Rate Design Reform

California Public Utilities Commission (CPUC) President Marybel Batjer says the state will not let skyrocketing electricity rates threaten reliability or the state's policy goals.

But affordability is a growing concern as California works toward a "future grid" and a dynamic new power system to meet the climate crisis and related extreme weather events, stakeholders and CPUC Staff maintain. Rates rising far faster than inflation are straining the budgets of vulnerable customers and new approaches that protect policy goals and customer bills are urgently needed, they agree.

Protecting ratepayers as California transitions to distributed energy resources (DER) and economy-wide electrification "will require aggressive actions," according to a report released by CPUC Staff in February.

At a day-long CPUC hearing, California utilities proposed cutting wildfire costs and raising revenues outside rates. Stakeholders proposed shifting the costs of supporting DER and electric vehicles (EV) out of rates to other sources of revenues. Others proposed breakthrough rate designs that could make managing costs more equitable.

Staff report finds rising rates

The upward pressure on rates could force unwelcome choices on policymakers, especially to protect low to moderate income (LMI) customers, according to the Staff report.

Driven by clean energy and electrification mandates as well as utility investments in system modernization, residential rates across California have risen faster than inflation since 2013, Staff found. And due to Net Energy Metering (NEM) and other DER incentives, impacts have been worse for LMI customers, it said.

By 2030, Pacific Gas and Electric (PG&E) residential rates will be 40% higher than if they had followed inflation, Staff projected. Southern California Edison (SCE) rates will be 20% higher and San Diego Gas and Electric (SDG&E) rates will be 70% higher.

LMI customers are "like canaries in a coal mine," said Jennifer Dowdell, an energy policy analyst for customer advocacy group The Utility Reform Network (TURN). "Rates are growing so much faster than wages that even the middle class may soon need rate relief."

The rise in rates is impacted by other factors, Staff reported.

"Rate based capital investments in transmission and distribution are accelerating," and wildfire mitigation costs have "significant rate impacts," Staff found. The report projected wildfire mitigation costs from 2021 to 2030 will cost PG&E $23.7 billion, SCE $17.2 billion, and SDG&E $3.9 billion.

Another factor is the costs of the state-mandated net energy metering (NEM) 2.0 program that compensates DER owners for electricity sent to their power systems. Net-metered generation was over 15% of PG&E, SCE and SDG&E residential electricity consumption in 2019, recent research showed.

An independent evaluation of the NEM 2.0 program from 2017 to 2019 found the policy "increases non-participant bills," Staff reported. In that period, an overall system evaluation found total benefits of $7.96 billion and total costs of $9.46 billion. A separate evaluation of customer bill impacts found total benefits of $7.58 billion and total costs of $20.58 billion.

Transportation and building electrification "can lead to lower household energy costs" where the cost of electricity is lower than the price of gasoline or natural gas, but the high "up-front" costs of EVs and DERs are a "barrier to participation" for LMI customers, Staff found. That leaves them with "incremental costs" as revenues covering system costs from more affluent customers who adopt DERs fall.

In addition, Staff found reducing the state's 46 MMT 2030 power sector emissions target to the proposed 38 MMT target would add $0.006/kWh to $0.008/kWh to all customers' rates because more emissions reductions would add new system transition costs and accelerate current patterns.

Revenue requirements for transmission system modernization also put major upward pressure on rates, Staff said. From 2016 to 2021, the three IOUs' requirements will increase 38.1%, Staff projected. And "every dollar put into the transmission rate base costs ratepayers in excess of $3.50 over the life of a transmission asset." Transmission use charges are also driving rates up.

Concerns about rates are important, but investments in DER offer "net benefits to the California economy" that Staff has overlooked, stakeholders responded.

A shift to a high home electrification scenario would add 4.7% to 5.8% to the total 2030 utility revenue requirement because investments would be needed for distribution system upgrades to manage the new load. But utilities' 8.5% increase in 2030 electricity sales could lower average rates, Staff acknowledged. And EV ownership with or without managed charging programs reduces driving costs.

But affordability is at risk, and "it is hard to pinpoint places where we should cut back," said CPUC Deputy Executive Director for Energy and Climate Policy Edward Randolph. Wildfire mitigation and transmission development are critical to avoiding outages, "and investments in clean energy are necessary to meet state policies, have minimal bill impacts, and could save money over time," he added.

Stakeholders have proposed two paradigm-shifting rate designs to address Staff concerns.

A volumetric charge fix

Stakeholder rate design proposals address a utility bill's fixed charge and volumetric per-kWh charge, but in different ways.

With electricity sales declining from "energy efficiency, energy conservation, and customer generation, the bill's fixed charges do not cover fixed costs," Staff said. Higher volumetric rates have been approved to cover fixed costs for infrastructure, DER and LMI subsidies, energy efficiency programs, and wildfire mitigation.

The Regulatory Assistance Project (RAP) Advanced Residential Rate Design proposes time-varying rates to cover costs not met by the fixed charges, RAP Associate Mark LeBel said. They are more granular than California's current time-of-use (TOU) rates and "are incentives to use electricity when it costs least and export electricity when the costs are highest because it is most valuable to the system," he said.

Consulting firm Verdant's NEM 2.0 study showed California's TOU rates create inequities, and an Energy and Environmental Economics study for the CPUC proposed high fixed charges as an alternative, LeBel said. The RAP rate design "allows for equity and encourages electrification." It also includes a unique "bidirectional distribution network charge" that "assures utility revenue requirements are met," he added.

RAP's bidirectional charge is a per kWh charge on imports and exports that matches the evolving grid's two-way power flows, LeBel said. It would vary according to netting and other options. And it could also be implemented incrementally, with increasingly nuanced time periods and sophisticated customer segments.

This rate design is only necessary in places like California and Hawaii with high penetrations of DER that are shifting costs, he added. "It does not solve all the challenges, but it can be part of a package of solution strategies."

A fixed charge fix

RAP's proposal does not solve California's fixed costs challenge, said Severin Borenstein, director of UC Berkeley's Energy Institute and professor of Business Administration and Public Policy.

Putting policy objectives in the volumetric part of utility rates or increasing all customers' fixed charges is "regressive," added Borenstein, who is also a member of the California Independent System Operator Board of Governors.

The price of electricity should reflect and cover the "social marginal cost" of each unit of electricity, he said. That is the cost of generation, transmission, distribution and greenhouse gas emissions in a unit of electricity plus the still-unpriced societal impacts of pollution from producing electricity.

California rates are "way above that" because fixed costs, including those for infrastructure, wildfire mitigation, and LMI and DER, are paid for through the volumetric charges, he said during a Feb. 24 CPUC hearing. A more "progressive" rate would recover fixed costs from an income-based fixed charge that would be low for LMI customers and higher for the more affluent.  

The fixed charge innovation is a more complicated rate design because it requires income information, and customers' privacy would require protections, Borenstein acknowledged. But California's tax authority and its utilities could resolve those obstacles.

The Borenstein data shows today's rate structure is regressive, LeBel agreed. But his rate design has implementation challenges, like income verification, that are probably only worth taking on at high levels of DER penetration, he said. And it "increases the rates of higher income customers, which gives the people who can most easily afford to defect from the grid the biggest incentive to do that."

Recent research does show a high volumetric charge could increase grid defections in high penetration markets, Borenstein said. "But this is a fixed charge increase. The wealthiest customers might face an $1,800/year fixed charge, but would have a $0.10/kWh volumetric charge. That is less reason to defect than the $0.40/kWh volumetric charge forecast for California."

There is a simpler approach, Borenstein said. California could add electricity to the programs it offers, through the state budget, to help LMI citizens with food and healthcare, but that would be "politically difficult" because it would have tax impacts. "There is no easy solution," he said. An income-based fixed charge "is the best alternative."

But the CPUC hearing produced other alternatives, including utility proposals for cutting costs and increasing revenues as well as stakeholder proposals for alternative funding.

Alternatives to rate redesigns

The rapid rise in California's rates makes finding solutions urgent, utilities and stakeholders agreed.

"We are in a rate crisis now with electricity costs growing faster than inflation, inequity rising, and wildfire costs coming," said CPUC Public Advocates Office Electricity Pricing and Customer Programs Branch Manager Mike Campbell. 

"Climate change is the existential problem of our time, but the commission's approach so far addresses it like the blind man encountering an elephant who sees only a part instead of the whole challenge," Center for Energy Efficiency and Renewable Technologies (CEERT) Senior Technical Consultant Jim Caldwell added.

PG&E is working on ways to reduce costs and generate other sources of revenue, said PG&E Vice President of Regulatory and External Affairs Robert Kenney. "Operational efficiencies" may save nearly $1 billion/year through 2025, and $973 million in revenue is expected from agreements with wireless provider SBA Communications for the future use of PG&E transmission towers, he said.

In addition, customer-funded wildfire self-insurance "can be a near term solution until better wildfire control technologies bring premiums down," said SCE Senior Vice President of Strategy and Regulatory Affairs Carla Peterman.

SCE's "tower of insurance" to meet the $1 billion coverage now mandated by California law may include layers of commercial insurance, bonds and reinsurances, and "premiums in some layers could exceed utility losses," Peterman, a former CPUC commissioner, said. "Self-insurance could be more affordable."

Self-insurance eliminates insurance company administrative costs and profits, and "if claims are low, new premiums will be minimal," she added. Savings could be "in the hundreds of millions of dollars  over a multi-year period." 

SDG&E's wildfire mitigations are the industry standard and it is investing in new technologies to improve its capabilities, said Scott Crider, the utility's chief customer officer. And the investments' "risk-spend" balance is focused on reducing the need for future wildfire mitigation capital expenditures.

The political barriers mentioned by Borenstein to leveraging public revenue for public programs like wildfire mitigation and building and transportation electrification may not be impossible to overcome, some stakeholders said.

"Many of the costs in rates are to achieve societal benefits," TURN's Dowdell said. "Traditional utility rate making is one of the most expensive and regressive ways to obtain those benefits."

When California utility rates were relatively low, they could be used for policy objectives, "but the state does not have that luxury anymore," Dowdell said. A better concept may be California ownership of assets like large-scale long duration storage, new transmission, and EV charging infrastructure needed to achieve state goals. Others saw this idea as having varying prospects of success because it could increase the tax burden.

"There's not one magical strategy," Dowdell added. "Tax revenues to pay for those investments could come from California's general fund or the state and municipalities could use their bonding authority for specific infrastructure projects."

At the close of the hearing, the CPUC's Randolph complimented the stakeholders' proposals but also cautioned broadly about unintended consequences as commissioners consider which to implement.

On the other hand, "the commission needs to recognize that even the right investments will put upward pressure on rates, but it also needs to look at the consequences of not investing," CEERT's Caldwell said.

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."

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By GridX

As regulators continue to implement public policy related to Renewable Portfolio Standards and other decarbonization measures, one their most often used tools is Rate Reform.  These reforms can take many shapes.  The most common is time variant rates, typically referred to as Time of Use (TOU) rates. 

There are, however, multiple business models that are being considered – often in parallel with a move to TOU rates.  These business models include Demand Response, Net Metering, Energy Efficiency, and Energy Storage.  All of these can play a role in meeting policy goals – and they all need the appropriate rate structures and incentives to be successful.

In many cases the urgency to pursue these business models is accelerating.  Paradoxically, the ability for utilities to quickly design, market and bill for these new pricing plans is often hindered by manual processes and legacy systems, which can slow innovation and frustrate regulators.  Of course, the regulatory process, itself, can also be a hindrance to rapid innovation.

For stakeholders in this Rate Reform process, the challenge is to design and create effective rates at a pace that will support achievement of the policy goals.  Rate Engineering, which combines a utility’s internal rate design expertise and a big data Enterprise Rate Engine, is an innovative process to address these dual challenges. Rate Engineering allows utilities to achieve policy and business objectives by providing a more comprehensive view of how new rate designs impact revenues, customer classes, and every customers’ bills.

A key aspect of the Rate Engineering method is Whole Population Bill Impact Analysis. This analysis consists of two parts: (1) calibration of the Enterprise Rate Engine against the utility CIS to ensure the accuracy of the analysis results, and (2) use of Big Data Billing Analytics to evaluate the bill impacts for all of the utility’s customers.

An Enterprise Rate Engine can calculate hundreds of millions of bills in hours. With this power, utilities can run a nearly unlimited number of scenarios when developing new rates. A potential new rate plan, or multiple potential rate plans, can be calculated over the utility’s entire customer base, using each customer’s historic or projected load. This allows the utility to study how a potential new rate plan will affect each individual customer as well as each customer class.

After the new rate or rate design has been approved, the same Enterprise Rate Engine and calculations are leveraged for rate education and marketing. This can be particularly useful when moving to time-of-use rate plans. Every single customer’s bill can be simulated, based on the individual customer’s actual load or estimated load profile, identifying which customers will experience a bill increase, and by how much, and which customers will experience a bill decrease, and by how much. With this information, the utility can proactively advise customers how their bill is going to change and how much usage the customer should change from peak to off-peak to realize time-of-use savings.

Benefits of an enterprise rate engine

More Precise Rate Implementation – Through calibration against the billing systems and evaluation of bill impacts for the whole customer population, the Rate Engineering approach results in more precise rate implementation. The massive amount of computation power made available by big data technology enables rate designers to simulate the bill impacts for a large number of design proposals, then choose the design with not only the right average, but also the right distribution of bill impacts among various rate classes.

More Comprehensive Analyses – By evaluating the bill impacts for the whole customer population, the Rate Engineering approach enables utilities to understand the impact of new rates on every single customer, every month, before submitting them for approval. The fine-granularity, bill impact analyses allows a utility to investigate the “tails,” those sub-populations whose bills are substantially impacted either positively or negatively.

Analyses Available to More Stakeholders – Given the importance of bill impact analyses with new rates, organizations outside of the rate design team have significant interest in the analysis results. The availability of across the Enterprise to the comprehensive fine-granularity, bill impact analyses frees the rate design team from these data requests and provide other stakeholders with self-serve options.

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."

A landmark settlement between Duke Energy and distributed energy resources (DER) advocates in North and South Carolina could remake the rooftop solar sector and be a model for ending regulatory disputes across the country.

The proposal, released Sept. 16, could calm contention between utilities and solar advocates over the perceived "cost shift" some utilities and policymakers see as a subsidy for rooftop solar paid by non-solar-owning customers. The settlement would, if approved by Duke's North and South Carolina regulators, pair rooftop solar with smart DER devices and time-varying rate designs to add to the utility's demand response capability and give customers an incentive to help address the utility's peak demand challenges.

"This is a totally new framework that treats self-consumed solar paired with demand response as energy efficiency and includes rate design innovations in dynamic pricing," said Duke Energy Vice President for Rate Design and Strategic Solutions Lon Huber. "We eliminate the cost shift, but retain a vibrant solar market, which could be a paradigm-changing win in the national net metering debate."

Legislative and regulatory conflicts continue to increase nationally over replacing the retail rate net energy metering (NEM) tariff typically paid to solar owners for electricity exported to utility systems, said North Carolina Clean Energy Technology Center (NCCETC) Senior Policy Program Director Autumn Proudlove. "Some states have delayed action, but the approved changes have reduced compensation."

Successor tariff debates ultimately slow rooftop solar growth, according to Proudlove. But Duke and other utilities who see how customer-owned DER can cost-effectively help reduce peak demand and meet policy goals are working with stakeholders across the country on ways to take advantage of those DER investments without imposing costs on other customers.

The new proposal, developed in response to solar policy directives in South Carolina's 2019-enacted Act 62, and North Carolina's 2017-enacted House Bill 589 (HB589), can accomplish those objectives, according to representatives of Duke, Sunrun, Vote Solar, the Southern Environmental Law Center (SELC) and the North Carolina Sustainable Energy Association (NCSEA) who helped shape the settlement.

Fights over NEM

NEM compensates rooftop solar owners for the generation their arrays send to the grid, and is available in 40 U.S. states and Washington, D.C. Compensation is set at the same retail rate customers pay for electricity, unless successor tariffs are in place that adjust that compensation.

NEM was deployed state by state to support early renewables growth. Retail rate compensation was a proxy for the value of the exported generation. Since at least 2013, utilities have complained about NEM to regulators, arguing its reduction in solar-owning customers' bills shifts system costs to the rest of the customer base. Solar advocates argue NEM benefits all utility customers by reducing operational costs.

The result is often-heated conflicts between utilities and solar advocates over a successor tariff that would theoretically represent the true value of distributed solar but prevent an undue shift of costs to non-solar-owning customers. The Duke settlement aims to eliminate some of those debates through rate design and smart technologies.

In many states, compensation debates "have been quite contentious" because utilities "want to reduce or eliminate the cost shift and have proposed compensation at avoided costs or wholesale rates," Proudlove said. Solar advocates are "realistic about coming changes," but want cost-benefit or value-of-solar studies to set a compensation that matches the value of their exported generation.  

South Carolina's Act 62 required review of the retail rate NEM provision by regulators in 2021 and North Carolina's HB589 required a review by 2027. With successor tariff debates likely and Duke subsidiaries the dominant electricity providers in both states, it made sense for stakeholders to work toward a plan, NCSEA General Counsel Peter Ledford said.

The proposal, which the settlement partners described as "unprecedented" and "paradigm-changing," has special significance because solar has struggled in the Southeast, regulators have been and continue to be hard on NEM policies, and installed solar capacity has only recently begun to match the region's resource potential.

Southern Company subsidiary Alabama Power's retail rate is $0.1337/kWh, but based on concerns about a cost shift, pays solar owners only a regulator-approved $0.035/kWh for exported electricity, SELC reported in 2019. And, in July, the utility won regulatory approval for one of the region's "highest solar-specific monthly charges," said SELC Senior Attorney and Solar Power Initiative Leader Lauren Bowen.  

In Florida, the 2019 regulatory approval of solar leasing, combined with the state's NEM, led to a boom in rooftop solar, Southern Alliance for Clean Energy (SACE) Energy Policy Attorney for Florida George Cavros reported Sept. 11. By the end of 2019, there were "nearly 60,000 customer-owned net-metered systems." But there was also a call for regulatory review of the NEM policy, Cavros reported.

"It is a pattern around the country," Bowen said. "At a certain rooftop solar penetration, the need for a variation on net metering is raised."

The North and South Carolina bills' requirements that retail rate NEM be reviewed make successor tariff debates likely and a new approach practical now, stakeholders said.

A sustainable solution

The settlement participants see the new proposal as a sustainable way to end the NEM and successor tariff debates.

"Collaborations on successor tariffs often produce piecemeal, short-term agreements," Vote Solar Senior Regional Director and Regulatory Counsel Thad Culley said. "This proposal is a comprehensive and paradigm-changing solution and should hold up over the long term."

The settlement proposal brings together time-of-use (TOU) rates, critical peak pricing (CPP) and incentives for participation in Duke's demand response programs, Sunrun Director for Public Policy Tyson Grinstead said. "No one piece is the perfect solution, but the package as a whole preserves the critical underpinnings of net metering."

It offers an upfront rebate for adding a smart thermostat that Duke could use to shed or shift customer usage and manage peak demand, he added. Taken as a whole, the benefits would be "as good as with net metering," Grinstead said.

The high-level Act 62 objectives required eliminating the cost shift, ensuring the solar market remain uninterrupted and offered the option of time-varying rates and other strategies, Huber said. "The settlement's combination of policy elements addresses those objectives and incorporates best practices for those options from other states into a scalable long-term framework."

The CPP and mandatory TOU rates send solar-owning customers improved price signals to reduce consumption when power prices are high, Huber said. "Along with monthly netting, solar owners will be able to maximize the value of self-consumption. A minimum bill, grid access fee, and non-bypassable charges assure that the cost of public programs and the grid are covered" without imposing costs on other customers.

Models of the settlement plan suggest a 92% or more reduction of the Duke-calculated cost shift from solar owners to non-solar-owners, Huber added. "The plan would increase solar owners' current average payback for their rooftop systems from 11 years to about 14 years, but with the demand response program incentives, it would likely come back in line with today's payback."

NCSEA has crunched the numbers, Ledford said. "This will not work for every customer in every situation, but we think the payback will make rooftop solar a good deal." Vote Solar's Culley agreed the plan "will offer good cost savings," if solar owners respond to price signals, and also noted it has a grandfathering provision that will protect current solar owners.

The plan's incentive will initially be available only to customers with smart thermostats, but eventually other flexible DERs will be eligible, Huber said. "If North Carolina and South Carolina regulators approve the proposal, customers' self-consumed solar and dispatchable demand response would be part of Duke's 'shared savings' energy efficiency program, making rebates eligible for cost recovery," he added.

If that happens, the utility would be allowed to recover the same 10.6% of the net benefits from utility savings that is allowed for any other technology in Duke's energy efficiency program, he said. And that makes it "in shareholders' interest for Duke customers to add rooftop solar." 

DER advocates defended the utility's cost recovery. It is an expenditure "that allows customers to invest their own capital to build a more distributed and reliable grid," Sunrun's Grinstead said. "That is a win-win."

Duke shareholders "should be able to earn on efficiency investments because it puts those investments on a level playing field with other capital investments that shareholders earn returns on," NCSEA's Ledford agreed. That is "a policy decision that was made in North Carolina 15 years ago and has played out well."

Will regulators approve?

The proposal now faces regulatory review from two commissions. "Duke's Carolinas system shares the costs of energy efficiency programs between the states, and both state commissions have to approve them," Huber said. Settlement partners are optimistic South Carolina regulators will approve because the proposal meets Act 62's objectives, but North Carolina approval is less certain, Huber said.

The energy efficiency provision is a key strength in North Carolina "because Duke has never had satisfactory visibility or control of DER on its system and that is a practical operational difficulty," NCSEA's Ledford said. This proposal resolves that because the smart thermostat provides visibility and some control over customer usage, protects the solar market's financial calculus, and protects and benefits customers not interested in solar, he added.

"It is too soon to say the North Carolina commission will approve it, but much of this has been negotiated between the utility and [solar] industry advocates who work in both states," Ledford said. "Opponents may not see this as a perfect solution, but once they look at the numbers, they will understand why it is a good compromise."

There are also uncertainties in South Carolina, said Grinstead, a former aide to Sen. Lindsey Graham, R-S.C. "Four new commissioners will be appointed to the seven-member commission by the legislature later this year and one of the first things they will take up is this settlement."

But the proposal meets Act 62's objectives, which will make approval more likely, VoteSolar's Culley said, agreeing with Huber. And in North Carolina, "if Duke and NCSEA agree on a settlement, as they did with HB589, it is likely to get approval."

While Huber is cautiously optimistic about approval in the Carolinas, he is also looking ahead. "This can guide the rest of the country on how to look at rooftop solar, and how to move beyond our traditional way of separating rooftop solar from other demand-side resources."

The Federal Energy Regulatory Commission on Friday reversed a March decision regarding jurisdiction over electric cooperative exit fees, in a ruling that experts say could have broader implications for rate cases.

FERC now says it has exclusive jurisdiction over Tri-State Generation and Transmission Association’s member system exit charges, preempting work the Colorado Public Utilities Commission (PUC) has been doing to set exit fees for a pair of distribution cooperatives that are members of Tri-State.

Energy attorney and Georgetown Law professor Scott Hempling says the decision may have wider impacts than the immediate case — but the issues are also likely headed to court for further argument. The PUC and involved cooperatives could each ask the U.S. Court of Appeals for the D.C. Circuit to review FERC's decision, though the parties say no decisions have been made yet.

FERC backed away from its March decision in which federal regulators said "we decline to find that we have exclusive jurisdiction over Tri-State’s exit charges." 

The March decision allowed complaints by La Plata Electric Association (LPEA) and United Power to more forward at the Colorado PUC. The two cooperatives have been asking state regulators to set exit charges to leave Tri-State's service in search of a cleaner and more affordable mix of power.

Now, however, FERC says that “after further consideration we are modifying the discussion of the Declaratory Order to find that Tri-State’s assessment of an exit charge constitutes a Commission jurisdictional rate subject to our exclusive jurisdiction."

That means, FERC regulators said in their decision, "we also conclude that the Colorado PUC’s jurisdiction over the complaints regarding Tri-State’s exit charges is preempted" as of Sept. 3, 2019, when Tri-State became a public utility subject to the federal ratemaking jurisdiction.

Tri-State by added a new, non-cooperative member, California-based Mieco, and came under FERC's jurisdiction. The company is a subsidiary of Marubeni Corp. and supplies gas to Tri-State power plants.

“This is a monumental decision for our members and Tri-State, and allows us all to move forward in our clean energy transition with much more certainty,” Tri-State CEO Duane Highley said in a statement.

This is likely not the end of the debate, however.

Was Tri-State's member addition legal? 

"There is still an important determination ... as to whether the Mieco scheme is legal," Karl Rábago, energy consultant and former Texas regulatory commissioner, said in an email. He called the dispute between FERC and state regulators an "extreme case of forum shopping" that could result in state lawmakers getting involved.

"This is the kind of regulatory scheming that can incite strong state-level legislative response," Rábago said. "The co-ops are member-owned/constituent-owned after all."

The Colorado PUC has until Nov. 5 to make a determination on challenges to an administrative law judge's recommended order that the commission approve an exit fee methodology proposed by United Power. Among the issues that will be taken up is whether the addition of Mieco was allowed — and this is where the cooperatives are now focusing their arguments.

"While FERC reversed itself as to preemption, Friday’s FERC order points out the ultimate decision belongs to the Colorado PUC about whether Tri-State improperly added non-utility members," LPEA CEO Jessica Matlock said in a statement. 

According to Matlock, Tri-State's non-utility member addition — which brought on FERC regulation — was "inconsistent with Colorado law ... the final say here on preemption rests with the Colorado PUC and we look forward to having an opportunity to be heard on that issue by the full Colorado PUC."

LPEA is still evaluating its options, regarding preemption issues, according to lawyers for the cooperative.

United Power interim CEO Bryant Robbins says the additions of Mieco and other new Tri-State members "were improper under Colorado law." The cooperative has argued to FERC that the Mieco membership agreement still requires PUC consideration.

United Power "has challenged the additions with the PUC, has filed expert testimony to support its position, and has asked the PUC to decide that issue," Bryant said.  "United Power still can and will pursue its claim through the PUC or other Colorado tribunals, if necessary, and intends to see that process through."

According Hempling, FERC's Aug. 28 order is likely to be appealed.

"Unless a court reverses what FERC did, the Colorado PUC has no jurisdiction to determine whether the exit fee is reasonable under Colorado law," said Hempling. "That's the end of the road for them."

Terry Bote, external affairs manager for the Colorado PUC, said the commission's legal counsel "is reviewing the FERC decision, but has not conferred with the commissioners yet."

Decision could impact other rate cases 

"FERC interpreted the Federal Power Act to say that the exit fee is part and parcel of wholesale sales, because it recovers costs that the exiting customers would have paid for wholesale service if they had not exited. FERC reasoned that its jurisdiction over cost recovery does not depend on the timing of the cost recovery," Hempling said. 

There is the potential for this decision to have impacts outside of the Colorado cooperatives, said Hempling.

"When we free customers to shop, they leave sunk costs behind. Putting aside moral, political and economic efficiency issues, it's pretty important to have predictable policies," Hempling said. "Among the 50 states and FERC, we don’t have consistent, predictable policies" regarding how those costs are handled.

The issue of cost responsibility is especially salient at the retail level, said Hempling, where there has been much debate about homeowners installing solar panels and whether the costs they no longer cover are borne by other non-solar customers. While he said there are no state-federal jurisdictional issues at play there — at least until solar customers start selling into wholesale markets — FERC's determination that exit fees are a part of wholesale rates will likely impact future cases.

The question now becomes, "will FERC settle on a predictable methodology or are we going to have dozens of cases where people argue the same thing," said Hempling.

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."

Hawaii's latest postcard from the power sector's future is the management audit its Public Utility Commission (HPUC) ordered in the Hawaiian Electric 2019 general rate case, which highlighted significant opportunities for a new kind of regulation.

The audit revealed weaknesses in business and operational practices that regulators, utility leaders and stakeholders can address as the state moves toward performance based regulation (PBR), the audit reported. The audit found strengths, but identified weaknesses, especially in the company's Energy Delivery division, where "urgent corrective actions" could "deliver annual benefits for customers" of $46 million by 2023.

"We're taking ownership of the need shown in the audit for us to become more efficient in a lot of areas," Hawaiian Electric CEO Scott Seu told Utility Dive. "Our very explicit commitment is that we are going to do that as our company transitions to 100% renewables and new regulation."

But the corporate culture revealed in the audit may prevent Hawaiian Electric from meeting that commitment, some stakeholders said. That prospect for failure will require special attention from regulators as Hawaii moves into the biggest U.S. test of PBR, they added. It also makes the audit a message to regulators across the country, Rábago Energy Principal and former Texas electric utilities regulator Karl Rábago told Utility Dive.

"Audits are not uncommon, but they are more uncommon than they should be, given the transformation in the electric utility sector," Rábago said.

What the auditor found                           

A "management audit will help ensure Hawaiian Electric is operating in a prudent and efficient manner for the benefit of ratepayers" and "identify opportunities for improved performance," the HPUC's September 2019 order initiating the audit reported.

The need for an audit began with "public backlash over high energy prices" and "rejection by the Commission of a number of [Hawaiian Electric's] proposals," auditor Munro Tulloch reported May 12. Hawaiian Electric has "already been proactive" in improving efficiency and savings, but also has "greater opportunities for improvement," Munro added.

Hawaiian Electric's "One Company" restructuring has supported and streamlined Hawaii's ongoing "transition to a 100% renewable future," the audit reported. But "costs and staffing levels have also increased," often without "a clear role or purpose."

In a move widely seen as creating the opportunity to make corporate level changes ahead of the audit's release, Hawaiian Electric's board appointed Seu as CEO in March after former CEO Alan Oshima retired to head Governor David Ige's Coronavirus-19 response.

Seu replaced the Energy Delivery head and began restructuring, the audit observed. These are "encouraging signs" that Hawaiian Electric "is serious about delivering performance improvements," but "the difficult implementation work remains."

Structural and operational improvements across Hawaiian Electric's divisions and especially in Energy Delivery could "deliver annual benefits for customers, through cost reductions and savings, of as much as $35.7 million" in a "best-case" scenario, the audit found. "A more realistic target is annual benefits and savings in the range of $25 million - $26.5 million to be progressively delivered by the end of 2022."

The Power Supply division, which operates power plants, has shown how to "reconcile the apparently conflicting objectives of improving performance and reducing costs," it reported. In contrast, the Energy Delivery division, which oversees transmission and distribution systems, had "little focus on costs, efficiency and managing the business effectively."

The Energy Division's review of smaller projects, including "high value programs for asset replacement," lacks "clear objective oversight," the audit added. This is especially important in Hawaii, where the rapid growth of distributed generation has necessitated significant distribution system investment, stakeholders told Utility Dive.

Energy Division supervisors and managers "apply little attention" to whether work is done "efficiently or within budget," the auditors found. There was "little effort to correlate what had actually been delivered versus expenditure."

Contrary to stakeholder criticism, Hawaiian Electric's support of Hawaii's groundbreaking 100% by 2045 renewable portfolio standard (RPS) has been strong, the audit found. "It has exceeded its mandated obligations" and criticisms "appear to be largely unfounded."

The problem is cost, it said. Meeting the RPS and the challenge of integrating rooftop solar have led to increased workload and costs, the audit recognized. But Hawaiian Electric increased staffing "with little evidence of any business cases supporting these additions."

Overall, the utility can achieve significant annual savings by focusing on two principles, the audit concluded. Asset Management should focus on "selecting the right work" for the utility and Energy Delivery should focus on "doing the work right" so that costs are controlled.

 

Hawaiian Electric responds

Hawaiian Electric had already planned "to dive deeper into the business processes in 2020," Seu said. "Energy delivery has an absolutely foundational role in our transition to 100% renewables. Addressing the audit recommendations is the work ahead of us, and we're going to get it done."

But "foundational changes to the delivery of electricity," like balancing renewables' variability and integrating distributed renewables, have expanded "the scope and complexity of utility planning" and transformation "is not always conducive to efficiency," the company's response, included in the audit, acknowledged.

"Urgent attention to cost containment and efficiency is necessary," the company also acknowledged. But "nowhere does the audit report indicate any illicit purpose" such as private gain in the shortcomings identified.

Progress will depend on balancing "traditional work like maintaining plants and equipment with upgrading and modernizing," Seu said. "We're the ones operating the entire energy system, balancing the individual interests, and we, the PUC, and the Consumer Advocate have to be mindful of all stakeholders' concerns."

But this is "an inflection point, a time to take a hard look at the efficiency of our operations and energy delivery," he added. "The audit found it will likely take three years to deliver sustainable annual savings and we will report regularly on our progress."

Key reactions

Stakeholders praised the audit's evenhandedness and accuracy, but differed on what it revealed about Hawaiian Electric's performance.

The auditors provided "a total view of the operations of a utility" that showed "the enormity of this challenging transformation," former HPUC Chair Mina Morita emailed Utility Dive.

It was "fair" and "instructive" and should help Hawaiian Electric's transition to "a more productive and efficient organization" that can meet "multiple objectives including important public policy goals," she added. "It showed the company is committed to the state's renewable energy future," but also showed the challenge of "maintaining an aging system" when policy "disregards other essentials of a well-run utility" like reliability and affordability.

The audit includes "a fairly reasonable scope of detail and analysis" and "generated a portfolio of action items," Hawaii Consumer Advocate Dean Nishina said. It confirmed that even if integrating variable and distributed renewables requires "additional costs," the pursuit of RPS goals should not be done "at any cost" and "costs were higher than they needed to be."

It showed Hawaiian Electric can provide basic services and meet the RPS "in a much more cost effective and efficient manner," Nishina told Utility Dive. "Many changes still need to be made and some will require time."

"The audit made it clear the company is bloated and has been wasting resources," ProVision Solar President Marco Mangelsdorf told Utility Dive. "It emphasized Hawaiian Electric's lack of both cost control and attention to inputs and outputs."

Mangelsdorf acknowledged some positive aspects of Hawaiian Electric's clean energy performance, but said there are still questions.

Hawaiian Electric allowed "a far higher rooftop solar penetration than was thought possible 10 years ago without compromising system reliability," Mangelsdorf said. "But the audit does not show whether change could have been faster and deeper."

Looming behind the audit is the groundbreaking transition Hawaii is making from traditional cost-based regulation to PBR, Seu, Nishina and stakeholders said. The next phase of the proceeding is scheduled to produce a final order on design and implementation from the HPUC by the end of 2020.

PBR

A key benefit of the audit will be better information sharing among regulators, stakeholders and Hawaiian Electric in the PBR proceeding that can lead to "a more balanced and equitable outcome," Munro Tulloch reported. Seu agreed.

"PBR is to give the utility a direct line of sight to rewards or penalties based on what it delivers for customers, with a multi-year rate plan, by running the business more efficiently," Seu said. "Performance incentives reward the utility for meeting goals with cost savings. Most will go to the customers, but if the performance is good enough, the utility gets a share."

Designing PBR will require "a good baseline and a transparent understanding of our cost structures and operations," Seu said. "The audit is a foundation for PBR with a multi-year rate plan and that was probably a critical driver for the commission ordering it."

The audit "will help immensely with PBR" because it provides "a baseline to gauge performance improvement gains," former HPUC Chair Morita agreed. "If it had not been done, it would appear the regulators were going into PBR blindly."

Some stakeholders saw even greater importance in the audit's implications for the transition to PBR.

It emphasizes that Hawaiian Electric has not delivered services to customers "in a cost-effective manner," and that needs to be part of "the design of the PBR framework," Consumer Advocate Nishina said. Otherwise, changes might lead to savings for shareholders "and customers may not see of the benefits."

The audit makes more clear the need for PBR's "paradigm shift" by "highlighting what traditional regulation has allowed Hawaiian Electric to get away with," EarthJustice Mid-Pacific Managing Attorney Isaac Moriwake told Utility Dive. "PBR is intended to move away from regulatory proceedings like rate cases because no one has time for that with a climate crisis and a 100% renewables goal just decades away."

But it also "raises questions about implementing the multi-year rate plan part of PBR," former regulator Rábago said. Incentives and monitoring performance on metrics and goals are supposed to keep Hawaiian Electric on track, but they may show that management does not see efficiency improvement opportunities, and that could turn PBR into "cost of service regulation by another name."

The audit "hammered home the urgent need to focus on performance," ProVision Solar's Mangelsdorf agreed.

The other benefit

The other benefit of the audit was that it showed their broader value. "We were forced to take ownership of some very hard messages," Seu said. Recent audits elsewhere have delivered similar lessons, utilities told Utility Dive.

In response to a New Jersey Board of Public Utilities October 2019 final audit report, Atlantic City Electric, an Exelon utility subsidiary of Pepco Holdings Inc. (PHI) is doing "a full review" of "the opportunities identified," PHI spokesperson Ben Armstrong emailed Utility Dive.

When the Pennsylvania Public Utility Commission's November 2019 audit report of UGI Utilities estimated changes can deliver annual savings of up to $713,000, and one-time savings of up to $7.13 million, then-Commissioner Andrew G. Place reported UGI "indicated agreement with 42" of the audit's 45 recommendations in its implementation plan.

National Grid sees the Massaschusetts Department of Public Utilities' coming audit over concerns about some spending and management practices as a way to "reinforce our commitment to continuous improvement," National Grid spokesperson Christine Milligan emailed Utility Dive. 

Audits, if properly focused and conducted, can be very useful for both regulators and regulated entities, consumer advocate and former auditor Nishina said.

"Costs for upgrading the nation's aging electricity infrastructure and integrating rising renewables penetrations are driving major utility investments," former Illinois Commerce Commission Chair Brien Sheahan told Utility Dive. "The greater the impact of those investments on rates, the greater the scrutiny commissions are going to give to how ratepayers money is spent."

Increased transparency and accountability for utilities through audits "are good, especially because commissions often bring in third party experts to relieve overburdened staffs," he added.

Rábago agreed. "Spending is ballooning across the industry and answers to reasonable questions about that spending in contested rate cases are not always satisfactory," he said. "The management audit might be better suited to the purpose. In Hawaii and other states, regulators should be asking themselves how traditional tools for overseeing the utility budgets have not revealed poor practices."

In that, "Hawaii may again be a leader," he added. "The generic symptoms from Hawaii are transferable to other jurisdictions and the audit may be an overlooked tool."

Rising renewables penetrations are increasing the need for utilities to alter rate designs.

More dynamic pricing can signal customers when bill savings are possible for shifting use away from high demand periods. Automated technologies can help customers respond. And strong customer participation in these programs can turn variable renewables' threats into system benefits.

But will this overburden customers?

The key is a "seamlessly" integrating wholesale prices and automated home appliances, writes Brattle Group Principal Ahmad Faruqui in his Public Utilities Fortnightly article, which imagines 2040 pricing structures.

Affordable automated home energy management systems with set-it, forget-it technologies could someday allow customers to preprogram use-parameters to match dynamic rates, utility rate design authorities told Utility Dive. But such automation is not yet available, and until it is, dynamic rates require interest in electricity bills few customers have.

An alternative paradigm is electricity providers delivering services through subscription agreements. Tiered price contracts would allow customers to choose parameters but leave control to electricity providers.

2040 rate designs

With over 85 million homes now equipped with advanced metering infrastructure (AMI), utilities are preparing to opt-out time of use (TOU) rates toward more dynamic rates.

Voluntary dynamic rates that vary with electricity's value to the system are offered by about half of U.S. investor-owned utilities, according to a 2018 Brattle Group study. On average, 3% of customers opt-in.

New rate designs that engage customers through dynamic price signals will be vital to meeting 2040's system and customer needs, Faruqui said. If the 2040 supply mix changes to high renewables penetrations and customer behaviors do not support demand side flexibility, "we have a major disappointment coming" from system instability and costs.

Today's rates fall short of the real time pricing (RTP) that would reward retail customers for responding to supply-demand dynamics. "RTP is the most extreme form of dynamic pricing and won't happen at scale until automated home energy management technologies go beyond today's smart thermostats," Faruqui said.

But "the next generation of technologies and customers will take over by 2040 and allow this transformation," he said.

Today's rate structures do not collect the cost of serving customers, Edison Electric Institute (EEI) Executive Director of Regulatory Affairs Adam Benshoff told Utility Dive.

"Today's AMI and smart meters are now available to just over 60% of U.S. homes and can allow a more dynamic pricing structure," Benshoff said. "Customers are smarter than we think. Where they have rate options, they have learned how their behavior impacts their energy use and what they pay for energy."

It remains uncertain whether RTP will make retail markets as price responsive as wholesale markets by 2040, he said. "Most residential customers have limited time and attention for rate complexities, but automated technologies will allow greater customer response."

Smart grid authorities and customer advocates consistently acknowledge that customer acceptance of dynamic rates will only come if policies first drive deployment of technologies that allow them to take advantage of the rates.

Automated technologies will allow RTP to deliver demand side flexibility because "once the parameters of customers' preferences are programed, customer engagement largely ends," Karl McDermott, a former Illinois Commerce Commissioner, told Utility Dive.

Customers' key decision "will be whether to install the home energy management system," because operating with pre-set parameters will be outsourced to a service provider, he said. 

The current level of technology deployment will not support the demand flexibility needed to balance a high renewables system, McDermott said. "But utilities are already trying to wrap their heads around the coming change."

Utilities look to 2040

High renewables penetrations, automated technologies and dynamic rates are coming, but utilities differ on how urgently change is needed.

Procurement of cost-effective large-scale renewables is a bigger concern, PacifiCorp spokesperson Bob Gravely told Utility Dive in an email. It is unclear if a new system of automated technologies and dynamic rates will be accepted by "a vast ecosystem of users," he added.

Ameren is aiming for a variety of dynamic pricing options, the utility's VP Steve Wills told Utility Dive, but currently AMI deployment is the biggest barrier.

Legislation passed by Missouri in 2018 requires AMI deployment to be completed by the mid-2020s, but "we can't move rates too quickly or customers' bills will change too fast," Willis said.

Set-it, forget-it technology is expected to "mature a lot over the next five years" and customers may engage if they see value from those applications, he said. But "industry needs to make it that easy for customers."

The 2040 reality will likely include "parts of many visions," CMS Energy Senior VP for customer experience Brian Rich told Utility Dive in an email. Technology that "allows us to manage demand in new ways" is in place, Rich said. "The next step is about customer engagement."

Southern California Edison (SCE) completed its AMI rollout, has optional RTP and will have migrated essentially all customers to TOU rates by 2021, Senior Advisor for Pricing Design and Research Andre Ramirez told Utility Dive.

Incremental changes over the last 10 years show Faruqui's 2040 vision is not unreasonable, SCE Pricing Design and Research Director Russell Garwacki added.

"The next question is how to proceed, and the answer is better rate structures and price signals and customer awareness," Ramirez said. "Customers will respond to the value proposition in price signals. It is a disservice to them and to progress to assume they won't, and that's not how we get to 2040."

Technology will follow, he said. "Until they understand the value proposition in controlling their energy use to lower their bills, customers will walk past smart technologies on Target and Costco shelves."

But early adopters already have smart technologies and are opting in to RTP offerings, Garwacki said. "The next generation of ratepayers will eventually become the driving force."

Experience with distributed solar and electric vehicles has shown that policy and regulatory frameworks develop "in response to the passion of the early adopters," Ramirez said. "People do not get excited about rates, they get excited about what rates enable them to do, whether it is lowering their bills or protecting the climate."

Price signals and technology can engage customers in the implementation of RTP, but there is another way to accomplish that goal.

Subscribing to electricity

By 2040, today's cell phone and online subscription plans may have evolved into a new paradigm for electricity delivery.

As distributed energy resources transform homes into power plants, more capabilities will be centered in the distribution system, and utilities will need more visibility and control of them, former commissioner McDermott said.

Contract plans and subscription rates from utilities and other electricity providers should be tested, he said. Customers could select the parameters of cost and service for utility-deployed technologies and allow them to be used to strengthen the system and lower their rates.

"The Faruqui paper about autonomous technology and RTP is exactly right, but only for about 10% to 15% of residential customers," Navigant Director Lon Huber told Utility Dive.

"A high renewables future will require significant over-procurement with economic curtailment and storage to protect against long-duration outages," Huber said. "Most customers would not want to be on a complex RTP rate to address that. High renewables penetration will make the marginal cost of energy essentially zero most of the time, with very expensive, hard-to-predict, capacity scarcity events."

The subscription concept "transfers all the complexity to electricity providers sophisticated enough to manage it," he added. "Netflix profits from handling bandwidth complexities, and electricity providers can profit from controlling demand flexibility, which should motivate them to see that advanced and automated technologies are deployed to customers and used."

Both RTP and subscriptions lead to automated technologies handling residential energy management, Huber said. 

Subscriptions and outcome-based, customer-centered pricing "is where everybody else in the economy is going," he added. "This is not a traditional flat bill offering. A subscription is straightforward to the customer, but complex to the provider. The question is who we want to shoulder that complexity."

Dynamic pricing optimizes the dynamic price of energy, but that is essentially fixed in a high renewables future in which the marginal cost of energy approaches zero, Helen Lo, co-author of a paper advocating for the subscription concept and member of the Sacramento Municipal Utility District (SMUD) distributed energy strategy team told Utility Dive. 

Customers could select from several plans that, if designed well, would be simpler than dynamic pricing, Lo said.

The concept faces three important "design challenges," the paper reported: Striking the right balance between the number and granularity of service plan options; balancing between too much customer choice and too much plan rigidity; and structuring proper enforcement mechanisms.

Customer choice, not an ideal rate structure, is the objective, Faruqui said. "People have different lifestyles and needs. By 2040, they will understand more and value options even more. Who knows what the world will be like in 20 years? My imagining of the future is to start the conversation."

Utilities hoping to efficiently balance the growing demand associated with electric vehicle adoption must view residential time-varying rates as "a bridge to direct load management," according to a new report from the Smart Electric Power Alliance (SEPA).

Spurred by declining vehicle prices and the availability of new models, the report says Navigant is now forecasting more than 20 million emissions-free vehicles on domestic roads by 2030, with an annual consumption of 93 TWh. As of July, the firm estimated less than 1.3 million zero emissions vechicles in the United States.

SEPA​ warns the increase in peak load can "strain the local distribution system, particularly when several EVs are clustered on single transformers." But the analysis, based on a survey of nearly 3,000 EV customers and 28 utilities offering EV-specific rates, also finds evidence that consumers can help ease the burden when presented with electric rates designed specifically for home charging.

EV rates are a "relatively new area, but our study has identified a number of important patterns emerging from recent experience," Ryan Hledik, a principal of The Brattle Group and co-author of the report, said in a statement.

Utilities with a marketing budget for EV-specific rates see a three-fold increase in enrollment, SEPA found. And those using more than three marketing channels have a 1.4x increase in customer enrollment. When EV rates are developed by utility-driven initiatives, rather than being required or recommended by customers, lawmakers or regulators, the report showed a 2.4x increase in enrollment.

"Utilities can directly influence many of the EV rate deployment elements that correlate to high enrollment levels," Hledik said.

The pool of potential customers for time-varying rates is significant: SEPA found 72% of non-enrolled customers were willing and able to charge their EV during off-peak hours. There is a caveat, however: the rate must result in bill savings and be convenient to use.

SEPA's survey found the rates generally successful: More than 90% of customers responded to the off-peak price signal, and a majority of utility respondents saw an average EV customer’s charging bill decline.

And customers stick with the rate offering. Utilities surveyed saw a high level of retention on their EV rate, said SEPA: Over 95% of participants enrolled at the beginning of the year remaining enrolled at the end of the year.

Utilities have a long-term interest in seeing customer adoption of new EV rates go smoothly. That could be a customer’s first exposure to load management, Erika Myers, principal of transportation electrification at SEPA and another of the report's authors said in statement.

In the future, utilities may be able to leverage vehicle batteries for advanced grid benefits. SEPA's report says the new rates are "an effective first step" in developing the necessary relationship with customers to eventually allow for those more advanced use cases.

"A utility should make every effort to ensure that the experience is positive to acclimate customers to the idea of using their vehicle battery for future vehicle-grid integration programs," said Myers. "Reducing barriers to participation, like up-front enrollment fees and short off-peak charging windows is absolutely crucial to maximize enrollment."

The potential goes beyond EVs to include other grid-connected devices that could respond to electricity pricing such as water heaters, air conditioners, swimming pool pumps, and laundry equipment.

"As customers become more comfortable with controlled loads through managed EV charging programs, it may also lead to greater acceptance of other utility load-control programs," SEPA concluded.

As battery prices fall, energy storage is becoming economical in a growing number of markets. While customer-owned systems remain nascent, new research from the Department of Energy's Berkeley Lab indicates they may pencil out for a growing number of residential and commercial customers — depending on how retail electricity rates are designed.

The study, "Implications of Rate Design for the Customer-Economics of Behind-the-Meter Storage," considers load data collected by Enernoc from 100 commercial customers in 2012. Using five-minute interval load data, researchers tallied and compared utility bill savings from behind-the-meter (BTM) storage across a range of rate structures and multiple customer types. They examined savings from avoided or reduced demand charges, which is commonly considered to be storage's main value. Researchers also quantified the savings potential from energy price arbitrage — using storage to avoid consuming higher-priced energy.

The results included some surprises, which the report's authors say can help inform regulators when developing new rates for customers with batteries, as well as project developers looking to find ideal service territories and customers for new deployments.

Arbitrage value

"The main surprise here is that the value from arbitrage, depending on the exact conditions ... can be just as high or higher in some cases, than the value from [reducing] demand charges," one of the studies' authors, Naïm Darghouth, told Utility Dive. "Demand charges are traditionally seen as the main driver for storage, but our research shows it is not just about the demand charge — it's really important to consider the arbitrage value from time varying rates as well."

For a hypothetical two-hour storage system sized at 20% of the customer's peak load, Berkeley Lab's analysis showed demand charge savings can range from $8/kW to $143/kW of storage capacity annually. For energy arbitrage, savings can range from $4/kW to $112/kW.

"With longer duration storage, energy arbitrage savings can be (sometimes substantially) larger than demand charge savings," the report found. "Arbitrage savings roughly scale with storage duration, whereas there are diminishing returns to demand charge reductions with increasing storage duration."

The report estimates 80% of all demand charge rates fall between $2/kW and $15/kW, with an overall median of $7/kW.

"The details of the rate design can greatly impact the value of storage," Darghouth said. "Perhaps that's not that surprising in itself, but quantifying and seeing the enormous valuation difference between utilities really drives that home."

The importance of rate design 

As utility regulators develop new rate structures, Darghouth said the team's analysis may take on greater weight.

"Bill savings from behind-the-meter storage are really closely linked to retail electric rate design," he said in a Sept. 5 webinar discussing the study results. "Because of its low penetration levels, rate design has more of an impact on the customer economics of storage than the other way around."

The shift from net metering to net billing, where electricity grid injections from customer-sited solar generation are compensated below the retail rate, will make energy storage more valuable, said Darghouth. As will the rise of time-of-use rates, critical peak pricing programs and any growth in residential demand charges.

"It's not just about the size of the demand charge: other rate design features are also key to understanding the customer-economics of BTM storage," the report concludes. And with longer duration storage, energy arbitrage savings can outstrip demand charge savings.

Berkeley Lab's analysis considered peak-period demand charge designs, demand charge averaging intervals, and time-of-use and critical peak pricing peak-to-off-peak energy price differentials, "all of which are significant to determining the customer bill savings from storage."

In the chart below, researchers showed the impact of demand charge design on bill savings from BTM storage on the shopping center with solar generation. While the demand charge rate is the "most-critical design feature" for demand charge savings, other mechanisms have a range of impacts.

The study showed peak period demand charges can increase the potential savings from demand charges. But there is a wide array of factors and rate mechanisms, from the frequency of measurement to ratchets that establish rolling demand charge minimums.

 "Averaging intervals also have a distinct impact ...with greater demand charge savings the shorter the averaging interval," the report found. "Season rates and ratchets have little effect on bill savings."

"Arbitrage savings roughly scale with storage duration, whereas there are diminishing returns to demand charge reductions with increasing storage duration," the report found.

For utilities designing new rates, all of this must be balanced.

"Utilities will need to consider bill savings to make sure they align with changes to their own costs," said Darghouth. "They want to know, 'Are we providing the right price signals?'"

'Peaky loads' stand to benefit most

The Berkeley Labs report analyzed the electricity use of a manufacturing facility, shopping center, and a shopping center with distributed solar.

"Storage is most effective at reducing demand charges for customers with narrow peaky loads," the research showed. Practically, that means those loads can benefit from storage systems with shorter durations. For flatter load profiles, like the consistent demand of the manufacturing plant, "storage cannot sustain the required discharge to reduce peak demand."

Energy arbitrage savings "scale more-or-less linearly with storage duration," the report found, "while demand charge savings face diminishing returns to scale."

That finding will likely have implications down the line, as longer-duration storage becomes more economic. Battery prices have dropped rapidly in recent years, opening up a wider range of use cases. 

Analysis in March by Bloomberg New Energy Finance (BNEF) found the cost of electricity from batteries has decreased by 76% since 2012, and the levelized cost of electricity for lithium-ion batteries has fallen 35% within the last year. And those price declines are showing up on the grid: The U.S. energy storage market in the first quarter of this year deployed 148.8 MW — a 232% increase from Q1 2018, according to Wood Mackenzie.

Behind-the-meter storage made up 46% of those first quarter deployments, representing a 138% jump from the same time last year.

As more storage comes online, it will become vital for utilities to understand rate design, said Darghouth.

"It's not just about the size of the demand charge, which has been the focus of previous research. There are other rate design features which are very important to understanding the economics of behind-the-meter storage for both residential and commercial customers," he said. "This is particularly important in this era of changing rate designs and PV compensation mechanisms."