient.

“In the 90s and early 2000s we had similar concerns around electricity demand that largely didn’t actually occur because the chips got better, the algorithms got better,” Robb said last month in a discussion hosted by the United States Energy Association. “We will see something similar happen with the AI chips ... We’re going to see load growth, but it’s probably not [going to be] as dramatic as we think right now.”

Because the electricity supply contracts between utilities and data centers are signed before construction begins, “a utility is effectively building generating capacity for power that is contracted and reserved for today, but will not be used until later,” Moody’s said. “Generation capacity forecasts are also vulnerable to unexpected customer departures, such as when a hyperscaler tenant decides to move to another location ... or when a colocation landlord has insufficient tenant demand to meet its power contract obligations.”

To minimize the potential for cross-customer subsidization, Moody’s said most state regulators will likely require utilities planning to serve a new data center to “institute safeguards that allocate associated costs to that customer.” Those could include requirements for the data center to pay for engineering and feasibility studies, along with local distribution and transmission integration costs.

Minimum payments for an operational data center, regardless of the actual power used, and early termination payments if the data center were to cease operations before a certain date, are also protections that regulators could put in place, Moody’s said.

Digital technology providers have long been frustrated with what they see as utilities’ innovation-impeding focus on reliability. But rapid load growth and potential artificial intelligence solutions are inspiring collaboration, particularly on ways to use and share power system data. 

Utilities have seen the data on significant projected load growth from transportation, manufacturing, building electrification and data centers. And tech companies like NVIDIA, Microsoft, IBM and Schneider Electric are beginning to understand the regulatory barriers holding utilities back from transitioning to advanced AI computing strategies, executives said.

Digital technologies’ skyrocketing computational power and hyperscale cloud resources are transforming previous assumptions about AI’s potential to learn, execute and optimize system operations, starting utilities on what some are calling the “technology transition.”

“The utility industry is conservative, but it faces clean energy and emissions reduction mandates,” said Marc Spieler, senior managing director, energy, for microprocessor market leader NVIDIA. Advanced computing’s “real time predictions can optimize” decision making on things like bulk system dispatch and maintenance and NVIDIA’s “dedicated modules will apply learning from other industries to the energy transition,” he added.

Utilities have used advanced computing in wildfire mitigation, vegetation management and predictive maintenance, and are beginning to consider its potential to optimize system dispatch, analysts said.

“The technology business model is ‘move fast and break things’ and they haven’t always understood why regulated utilities don’t move as fast,” said Edison Electric Institute General Counsel, Corporate Secretary and Executive Vice President, Clean Energy, Emily Sanford Fisher. “But there seems to be a new spirit of cooperation on solving utility challenges.”

One obstacle may slow this technology transition. Tech companies have seen how innovations in advanced computing from other sectors can maximize AI capabilities. But utilities still must verify that potential and convince regulators that investments in implementing advanced computing capabilities are justified.

The challenge and the potential

The rapidly rising load growth is clear.

“Over the past year, grid planners nearly doubled the 5-year load growth forecast” from “2.6% to 4.7% growth,” a December 2023 Grid Strategies study reported. The 2024 forecast “is likely to show an even higher nationwide growth rate,” driven by investment in new manufacturing, industrial, and data centers, it added.

Broad use of advanced computing is now providing “some decision support to bulk system operators” for managing the new load, said Jeremy Renshaw, senior technical executive, AI, quantum, and innovation, with the Electric Power Research Institute.

But fully optimizing distribution system operations and dispatch “could be one breakthrough or years away,” Renshaw added.

Many tech companies are putting advanced computing to work in hopes of finding that breakthrough.

Tech companies at work

Advanced computing is starting to serve utilities.

BrightNight’s PowerAlpha platform can help design, operate and optimize clean energy projects to significantly increase load factors and reduce costs, said BrightNight Chief Technology Officer Kiran Kumaraswamy. Its machine learning and AI-based algorithms are focused on utility-scale assets, but it does not have “the level of granularity to optimize the distribution system,” he said.

Weather forecasts using machine learning have allowed Amperon clients to buy lower-priced power ahead of extreme events instead of facing elevated scarcity pricing, said Amperon CEO and co-founder Sean Kelly. “A person can’t compute hourly updates on 15-day forecasts and weekly longer term forecasts for up to 28 weather variables at 30,000 locations,” he added.

“Call it machine learning or AI,” but the Neara-built “computerized replica” of the Southern California Edison system will “apply more variables than a human can assimilate,” said Rob Brook, senior vice president and managing director, Americas, at advanced computing provider Neara. It “identifies ways to improve” wildfire mitigation and “removes human error and human cost,” he added.

But while much of the current focus on AI in the power sector is on bulk system and maintenance, one advanced computing-based company appears to be on the verge of a breakthrough in using advanced computing at the distribution system level.

“Utilidata is deploying the first distribution system AI platform,” using a “customized NVIDIA module,” said Utilidata President and Chief Operating Officer Jess Melanson. It is now being installed with Aclara meters, but it will “eventually be used in other system hardware like transformers,” he added. 

Both NVIDIA and Utilidata see “huge opportunity” in power system applications, Melanson said. “Until now, Utilidata analyses have used incomplete, old, or bad data,” but the world-standard NVIDIA chip allows Utilidata’s Karman platform analysis to detail “what is happening on the system, what will likely happen next, and what the best responses are,” he added. 

That level of intelligence at the distribution system level could allow customer-owned resources to play a greater role in reliability and reduce overall customer costs.

A key potential obstruction to realizing the benefits of advanced computing is limited access to utility and private customer data. It is a challenge those in the advanced computing world, including NVIDIA and IBM, take seriously.

Foundation modeling and federated learning

NVIDIA’s software allows advanced computing “to anticipate patterns in the data and identify the next best action,” according to NVIDIA’s Spieler. It could, for instance, allow utilities to have a greater understanding of where outages might occur and do proactive maintenance, several analysts said.

The challenge of utilities not sharing the proprietary data needed to develop a greater and more granular understanding of the power system is real, “but federated learning, which is used in healthcare to protect patient data, can be a solution,” Spieler said. “With federated learning, collaborators can build models of their data and share it at a centralized location,” he added.

NVIDIA FLARE, a federated learning software tool, “builds additional synthetic data to solve new problems,” which answers privacy concerns, Spieler said.

“Utilities take data security seriously,” and must be sure it will be shared “in the right way,” EEI’s Fisher said. “There must be protocols to protect critical energy infrastructure information,” though “it is good news that there are constructive conversations about how to work together to do that,” she added.

Some think federated learning may be too limited a model for the complexities of the power system’s diverse regional uniquenesses and varying resource mixes.

“Foundation models are emerging to expand advanced computing capabilities,” said IBM Global Chief Technology Officer and Solution Leader, Energy, Environment and Utilities, Bryan Sacks. 

Instead of AI components being applied to individual problems, “orders of magnitude more data are pre-trained as a foundation model for multiple problems,” Sacks said. A foundation model could capture the power system’s diversity without divulging any operator’s proprietary specifics. But “the metering and monitoring system data used by utilities for operational decisions is not in current large language models and is protected from being shared externally,” he added.

“For a foundation model to understand power system operations, it needs specific time and place data for each connected asset, but that data must be anonymized,” Sacks said. “IBM has started a working group to build a foundation model to be trained from anonymized data for power system real-time and day ahead operations and long-term planning,” he added.

Different power system stakeholders would be able “to fine tune that foundation model to solve their different problems,” Sacks said. But “regulatory barriers or restrictions on market participants obtaining access to the data needed to train the model is a real concern,” he added.

IBM is engaging global stakeholders to contribute primary research, according to Sacks. It will also engage regulators “to help establish a governance system that will facilitate data sharing,” and build effective “guardrails” to protect the system and the data, he said.

IBM’s recognition of regulatory issues puts it on common ground with what utilities say is their foremost concern.

Utilities and regulators

Utilities seem more realistic than tech companies about the regulatory barriers to advanced computing.

Using advanced computing to optimize the distribution system in real time will require utilities and regulators to have “enough confidence” in it, said Steve Smith, National Grid group head of strategy, innovation and market analytics and president of National Grid Partners Corporate Venture Capital Fund. “We could be there in 10 years or 15 years,” he added.

“Tech companies and utilities have radically different business models,” and “tech companies don’t understand why it takes 10 years to bring new transmission online,” added EEI’s Fisher. It actually only takes regulated utilities “18 months to 24 months to build transmission, but it takes them eight years to site, permit and litigate it,” she said.

Introducing advanced computing will require “concrete evidence” for utilities and regulators concerned about rising rates that “the needed grid modernization expenditures will reduce customer costs,” Fisher said.

“Foundation models have a lot of potential for the energy industry,” and data federation is “absolutely required to derive and harmonize data from disparate siloed utility systems,” said Scott Harden, chief technology officer for global innovation with electric technology provider Schneider Electric.

An ideal power system architecture would be built on a power sector foundation model that captures the key features of its diversity and challenges, Harden said. It would also have much more extensive deployment of phasor measurement units — hardware devices that can record and transmit transmission and distribution system data — as well as “full deployment of smart meters at the system edge, and all data would be federated,” he added.

Building that architecture could begin with regulatory support of “the new computing power and the technologies needed to make it work,” Harden said. It is not yet clear how burdensome the cost and time for deployment would be, “but the more important question is what the cost would be for not deploying it,” he added.

“It is early days for everyone in a big AI space, and the question now is how to navigate that space,” Commissioner Allison Clements of the Federal Energy Regulatory Commission told Utility Dive. Advanced computing applications now in use “can create a positive feedback loop if federal and state regulators drive it,” she added.

“Regulators must have a growth mindset in this moment of change because this is the early part of the messy middle of grid modernization,” Clements said. Utilities “are working rate case by rate case to understand how to make this transition while protecting reliability and affordability,” she added.

“Federal and state regulators need to lean in because AI capabilities are coming,” Clements added. “Whether or not it benefits society or causes problems is up to utilities, policymakers, legislators and other leaders.”

More than 16,200 residential solar-plus-storage systems will participate in Sunrun’s CalReady virtual power plant this summer, ready at a moment’s notice to supply power to the grid when demand peaks on hot evenings.

Participation in the virtual power plant, operated under the California Energy Commission’s Demand Side Grid Support Program, is nearly double the showing for Sunrun’s first-of-its-kind VPP pilot with PG&E last year. That collaboration resulted in “a real power plant” that peaked at 32 MW and averaged 27 MW over a two-hour peak every day for 90 days straight, Sunrun Head of Grid Services and VPPs Chris Rauscher told Utility Dive.

PG&E does not plan to collaborate with Sunrun on VPPs this year, but the companies are “exploring possibilities for future programs … PG&E sees VPPs as an essential part of California’s clean energy future and is actively looking to integrate more VPP resources into our portfolio and improve their performance as a reliable resource,” PG&E spokesperson Paul Doherty said. The utility expects to have approximately 412 MW of VPP resources this year, he added.

Like PG&E, Sunrun’s Rauscher believes VPPs are ready for prime time despite lingering misconceptions stemming in part from the distributed energy industry’s own marketing missteps. 

“We’ve shown that VPPs provide real value to the grid, utilities and customers, but historically [VPPs] have been victims of their own branding,” he said. Rather than “virtual,” Rauscher prefers “distributed” power plants.

Best practices for simpler, more customer-friendly VPPs

With abundant sunshine, high electricity rates, eco-conscious residents and aggressive decarbonization goals, California is ground zero for VPP adoption. The state hosted 24% of all North American VPP projects, Wood Mackenzie said in a report released March 29, 2023. 

But a Brattle Group report released earlier this year put California 34th out of 50 states in a broader measure of utility-led demand-response capacity, behind smaller states with more robust DR incentives for large agricultural, commercial and industrial users. Rauscher believes residential VPPs can help. 

Sunrun, which sells home solar, storage, EV charging and energy management systems, has nearly 1 million customers in the U.S. But the company needs help from utilities and state regulators to harness those resources into VPPs, Rauscher said.

“VPP programs can be overly complicated, and they don’t have to be,” he said.

Well-designed VPP programs typically cover entire states or utility territories, are “open-access or bring-your-own-device” rather than limited to a particular battery type, meter at the battery level and require no special utility software, Rauscher said. As an aggregator, he added, Sunrun has its own VPP management software and can bring “an entire fleet” of Sunrun subscribers to scale bring-your-own-device programs faster.

Straightforward financial incentive programs like CalReady or New England’s ConnectedSolutions can encourage customer participation in VPP programs, Rauscher said. 

State policy can set the stage for VPP growth as well. California’s solar attachment rate jumped from approximately 10% to 60% after the state enacted its storage-friendly NEM 3.0 net energy metering tariff in April 2023, according to a Lawrence Berkeley National Laboratory technical brief. 

Third-party ownership of solar-and-storage systems in California also surged from 11% to 52% during the same period, in part because larger home energy companies like Sunrun — which leases the majority of its systems — accounted for a higher share of installations, the brief said.

“Our primary customer type is not really an early adopter,” but rather a “busy family” looking to save money and access backup power, Rauscher said. Though financially beneficial in markets with performance-based incentives for home energy systems, VPP participation is often a secondary benefit for Sunrun’s customers, he said.

In Rauscher’s view, targeting early adopters is not the most efficient way to drive VPP participation at scale. He worries this approach could reinforce perceptions of VPPs as complex and inconvenient. It’s better, he said, to reassure customers that participation won’t cause any discomfort and won’t fully drain their batteries while ensuring “[they] don’t have to do anything” to enjoy its benefits.

Showing utilities the value of VPPs

Utilities, grid operators and policymakers are paying more attention to VPPs’ potential as the solar industry matures, driving changes in how and when power is produced and consumed, Rauscher said. High solar penetration on the CAISO grid, for example, means “PG&E has a new peak after sundown,” he noted.

Projected load growth is also sharpening the resource-adequacy case for VPPs, which can be assembled faster than a traditional power plant can be built — or time-of-use tariffs updated — and dispatched in seconds. The Sunrun-PG&E pilot took just six months to roll out, faster than “you [can] turn on any peaking resource in the 30-MW range,” Rauscher said.

Meanwhile, Sunrun’s PowerOn Puerto Rico VPP, the largest participant in the island territory’s Battery Emergency Demand Response Program, supports reliability on a grid that experiences frequent generator outages. When supply falters, Sunrun “pushes max power” from the VPP’s more than 2,000 batteries, giving local utility LUMA time to triage the grid without resorting to rolling blackouts, Rauscher said. 

That has happened “a dozen times since last fall,” Sunrun CEO Mary Powell said in a May 1 press release.

PowerOn Puerto Rico’s success shows that “any utility today can have a VPP program,” even one beset by grid reliability issues, Rauscher said. “[Every U.S.] utility is on a spectrum between PG&E and LUMA.”

Along with new research suggesting broader VPP adoption can defer the need for costly infrastructure upgrades — such as a May 2023 Brattle Group report that found 60 GW of VPP deployment could avoid $15 billion to $35 billion in otherwise-needed capacity investments in the next decade — these real-world “proof points” demonstrate VPPs’ value to utilities and grid operators, Rauscher said. 

Rauscher believes utilities, like their customers, ultimately favor simplicity and clarity when considering new systems and technologies. Fortunately, VPPs’ strongest present-day value proposition — flattening demand peaks — is easy to understand and easy for VPP aggregators like Sunrun to customize for different grids or consumption patterns, he said.

“It’s very easy for us to program batteries to charge during the duck curve,” and then discharge in staged cohorts “to knock down peaks sequentially,” Rauscher said. 

The “more sophisticated stuff,” such as locational value, frequency regulation and other grid services enabled by VPP programs like Utah’s Wattsmart, “should come after” peak-shaving and emergency response, he added. 

But Rauscher acknowledges that in a world where VPPs have truly gone mainstream, Sunrun won’t be the only successful model. 

“There should be room for all different approaches and designs,” he said.

Duke Energy is developing a framework for offering clean energy to large commercial and industrial customers in the Carolinas, with an initial focus on Amazon, Google, Microsoft and Nucor, the companies said May 29.

The planned Accelerating Clean Energy tariffs will include financing options that could be used to support emerging technologies such as long-duration energy storage and advanced nuclear power as well as “mega” projects, Lon Huber, senior vice president for pricing and customer solutions, said in an interview.

Duke expects to begin filing new tariffs with utility regulators in North Carolina and South Carolina within a month or two, but the process will occur in stages, Huber said. The clean energy tariffs will be available to Duke’s C&I customers.

The C&I class makes up about 35% of Duke’s overall load in the Carolinas, but it is expected to grow in the next five years as technology companies and manufacturers expand their operations, according to Huber.

The Accelerating Clean Energy program will offer C&I companies a suite of clean energy options to pick from to meet their clean energy goals without increasing costs for other customers, he said. A company would have an individual “lean transition tariff” that could cover, for example, demand response, onsite generation and 24/7 clean energy, according to Huber.

The planned program is multifaceted “because it has to be comprehensive … because there's no silver bullet on clean energy yet, so you need to have a bunch of different technologies that work in harmony to get to deep decarbonisation,” Huber said. “It takes ‘all of the above’ to do this both at a system level but also individualized for a customer.”

The plan includes the potential for various financing options that could enable emerging technology, such as a premium for a resource’s attributes, help with cost overrun protection and low-cost financing, according to Huber. 

“It creates and formalizes a new pillar of support for emerging clean tech and large mega projects, and this is something that really hasn't been standardized or done on any scale before,” he said. “We'll be working it out with these partners, with regulators and other stakeholders on what's the best way to structure a tariff to help capture the variety of different ways a large customer can support these types of emerging or big clean energy projects.”

The companies signing initial memorandums of understanding with Duke have a range of clean energy goals.

Google, for example, aims to run its operations on clean electricity every hour of the day by 2030. “Through collaboration with Duke Energy, the Clean Transition Tariff creates a pathway for us and our peers to bring new, innovative solutions to the forefront faster,” Briana Kobor, Google’s head of energy market innovation, said in a statement.

It’s good that large customers are pushing for increased clean energy options beyond “business as usual” utility supply, but there may be smaller C&I customers and residential customers that would also want clean power beyond what Duke already offers, according to Nick Jimenez, senior attorney at the Southern Environmental Law Center.

Also, the plans by the large customers like Google to acquire clean energy for their facilities may call into question Duke’s recent proposal to add about 2 GW of gas-fired generation to meet rising loads, Jimenez said.

“If there's a tariff coming that allows all of these large corporate entities that have significant climate goals to procure new clean generation for themselves, then we shouldn't be building gas plants to also meet that load,” he said.

Constellation Energy has issued a $900 million, 30-year green bond to finance “maintenance, expansion and life extensions” of its nuclear reactor fleet and other investments “that reduce or avoid carbon emissions or provide other environmental benefits,” the company said in a March 18 news release.

Based on a comprehensive green financing framework released by Constellation last month and structured by Crédit Agricole CIB, this is the first green bond that could be used to finance nuclear energy in the United States, the company said.

“With the nation’s first-ever corporate nuclear green bond issuance as part of our long-term financing mix, Constellation and the market have again confirmed: Nuclear investments are long-term sustainability investments,” Dan Eggers, executive vice president and CFO at Constellation, said in the release.

Constellation’s green bond issue comes as U.S. grid planners forecast a 4.7% rise in electricity demand over the next five years and highlights a growing consensus among utilities and power-hungry industrial users that nuclear power will play an important role in the energy transition. 

“Constellation's green bond issuance is an example of how to support investments in all clean energy, including nuclear energy,” Nuclear Innovation Alliance Executive Director Judi Greenwald told Utility Dive in an email.

Constellation says it is the top U.S. producer of carbon-free electricity, accounting for 10% of the country’s total clean generation. The company operates the United States’ largest nuclear reactor fleet alongside wind, solar, fossil gas, and hydropower generation assets.

Constellation’s green financing framework names several “eligible green categories” that could receive green bond proceeds. 

Among Constellation’s clean energy fleet, the nuclear power category includes “increased capacity through uprates” of existing nuclear reactors and the development and deployment of advanced reactors “that produce energy from nuclear processes with minimal waste from the fuel cycle.” 

The operational emissions reductions category covers fossil gas decarbonization initiatives to keep Constellation on pace with its 2030 emissions-reduction target and 2040 net-zero goal, including carbon capture systems that reduce power plant greenhouse gas emissions to below 270 grams of carbon dioxide per kilowatt hour or by 90% and plant retrofits that enable hydrogen blending. 

Other investment categories eligible for green bond proceeds are clean hydrogen, including electrolyzer and transportation investments; energy storage, including batteries, pumped hydro and “flexible grid and energy capacity” investments; and “long-term and project-specific procurement expenditures supporting programs to bring off-site renewable energy to customers,” such as Constellation Offsite Renewables solutions that combine renewable energy certificates with load-following energy supply contracts. 

A Constellation representative referred questions about specific initiatives that could receive proceeds from the current bond issue to the company’s green financing framework. 

In the March 18 news release, Romina Reversi, Americas head of sustainable investment banking at Crédit Agricole CIB, said Constellation’s bond “will undoubtedly serve as an inspiration for future global nuclear focused green bond issuances.”

Constellation could benefit from such issuances. Company spokesperson Paul Adams told Utility Dive in an email that “we do expect to utilize green instruments in the future” and that Constellation’s nuclear business would likely be the biggest beneficiary.

“It is safe to say that nuclear investments would continue to comprise a large share of the use-of-proceeds going forward given the level of investment we make in that foundational area of our business,” Adams said.

Investor-owned utilities facing increased physical risks from climate change should adopt a three-pronged strategy that includes “reducing damages from physical events, minimizing litigation risk, and expanding capabilities for cost recovery,” S&P Global Ratings said in a November report.

Utility credit downgrades “directly related to physical risks have significantly increased” in the past six years, S&P said. And “the credit quality of utilities with physical risk exposure could come under even more pressure if comprehensive risk-reduction strategies are not effectively implemented.”

From 2005 to 2017, S&P downgraded two North American IOUs due to physical risks from climate change. From 2018 to 2023, it downgraded 19, including utilities impacted by the 2018 Camp Fire wildfire in California, 2021 Winter Storm Uri, 2021 Hurricane Ida, and the 2023 wildfires in Maui.

Utilities hit with downgrades this year include PacifiCorp and Hawaii Electric Light Co., while S&P also revised the rating outlooks to negative for Berkshire Hathaway Energy, Fortis Inc. and Xcel Energy subsidiary Public Service Co. of Colorado.

A major risk to utilities’ credit worthiness is “regulatory lag,” S&P said — the gap between when a utility incurs a cost and when it is recovered from ratepayers. 

“We believe it's important for the IOU industry to significantly increase and broaden recovery capabilities,” S&P said, including through the use of storm reserves, increased commercial insurance levels, self-insurance, development of special wildfire funds, and securitization. 

“We expect that the industry will continue to effectively manage regulatory risk with a focus on reducing regulatory lag,” Gabe Grosberg, managing director of North America Regulated Utilities for S&P Global Ratings, said in an email.

Most IOUs have already implemented some combination of decoupling, formula rate plans, forward test years, multiyear rate cases and regulatory riders over the past decade, Grosberg said. “We expect that the industry will remain proactive.”

Securitization — where utilities issue debt to cover costs, and that debt is secured by a non-bypassable charge on customer bills — is another way utilities can ensure cost recovery. “Because the debt is secured by the high likelihood of customers paying their bills, the associated interest costs are typically lower,” Grosberg said.

But while developing new avenues to recover costs will support a utility’s credit quality, S&P said “this alone without reducing damages from physical events or minimizing litigation risk, would likely not be sufficient to reduce credit risks.”

There are nine civil lawsuits pending against nine utilities because of wildfires, according to S&P’s report.

“While there are differences between states' standards of negligence, we consider litigation a material credit risk that affects the entire industry,” S&P said.

Connecticut regulators and stakeholders are building a new utility regulatory framework to achieve state policy goals and make electricity more affordable but utilities say they could be misguided.

The Connecticut Public Utilities Regulatory Authority, or PURA, phase one final decision (Docket 21-05-15) on performance-based regulation, or PBR, was released April 26, 2023. Like the landmark Hawaii 2021 PBR framework it drew on, the Connecticut decision adopted goals, foundational considerations and priority outcomes for a controversial regulatory “paradigm shift” to a new utility business model.

Connecticut’s “legacy business model,” and traditional regulation of utilities are “fundamentally at odds” with today’s technologies, policies, and accelerating adoption of distributed energy resources,” the decision said. The state’s utilities and regulators fully agree on this premise but differ over the resolution.

“There is potential for PBR to work out well,” but “the current regulatory environment seems overly punitive,” said Douglas Horton, vice president, distribution rates and regulatory requirements, for Eversource Energy, Connecticut’s dominant investor-owned utility. “Lowering the utility return on equity and replacing it with performance incentives” could “have drastic ramifications,” Horton cautioned.

“Utilities should welcome PBR because it gives them tools to earn from better performance,” responded PURA Chair Marissa Gillett. “It specifically tells utilities what is expected of them and how to demonstrate that performance, which is a level of certainty they have never had,” and “more helpful guidance toward earnings than how to achieve cost recovery in a rate case,” she added.

Other states like Illinois and New York have limited and targeted performance-based measures that better align utility and customer interests, but Connecticut is expanding on Hawaii’s work by undertaking even greater comprehensive regulatory reform, analysts agree. Many stakeholders support PURA’s customer-focused plan, but reduced utility revenues could impede urgently needed investment in distribution system infrastructure upgrades, the state’s IOUs said.

Connecticut’s PBR

Like Hawaii, Connecticut’s phase one objective was to begin its new and comprehensive regulatory transformation with key goals and foundational considerations linked to priority outcomes for utilities, Chair Gillett said.

The goals are better utility operations, meeting public policy goals, better customer service, and reasonable, equitable and affordable rates, the final decision reported. It acknowledged the goals “may require” new utility investments that impede achieving affordable rates “in the short-term.” But “tension between regulatory goals is an inherent aspect of utility regulation,” it added.

“Connecticut’s Governor and lawmakers want this regulatory reform because of frustrations with high electricity rates, but they recognize infrastructure investment is needed to reach state policy goals,” Chair Gillett said. Hawaii investors and stakeholders told introductory PURA workshops that “certainty, predictability, and clear rules,” can lead to investment community commitment, she added.

Stakeholders in Connecticut are deep into the first docket of phase two (Docket 21-05-15RE01) of the PBR process, examining how utility revenues will be earned and shared. It could guide “the remainder of the PBR investigation” and the state’s future utility regulation, according to the phase one decision. But it is leading to heated stakeholder differences about whether there are adequate protections for utilities and their customers that do not appear to have easy solutions, most stakeholders agreed.

The overall process will have three phases, expected to be completed by the end of 2024. Discussions on performance metrics, scorecards and performance incentive mechanisms, or PIMs, are getting started as part of the second docket of phase two (Docket 21-05-15RE02). And the concept of a preliminary integrated distribution system planning, or IDSP, design, is being developed in a third docket (Docket 21-05-15RE03). 

As interest in PBR elements, and especially PIMs, accelerates around the country, regulators, utilities and other stakeholders in many states have ongoing work that has informed Connecticut, Gillett and others said.

Other PBRs

There were at least 24 state regulatory PBR actions in the North Carolina Clean Energy Technology Center, or NCCETC, October 26 Grid Modernization policy update. But the many other states working on PBR are taking significantly more limited approaches than Connecticut is taking on, said NCCETC Associate Director, Policy and Markets, Autumn Proudlove.

Many IOUs, including Xcel Energy Colorado, Central Maine Power and Unitil Massachusetts, have proposed PIMs, NCCETC found. PIMs are being studied in Illinois, North Carolina and New Hampshire. Broader PBR proceedings are ongoing in Arizona, Maryland, Michigan, Minnesota and Iowa. In other states, utilities or regulators have considered PIMs for energy efficiency, battery storage and resilience.

The main lesson from other states is a warning, said Conservation Law Foundation, or CLF, vice president and director, Connecticut, Shannon Laun. PBR is “unlikely to be effective without a comprehensive shift from cost-of-service ratemaking to a comprehensive performance-based framework,” she added.

But Connecticut has learned additional important lessons from other states. 

“In the same way New York and Hawaii are still working to improve performance mechanisms, we want a PBR framework that allows making adjustments to PIMs or adding PIMs, Gillett said. “The intent is to communicate to all stakeholders that they can expect changes and how to seek them,” she added.

Illinois equity provisions showed how PIMs can drive equity performance, Consumer Counsel Claire Coleman of the Connecticut State Office of Consumer Counsel added.

“Connecticut is improving Hawaii's work, with the metrics and incentives for equity Hawaii postponed,” said Strategen Consulting Partner, Executive Vice President, and Head of Consulting Services Matthew McDonnell, who acted as legal consultant to the Hawaii commission and is doing the same for PURA.

“In Hawaii, skeptics said PBR was for distribution utilities and in Connecticut they are saying Hawaii showed it is for vertically integrated utilities, but PBR can be designed to suit any market structure,” McDonnell said.

Recent phase two discussions have raised a question many stakeholders agree could determine the direction of PBR in Connecticut: Should utilities have PIMs for outcomes over which they have limited control?

The big debate: Control

An emerging debate over what outcomes utilities can impact may be pivotal, just as it was in Hawaii, analysts agreed.

“It is clear there are different opinions on whether utilities should have PIMs for outcomes they don't view as within their control,” Chair Gillett said. The purpose of this docket is for each stakeholder to provide persuasive evidence to the record supporting their position,” she added.

Hawaiian Electric’s concerns about control “showed additional PIMS would be needed” to create revenue opportunities for the utility “based on performance instead of on traditional cost recovery,” said Strategen Director of Regulatory Innovation Jennifer Potter, a commissioner with the Hawaii Public Utilities Commission during its PBR development and approval.

The utilities’ concern with control and financial interests is understandable, acknowledged Vote Solar Regulatory Director, Northeast, Lindsay Griffin and CLF’s Laun. Some utility control of outcomes is necessary with a PIM, the Connecticut Office of Consumer Counsel agreed in an August filing. But the need for 100% control narrows the potential of PIMs to drive outcomes, Consumer Counsel Coleman added.

Traditional cost-of-service ratemaking has prevented rates “too high for customers,” and rates “not too low for utilities to remain financially sound,” said Eversource Energy’s Horton. “PBR with those goals can align utilities’ incentives with state policy and customer concerns,” he added.

But PURA’s PBR framework would be “punitive if it included penalties for things not within a utility’s control and quantifiable against a measured baseline,” Horton said. Eversource estimates that costs for generation, transmission service, and meeting policy goals leave only about 25% of a customer’s bill in a distribution utility’s control, he added.

Penalties and rewards for managing that 25% “would absolutely be acceptable, but it is not clear if that is PURA’s intention,” Horton said.

Because of PURA’s work on PBR, S&P Global Regulatory Research Associates found, Connecticut’s uncertain regulatory environment for utilities has become “one of the lowest ranked in the U.S.,” Horton said.

PURA’s ratings “will improve significantly once PBR is in place and stakeholders realize it benefits utilities and their customers and meets Connecticut policy goals,” Chair Gillett responded. Meanwhile, “the sky is not falling, and Eversource just reported record-breaking profits,” she added.

But “it is important not to expect rates lower than they are today,” Gillett continued. Significant capital expenditures will be needed to modernize Connecticut’s aging infrastructure, but “PBR can keep rates lower than they otherwise would have been because the utilities will have incentives to achieve the best outcomes for customers,” she added.

The first of Avangrid subsidiary United llluminating’s four core principles for PBR design “is that utilities must have control of outcomes for which PIMs require them to use resources, time and energy,” said Daniel Canavan, vice president, regulatory affairs, for the smaller of Connecticut’s IOUs.

PIMs “should also be based on objective metrics,” that have been “tracked over time” because new metrics could be distorted by “unique events,” Canavan said. And, “PURA should tread cautiously when using customer resources to achieve an outcome not shown by a cost-benefit analysis to provide more customer benefit than it costs,” he added.

Adequate data will be needed to set PIM baselines, both Consumer Counsel Coleman and CLF’s Laun agreed.

“Stakeholders do not want utilities to be accountable for what they cannot control, though 100% control is perhaps a bridge too far,” Laun continued. But the threat to utilities “is not completely clear” because “PBR will only negatively impact the utility if it fails to meet the performance standards,” she added.

Other stakeholders see the utility concern with control as doubts about the viability of eliminating the financial certainty of returns guaranteed by cost-of-service ratemaking.

The real debate: Money

PURA’s phase one decision called for a paradigm shift to equalize utility biases between the capital expenditures that earn returns on equity, or ROE, and less capital-intensive performance-focused expenditures.

Part of regulation is to make utilities perform more “like competitive businesses,” said Regulatory Assistance Project, or RAP, Senior Associate Mark LeBel, the lead author on a new RAP study of PBR’s potential. “Higher ROEs are good policy only if the utility earns them,” he added.

If utilities perform well, “they should expect to earn more than the cost of equity and reward their investors,” but “if they perform poorly, they should expect only the cost of equity, or perhaps less,” LeBel said.

“Discussions about lowering the ROE and replacing it with PIMs are “unsettling,” said Eversource’s Horton. It is not clear that will provide utilities a market-competitive ROE that will “attract investor capital,” he added.

Equalizing incentives for capital expenditures and operational expenditures “would not necessarily increase the utility’s earnings,” Horton said. It “adds a new return component” which could work against affordability and make IOU financials less investor friendly, he said.

PBR could make it “difficult to attract the capital needed to upgrade Connecticut’s aging infrastructure,” Horton continued. If PIMs are inadequate to meet utilities’ revenue requirements, failing infrastructure could cause PBR to “collapse under its own weight,” he said.

The utilities’ concern about their revenue requirements is legitimate, said Strategen’s McDonnell. “Hawaii spent almost two years setting its revenue mechanism,” and Connecticut “may spend the entire next phase of the proceeding” addressing that concern, he added.

But the goal of PBR is to protect the utility's financial integrity while also accurately calibrating risk between utilities and customers,” Strategen’s McDonnell continued. “That does not mean zero utility risk” or “insulating utilities from the responsibility to perform at a high level to earn PIMs,” he said.

PBR requires utilities to face more uncertainty about their revenue requirements than traditional regulation, McDonnell acknowledged. Guardrails that ensure protection against unintended outcomes can allow them to focus on understanding the risks and opportunities in the rewards and penalties for performance, he said.

PURA understands the importance of the utilities’ financial integrity, McDonnell said. “The cost-of-service revenue requirement is the starting point in building a PBR framework that allows utilities to learn to secure earnings with PIMs,” he added.

“The utilities financial stability and integrity are important to PURA because state law obligates it to recognize how that bears on utilities’ services to ratepayers,” Chair Gillett said. “But I am an activist regulator because a regulator with a different regulatory philosophy is needed to meet the policy goals of the Governor and the legislature,” she added.

“PBR will provide the certainty and clarity that investors want and that utilities need to work with it,” Gillett continued. And “Connecticut utilities’ credit and financials will remain stable or improve when PBR is fully implemented, just as they did for Hawaiian Electric,” she added.

Utility companies will likely continue selling non-core assets and shares in their companies to avoid issuing equity as they prepare to spend billions on energy infrastructure, Moody’s Investors Service said Nov. 8.

“Some planned asset sales are driven more by a company's desire to reduce business risk in conjunction with its efforts to improve its balance sheet and to avoid additional debt issuance,” the credit ratings agency said.

Proceeds from utility asset sales totaled $5.8 billion in the first half this year compared to $2.2 billion in equity issuances, according to Moody’s. Last year, utility asset sale proceeds totaled $7 billion compared to $8.8 billion in equity issuances, the ratings agency said.

Moody’s highlighted pending utility transactions that will lead to significant proceeds in the next 18 months. They include:

• FirstEnergy agreeing to sell an additional 30% stake in FirstEnergy Transmission for about $3.5 billion;
• Dominion Energy agreeing to sell its natural gas distribution utilities for $9.4 billion and its 50% stake in the Cove Point liquefied natural gas facility for about $3.3 billion; and,
• Eversource Energy preparing to sell its 50% share in three offshore wind projects totaling 1,758 MW.

Also, NiSource, American Electric Power and Duke Energy are divesting assets to pay for growing capital investment plans, Moody’s said.

The five-year capital investment plans for a group of 28 rated utility companies totals $745 billion, according to Moody’s. The companies with the largest five-year capital spending plans are: Duke at $65 billion, Pacific Gas & Electric at $51.6 billion, Dominion at $47 billion, Berkshire Hathaway Energy at $45.3 billion and Southern Co. at $40.5 billion.

However, state regulators may push back on proposed spending by utilities in an effort to protect customers from rising electric rates, according to Moody’s.

Also, high interest rates are making debt issuances more costly so utility regulators may heighten their scrutiny of how utilities finance their rate base growth because they typically recover the cost of debt through customer rates, Moody’s said.

“Amid high interest rates, a focus on customer affordability and regulatory desires around rate stability, US investor-owned utilities will likely increase their use of equity as a funding source to maintain a balanced mix of both debt and equity,” Moody’s said.

Overall, the 28 utility companies Moody’s assesed will need at least $25 billion in equity in each of the next two years to fund their investment plans, up from about $15 billion last year. Utility companies may need additional equity to support their credit quality, the ratings agency said.

In the next two years, Moody’s said it expects cash flow from operations for the utility companies it analyzed will range between $99 billion and $105 billion, which will not keep pace with cash outflows.

“Regulatory support, as well as a company's ability to navigate state legislative developments and to develop capital investment plans that are aligned with [a] state's decarbonization initiatives, typically ensures timely recovery of investment costs, which increases internally generated cash flow,” Moody’s said.