Utility Business Model Reform

A Dec. 23 order by Hawaii's utility commission may lead to the most significant change in power system regulation in U.S. history by giving Hawaiian Electric new control over its future, proceeding participants said.

Hawaiian Electric will become the first U.S. investor-owned utility to transition away from cost of service (COS) regulation. Over five years, it will move from earning revenues based on capital expenditures to Performance Based Regulation (PBR) and financial stability, based on limited rate-based revenues and rewards for achieving public policy goals and cutting customer costs.

The commission's order, developed over an almost three-year stakeholder proceeding, aligns "the company's actions, the customers' experience and Hawaii's ambitious clean energy goals," Hawaiian Electric spokesperson Jim Kelly said in a statement. It provides "the right incentives to aggressively move ahead with modernizing our company and Hawaii's energy system."

Hawaii's regulators and stakeholders acknowledged they are asking a lot of their electricity provider.

"The utility has faced more regulatory innovation in the last ten years than over the prior century, and this holds its feet to the fire," said Murray Clay, president of the Ulupono Initiative, which led advocacy for a key PBR component. COS regulation "has protected Hawaiian Electric and this asks it to act more like it is in a competitive environment."

To support the utility through this unprecedented transition, the order includes reviews, opportunities to revise, and allowances for limited guaranteed returns. But the commission asserted its intention to make PBR work and "not to return" to traditional regulation.

If successful, this PBR framework could be a template for U.S. power system transformation, said commissioners from the mainland who helped design the framework. 

Keys to Hawaii's PBR

The PBR order accomplished three guiding principles set out in the first phase of the proceeding (Docket 2018-0088) to align utility and customer interests and state policy goals, Hawaii Public Utilities Commission Chair James Griffin told Utility Dive. It offers "day 1 customer savings," streamlines the utility's "regulatory burden," and provides safeguards to protect the utility's finances and credit ratings.

PBR's challenging acronyms, detailed below, begin with a multi-year rate plan (MYRP) that reduces the regulatory burden by lengthening rate case intervals from three years to five years. That will allow the utility to use rewards from performance incentive mechanisms (PIMs) and earnings sharing mechanisms to innovate and expand benefits to customers and shareholders, Griffin said.

Day 1 Savings

"Hawaii has very aggressive clean energy goals, but we also have a very high cost of energy," Griffin said. "The revenue cap regulation will be a strong incentive for cost control."

The Annual Revenue Adjustment limits revenue growth to inflation and returns on specially allowed expenditures minus earnings shared with customers. But the utility has PBR mechanisms to increase earnings during the five-year rate plan.

Customers get a 0.22% share of those performance earnings. In the first five-year MYRP, they also get an average of $22.16 million/year in the form of a further reduction in the utility's allowed annual revenues to compensate them for waste found by a commission-ordered management audit in Hawaiian Electric's last general rate case. Together, these should result in lower monthly bills.

In the fourth year of the MYRP, the commission will "comprehensively review" the performance and make necessary adjustments, the order reported.

"There will be day one savings when this goes into effect and we expect to see more savings as the other opportunities are used," Griffin said.

Utility opportunities

The performance incentive and earnings sharing mechanisms will act as rewards for over-performing and penalties for under-performing, and the accelerated Renewable Portfolio Standard (RPS-A) PIM is the "centerpiece," Griffin said.

The RPS-A, on which Clay's Ulupono Initiative took the advocacy lead, rewards Hawaiian Electric for adding renewables faster than scheduled under Hawaii's 100% renewables by 2045 mandate.

The utility will get $20 for every MWh exceeding the annual mandate for 2021 and 2022, $15 for every extra 2023 MWh exceeding the annual mandate, and $10 for 2024 and 2025 MWhs above the mandate for that year. The intent is to "maximize cost-savings early" and also to make renewables "part of Hawaii's economic recovery from the COVID emergency," Griffin said.

In many places, accelerating renewables reduces utility costs and rates, and "in Hawaii, renewables back out much more expensive fuel oil," said Gridworks Senior Fellow Mike Florio, a former California utilities commissioner and advisor to Hawaii's commission.

Initially, there was a concern about "narrow, programmatic, activity-based PIMs that suited parties' particular interests" but led to "a suboptimal portfolio of incentives," Ulupono's Clay said. But Ulupono modeling showed the RPS-A keeps revenue growth at inflation while growing large-scale renewables and meeting objectives like reduced rates and increased distributed resources, he said.

There are also PIMs rewarding the utility for streamlining distributed resources' interconnection and using them to provide grid services, he added. Other incentive mechanisms can accelerate pilots, improve the use of advanced metering, expand energy efficiency, and protect reliability. But "the value of non RPS-A PIMs collectively is far less than the $10 million/year value of the RPS-A," he said.

"The RPS-A is the first U.S. clean energy PIM," said Earthjustice Managing Attorney Isaac Moriwake, representing clean energy advocate Blue Planet Foundation. "After debate about its calculation, even the utility ended up supporting it."

Careful consideration is needed for the final PIM metrics, to be designed by a PBR stakeholder working group by June 1, 2021, cautioned Hawaii Consumer Advocacy Executive Director Dean Nishina. "Having more than one PIM that focuses on the same activity or measured outcome could provide mixed signals to the utility."

And if Hawaiian Electric earns PIMs for streamlining interconnections and for accelerating deployment of the renewables it is interconnecting, that is "double rewards for a single activity," Nishina said.

But the grid services PIM may have a big market impact, said Rábago Energy Principal and former Texas electric utilities regulator Karl Rábago. "It recognizes that there must be a transactional framework or tariff in which the utility compensates the system value of distributed resources," he said.

The utility has long used the order's performance metrics on reliability and customer engagement, the statement from Hawaiian Electric's Kelly said. But "others are new and promising for the company and its customers, including incentives for creating innovative pilot programs and achieving renewable energy goals faster."

Utility safeguards

The first safeguard of the utility's finances is the Annual Revenue Adjustment, Chair Griffin said. The automatic annual rate adjustments "reduce some of the regulatory lag" of getting revenues to the utility through rate cases, allowing investment in innovations that can earn PIMs, which benefits Hawaiian Electric, its customers and its investors, he said.

A second safeguard is the Earnings Sharing Mechanisms, "which protect the utility and customers from excessive earnings or losses," according to the order. Hawaiian Electric must share with customers, through bill credits or charges, earnings over 3% above its currently set return on equity (ROE) of 9.5% or losses more than 3% below it.

"If Hawaiian Electric's ROE drops too low, it gets money shared back and if the ROE goes too high, customers share in the returns," Ulupono's Clay said.

A third safeguard is the commission's discretion to use a "Re-Opener" provision to consider adjusting or modifying elements of the order, Chair Griffin said. It would be "triggered" if rating agencies forecast "a potential credit downgrade below investment-grade status" or if the utility's earnings or losses are excessive, he added.

The PBR framework's other safeguard is the Exceptional Project Recovery Mechanism. It allows the utility "above Annual Revenue Adjustment" recovery of costs for certain large expenditures, with "case-by-case" commission approval, the order said. Because it allows recovery of operations and maintenance and program costs as well as recovery for capital expenditures, it can "mitigate" biases toward spending in COS, the order said.

While the commission is committed to PBR and many proceeding participants are supportive, they will be watching indicators of Hawaiian Electric's performance.

Things to watch

First reactions from the financial community are inconclusive. Analysts with Moody's and Credit Suisse who followed the proceeding did not respond to Utility Dive queries.

The order "derisks downsides" such as "PUC denial of new capital investments or lower authorized ROEs," acknowledged a Dec. 24 Bank of America financial analysis. But "upside risks" like opportunities for expanded ROE kept Hawaiian Electric's rating at "underperform considering considerable execution risks."

The biggest thing to watch, however, may be whether elements that protect the utility's financial stability preserve COS regulation and defeat the new paradigm. It is a reasonable concern, but the order shows the commission's commitment to PBR will prevent it, stakeholders said.

COS regulation "drove the capital expansion that created the modern grid, and its capital bias is strong," said Earthjustice's Moriwake. But this order is "tough love" because it includes a revenue cap, ambitious but doable goals, and safeguards to protect the "transformation to a new paradigm." 

And the Exceptional Project Recovery Mechanism will impact no more than a third of the utility's capital expenditures, added former Colorado Public Utilities Commission Chair and Blue Planet advisor Ron Binz. "Two-thirds of its returns will depend on how Hawaiian Electric runs its business."

Given the utility's "past tendency" to rely on approval of "special cost recovery" from the commission, the consumer advocate's office will be watching "applications for additional cost recovery" through the Exceptional Project Recovery Mechanism, said Nishina.

Though stakeholders agreed with Nishina's hesitations, many said this PBR framework could change U.S utility regulation.

"This is the most consequential decision in the commission's history in terms of its comprehensive scope and leadership vision," Moriwake said. 

Three former mainland utility commissioners agreed.

A national template

Hawaii's high energy costs make it uniquely able to benefit from the transition to renewable generation, acknowledged Binz. But "this approach to PBR can be transferred to other utilities because this is regulation of the company, not fuel costs."

Unlike traditional regulation, PBR can drive utility innovation to accomplish "societal goals like reducing emissions, and improving customer engagement without compromising safety or reliability," he added.

Wires-only companies could use MYRPs for ongoing infrastructure builds and Hawaii's Exceptional Project Recovery Mechanism for large investments, he said. Regulators in the Southeast can extend the period between rate cases and offer performance incentives to drive innovation. Even utilities like NV Energy and Xcel Energy can use PIMs "to increase earnings by being smart," he added.

California needs "business model reform to move beyond disincentives to distributed resources," GridWorks' Florio said. "The RPS-A is an incentive to distributed resources growth, and the grid services PIM is a hidden gem because it will increase the use of renewables plus battery storage and accelerate natural gas plant retirements."

Hawaii's PBR can be a national model, agreed Rábago.

"This order may thread the needle by thinking big picture, but [also by] asking what can in reality be done," he said. "An example is that it extends three-year rate plans to five years instead of the originally proposed eight years, but includes specific language indicating the transition will last beyond five years."

It is "based on precedent and years of work" and "begins building a bridge to a new regulatory paradigm that gives the utility achievable goals and safeguards and protects investors and private sector participation," Rábago said. "It will take five tough years of overseeing complex metrics and a difficult cultural transformation at the utility, but it is a good plan for building that bridge."

Utilities' ability to protect reliability in today's rapid transition to variable, distributed generation faces two key barriers and regulators' help is needed to overcome them.

Advanced demand response (DR) can use the flexibility of customer-owned technologies to meet the balancing challenges of the changing supply mix, regulators and utility executives agreed during an Oct. 20 symposium hosted by The Brattle Group. Utility pilots are revealing what works, but also showing how technology and incentive structures are keeping flexible loads, such as customer-owned solar and smart thermostats, from supporting reliability.

"Load flexibility can shift energy use to when it costs less, shape energy use to match renewables' availability, and to allow them to meet other system needs," said Minnesota Public Service Matt Schuerger during the symposium. "And it can be a cost-effective solution for reliability by offsetting other investments in generation with lower-cost customer-owned distributed technologies."

That cost-effectiveness may soon make the flexibility of advanced DR valuable.

"As transportation and building electrification initiatives grow, flexibility might become necessary for utilities to manage cost," said symposium co-chair and Brattle Group Principal Ryan Hledik. In fact, "the regulatory approval of grid modernization investments to support electrification, decarbonization, and increase utility revenues could be justified by the cost-effectiveness of flexibility."

Utility advanced DR pilots are growing, but regulators have only begun to resolve the two key barriers of finding technologies to manage distribution systems and creating incentives for stakeholders, Brattle's symposium revealed. Inadequate system controls and compensation mechanisms have left load flexibility's enormous potential to meet U.S. reliability needs little used, participants agreed. 

The potential of advanced DR

Almost 70% of today's approximately 60 GW of U.S. DR capability comes from traditional commercial-industrial load management, according to a June 2019 Brattle study. But new demand-side smart technologies, utility control and communications technologies could transfer market dominance to residential customers within the next ten years, according to Brattle.

The resulting nearly 200 GW of cost-effective load flexibility from existing and new DR could meet up to 20% of the estimated 2030 U.S. peak load, avoiding over $15 billion annually in system costs, Brattle found. Existing incentives and technologies can deliver an estimated 40% of the new load flexibility capacity, but the other 60% will require new technology and incentive solutions.

The bulk of the 2030 value will be in avoided capital expenditures for new generation, Brattle estimated. Avoided expenditures for transmission and distribution infrastructure and for ancillary services will also add value.

Regulators can advance load flexibility in two key ways, symposium participants agreed. Regulators can approve trials to improve hardware and software, like advanced distribution management systems (ADMS) and distributed energy resource management systems (DERMS), needed for utilities to manage customer-owned smart devices.

They can also give utilities the incentive to move away from investments in generation and other system infrastructure by allowing them comparable returns for investments in customer-sited flexible technologies, the symposium speakers said.

Driven by competition from distributed energy resources (DER) providers, new utility programs have shown load flexibility can be reliable. "The question is no longer whether load flexibility is reliable, but whether utilities, regulators and stakeholders want to do it," Brattle's Hledik said. "Some are starting to understand how demand-side resources can lower system costs and increase their systems' flexibility."

Utilities and regulators are demonstrating that new understanding through pilots.

The technology barrier

Pilots are a way to break down the technology barriers, utilities and regulators told the symposium.

Xcel Energy Minnesota is developing a variety of DER-based peak reduction programs that allow customers to give the utility control of smart thermostats and appliances. But Xcel-commissioned research by Brattle showed a limited value proposition in peak shaving and grid services until utility control-room management of the flexibility from DERs improves, Xcel Senior Regulatory Analyst Jessica Peterson told the symposium.

Since 2015, Xcel's strategy to expand use of DERs has been to evolve "toward flexibility" by gradually introducing advanced practices like controlling customer thermostats and devices, Peterson said. With its learning, it has set higher goals for advanced DR programs using customer-sited resources.

But distribution system control "technology is a huge challenge right now because it needs to evolve more to meet utilities' needs," she said. Xcel chose a DERMS system that it found could not connect to all its customer's devices. "We need to be able to connect with and control any equipment a customer or third party may want to use and we're still looking for that technology."

A big step forward would be streamlining the regulatory approval process "so we can move more quickly to trials of unproven new technologies," she added.

Minnesota's utility commission acknowledged Xcel's concerns in its 2017 order approving the company's last integrated resource plan, Commissioner Schuerger said. The order required 400 MW of additional DR by 2023, a full and thorough cost effectiveness study, and an evaluation of new advanced DR and load flexibility technologies.

Minnesota's resource mix is changing rapidly, Commissioner Schuerger said. To support an expected 45% or higher renewables penetration by 2030, the commission is evaluating investments in distribution grid modernization and focusing on "overcoming technology barriers," he added.

Portland General Electric (PGE) was an early leader in testing load flexibility.

It began with limited smart thermostat, residential storage, grid integrated water heating, and smart EV charging programs, its Manager of the Customer Program Portfolio Jason Salmi Klotz told the symposium.

Its proposed smart grid test bed program would pilot smart devices and appliances controlled through new communications technologies, Salmi Klotz said. The program aims to better understand the values and services flexibility can offer to the distribution and bulk electric systems. It will also explore customer rate design preferences and other factors impacting customer participation.

But there are challenges ahead, PGE Director of Retail Technology Strategy Conrad Eustis told Utility Dive in 2019. The lack of customer devices with the needed communications capabilities may prevent Brattle's 200 GW load flexibility forecast for 2030 from being realized until 2050.

Utilities and commissioners have every right to be concerned about inadequate system controls, but "we can develop any technology to meet customer needs," Salmi Klotz said. Though PGE's test bed will demonstrate new ADMS and DERMS breakthroughs, he shares Xcel's concerns about the lack of interoperability and open standards that prevent visibility and management of all customer technologies, and have already imposed costs on PGE customers.

"Closing the communications standards gap would accelerate our ability to develop and deliver cost effective solutions," he said. Technology is a baseline issue, but Oregon regulators are working with PGE "to open that discussion about solutions."

"The technologies load flexibility depends on may be acceptable for cell phones but not for electric system reliability," said Phil Markham, smart buildings research and development manager for Southern Company and its subsidiaries in Alabama, Mississippi and Georgia. Flexibility "could be a threat to grid stability" without "granular control," he added. 

But because load flexibility is a part of decarbonization, it offers "opportunities to make capital investments in electrification," he added. Regulators need to support research on "communications with open standards to allow utilities to connect through a reliable communications network with the range of customer technologies," he said, endorsing the Xcel and PGE position.

Streamlining the development of new technologies like energy management systems is "essential" to adding load flexibility, spokesperson Craig Bell for Southern Company subsidiary Georgia Power agreed. That is the "goal" of the load flexibility pilots it has proposed to Georgia's regulators.

"I'm hired to understand and prepare Georgia for what will be needed in the future," Georgia Public Service Commission Vice Chair Tim Echols told the symposium. The legislatively mandated integrated resource planning process includes "a pilot project opportunity" that allows regulators to green light load flexibility trials and the commission has multiple innovation sandboxes on DER ongoing.

"Regulators need to create the space for utilities and third parties to innovate and create financial rewards," Sacramento Municipal Utility District CFO Jennifer Davidson told the symposium. "We cannot do it alone. The need for innovation is too big."

But Hledik said the technology barrier is already being addressed. "Utility pilots and small programs are using technologies to communicate with customer-owned smart devices and DER," he insisted. "It may not be the level of sophistication some utilities would like, but it's been enough to meet system needs."

The other barrier to load flexibility is the disincentive in the state regulatory model to utility investment in flexibility technologies, but that can be addressed, Hledik said.

The incentive barrier

Breaking down the incentive barrier may be more complicated.

PGE's test bed may allow trials of innovative transactive or subscription rates that provide compensation to customers for allowing the utility to use their DER for load flexibility, but if they are scaled, they would have to be worked into the traditional regulatory model, Salmi Klotz said.

There are also discussions with Oregon regulators to address the incentive barrier through a new specially designed compensation rate to participants in load flexibility programs based on the value of the service they provide, he added.

It is possible the test bed could trial direct monetary incentives to customers, but PGE is still working on how to structure them, Salmi Klotz said. It will likely require "layering incentives" to get adequately high "levels of engagement and participation."

The other approach is compensation to utilities that offset their losses of guaranteed returns for infrastructure investments, he said. That could be through performance-based regulation incentivizing load flexibility additions, or adjusting the utility's rate of return to make using flexibility as beneficial to the utility bottom line as capital expenditures on central generation.

Introducing those kinds of changes "does not have to be a barrier if the utility's approach is customer-centric," Salmi Klotz said. "The regulatory compact is based on service in the public interest and load flexibility is in the public interest because it gives customers a way to lower their bills and makes the utility a tool for policy implementation, which justifies a rate of return for supporting flexibility."

The Minnesota commission has been "actively evaluating and advancing" performance-based regulation, Commissioner Schuerger said. The objective is developing performance metrics that "cost-effectively align generation with load and reduce peak demand." 

Xcel is already working under a multi-year rate plan and, with stakeholder input, has identified performance-based goals, outcomes and metrics, he added. "Xcel's Q1 2021 report on its performance, using those metrics for the first time, is expected to lead to data-based performance incentives for advanced DR and load flexibility."

But the new metrics, and the incentives they could lead to, "are intended to improve and evolve the traditional cost of service ratemaking paradigm, not replace it," Schuerger stressed. "They can also evolve traditional DR into more flexible advanced DR," he said.

The next big question

Regulators and utilities must break down these barriers, but they also must take the next big step, Brattle's Hledik said.

Through 2030, load flexibility will "get smarter" and then "get bigger," growth will be led by residential customers with new access to smart devices, and regulators will support pilots, Brattle predicted in its 2019 paper.

But a lot of pilots, which are important when they test new and unproven features of flexibility, "will never become full-scale programs," Hledik said. "They are being done without planning for full-scale deployment, and without that planning, there is a strong possibility there will be no further deployment."

That is an indicator of "the bigger problems" of mistrust of technologies and of not addressing the disincentive to investment, he said. "Pilots have shown and are showing flexibility saves system and customer costs and they should be scaled."

Scaling flexibilty pilots is important, Commissioner Schuerger agreed during the symposium.

"There is a risk to ratepayers and to the public interest of not developing new load flexibility programs," he said. "Institutional inertia could lead to addressing reliability with investments that could become stranded, increasing costs to ratepayers."

The record before the Minnesota commission "shows advanced demand response and load flexibility are cost effective," Schuerger said. "There is a real danger of letting the perfect be the enemy of the good. To protect ratepayers, we have to develop new programs, learn from them, and move forward."

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By Electric Power Engineers

How long has it been now? Two months since we, here in the US that is, started realizing that COVID-19 is a serious threat?

Like others, I was in disbelief, and had doubts about the extreme measures that the world is taking, until we started to have visibility on how quickly critical cases can ramp up.  If my mom or dad were alive today, I would be devastated and outraged if the hospital could not accommodate either of them if they got seriously ill. I understand.

This situation is devastating, shocking, and unexpected. It took our team at Electric Power Engineers (EPE) a few weeks to just react to the situation setting the systems and policies in place for our people. We are doing our bit to control the spread of this virus. 

The impact on our industry and our business

EPE’s next priority is to make sure we do all we can to ride through this pandemic with minimal impact on our business, our employees, and the clients we serve.  We are keen on remaining available to those who count on our services, and consider it our duty to do our best to keep the supply/chain cycle connected and flowing.  

We are reaching out to our clients, working with them, to keep projects moving. We want to ensure that we keep our workforce employed, along with avoiding a spike in workload from the industry that exceeds the resources’ capacity once the pandemic subsides. We all must work together to keep inching forward so we can also "flatten" the curve in the impact the economy will see. 

What will be the long-term impact on our industry, renewables, storage, technology, utility operations and planning? It’s too soon to speculate on how much and for how long, but there will surely be an impact within our sector. The effects will come from many related disruptions and uncertainties: supply chain, labor force, financing criteria, and the impact on sequencing of execution. Add to that the low oil prices, and uncertainty/change in utility loads--  we have some very interesting times ahead of us.

Are we concerned? Of course, we are. But we must believe that we will ride through this. At the same time, it will require a lot of hard work and out-of-the-box thinking to deal with this volatile situation and associated uncertainty. 

This is not just a disruption; this is a wake-up call that will change how we operate and plan moving forward.

As our management team at EPE was developing the criteria to evaluate the impact of this pandemic on our business, it struck me how similar that process is to the contingency planning we do to keep electric grids reliable. We evaluate the threats one-by-one, and study the flow of load, which now has a higher degree of uncertainty and variability, to ensure that we have the right resources & systems to deliver. 

Unfortunately, this type of planned deliberate approach is not happening at the grid level, and we need to change that. We need to seriously consider slowing down the process of changing the world we know until we have planned and simulated for unknown contingencies such as the one we are currently facing. Viruses and diseases are not the only threats. Cybersecurity is also a huge risk, now heightened with more people working from home and our dependency on interconnected devices. We are moving too fast in changing our electric grid, and we know we are not planning enough.

Designing our future systems cannot be an ad hoc process of simply reacting to accommodate available new technology. Our industry does not value planning as much as operation, and is therefore much more reactive than proactive. This is very risky. I do not sleep at night, thinking how we are going to keep the lights on in this rapidly changing electric ecosystem. To address this risk, we should literarily simulate the operation of such systems in planning mode - and on large scale for months and years - before we begin to implement new designs.  

All of these issues must be addressed holistically and with forethought: What technology should we select, how fast and how much do we want and need? What about microgrids, large-scale grids, communication, resource & demand dispatch,  distribution, impact on environment, cybersecurity threats, pandemics, natural disasters – all of these concerns must be integrated into the planning and design for the future reliable and resilient grid that we all desire. Short-term self-interest should not be allowed to drive products and supplies to the marketplace and dictate how the future should be, further pushing us into an inherently risky reactive stance. 

What we allow to happen today to our planet and to our electric grid networks -- the technology and systems we adopt -- will dictate whether we will truly have a sustainable future for ourselves and our children, and whether we can meet the demands of our fellow humans in times of crisis and threats.  We all must start planning on a large massive scale, today. We must plan diligently, and must both raise awareness of and advocate for this approach. We should take this COVID-19 pandemic for the warning that it truly is. In order to create the future grid that we want, we need to step back and anticipate the unexpected while planning for the future power system that we want and need.

These gaps are why EPE chose to invest in R&D and in building our ENER-i planning software.  

New time-of-use rate pilots in Maryland show how effective time-varying rates can be and also reveal an early step in the evolution of rate design.

Three Maryland investor-owned utility (IOU) pilots of new time-of-use (TOU) rates significantly reduced peak demand and customer bills, a September 2020 Brattle Group assessment found. The success was built on the power system's emerging transition to variable and distributed renewables and customers' greater access to enabling technologies and familiarity with responding to price signals, the study found.

"Rate designs differ widely in the accuracy of the price signals they send to customers, from flat rates to day-of real-time rates," said California Solar & Storage Association Regulatory Affairs Senior Advisor and rate design authority Scott Murtishaw. "The more precise the price signal, the more customers can help address variable energy sources with flexible loads and storage to accelerate decarbonization."

Maryland was ready for new rates because it had deployed smart meters, its customers were familiar with alternative rates, and distributed energy resources (DER) are growing there, said Brattle Principal Sanem Sergici, who led the study of the pilots. The success of these new rates moves Maryland along the energy transition trail that states from Hawaii and California to South Carolina have recently blazed.

Those states have shown that success with TOU rates can allow utilities to begin to integrate more variable and distributed generation and lead to more sophisticated time-varying rates. And those more sophisticated rates allow for higher penetrations of variable and distributed generation that further advance the energy transition.

Maryland's TOU pilots

A TOU rate's varying prices are higher during peak demand periods, which signals customers to shift usage to lower-priced off-peak periods. That can reduce the individual customer's bill. Reducing a utility's need to invest to meet rising peaks can also reduce all customers' bills.  

In Maryland and many other states, TOU and other new rate designs are possible because of the deployment of advanced metering infrastructure (AMI). AMI's "digital link" between utilities and customers allows "expanded services" like home energy management, usage alerts and "time-varying" rates, the Edison Foundation reported in December 2019.

Maryland is ahead of other jurisdictions "on advanced metering and technologies that link customer savings opportunities to savings that benefit all ratepayers," Maryland Public Service Commission (PSC) Chair Jason M. Stanek emailed. And through the state's peak time rebates (PTR) program, put in place in 2008, customers learned "they can save money through reducing usage."

The PTR program rewards customers for voluntarily reducing usage when pre-notified of a coming demand spike and is "the most succesful such program in the U.S.," Brattle's Sergici said. "Since 2014, roughly 1.5 million Maryland customers have participated" in significantly reducing these intermittent critical peaks when demand is highest.

The PTR program's high customer satisfaction ratings "may have made the commission willing to offer more innovative programs," Sergici said. And a 2017 PSC order suggests commissioners saw an opportunity to prepare for their next challenge, she added.

With customer-sited DER emerging, Maryland can begin assessing the potential of time-varying rates' price signals to empower "customers, utilities and all other stakeholders," the order initiating the PC44 grid modernization docket said.

In response, Maryland IOUs, Baltimore Gas and Electric, Pepco and Delmarva Power and Light implemented still-ongoing TOU pilots that offered summer peak period rates four times to six times higher than off-peak rates, according Brattle's study of June 2019 through May 2020 impacts.

The customers who opted in represented significant portions of low- and moderate-income (LMI) and non-LMI demographics for small pilots, stakeholders agreed. Across all utility programs and customer types, summer peak demand was reduced 10.2% to 14.8%, non-summer peak demand fell 5.1% to 6.1%, and bills were reduced 5% to 10%, Brattle found.

Ratepayer advocates have often opposed TOU rates because they could disadvantage LMI customers with less usage flexibility and less access to enabling technologies, Brattle reported. But these results represent "conclusive evidence that LMI customers respond to the TOU prices by as much or nearly as much as non-LMI customers."

Brattle's findings were preliminary but significant, and suggest that rate designs follow the availability of technologies like AMI and customer familiarity with rate options, said former Maine utility commissioner and current Bernstein Shur energy and environmental attorney David Littell, who co-chaired the PC44 Rate Design Work Group. 

The preliminary findings show TOU rates can impact some system costs, but more piloting and study are still needed, added attorney William Fields, lead ratepayer advocate on the pilots for the Maryland Office of People's Counsel.

About two-thirds of customers who opted in would have had bill decreases without changing their behavior but "found ways to get more savings," Sergici said. "That's important because customers typically only opt in if they already expect benefits and those benefits do not add real system value."

The initial PSC order specifically required opt-in pilots, "which seemed to be a signal the PSC will not move immediately to default TOU rates," she added. "But the success of the pilots, especially for LMI customers, could lead to another step."

Many states with rising variable and distributed renewables penetrations are piloting rate designs with "more complex and granular elements," said North Carolina Clean Energy Technology Center (NCCETC) Senior Policy Program Director Autumn Proudlove.

The Littell and Proudlove observations suggest rate designs evolve in response to the changing energy resource mix, access to enabling technologies, and customer readiness. Recent innovative rate design implementations suggest the same thing.       

Advancing TOU

Other states are also demonstrating the evolution of rate designs.

South Carolina's 2019 Act 62, which capped DER growth without altering rate design, was not a sustainable approach to its growing DER penetration, stakeholders found. A potentially more durable rate design solution based on time-varying rates proposed by Duke Energy and DER advocates is now before South Carolina regulators.

The proposal combines a TOU rate and a more dynamic peak pricing version of Maryland's PTR rate with incentives for participation in Duke's demand response and energy efficiency programs. If approved, it could be an advanced rate design that grows DER, reduces utility peak demand challenges, and supports policy goals without imposing costs on other customers, Proudlove said.

Hawaii struggled for years to design a TOU rate that would do those things, Utility Dive has reported. Recent data suggests it may have found the answer.

In October 2015, the Hawaii PUC changed the fixed retail rate compensating solar owning customers to a TOU rate design. It was intended to drive new solar owners to add battery storage. But batteries were expensive at the time and by May 2016 permits for solar installation were down 27.3% compared to the prior year.

An October 2017 TOU rate design restructuring was more successful. In the first nine months of 2020, 75.2% of metropolitan Honolulu region PV systems included battery storage, ​Pacific Business News reported in October 2020. 

The TOU rates worked but "Hawaii waited too long to impose a solar rate design with smart price signals," Duke Energy Vice President for Rate Design and Strategic Solutions Lon Huber said at the time. "States need to get ahead of the solar penetration with forward-looking rate designs."

California, which has piloted TOU rates since 2003 and has already implemented a successful TOU rate for solar owners to drive battery growth, may be ready to "get ahead" on what appears to be a next step in rate design evolution.

To real-time pricing

California's next step to more dynamic time-varying rates could further demonstrate the link between rate design, the resource mix, enabling technologies and customer readiness, stakeholders said.

The state has been working to address demand spikes and high rates for decades, Brattle Principal Ahmad Faruqui, a student of rate design history, recalled. 

Customer demand for lower bills led California to retail restructuring, but there were no enabling technologies or new energy resources that would lower rates, Faruqui said. After the 1999 to 2001 energy crisis, state policymakers retored regulation and "there was a push for more dynamic pricing and smart meters."

After years of the kind of piloting Maryland is doing now, and with its rapid growth of increasingly dynamic supply and demand, California may be ready for real-time pricing (RTP), Faruqui said. But implementation will depend on the availability of enabling technologies, he added.

Regulators in the California Energy Commission (CEC) and California Public Utilities Commission (CPUC) in various proceedings to prepare the state for a power mix to support its zero emissions goals, want to move ahead with RTP pilots, Brattle's Sergici said.

The CEC recognized RTP as a potential solution to load and supply variability and rising costs in its January 10 action initiating a stakeholder study of load management. In response, California's IOUs called for "comprehensive pilot studies that fully assess the costs and benefits of real-time rates," in their March 16 CEC filing.

RTP would be especially effective at addressing the price volatility from California's variable supply and flexible load, said California Solar & Storage Association's Murtishaw.

Over 100,000 Oklahoma Gas and Electric residential customers and over 40,000 residential Illinois customers have opted in for RTP rates, Murtishaw replied to a July 17 CPUC ruling rejecting a 2019 San Diego Gas and Electric territory-wide RTP proposal.

Almost 1.1 million California customers voluntarily participate in demand response programs, which shows they can respond to price signals, Murtishaw added in Aug. 31 testimony proposing a scaled-back RTP pilot.

A pilot would show RTP's favorable impacts on load, utility costs and customer bills, and lead to investment in the needed enabling automated technologies and aggregation services, Murtishaw said. But without those technologies and services, limited California customer experience with real-time pricing will lead to doubts from regulators and resistance from utilities.

RTP is "not essential" but it can cost-effectively address California's steep demand peaks, high price volatility from variable and distributed renewables, and unpredictable emergencies, he added. And with further deployment of enabling technologies and services RTP "will be more viable."

There is a next step in rate design evolution beyond RTP that may use those services and technologies to turn price signals around.

Subscriptions

A newer type of rate design could eventually include the full range of options, from Maryland's basic TOU design to California' real time rates, or allow more sophisticated pricing to be implemented by utility experts.

Rate design is evolving toward time-varying rates, NCCETC's Proudlove acknowledged. But "if the barriers to smart and enabling technologies and services are overcome, more customers might find the 'set it and forget it' simplicity of subscription rates more appealing, and utilities might be able to use them as effectively as other rate designs."

Advanced TOU rates with peak pricing features "probably are not for everybody," said Duke's Huber, who proposed one of the first modern subscription rates for U.S. electric utilities. "But why are utilities only sending price signals to consumers? Utilities ought to have the opportunity to receive price signals and learn from their customers' choices," he said.

Subscription rates recognize that some customers will allow utilities limited control of their usage if the utilities provide smart technologies they can pre-set to their preferences, he added. "Underlying subscription rates would be very sophisticated rate designs managed by utilities." 

Utility experts could optimize supply and demand in response to wholesale market prices and meet customer needs with the full range of available resources more cost effectively than most residential customers, he said.

The energy transition will require "every demand- and supply-side solution we have, and rate design-enabled load flexibility will be a key tool," Huber said. "Customers who give utilities more control of their loads should benefit more financially for providing more system benefit, because key peak event days are very much 'Ask not what the grid can do for you, ask what you can do for the grid' events."

Utilities are pushing for a bigger role in integrating distributed energy resources (DER) in their service territories, saying their ownership would benefit customers. They also see economic opportunity and other advantages in the flexibility of DER, which is becoming vital in today's power sector transition.

"Utilities are now critical in decarbonization and, as power grid experts, they are leading innovation," said Duke Energy Vice President of Rate Design and Strategic Solutions Lon Huber. "All clean energy options should be on the table, and if a program is structured in a way that provides benefits to all customers — participants and non-participants — it is a win-win that should be pursued."

Meanwhile, a new study from the Department of Energy's Lawrence Berkeley National Laboratory finds benefits of utility DER ownership, though private sector advocates say the data may not tell the whole story.

Utilities competing against private providers exposes shareholders to unnecessary risk, former Federal Energy Regulatory Commission Chair Jon Wellinghoff said, reaffirming his 2015 position, which was cited in the LBNL study. Utilities should instead "host" the "grid marketplace" and "allow third parties to bear the risk of selling DER to end customers," Wellinghoff wrote in a 2015 op-ed.

Though many regulators have accepted utilities' move from traditional, centralized generation to utility-scale renewables, until recently states such as Mississippi and Florida have seen utility DER ownership as intruding in the private market.

But a debate in Florida over whether utilities should be allowed to own community solar may foreshadow a shift in power sector dynamics.

Rooftop solar could increase utility shareholder earnings

Utility-owned rooftop solar programs could increase total shareholder earnings by 2% to 5% over 20 years, LBNL modeling found, compared to an estimated 2% loss over 20 years from the same amount of customer-owned or leased rooftop solar.

Shareholder benefits come largely from ratepayer-paid returns for utility capital expenditures on solar and from limiting compensation to private, net-metered solar owners, LBNL found.

Under LBNL's scenario, rates increase due to additional utility spending, but only by 2%, comparable to the 2.2% bill increase non-rooftop solar customers would see because of net metering compensation and other costs, LBNL Research Scientist and study co-author Galen Barbose said.

"Shareholders win and customers break even in our base case assumptions," Barbose said.

Less certain assumptions could further improve the value proposition for utilities, he added. Better visibility and control of solar, lower interconnection costs, and potentially deferring system upgrade costs, could all make it "a win for utilities and a marginal win for customers."

The role of regulated utilities in private markets "raises thorny policy questions for regulators and stakeholders," Barbose acknowledged. But this study addresses "a simple and perhaps threshold question of the basic economics for utilities owning rooftop solar."

As the market moves beyond early adopters, there is some logic in utilities owning DER when the value proposition is potentially neutral for customers and better for shareholders, Rábago Energy Principal Karl Rábago, a former Assistant Secretary of Energy and Texas utilities commissioner acknowledged.

But utility ownership is only "the second-best solution," Rábago said. Shareholder and non-participating customers benefits are small and should not justify allowing DER ownership by "institutions which typically innovate more slowly and at higher costs than the competitive market."

Solar installers oppose utility interference

Not surprisingly, solar installers agree with Rábago. The private market is "the best way to achieve cost reduction and innovation," Sunrun Chief Policy Officer Anne Hoskins said. Utilities' best role is in "enabling network access." 

Sunrun is working on virtual power plants and non-wires alternatives in which utilities will "play a central role" but will not own the resources, said Hoskins, a former Maryland utility regulator and utility executive.

Utilities do fill one key role in distributed solar ownership, Rábago, Hoskins and Huber agreed — addressing underserved or hard to serve markets.

That "is the reason utilities were given monopoly franchises," Rábago said. "LBNL's paper shows there is not a legitimate shareholder argument against utilities owning solar in those markets."

The value proposition for utility-owned rooftop solar is especially strong for low income customers who lack the resources to invest in solar for themselves, and do not have access to community solar, Huber said.

Nevertheless, the private market has usually won regulatory protection because it is growing rooftop solar impressively, Hoskins said.

Utility-led rooftop solar programs have been approved in Arizona and Texas, and utility-led rooftop solar pilot proposals are pending before regulators in Arkansas and Mississippi. But many utilities are seeing greater benefit in community solar, leading to a shift in focus that raises the same ownership questions, said North Carolina Clean Energy Technology Center Senior Manager of Policy Research Autumn Proudlove.

This suggests the marginal benefits of rooftop solar ownership identified by LBNL may not be the whole story.

Arizona Public Service (APS) is methodically testing new use cases for its groundbreaking utility-owned rooftop solar programs, but concluded it has limited peak load reduction value, spokesperson Jill Hanks said in an email. APS, along with San Antonio's CPS Energy and Tucson Electric Power, all leaders in piloting utility-led rooftop solar pilots, are all now focused on community solar.

These proposals raise the question of what the appropriate boundary is between regulated and competitive markets. Florida regulators may soon need to define that boundary. 

Florida's community solar debate

Duke Energy Florida proposed a 749 MW Clean Energy Connection program in July that would give customers bill credits for community solar participation. Up to 65% of capacity will go to large business customers, 10% to local governments, 25% to residential customers and small businesses, and 28% to low income customers.

Some stakeholders, including solar advocates Southern Alliance for Clean Energy (SACE) and Vote Solar, agreed utility ownership was "in the public interest" after coming to an agreement with Duke on adding the carve-out for local government and low income customers.

The yet-to-be approved program is already fully subscribed, Duke's Huber said.

But other stakeholders fear the program will result in unfair rates. The program's design includes "numerous fatal flaws" and is "not in the public interest" because it would impose a "rate burden" of "several hundreds of millions of dollars" on the utility's non-participating customers, Rábago wrote in October comments. The program only benefits participating customers, making it "a subsidy program for the very few, and a travesty of the concept of community shared solar."

Duke contradicts this assertion, saying 12.7% of the projected $465.1 million in net benefits will go to program participants while 87.3% will go "to the general body of customers," in its filed comments.

But Rábago questioned the assumptions in these numbers about "value derived from avoided costs" for infrastructure building and maintenance by deploying community solar. Those assumptions are uncertain, "increasing the risk to non-participants," he wrote.

The proposal provides benefits that induce customers "not to pursue free market options" like rooftop solar and "reduces or eliminates the opportunity for competitive developers," Rábago added.

The program is structured to provide net benefits to all Duke Energy Florida customers and avoid any "long-term cost shift to non-participating customers," Huber responded. That is "because the cost of the solar is so low for larger installations."

Their disagreement reverses a long-standing debate about the value of solar.

Solar advocates have long argued that the true value of distributed solar includes the infrastructure costs utilities avoid when customers install it. Rábago said those costs are uncertain. Regulated utilities have long denied there are significant avoided costs from distributed solar.

But community solar does avoid infrastructure costs, Huber said. Duke's calculations are based on assumptions used by solar advocates, including Rábago, in value of solar proceedings across the country that typically include avoided costs as part of the value, Huber said.

Florida regulators may choose to protect the private market by ruling against Duke ownership of community solar. But they also may affirm a new "convergence" between utilities and the private sector in which a new generation of utility leaders may now be able to pursue utility ownership of DER more aggressively.

A potential convergence between regulated and free markets

The potential convergence is clear in Duke's agreement with stakeholders. In addition to its provisions for local governments and low-income customers, Duke commits to protecting retail rate compensation for rooftop solar owners' exported electricity through 2023, making the utility's solar "complementary to rooftop solar," SACE Solar Program Director Bryan Jacob said.

Duke will also consider using solar and solar-plus-storage systems to defer or replace investments in new natural gas generation. And its competitive solicitation for developers gives the private sector a role in the program, Vote Solar Southeast Director Katie Chiles Ottenweller added.

While Rábago sees utilities as a "second best" option for DER development, he also sees why parties are converging toward it.

"The distributed solar market is expanding and utilities don't want to lose that market share," Rábago said of the compromises in the agreement. "The LBNL paper adds the argument that there is shareholder value in distributed solar."

Duke's proposal demonstrates how once clearly partitioned markets "are now overlapping, intersecting and interacting through a series of convergences," he said. For example, "the cost of solar is now so low that even the relatively economically inefficient, traditional electric utility can make money for shareholders in this business."

Hints of these debates over utility DER ownership have been seen in Arkansas and Mississippi, and in the Colorado debate over Xcel Energy's ownership of community solar.

Solar has also converged with "things the utility has the regulatory and economic leverage to do something about," he added. "It can't do anything about things like natural gas prices, but it can attempt to control the solar market segment."

Utilities' ability to bring DER ownership proposals to regulators, and the low costs of distributed solar, are converging with utilities' growing need for distribution system modernization, Rábago said. They can now argue their massive capital investments in DER and system infrastructure are for reliability and resilience, but that spending will also accelerate returns and increase shareholder earnings, he added.

Finally, there is "a generational convergence in which utility management is, like much of the public, evolving," he said. As the generation of leadership that resisted DER growth retires, "new managers are emerging who do not see risks but opportunity" in distributed technologies.

"The LBNL paper is a postcard from the convergence that says owning assets on the distribution system is an opportunity," Rábago said. "Regulators may let utilities do this because it suits their jurisdictions, but that will erode the principle of the free market."

"We need to dramatically scale up dependable and cost-effective clean energy solutions to meet aggressive climate goals," Duke's Huber responded. Some solar advocates are "still stuck in the outdated 'If it is from the utility, it is bad' narrative," but Duke's innovative rooftop solar policy in the Carolinas and its intention to link storage with the proposed community solar program in Florida "show it is driving innovation," he said.

Regulators and policymakers should now recognize that "this kind of fundamental decision about regulated and competitive markets is before them, or will soon be," Rábago said. "Their answer will test their belief in free market principles against their confidence in regulated monopolies' ability to deliver value in this rapidly evolving market."

Securitization is a financial tool that can reduce utility debt with low interest bonds secured by ratepayers, and with utilities' growing costs related to COVID-19, the energy transition, and climate change, interest is accelerating.

But utilities and their customers are facing hundreds of millions or even billions of dollars in such costs, which is raising oversight concerns. When oversight has been introduced, it has led to lower interest rates and lower transaction costs, stakeholders in such proceedings told Utility Dive.

Duke Energy's $1 billion proposal to use securitization to meet storm recovery expenses in North Carolina provides the criteria necessary for the commission to evaluate Duke Energy's proposed transactions, Duke spokesperson Meredith Archie said in an email. It allows the commission "to determine whether and to what extent it wants to be involved in the transaction once it issues its order."

But clear state laws on securitization are needed to "protect the public," former Colorado Public Utilities Commission Chair and authority on securitization Ron Lehr said. State laws "should encourage regulators to ask what incentives are involved when big banks and a big utility work together and whether those incentives align with the public interest."

Utilities and customer advocates differ on oversight. Duke, though committed to legislative and regulatory guidance on securitization, argued in its proceeding that it can manage bond term negotiations, and the financial transactions that follow, on its own. But with hundreds of billions in potentially securitized dollars at stake, customer advocates contend experts representing ratepayers should have a role in those negotiations.

Securitization is coming

Securitization allows utilities to offer long-term bonds to investors to pay off short-term debt. According to a 2018 Moody's report, it "can be a credit positive tool for regulated utilities" because it is an "immediate source of cash" and can "avoid potentially credit negative events" like continued reliance on uneconomic fossil generation.

Ratepayers benefit because the cost of the securitized debt is lower than the utility's typical cost of debt, which reduces the monthly bill impact, Moody's added. The bonds have lower interest rates because they are long-term and secured by the high likelihood of customers paying their bills. But enabling state legislation is necessary for credit agencies to provide the AAA credit rating for securitized debt that makes interest rates low.

At least five states passed legislation approving regulatory consideration of securitization by utility regulators in 2019, and at least 18 others have some kind of regulatory, legislative or advocacy effort in the works, according to Energy Innovation and others.

The 2020s are likely to see a lot more securitizations, said RMI Electricity Practice Principal and Stanford-Precourt Institute for Energy Research Associate Uday Varadarajan.

The Biden administration's commitment to addressing climate issues is likely to accelerate retirements among the approximately 130 GW of remaining operating coal plant assets, he said, leaving about $90 billion in stranded costs eligible for securitization, not counting gas plants or other infrastructure that could be eligible.

It also does not include the huge debt associated with COVID-19, he added.

Shutoff moratoria allowing COVID-19-impacted residential and small business customers to defer utility payments without losing service have been invaluable to millions, according to the National Energy Assistance Directors' Association (NEADA). But when the pandemic fades, national economic recovery could be impacted by potentially huge debts to utilities, NEADA added.

The December stimulus bill included $25 billion for unpaid rent and utility bills, and the Biden proposal would add $5 billion, but unpaid 2020 bills could require up to $70 billion, according to Moody's Analytics Chief Economist Mark Zandi. Unpaid utility bills alone could reach $35 billion to $40 billion by March 2021, NEADA Executive Director Mark Wolfe said in November. And much of the debt has yet to be included in their estimates.

Securitization could address that debt, though state-enabling legislation is inconsistent in availability and in providing robust oversight, RMI's Varadarajan said. "But even if securitization's benefits are diluted, it can be of significant value to ratepayers because interest rates are almost always reduced" compared to typical utility interest rates.

Arguments for better oversight are, however, "critically important," he added. The utility is responsible to its shareholders and the bank underwriting the securitized bonds, which means "utility and ratepayer interests might not be aligned."

Customer protections

There are two key areas of oversight needed to protect customers as the billions of dollars in securitized offerings mount, according to Saber Partners CEO and securitization negotiations expert Joseph Fichera.

First, customers need to be represented in the negotiations.

There have been relatively few securitizations, and things like loan term, loan amount, and factors in the larger economy have varied significantly, Fichera acknowledged. But the limited data shows securitization negotiations that include ratepayer representatives have better results for customers, he said.

Past proceedings involving Duke Energy Florida, Centerpoint Energy Texas, and West Virginia's Allegheny Power-Energy substantiated his concerns, Fichera said.

In Duke Energy Florida's 2015-16 securitizations for storm recovery, Saber proposed a set of longer-term bonds than those proposed by the utility and its bankers, Fichera said. And the ones selected by regulators saved the utility's customers "over $3 million on a net present value basis by achieving interest rates closer to those from long-term Treasury bonds."

Financial advisor expertise was "instrumental" in obtaining customer savings in those proceedings, Deputy Public Counsel Charles Rehwinke confirmed in June 2016 Florida Public Service Commission testimony.

Saber similarly contributed to significant customer savings in a 2009 West Virginia securitization case and a 2005 proceeding for Texas CenterPoint Energy.

Regulators can and do order the utility's bank to use interest rates as close as possible to U.S. Treasury bond rates, Fichera said. But having a ratepayer representative in the negotiations assures the utility's bank follows the order to obtain "the lowest rate possible."

The second type of needed oversight is protecting customers from excessive transaction charges as the funds are dispersed and repaid, Fichera said.

In the 2015-2016 Florida securitization, Duke's initial estimate of set-up and billing service costs were between $1.9 million and $2.9 million, Saber Senior Advisor Paul Sutherland said in an email. After Saber "analysis and pushback," the utility settled on a cost of $395,000. Saber-identified unnecessary costs in West Virginia's Allegheny Power-Energy 2007 securitization of coal plant upgrade costs led to $1.1 million in ratepayer savings, he added.

Three other "best practices" essential to regulatory proceedings on securitization described in April 2006 testimony to the Florida commission remain current, Fichera wrote. The first is that "decisions affecting ratepayers should be made in conjunction with someone with a specific and direct fiduciary duty to ratepayers."

In addition, the standard for securitizations must be "the maximum present value savings for ratepayers," he added. In the absence of that standard, "underwriters and investors will have the negotiating leverage to dictate a final cost to ratepayers."

A third best practice is that every element of the final agreement must be certified by the utility, the underwriters and an independent advisor, in writing, as meeting that standard, he said.

These customer protections are not essential to obtaining AAA ratings, Moody's Vice President and Senior Analyst Robert Petrosino said. The key is enabling legislation that allows the bond to be secured by customers. "Even without the lowest rates and transaction charges, a long-term, AAA-rated security will lower utility and customer costs."

Securitization proceedings on utility proposals should and typically do include oversight from commissioners and consumer advocates, Petrosino acknowledged. "But whether the negotiation includes a team representing ratepayers is not relevant to the rating agency because pricing is determined by the marketplace and nobody else."

Other experts said negotiations in securitization proceedings do require advisors on behalf consumers.

Regulators, utilities, lawmakers and ratepayers – oh my!

Regulators and utilities agree authority on securitization should be in enabling state law to make certain proceedings are done with high standards and are backed by the authority of the state.

In California, use of securitization to recover wildfire-related losses for utilities, some of it already approved, could involve as much as $12.5 billion. Its use for COVID-19 losses is also under discussion.

The commission "can only approve a securitization when we have legislative authorization to do so for a special purpose," said California Public Utilities Commission (CPUC) spokesperson Terrie Prosper. "In our proceedings, public interest interveners participate fully and raise many questions," including on who is to be part of the securitization negotiations and on how transaction costs will be overseen.

Final rulings on securitization debates about how to follow the law's guidance come from an administrative law judge, she added. "If these issues are shown to require active intervention, the CPUC can take appropriate steps."

Utilities expressed confidence that stakeholder proceedings allow ratepayer advocates to be heard, and that they are best positioned to recognize what protections their customers require.

Southern California Edison is "pursuing" what could be a $1.75 billion wildfire mitigation securitization under a CPUC order which "followed a robust, statutorily mandated process," spokesperson Ron Gales said. The proceeding included stakeholder and public input, and the commission's financing order "established a Finance Team to provide oversight into issuance of the securitization bonds."

Duke Energy Carolinas could have $980 million in securitized bonds for storm damage mitigation in North Carolina by the end of 2021 and its current proceeding filings comply with all state legislative and commission guidance, Duke's Archie said.

In its "many years of experience" with long-term debt issuances, the utility has always used "well-established business standards," representing customers' best interests, she added. In the current proceeding, Duke "will use its best efforts to minimize costs and will certify to the Commission that the bonds provide quantifiable savings" for customers.

In today's utility securitizations, "the utility has no incentive, and no opportunity to create an incentive for itself," for a higher interest rate or more transaction processing revenues, added former Commissioner with the New Mexico Public Regulation Commission Doug Howe. The utility receives the bond proceeds "in an upfront payment" and, afterwards, "is just a middleman with no control."

Ratings agencies and the bond market "determine the rates" and the issuing financial institution has the "legal obligation to obtain the lowest offered rates in the market," Howe said. A "bond trustee" handles implementation and most enabling legislation requires a commission-approved competitive solicitation in which "hundreds of trustees compete" to determine the trustee, he added.

"Legislation can obligate the commission to seek the lowest possible costs for ratepayers, but that does not necessarily mean the implementation will achieve it," GridWorks Senior Fellow and former California utilities commissioner Mike Florio said. "These are issuances of hundreds of millions of dollars, and just a few tenths of a percent in inflated transaction charges can be real money."

With securitizations accelerating in use and size, financial advisors can be important, sometimes in unexpected ways, he added. In a utility bankruptcy during his tenure, "we discovered the tax treatment could affect ratepayer value over time by around a billion dollars, and understanding that allowed reaching a settlement."

Commissions without expertise, but aware that securitizations may benefit both utilities and their customers, might approve negotiations with shortcomings that financial advisors can identify, Lehr added. "Regulators should look for who has what incentives, and where incentives seem antithetical to the public interest, there may be a need for oversight."

The financial obligation of utilities and their financial advisors is to utility shareholders, concluded a September 2020 white paper on securitization-enabling legislation, co-authored by Lehr. To correct that, state legislation should "support the commissions' fiduciary duties to consumers and the public interest."

Legislation should give regulators the authority and resources to carry out robust oversight, Lehr added. That includes "the authority to require evidence in the utility's filing from a bond team representing ratepayers in negotiations on the deal structure and transaction fees."

Legislation should also consider "the many purposes of securitization and not set limits except for the utility taking on too much debt," Lehr said. California can use it for wildfires, Florida can use it for hurricanes, Duke can use it for coal ash cleanup, and West Virginia can use it for pollution control.

"It is probably better policy to authorize securitized bonds and not need them if other better options emerge than to need them and not have the authorization in place," the white paper concluded.

Momentum is growing for giving electricity customers the kind of predictable subscription bill options that smartphone and home entertainment customers get.

Fixed rates — once preferred to align costs and revenues — are losing regulatory support as variable supply and load make demand peaks the bigger concern. Dynamic rates with price signals that flatten peaks and shift load to match supply are becoming the favored rate design. But the subscription rate concept, coupled with enabling smart home energy management technologies, is gaining momentum and could offer the benefits of both.

"Energy costs today are higher than they should be because customers value bill simplicity more than savings or environmental impacts," Brattle Group Principal Ryan Hledik, co-author of a new paper outlining a subscription-based rate design, told Utility Dive. "A FixedBill+ rate can combine a fixed bill's simplicity with the energy use benefits of energy efficiency and demand response," he said.

A groundbreaking 2018 subscription rate proposal by Lon Huber was less explicit about the role of enabling technologies and potential savings. Huber worked for Navigant at the time, but is now vice president for rate design and strategic solutions at Duke Energy.

"Many customers are no more interested in the electricity system details on their bills than they are in IT protocols and servers that stream their Netflix subscription," Huber told Utility Dive. "New energy service subscription concepts can stabilize the bill, increase clean resources, and lower electricity costs for all customers." 

It is time for real world pilots of a subscription rate coupled with enabling technologies, Huber, Hledik and other advocates said. 

But regulators must be cautious because poorly designed subscription approaches and those that do not include access to enabling technologies could lead to over-consumption that imposes costs on other customers and compromises utility revenues needed for a reliable power system, electricity retailers and authorities on rate design told Utility Dive. 

The proposal

Surveys show some customers "prefer simplicity and freedom from managing their energy," the June 2020 Brattle Group-Energy Impact Partners (EIP) paper found. Instead of a bill for the changing amount of electricity a customer consumes each month, FixedBill+ would offer a monthly bill "guaranteed to remain constant for a specified term." 

The voluntary rate is like those from "a growing number of subscription-based consumer goods" providers, the paper reported. Though interest from utilities, competitive electricity retailers, and third-party energy managers is growing, there are few results of real-world applications for electricity, they told Utility Dive.

Huber, who originated the Energy Service Subscription Plan in a detailed 2018 Navigant paper, agreed. But the hypothetical Brattle case, which is an important addition, "appears to be based on reasonable assumptions" and "shows a customer can save, the system can benefit from demand side management programs, and the utility is compensated for taking on additional risk."

Electricity providers, including Georgia Power, Consumers Energy and retailers in Texas, have offered fixed rate "all-you-can-eat" plans with no incentives to reduce usage, the recent Brattle paper said. The opt-in FixedBill+ "is entirely stable and predictable for the full one-year term," but also includes "flexibility benefits, environmental benefits, and cost savings from energy efficiency (EE) and demand response (DR) programs."

The combination could lower customers' annual bills 3% relative to standard rates, and 6% relative to a conventional fixed bill, the paper's hypothetical case found.

The first element in a FixedBill+ that can allow those benefits is "comprehensive energy management" by electricity providers through smart demand side management (DSM) technologies, the paper said. Customers must also consent to "periodic adjustments" to the initial fixed rate, as their usage patterns evolve. Finally, there must be "incentives for energy providers to reduce costs," it said.

FixedBill+ shifts the financial risk from "the shoulders of customers" to "sophisticated electricity providers" who have the incentives, expertise and tools to reduce costs, Hledik said.

Duke's Huber agreed. Only if the provider delivers "a compelling value proposition" with energy management through smart technologies and DR measures will it fully align its interests with those of the customer and the system, he told Utility Dive in 2018.

Those DR and EE technologies and measures could provide 200 GW of cost-effective load flexibility potential in the U.S. by 2030 that would reduce U.S. peak load by 20%, according to a 2019 Brattle Group study.

Demand for more bill simplicity could accelerate interest in enabling EE and DR technologies and programs, Hledik added.

Along with customer demand, the power system's transition to fixed cost generation will drive adoption of FixedBill+ and other subscription rate approaches, the paper also reported. 

"Fossil-fuel-based power is affected by variable costs" because it is "dependent on fuel prices," it said. Renewable generation requires "substantial up-front investment," but has few variable costs.

"A fixed rate, and not a variable per-kWh rate, is the best way to align the cost of service with changing system costs," Brattle's Hledik said. "This concept is ready for more market research, regulatory innovation and pilots."

"We are still in the early stages of what we can do with the concept and who we market it to," Duke's Huber agreed.

In the real world

The fixed charge part of the rate designs proposed by Brattle and Huber are not new, but have been rejected by state regulators who say they can drive overconsumption when not paired with home energy management technologies, said Autumn Proudlove, senior policy research manager at the North Carolina Clean Energy Technology Center, and lead author of the center's national policy activity quarterlies.

"Fixed charges are still being proposed, but we're seeing fewer of them," Proudlove told Utility Dive. And subscrtiption rates are still untested. The only subscription rate option to all residential customers that has even been proposed is from Arizona Public Service (APS), though Nevada's Senate Bill 300 ordered regulators to consider it, she added.

A recently completed proof-of-concept pilot tested a largely fixed subscription rate that included a small real-time pricing element, TeMix Founder/CEO Edward Cazalet, who partnered with Southern California Edison (SCE) on the pilot, told Utility Dive. Automated DR and EE technologies and programs were designed into the rate pilot.

Outcomes suggested that "on a widespread basis, those kinds of programs could significantly reduce peak load" and the pilot proved "automation works" when programable energy management technologies are available for customers to set to their preferences, Cazalet said.

SCE "has not formed an opinion on the practical adoption of such rates," SCE Principal Manager for Modeling, Forecasting and Economic Analysis Reuben Behlihomji emailed Utility Dive. But the utility sees "subscription pricing as a tool that customers can use to manage price or inflation risk" and supports studies and pilots "to further vet such pricing with and without smart technologies."

Voluntary fixed "budget bill" offerings from APS and Arizona's Salt River Project have given customers rate stability, Arizona Residential Utility Consumer Office (RUCO) Director Jorge Fuentes told Utility Dive. But APS's proposed subscription rate paired with smart DSM technologies and DR measures "can flow system benefits to all customers by helping to flatten peak demand," he said.

RUCO "would only support a pilot" of subscription rates and only if it shifts at "least part of the program's risk to shareholders and targets flattening peak demand to benefit all customers," he added.

The limited real-world evidence of the promise of a fixed subscription rate plus DSM offerings has led to concerns about advocates' claims. 

Concerns

Any new rate design, including subscription rates, must be carefully studied to be sure it is in the public interest, Regulatory Assistance Project Associate Mark LeBel told Utility Dive.

A subscription rate "could be reasonable where somebody, presumably whoever manages the customer's load, would clearly be on the hook for higher costs," LeBel said. But "all-you-can-eat programs with one flat fee for any amount of electricity use are clearly unreasonable because it is important to have incentives to manage usage." 

Over-consumption could lead to a utility "under-recovering" expenses and "passing that onto customers," he added. "That is a cost shift."

But a well-designed, voluntary subscription plan would allow the electricity provider to use DSM and automation to address over-consumption, Huber wrote in his 2018 paper. And any plan would be a "regulator-approved pricing agreement" designed to prevent cost shifts.

The concept, as described by Huber and the recent Brattle/EIP paper, continues to be carefully studied, Helen Lo, co-author of a 2019 paper on subscription rates and a member of the Sacramento Municipal Utility District distributed energy strategy team, told Utility Dive. "But work is needed to unpack the implicit assumptions about business process protocols and technologies."

A subscription-based model that includes DSM in a meaningful way can help optimize system costs but "would be a paradigm shift and requires evolution, not revolution," Lo said. "There are many important questions that go beyond the Brattle paper, and now is the time to do the methodical groundwork necessary."

The concept must consider "reliability, future transmission and distribution infrastructure requirements, and the entire palette of system needs," she said. And subscription rate designs will also require "forward thinking" because programs and offerings will change as energy supply "moves from 45% to 50% of the total system cost toward zero marginal cost," she added.

"Customers don't buy electrons, they buy the value the electrons have for their businesses or homes, and cost is not independent of value," she said. With a nearly zero marginal cost energy supply, "instead of the electricity provider sending a price signal, the customer's choice of program and program cost is the signal."

Not all electricity providers see subscription rates in the future.

Brattle's proposal seems "stuck in a world of monopoly retail electric providers," GridPolicy CEO and former Federal Energy Regulatory Commission Chair Jon Wellinghoff emailed Utility Dive. "The modern world of energy services will be more aligned with the Texas retail electricity model." 

Fixed bills are not effective because "retail electricity is microeconomics at its best and if you remove price from the demand and supply curve, the market doesn't work," Rich Blaser, co-CEO and co-Founder of Texas retail electricity provider Infinite Energy, told Utility Dive. "If the price is always the same, there is no incentive to conserve."

Infinite Energy's tiered rate offers lower prices for lower usage, Blaser said. "I'm not a fan of FixedBill+, but I'm a fan of consumer choice. But even with demand response and energy efficiency, the supplier is taking the risk. We give our customers as much information as possible and a lower rate if they use less electricity."

But supporters of FixedBill+ see that differently.

With utilities moving slowly and retail providers skeptical of subscriptions, there is an opening in the market and "nature abhors a vacuum," EIP Senior Director of Research and paper co-author Andy Lubershane told Utility Dive. "A growing segment of customers want this, and some entities will find ways to deliver it."

Possibilities

Utilities and regulators "are reluctant to try new rate designs until they are sure of the returns they require," EIP's Lubershane said. And competitive retailers "need to balance the cost of providing a high-quality service with customer behavior risks."

But the paper's hypothetical case "shows it is possible to offer FixedBill+ with low risk to the customer or the energy provider," he added. EIP client Arcadia's billing platform "is a good example," he said.

Arcadia, an independent electricity provider, initiated pilots of FixedBill+-like offerings in early 2020 in Pepco and Salt River Project territories involving "several hundred customers," the company's Senior Director for Policy and Regulatory Affairs Richard Caperton told Utility Dive. "The paper's quantitative analysis shows there is money to be made in this space and third parties are well positioned to seize the opportunity." 

Arcadia offers a fixed rate in return for customer participation in automated EE and DR programs. Aside from handling billing, the utilities are not involved. Results are expected later this year. Among surveyed customers in the pilot territories, 60% wanted bill predictability and only 40% wanted clean energy or bill savings, which suggests subscription rates like those proposed by Brattle and Huber can find takers, Caperton reported. 

There are risks in FixedBill+-type subscription offerings, Lubershane said. "But they are already accepted in other sectors, and pilots that include EE and DR technologies and measures can show how the energy sector will respond. The winners will be those who do it in a way that has negligible impact on consumers while getting the most benefit for the provider and the system."

The ultimate dream for distributed energy resources (DER) is "transactive energy" and a completely decentralized energy marketplace that allows transactions between all residential and commercial customers on the distribution system.

Transactive energy is now done in wholesale power markets, but the transactions are enabled by system operators’ automated mechanisms for supply-demand balancing. Those kinds of technologies, regulations and clear price signals are not yet available at the retail level. But new software platforms could soon allow customer-to-customer transactions by automating supply-demand balancing based on real time DER market value.

"Transactive energy should derive optimum value from customer-owned or utility-owned assets," Avista Utilities Electrical Engineering Fellow and Technology Strategist Curtis Kirkeby told Utility Dive. "But value is not cost per kWh, it is the relative costs of keeping electricity flowing. On the distribution system, value is complex because of the magnitude of customers and assets."

New pilots are using technology-enabled auctions to develop price signals and resolve some of the complexities of DER value. A pioneering new Green Mountain Power program will use third-party developed software to show what premium customers are willing to pay for renewables generated electricity. The bigger question, which power system stakeholders are now working on, is what the value of peer-to-peer transactions can be in balancing system needs and meeting policy goals.

What transactive energy is

Transactive energy would allow customers to market energy they generate to other customers on the distribution system. But that could compromise the utility's management of the distribution system. GMP's undertaking goes further than previous pilots in testing if transactions can take place without threatening utility control.

Significant early pilots by the Pacific Northwest National Laboratory (PNNL) in the 1990s advanced understanding of transactive energy’s value. It is a combination of power consumers’ preferences and choices and "how much an individual or entity who consumes power is willing to pay for energy when there is too much demand and not enough supply," early PNNL work concluded.

Today's drivers toward transactive energy are the "economic, technological and customer preference opportunities" available from DER, according to the 2018 Gridwise Architecture Council (GWAC) Roadmap. Limited DER deployment has been possible with "ad hoc arrangements" for utility management of them, but rising penetrations require "a more robust response to maintaining and enhancing safety, reliability, and resilience of distribution energy systems."

DER can provide those values but it "will likely involve a real time price signal to monetize the operational needs of the system," ​Ron Melton, group leader of distributed systems at PNNL told Utility Dive.

It will also necessitate smart devices and an automated transaction platform to engage "the human preferences programed into the devices and the real time signals," Melton said. "We don’t envision consumers glued to dashboards watching price signals to decide when to use clothes dryers or charge electric vehicles."

PNNL’s 2006-07 Olympic Peninsula Demonstration Project was probably the first significant test of transactive energy. Communications-enabled DER with pre-programed devices allowed system operators "to manage system peak load and distribution constraints," according to a 2019 Smart Electric Power Alliance (SEPA) whitepaper.

PNNL’s 2009 to 2015 $178 million Pacific Northwest Demonstration Project expanded the validation to five states, the Bonneville Power Administration, and 11 utilities. It used a transactive energy management system and 55 intelligent technologies, including smart meters, innovative batteries and voltage controls.

But it called for better automation capabilities, now available in smart technologies, to get more benefits from smart meter data, improve smart interconnections, and grow DER markets.

Simulations from 2015 to 2018 by multiple research agencies found transactive energy can reduce voltage violations, lower customer bills, improve power flows, and reduce line losses, according to a National Institute of Standards and Technology (NIST) report.

Today, microgrid pilots are becoming the preferred transactive energy study sites, researchers and analysts agreed.

Transactive energy’s cavemen

The biggest impediment to utility deployment of transactive energy is that few jurisdictions allow the real-time pricing that is used in peer-to-peer transactions. Part of regulators' reluctance to facilitate that is their concern with bringing too much DER onto distribution systems before technologies are available to manage them.

Microgrids are "the cavemen of transactive energy" because they will begin growing new transactive energy technologies and make it more familiar to consumers and regulators, Clean Energy Ventures Managing Director Dan Goldman, who has led investments in transactive energy software technologies, told Utility Dive.

PNNL is again leading the way. Its Connected Homes project is testing connected devices in residential buildings that will allow more streamlined transactions, its website reported. The Clean Energy and Transactive Campus, launched in 2015, has led to innovations in distributed devices and control systems that more efficiently and cost-effectively manage DER and building energy usage.

Other important microgrid projects are being piloted in Maine, Southern California and Washington state by Avista Utilities.

Avista is currently developing a microgrid that will optimize energy use in "a hub building and five buildings of about 160,000 square feet each that will have a net zero energy impact," Kirkeby said. As a subset of the grid, microgrids advance understanding of "how to get to transactive energy, engage customers, and how the utility participates," he added.

Maine’s Isle au Haut is adding solar, storage, diesel backup, smart water heaters and a microgrid platform to its power system, SEPA reported. The total cost will be less than the $1.7 million necessary to replace the island’s aging undersea cable link to Maine’s power system.

This microgrid is an "outlier" to others because its focus is not price but system supply-demand balancing, Kay Aikin, CEO for project software provider Introspective Systems told Utility Dive. Software will optimize the microgrid's ability to meet demand based on customer preferences, aggregated demand curves, a market clearing price, and a negotiated real time price that completes the transaction.

The GMP project establishes value for distributed renewables to customers and the power system by allowing "transactions for excess supply," Aikin said. But it doesn't "solve the key problem of controlling and balancing energy supply and demand."

Today’s power system matches supply with load, but high penetrations of variable renewables will make that difficult, she said. Introspective’s communications network "uses aggregated small flexible distributed appliances, devices and technologies" and "turns them on and off to increase or decrease total load" to balance the system.

Using distributed devices and control technologies, system operators could transform "40% of a utility’s load" into flexible resources that can "contribute to system balancing," Aikin said. That could reduce battery requirements for renewables integration "tenfold" and, "at today’s battery prices, that is a game changer."

As regulators begin to see benefits like these from customer-to-customer transactions, they will allow more real-time pricing and that will lead to more DER on the system, Aikin said.

But technology has to give customers the ability to manage 100% renewables before utilities make that transition, she added. "If we try to put 100% renewables on the network as it is right now, disruptions caused by system imbalances could be a nightmare."

A project aimed at increasing understanding of the impacts of real time pricing is being piloted in California. The small Retail Automated Transactive Energy System (RATES) Pilot was deployed in 2015 by TeMix and Universal Devices, with the support of Southern California Edison (SCE), SEPA reported. 

A final report on its accomplishments is being finalized, SCE spokesperson Jude Schneider emailed Utility Dive. It was designed to better understand customer responses to real-time pricing and included the important innovation of allowing customers the option to pre-select the amount of energy consumption they want from the program.

Like TeMix, the breakthrough Green Mountain Power (GMP) program offers customers options for buying more renewables-generated electricity at their designated prices. GMP is counting on LO3 Energy’s Pando platform to allow automated transactions that will turn the potential system imbalance nightmare foreseen by Aikin into a 100% renewables reality for customers and their utilities.

GMP is also counting on Pando to make participation accessible enough to overcome the challenge of getting customers to be more proactive. 

Is this it?

Beginning in February, GMP customers got the opportunity to expand the utility’s 60% renewables standard offer to 100% by purchasing DER-owning customers’ excess generation through Pando, GMP VP and Chief Innovation Officer Josh Castonguay told Utility Dive.

Through the Pando online marketplace, customers can select a fixed premium price of about $0.03/kWh over their retail rate to purchase enough additional renewables to match 100% of their usage, he said.

The estimated 200 customers selling into the platform will come from GMP’s existing net metered customers, , according to GMP’s proposal to its regulators. The anticipated aggregated demand through Pando, largely expected to be from commercial customers, is expected to be around 500 MWh per year.

Buyers can also set "their own price or budget limit options" through the marketplace dashboard, Castonguay said. If there is an offering in the Pando platform’s daily online auction that matches that "bid," they get the renewables they want credited to them.

Using the Pando platform "within an existing regulatory and commercial market reality" is "a small, pragmatic step toward a long-term transactive energy vision," LO3 Energy Director of Strategy and Operations Matt Brown told Utility Dive.

Through Pando-based auctions, securely moderated and ledgered by Blockchain, GMP "will be the first U.S. utility to operate a commercial-scale transactive energy platform with regulators’ approval," Brown said. "It will compensate distributed assets and meet regulators’ objectives of transparent and equitable cost allocation using market principles."

The daily auction will set a "clearing price" for DER generation, based on customer demand at the prices offered by DER owners, he added. "The floor price is the retail rate because GMP’s net energy metering assures at least that compensation and makes the utility the buyer of last resort. But the DER owner has the opportunity to earn a premium if there is demand."

LO3's simulations and shadow marketplaces have shown roughly 30% of customers engaged by such offerings will pay a premium of up to 10% for local clean energy, Brown reported. The viability of future similar marketplaces may be guided by the GMP program’s demand and average clearing price.

But the program will also allow LO3 to build, test and iterate other Pando platform functions, like more dynamic pricing or customer engagement offerings, and it may eventually provide new revenue streams for GMP, Brown said. "They may be able to earn subscription or transaction fees for providing a frictionless platform that allows DER owners to earn a premium and buyers to access local renewables." 

It could also connect customers to utility efficiency and rate design initiatives, he added. "The long-term outcome could be a new role for the utility as a service provider rather than a deliverer of electrons."

Initial results of the GMP program are expected in the spring. The outcome depends on "whether this is something customers want" enough to participate through the Pando platform, Castonguay said. It is not certain that bidding and buying in the marketplace will be seen as an opportunity or an obstacle "and the only way to know is to try it."

A similar transactive energy marketplace is being developed by Ameren Illinois and software provider Opus One Solutions, according to the utility’s press release. Opus One did not respond to requests to describe its platform and Ameren declined an interview, but is "using the simulator developed in the project to gain insights," utility spokesperson Marcelyn Love emailed.

The challenges of transacting value

Transactive energy could lead to new utility business models, but "economic tools and processes" are needed that distinguish value from cost so that the transactions are priced according to value, SEPA reported. Another critical regulatory barrier is the need for a formal distinction between peer-to-peer transactions and transactions between electricity providers and their customers.

A transaction is based on "a derived economic value" and "the challenge is that we don't have all the answers about when and where value is," Avista’s Kirkeby said. "Without complete information on every factor affecting every asset that's providing or using energy, the value on which a transaction is based may not be accurate."

The GMP program "is a very specific play with specific customers, but that is just one piece of transactive energy," he said. "It doesn't capture the value of addressing constraints or the role of infrastructure and resources in overcoming constraints at the most granular level. Without understanding and compensating that value, we risk cross subsidies."

Transactive energy done properly "will benefit all power system users," but peer to peer transactions without a detailed understanding of where and when assets and resources have value threaten reliability, Kirkeby added. "If you don't alleviate a capacity issue totally, you just changed it to a different time or location."

To get to a 100% renewables future, "we can't do things the way we're currently doing them, and the transactive concept is probably a key change," he said. "But the power system is the most complex machine that humans have ever created and interfering with reliable energy delivery can inflict real harm."

More transactive energy pilots are needed before high DER penetrations create "operational problems," PNNL’s Melton said. "The hard work of formulating algorithms to manage the price signals, bids and customer preferences that are the basis of the transactions is still being done."

Colorado's current utility regulatory model is already leading the state toward clean, reliable energy, and does not need an overhaul, according to the state's largest investor-owned utility (IOU).

Xcel Energy's Colorado subsidiary filed comments with state regulators Jan. 10 in response to the state's proceeding examining the potential benefits of performance-based regulation (PBR), in which utilities are rewarded based on their ability to deliver on preset goals and metrics.

PBR would be a major shift from the traditional cost-of-service model, which some critics say makes utilities biased toward large-scale capital infrastructure rather than new distributed energy technologies.

Colorado Gov. Jared Polis, D, has named PBR among the policies the state needs to pursue in order to achieve his declared goal of 100% renewable energy for Colorado by 2040.

In 2019, the Colorado legislature passed a bill directing the Public Utilities Commission (PUC) to open the proceeding and report on PBR and performance incentive mechanisms for the state's IOUs by November of 2020. The governor's climate and energy policy "roadmap" said that PBR can "better align utility investment and operations with public goals such as emissions reductions, cost savings to ratepayers, and reliability."

But any changes to Colorado's regulation of electric utilities "should be grounded in thoughtful and cautious deliberation in order to avoid jeopardizing the industry-leading progress the Company is making in advancing Colorado's energy policy," Public Service Co. of Colorado, also known as Xcel Energy-Colorado, said in its initial comments.

That progress, the utility argued, includes Xcel Energy's commitment, announced at the end of 2018, to reduce carbon emissions across all its companies 80% below 2005 levels by 2030 and 100% by 2050. The utility has also been able maintain high reliability of service and relatively low rates, the comments said.

"These are not the markings of a regulatory system in need of an overhaul," according to the comments. If the goal of PBR is to address poor performance by the utility, then "the instances where [performance-based incentive mechanisms] may be useful are likely to be limited" because the utility has had "success in achieving public benefit goals," Xcel Energy said.

But exactly what those goals should be is up for discussion. Groups pushing for PBR in Colorado believe the current regulatory model — in which a utility achieves a higher return on equity through capital investments such as building new power plants — does not give utilities sufficient incentives to pursue distributed energy.

"The traditional cost-of-service regulation model creates inherent financial biases that incentivize utility capital expenditures in generation, transmission, and distribution infrastructure to the exclusion of non-utility owned assets and services that could otherwise serve customers at lower costs to ratepayers," the Colorado Solar and Storage Association and the Solar Energy Industries Association said in their comments.

"While this model was largely effective in delivering reliable power supplies to customers when assumptions about economic efficiencies gained by monopoly franchises held true, these assumptions do not all hold true today."

Rather than driving improvements in specific metrics like reliability, PBR should be about "aligning utility expectations with a 21st-century grid," Advanced Energy Economy (AEE) Principal Coley Girouard told Utility Dive. AEE has advocated for PBR reforms in several states and is also participating in the Colorado proceeding.  

In their comments, the AEE urged that the PUC "use PBR to drive outcomes related to system-wide metrics such as peak demand reduction, increased energy efficiency, and greenhouse gas reductions" because "the existing regulatory framework is unlikely to sufficiently motivate utilities to actively seek out the best means for achieving these goals."

For example, the PUC could give the utility additional compensation if it is able to reduce its peak demand, but financially penalize the utility if its peak demand increases. In its comments, AEE supports an "outcome-based" approach based on broad goals like reducing peak demand, rather than dictating exactly what programs the utility should enact.

Girouard said the hope is that through these outcomes and incentives, utility strategies like integrating rooftop solar or other distributed energy resources can compete on a level playing field with infrastructure-heavy options like building power plants or distribution lines. PBR "doesn't predetermine that the traditional infrastructure way is the only way to do it" like the current system does, he said.

Potential pitfalls

Xcel Energy, however, warned that regulators should act cautiously when implementing PBR because performance metrics can have "potential pitfalls."

"The Commission should carefully consider how certain performance metrics will actually drive utility behavior and how such mechanisms will result in shifting of resources and attention to certain areas of focus and possibly away from others," the utility said.

On several commonly-used measures of utility performance, Colorado scores above average.

Colorado's average retail price of electricity was 10.02 cents/kWh, just under the national average of 10.53 cents/kWh, according to 2018 data from the U.S. Energy Information Administration. Xcel's average power interruptions were also below the national average by 36 minutes, according to the EIA.

Other states considering PBR are grappling with this issue of benchmarking: If the utility's earnings are determined by its performance, to what baseline should the utility's performance be compared?

"Just because a utility has comparatively favorable rates and reliability metrics does not necessarily mean it is managing all assets and processes well," R Street Institute Director of Energy and Environmental Policy Devin Hartman said in an email to Utility Dive. "A big challenge in peer comparisons is the baseline — in an industry with chronically poor performance, even the stronger performers have much room for improvement but it's not reflected in a lot of metrics."

The R Street Institute is a think tank that has filed a notice to appear in Colorado's PBR proceeding, and has also been involved in an ongoing PBR case in Minnesota.

Chris Villarreal, an associate fellow with the R Street Institute, told Utility Dive that reforms to the traditional model can be made gradually, without dramatically upsetting the status quo.

Research shows that a way to implement PBR "is to start small," he said, by beginning with a few targeted metrics, and over time introducing more. PBR should also not be viewed as the sole option for reform, and should be accompanied by other efforts like distribution planning to ensure that reliability is maintained, Villarreal said.

Xcel is one of two IOUs in Colorado. The second IOU, Black Hills Energy, is participating in the PUC's proceeding and has no comments on PBR at this time, a spokesperson told Utility Dive in an email.

The PUC has said it anticipates comments from the various participants on the PBR proceeding to be completed by July, with the report to follow by a deadline of Nov. 30.

Here are three things power sector policymakers are reaching agreement on: The mid-century goal is a zero emissions economy; wind and solar alone cannot do that; and green hydrogen may be a solution.

Green hydrogen is produced by a renewables-powered electrolyzer that splits water (H2O) to make hydrogen (H2) gas. The process makes renewable hydrogen (RH2) gas more expensive than the wind or solar used to create it, but it can generate zero emissions electricity in turbines or fuel cells, be stored in higher densities and lighter weights than batteries to meet long duration storage needs, and be used in high-heat industrial processes. 

As renewables deployments rise and costs fall, "there is likely to be a good business case for renewable hydrogen," Rocky Mountain Institute (RMI) Senior Principal for Industry and Heavy Transport Thomas Koch Blank told Utility Dive. "Utilities would be well served by understanding the technology and developing some hydrogen capacity before it is needed."

Green hydrogen is not new, but today's zero-emissions ambitions and abundant, low cost wind and solar are demanding reconsideration of its value and affordability.

A groundbreaking project led by the Los Angeles Department of Water and Power (LADWP) will use an H2-natural gas blend and pilot RH2 storage at the site. These may be big steps toward a business case for RH2 in a zero-emissions economy.

A green hydrogen economy?

"Hydrogen is a key industrial commodity around the world that we know how to use and store, but over 99% is derived by using fossil fuels, which aggravates the climate crisis," Green Hydrogen Coalition Founder and President Janice Lin told Utility Dive. "Green hydrogen can accelerate decarbonization."

RH2 can be "stored for long periods and used on demand" for grid balancing and can be "combusted to generate high-temperature heat for industry," a November 2019 Center for Climate and Energy Solutions paper reported. RH2 may also be "particularly useful" as an emissions-free fuel for large vehicles like buses, trucks, airplanes and ocean shipping.

"The business model for green hydrogen will begin with those applications," Lin said.

At a renewables penetration of "about 60%," RH2, or comparable long duration storage, "will be necessary" for grid reliability, University of California, Irvine, Chief Scientist of Renewable Fuels and Energy Storage Jeffrey G. Reed told Utility Dive. Alternatives like overbuilding wind and solar or batteries would be much more expensive, he said.

That high renewables penetration is coming. Nine states, districts and territories, 13 counties, 159 cities and six leading utilities have committed to 100% renewable energy by 2050, according to Sierra Clubs' Ready for 100 project. As many as 15 other states are working toward 100% commitments, Sierra Club spokesperson Stephanie Steinbrecher emailed Utility Dive. 

The market potential is large. The U.S. produces 10 million metric tons of H2 with fossil fuels annually, according to the Department of Energy. Only 1% to 4% is RH2, which "signifies both the long way the technology has to go but also the potential for significant growth," according to Navigant Research.

Many of the business cases for green hydrogen depend on the relative prices of RH2 and electricity, UC Irvine's Reed said. "Through the 2020s and 2030s, production costs will likely come down dramatically as the need for what green hydrogen can do becomes greater" and scale production grows.

Today's almost "non-existent" demand could "reach 275 million metric tons by 2050," according to an August 2019 BNEF assessment. Today's price of RH2, which ranges from $2.50/kg to $6.80/kg, will be as low as $1.40/kg by 2030 and $0.80/kg by 2050, which is about $6/MMBTU, Bloomberg forecasted.

UC Irvine's more conservative analysis forecasted slightly under $2/kg in 2050, Reed said. "That is $16/MMBTU and would produce $0.10/kWh electricity from a combined cycle power plant. At $1/kg, it would be about $0.05/kWh, which is cost competitive for firm, fast-responding power and less expensive than other types of storage."

The Feb. 21 NYMEX natural gas futures price was $1.90/MMBTU, which shows the challenge RH2 still faces before it can be widely competitive with other generation sources.

But today's price forecasts are not the whole story. The higher the penetration of low-cost wind and solar, the more economic RH2 will be for power generation and the more it will be needed in reliability applications, Reed, Koch Blank and others told Utility Dive.

And the ​recent offer of $2.67/kg price for RH2 delivery in 2022 delivery by a hydrogen supplier H2 V Energies, suggests LADWP may surprise skeptical analysts.

Green hydrogen power plants

The two-unit 840 MW combined cycle natural gas-H2 Intermountain Power Project in northwestern Utah, led by LADWP, will replace an 1,800 MW Utah coal facility. It already has a secure water supply, a 2,400 MW high voltage direct current transmission link to the high-demand LA region, and it will interconnect with large existing and potential supplies of wind, geothermal, hydropower and solar.

In addition, the project will be built over unique underground salt caverns that are "ideal for storing hydrogen at high pressures," according to LADWP. A proposed 160 MW Compressed Air Energy Storage (CAES) pilot project would test storing wind and solar generation that would otherwise be curtailed as RH2 for seasonal reserves.

The turbines "will be able to burn a 30% renewable hydrogen/70% natural gas blend when the plant goes online in 2025," LADWP Intermountain Power Project Operating Agent Gregory Huynh told Utility Dive. "There will be a pathway to retrofit the units with modifications to get to 100% renewable hydrogen by 2045, to meet the Los Angeles zero-emissions mandate."

The initial 30% blend could be RH2 produced with imported or onsite renewables-generated electricity, Huynh said. "That is all still very preliminary."

As a first-of-its kind project, Intermountain's "economics remain to be seen" and "could be quite expensive," he acknowledged. "But electrolyzer costs are coming down and more adoption could drive that faster, like it did with solar. Our goal is to be cost competitive, but we need steps like these to get there."

LADWP has had "preliminary discussions on the feasibility" of producing or using hydrogen at its other natural gas plants and is "tracking the industry's progress," Huynh added. RH2 is an "important" potential solution to problems for getting to a zero emissions economy and could provide utilities with other revenue streams, "but we're focused on the first revenue stream right now, which is making electricity."

LADWP's plan to store large volumes of RH2 is an innovative recognition of the market's coming need for longer-duration, multi-day and seasonal storage, Green Hydrogen Coaliton's Lin said. Stored RH2 from low-cost renewables is likely to be more cost-effective than batteries and "can serve energy, capacity and ancillary services markets."

It is also important for utilities to see that "hydrogen strategies are electrification strategies," UC Irvine's Reed added. Because green hydrogen's "feedstock" is "largely renewable electricity," utilities can increase kWh sales by using it for hard-to-meet needs of the power, industrial and transportation sectors.

Early business case

A key early RH2 business case will be "arbitrage of power market prices," RMI's Koch Blank said. "Utilities can produce and store hydrogen when [electricity] prices are low and use it to generate power when prices are higher. In the near-term, that will be where over-generation is curtailed. Assets would be underutilized, but the virtually free power makes that business case feasible if the price differential is big enough."

When demand for seasonal storage is greater and RH2's price has come down, "its high energy density will allow humongous storage without a battery the size of Iowa," Koch Blank added.

The LADWP project may demonstrate another RH2 opportunity for utilities, he said. The falling price of energy and increasing value of peak demand capacity that comes with high renewables penetrations "has introduced volatility in demand and price that utilities and their customers do not like, and the storage potential of green hydrogen could reduce that volatility."

Finally, RH2 will allow leveraging some existing natural gas infrastructure built for its methane molecule "to avoid totally stranding those assets," UC Irvine's Reed said.

"Leading turbine manufacturers like Mitsubishi and Siemens know it is not technically daunting to retrofit [natural gas plant] turbines for green hydrogen," he said.

Mitsubishi has natural gas units in operation using blends of up to 90% hydrogen, Mitsubishi Marketing Vice President Todd Brezler told Utility Dive. The turbines it will bring to market "will be engineered to burn 30% hydrogen blends by 2025 and they will eventually be retrofitted to burn 100% hydrogen by basically swapping out combustion system parts during planned maintenances, at costs similar to replacing other parts."

RH2 and methane are "different molecules, but engineers will figure out the chemistry equations at costs that will allow green hydrogen to compete economically," he added. "By 2030, electrolyzer costs will be down enough to make renewable hydrogen cost-competitive and turn potentially stranded natural gas system assets into assets that can provide carbon-free power."

The Southern California Gas Company's (SoCalGas) natural gas storage facilities, which are depleted oil formations, "could be as good as salt caverns for storing hydrogen," Reed said. Building new pipelines or retrofitting existing ones "would have costs, but existing rights-of-way will be very valuable, and if we can reuse or evolve that system, it could help make green hydrogen cost effective."

SoCalGas is working "to repurpose our existing infrastructure to meet California's carbon neutrality and climate goals," SoCalGas Public Policy and Planning Manager Tanya Peacock told a Verdexchange audience Jan. 27. Delivery of natural gas-RH2 blends through the existing system can "help in the evolution of renewables."

That evolution could happen at the distribution system level as well.

Distributed green hydrogen

The cost and complexities of a new or retrofitted pipeline system could delay the vital decarbonizing of the transport and industrial sectors, Koch Blank, Reed, Lin and others agreed.

Fossil fuel combustion is today's best option to get the "continuous" or "on demand" temperatures of over 300°C, and often over 800°C, needed to manufacture vital commodities like cement, steel and plastics, Columbia University Center on Global Energy Policy Senior Research Scholar Julio Friedmann's October 2019 paper reported.

RH2 combustion could, however, soon be cost-competitive enough to replace fossil fuels in powering industrial processes, Friedmann concluded. But delivery of RH2 to industrial sites remains a challenge.

Delivery also remains a challenge for RH2 in transportation. 

With adequate policy and incentive support, there could be a "hydrogen transportation sector" by "the mid to late 2020s," UC Irvine's August 2019 report to the California Energy Commission concluded. "Dozens of new renewable hydrogen production facilities will be needed to meet demand by 2030."

Support for RH2 in transportation was recently endorsed by a December 2019 Southern California Edison white paper and a February 2019 Pacific Gas and Electric regulatory filing.

"Green hydrogen is in the money right now" for some industrial vehicles, Green Hydrogen Coaliton's Lin said. And medium and heavy-duty long distance, high utilization, and heavy payload transport like some bus and truck fleets, long-flight jumbo jets and shipping "will be a really good fit."

And there is a way to bypass the delivery obstacle, green hydrogen advocates agreed.

"A dedicated hydrogen pipeline would be a super gamechanger," Lin said. "But water could also be electrolyzed at the site where green hydrogen is used."

Electrolyzers producing RH2 from water and renewables-generated electricity at industrial and medium and heavy-duty fleet sites "makes sense," Koch Blank said.

Utilities could use managed charging methods developed for electric vehicles (EVs) to get similar or greater system benefits, he added. And co-locating electrolyzers and RH2 storage at fast charger and fuel cell refueling sites could help reduce load spikes.

Regulators could support utility participation in electrolyzer deployment in the same ways they supported EV charger infrastructure deployment, UC Irvine's Reed agreed. There is "a compelling regulatory argument" in load management benefits and new revenues.

"Electric utilities need to pay attention to green hydrogen because, like EVs, it is a potentially growing load they never before had access to," Lin added. "Innovation that is hard to imagine is coming" and "the transition to green hydrogen offers something for every incumbent, from electric and gas utilities to policymakers and private developers."

What regulatory actions could help establish a path to higher renewables integration?

Regulators, legislators and other stakeholders highlighted the importance of flexibility, business model changes and enabling non-wires alternatives, during the Interstate Renewable Energy Council (IREC) Vision Summit​ on Wednesday.

But restructured utilities are finding it difficult to encourage non-wires alternatives, such as distributed energy resources (DERs).

"There's no incentive for the wires utility part of Exelon to go acquire that commodity," under the current business model, Steve Steffel, DER planning and analytics manager for Pepco Holdings, an Exelon subsidiary, told Utility Dive.

The creation of a Distribution System Operator (DSO) that can transact energy at the distribution level could advance Exelon's utilities to expand access to renewables and DERs, he said. Exelon views transactive energy as a possible activity "down the road," and separating the ownership and the operation of electric distribution. 

DSO considerations are not new, but a lot of unanswered questions remain about the benefits of distributed resources aggregation and the creation of a formal distribution operator, according to Sara Baldwin, regulatory VP at IREC​.

"The concept is definitely out there and people are looking at different ways of approaching how to manage distributed resources on the grid,” she told Utility Dive.

Many energy policy experts have highlighted the need for distributed resources, including storage and demand response, on the grid. Encouraging DER, non-wires deployment and continued growth is key to avoiding costly upgrades for transformers or substations, former Hawaii regulator Lorraine Akiba said at the IREC Vision Summit.

The Hawaii Public Utilities Commission announced its intent in 2014 to modernize the state's utility business models, which "gave regulatory certainty that we're going to treat DERs, ... energy efficiency, demand response, electric vehicles and electric storage as generation resources,” to encourage growth, said Akiba, who currently works as a regulatory and public policy consultant.

However, while regulators can direct Hawaiian Electric, the biggest investor-owned utility in Hawaii, to issue power purchase agreements (PPAs) for non-wires alternatives, DERs and demand response, a restructured utility would need other mechanisms to impact the growth of those resources.

"For us, what are we going to do with these PPAs, you know? That's kind of the challenge" that a DSO market would address, Steffel said.

However, electric distribution is vertically integrated, largely, with utilities like Exelon owning and operating the distribution grid. Establishing a DSO that includes behind-the-meter solutions would separate the operations aspect, to enable DER and non-wires solutions to plug in, according to Ric O'Connell, GridLab executive director.

"The idea I like is the distribution grid as a platform that you know, electric vehicles, [energy] efficiency, all that stuff can come and plug into," O'Connell told Utility Dive.

"What it would do is allow everybody to operate economically, but [the DSO would] step in if there was, you know, going to be grid problems to manage and operate," Steffel said.

While the grid has distribution automation today to reconfigure circuits in the event of a fault, it does not know how to switch a negative load, creating the need for monitoring that would come with a DSO, he said.

California and other states with a lot of solar energy have experienced zones with so much solar output so as to create negative load or negative electricity pricing caused by an oversupply of generation.

Without DSO capabilities, the increase of DER resources "will affect reliability and other issues down the road," he said. "I know there's a lot of things you can do semi-autonomously, but there's also things that you have to do with control if you're going to continue on the higher [renewables, DER] penetration path," like controlling different combinations of resources and changing the power factor.

"If we could do the [distribution-level] transactions and manage that between one customer to another, that would be a whole ‘nother paradigm. We're looking at that, whether we use blockchain or whatever to do the back-office transaction," Steffel added.

One challenge to build out DSO markets, he said, would be to carry out transactions while adding values to stakeholders, so that "nobody's losing money or it's not lowering the value of what we're delivering."

Exelon could be ahead of the curve on evaluating DSO possibilities, but it could also be among the "most interested in the DSO model” due to its restructured businesses, GridLab's O'Connell said.

DSO markets: Not tomorrow's solution

DSO discussions are "definitely floating around," Steffel said, but transmission system operators largely control distribution-level energy supplies by having them work through the transmission marketplace.

"There'd have to be a distribution system operation marketplace... a different paradigm" within the existing market structures.

PJM Interconnection and other transmission operators, "they probably would have to do a lot of negotiating to figure out how the two entities could operate," Steffel said.

"A DSO would allow for a lot more of this idea of transactive energy," he said, of neighbors supplying neighbors from their DERs through the distribution system.

"The people operating this would probably have a wall of separation so they're totally neutral and not biased ... But I think down the road of that, if we're going to continue to put more and more DERs, and that's basically distribution-level generation, you're probably going to have to have that," he said.

However, any substantive movement on this is a long way off, according to many stakeholders.

"I do think that before we get to the DSO, we really need to focus on data" related to DERs, Mike O'Boyle, electricity policy director at Energy Innovation, told Utility Dive.

"What data do DER providers need and what data does the utility need to provide to regulators and stakeholders in order for this whole model to work?"

Beyond those questions, utilities must understand hosting capacity and provide a data platform for the distribution grid, he said. California and, to some extent, Illinois are the farthest along in sharing anonymous system data, according to O'Boyle, which is necessary for an operator to gain visibility within DERs.