When it comes to defining the future of distributed energy resources, Rhode Island is out to prove Mark Twain right when he said “it’s not the size of the dog in the fight, but the size of the fight in the dog.”

Back in 2014, the smallest U.S. state enacted its Renewable Energy Growth (REG) program to stimulate utility adoption of distributed energy resources (DERs). The REG program mandated state regulators open a proceeding in the second half of 2015 to decide if the state needed rate structure reforms to respond to growth in DERs, such as rooftop solar.

The state was well along toward its initial goal for 40 MW of DER and was making plans for 160 MW more by 2019 when the Rhode Island Public Utilities Commission (PUC) convened the mandated proceeding (docket 4568) last July. But familiar disagreements over customer fees and the value of distributed resources quickly froze progress, with stakeholders balking at an initial utility rate proposal.

Now, the state is beginning work on a new docket regulators hope will take the heat out of DER discussions and allow the two sides to forge a path forward. Through a step-by-step regulatory process that leverages the state’s history of power sector collaboration, stakeholders hope to settle on common expectations and measurements to evaluate future distributed energy proposals.

Rhode Island’s REG

Passed in June 2014, Rhode Island’s REG program required utility National Grid to file a revenue neutral rate redesign proposal outlining how customers can pay their fair share for use of the grid, whether or not they install DERs.

“Our proposal,” National Grid Director of Environment Tim Roughan said, “was how to pay for the system and fairly allocate costs.”

The investor-owned utility, by far the state's largest electricity provider, proposed a tiered customer charge for residential and small business customers, along with other changes.

The proposal was unanimously rejected by the 13 intervenors in the proceeding.

The tiered charge proposal was “inappropriate" because it was not "a long term solution to addressing the changing nature of the electricity system,” Janet Gail Besser, vice president of government affairs at the Northeast Clean Energy Council told the PUC.

The 2014 law placed significant limitations on any utility proposal, intervenors said, because it stipulated that any rate changes must be revenue-neutral, making the proceeding distinct from a rate increase proposal.

In response to stakeholder objections and a rising call for more thinking about future rate designs that could better support DER, National Grid withdrew its proposal.

In its letter to the commission, National Grid wrote that it supports further discussion on “rate design and distribution cost allocation” and about a “changing distribution system that is expected to include more distributed energy resources.”

At that point, the PUC Chairperson Margaret Curren asked for a new docket and the regulatory staff sent out a memo defining the goals of a new proceeding, docket 4600, intended “to investigate the changing distribution system.”

Docket 4600’s aim: A common metric

One of the sources of dispute in the previous docket (4568) was inadequately-substantiated claims that DERs provide benefits to the grid, PUC staff wrote in the memo. Those arguing the point failed to show how such benefits could be measured or whether they supported the goals of legislated state policies, they wrote.

To set the best rates for the REG Program, intervenors in docket 4600 should seek an improved understanding of the costs and benefits of all the state’s programs by asking one two-part question, the memo instructs — “What attributes are possible to measure on the electric system and why should they be measured?”

The commissioners’s written decision in docket 4568 showed it interprets the REG statute to require several specific factors to be considered in answering the question, the staff memo explains.

Of those factors, docket 4600 intervenors should be especially focused on “the benefits of distributed-energy resources” and “the distribution services being provided to net-metered customers when the distributed generation is not producing electricity,” the memo instructs.

Those participating in the docket, the memo adds, should use “equitable ratemaking principles regarding the allocation of the costs of the distribution system” and “cost causation principles” to evaluate those costs and benefits “that can and should be included in distribution rates.”

Intervenors should consider all “reasonable rate design options” and “fair rate structures” and be guided by the principle of least-cost procurement, the memo directs. To be considered, a rate should be simple, understandable and transparent for non-net metered and net metered customers.

One of the key potential outcomes of the proceeding could be a way to rectify the inefficient way the commission currently reviews the state’s many utility renewable energy and efficiency programs, the memo notes.

The present “piecemeal setting of rates” may be a cause of higher program costs and higher costs to developers and consumers, especially if a state policy goal is being funded in multiple programs or if a goal of one program is at odds with the goal of another.

These “unintended investment signals” to the utility could be rectified if the 4600 proceeding can identify a single set of metrics that would apply to ratemaking for all future programs.

The metrics could then determine if rate proposals and incentives related to any program are reasonable. They could also be used to determine the most cost-effective program for the utility to use in implementing a given policy goal.

“Such a single set of measurements may be beyond what is possible from one single docket,” the memo notes, “but staff recommends the PUC recognize this ideal, and let it inform the new docket.”

A “normalization of least-cost procurement” could lead to reaching state policy goals in a more “cost effective, reliable, prudent, and environmentally responsible” way, the memo notes. “While it may not be a readily achievable outcome in the new docket, it is an appropriate guiding principle.”

Whether or not a common metric for utility DER program possible at once, the memo outlines three guiding questions for the new docket.

• What are the costs and benefits that can be applied across any and/or all programs, identifying each and whether each is aligned with state policy?

• At what level should these costs and benefits be quantified — where physically on the system and where in cost-allocation and rates?

• How can we best measure these costs and benefits at these levels — what level of visibility is required on the system and how is that visibility accomplished?

The proceeding is an effort to get stakeholders “to identify the new factors for future rate cases,” PUC Staffer Todd Bianco told Utility Dive. “We need a basic set of ground rules.”

In this “lower intensity” docket, the stakeholders will be able to identify and report to the commission the issues without the pressure of a rate case or a specific contested proposal.

Docket 4600 is to deal only with the evaluation of currently available regulatory mechanisms, Bianco said. Whereas other states, like New York, have sought to tackle a variety of utility ratemaking and business model reforms at once, the Rhode Island commission wants actual ratemaking left to rate cases and broader questions on alternative utility business models left to the state’s Systems Integration Rhode Island (SIRI) process.

The debate in docket 4586 suggested that National Grid and clean energy advocates may agree on the need for time-varying rates (TVR) and the expansion of advanced metering infrastructure (AMI) to support them, Bianco said. But they may be less ready to agree on the specific costs and benefits of DER.

One thing intervenors may try to achieve is a framework that would allow the commission to make an “apples-to-apples comparison’ of the costs and benefits of new infrastructure on the distribution system and the costs and benefits of a non-wires alternative (NWA)," Bianco said. “That is as far as the docket will probably go."

Clean energy stakeholder goals

The SIRI process, directed by the Rhode Island Office of Energy Resources (OER), “was the first effort to frame out all the issues related to the future of the Rhode Island electric grid,” Bianco said. “The commissioners said they had been thinking about many of the same issues.”

Assessing the DER market potential, costs, and benefits of AMI and TVR are the most likely of the six recommendations from the SIRI final report, released late last year, to be dealt with in Docket 4600, OER Program Development Chief Danny Musher said.

Stakeholders may also at least touch on another of the SIRI report’s recommendations​, performance-based ratemaking (PBR), because Rhode Island already has some performance incentives for National Grid, Musher said. PBR could better align utility incentives with state policy goals and priorities.

Much of the discussion of various rate designs is likely to get into ways to support the growth of cost-effective, comprehensive non-wire alternatives on Rhode Island’s distribution system, Musher said. A key recommendation in the SIRI report, NWAs incorporate DER as a grid service to cost-effectively defer, avoid, or reduce utility expenditures on distribution infrastructure.

The relevance to the 4600 discussions is that NWAs can only be fully cost-effective if rate structures are in place that fully value DER, according to the SIRI report.

Strategic electrification of transport and large loads and active demand management may also enter the 4600 discussions, Musher said, because they would similarly benefit from better understanding of DER valuations.

Of the few intervenors who have so far filed, comments from the Pace Energy and Climate Center may be most telling of things to come.

“Getting the value of DER right is essential for setting compensation rates and charges,” Pace Executive Director Karl Rabago wrote. Doing so “guides market participants to economically efficient investment decisions” while at the same time being fair to customers who do and do not own DER.

An accurate value of DER would be a complete analysis of costs and benefits across all programs that the commission regulates, Rabago, a former Texas utility commissioner, wrote. It also “reproduces” the avoided cost analysis utilities understand so well because it establishes an “indifferent price” at the customer meter that makes utilities agnostic to procurement choices.

The indifferent price that comes from good DER valuation is the foundation the PUC is seeking for better management of incentives without compromising a reliable, safe, and affordable distribution system, Rabago wrote. And it can be periodically reassessed to prevent incentives from creating market distortions and regulatory havoc the way volumetric caps on deployment have.

An accurately-designed value of DER should be technology agnostic, include long-term as well as short-term costs and benefits, and take advantage of the many methodologies available to quantify uncertainty, rather than omitting them, Rabago adds.

Finally, he notes, DER valuations that fail to come to terms with the complicated questions of sunk costs, fixed costs, and the societal and externalized benefits of DER are not sufficiently comprehensive to meet the terms described in the staff memo.

National Grid’s aims

There are a lot of options for Rhode Island’s future grid “but they come with different price tags,” National Grid’s Roughan said. The utility’s foremost objective is “to identify and do what the state wants done as long as it is fair to the full range of our customers.”

Deploying AMI and moving to TVR is one of the options and it might have been one of the utility’s initial choices if it had not been statutorily-limited to a revenue neutral proposal, he said. “Part of this process may well be looking at the costs and benefits of adding AMI and moving to time varying rates.”

National Grid is already working on AMI in Massachusetts and New York, Roughan pointed out. “We can add significant cost efficiencies if Rhode Island also chooses to do AMI technology.”

Studies on AMI have not yet demonstrated “a slam dunk of benefits over costs,” Roughan said. Choosing to deploy AMI is still “a leap of faith that you can get to the more interesting ways to use it and the real savings smart meters are capable of providing.”

It is just one possible consideration for the 4600 docket, he said. Stakeholders can also take up the state’s many efficiency programs and customer-funded clean energy programs. “We are looking for the most cost-effective programs and how to leverage them to optimize investment in electric utility infrastructure.”

The docket will be the “ground floor” of understanding when alternatives to utility infrastructure expenditures can and cannot use DER to “deliver value at a lower cost,” Roughan said.

It is premature to suggest alternative rate designs for discussion in the docket and the utility is more interested in knowing what rate designs the other stakeholders want to evaluate, he said. Rhode Island already has decoupling and some incentives for service, he added.

“With most incentives, all you are doing is preventing penalties and that asymmetry does not promote innovation so we are very interested in performance-based incentives, especially if our partners are interested,” Roughan said.

Pressed on what National Grid would like to see included into the discussion, Roughan paused before raising a rarely mentioned point.

“Getting customers to change their behavior is very complicated and involved and some stakeholders don’t recognize the difficulty of selling programs to customers and keeping them engaged over time,” he said.

A system peak load may happen every summer or may not happen for three summers in a row, he went on. “In programs that enroll customers to address system peaks, we may not need to call an event for days or years and then, all of a sudden, we need them to respond. How do you keep those customers engaged?”

If a demand response program is put in place to defer a long-term system upgrade, "a one or two year pilot doesn’t give you any confidence the customer will be there for ten or fifteen years," he added. “We all need to work together to address this enormous challenge of being sure customers will participate.”

The challenge is “sometimes downplayed by other stakeholders who have not tried to get people to participate during a heat wave over all four hours of a call, all three days in a week, four weeks in the summer, and five, six, or seven summers in a row,” Roughan said. “That is the difficult piece we are working on.”

National Grid pilot programs are beginning to offer some insights into how to get customers to opt in “without hitting them over the head with a stick in the form of a huge bill, which is a non-starter,” he said.

“People say they will change their behavior because of price signals but what if they don’t? What if their $200 electric bill is nothing compared to their $400 cell phone bill or their $200 cable TV bill and just another cost of living?” Roughan asked.

These questions need to be part of the docket 4600 discussions, he added. Part of the solution is automation, but “there are still a lot of things that have to happen so the technologies can be automated enough to get more customer involvement.”

The commission is aware of the utility’s concern, Bianco said, and the stakeholders also know the utility has much more information about the system and has much more of the engineering expertise necessary to operate it.

“But the stakeholders want to be aware of as much as they can, and this lower-stakes docket is the way to make that happen,” Bianco said. “It will allow National Grid to be more forthcoming about its challenges and will allow the stakeholders to better understand them.”

Confidence in collaboration

Despite the rancor of docket 4586, a number of clean energy intervenors expressed confidence in 4600.

Rhode Island’s Energy Efficiency and Resource Management Council (EERMC), formed to implement its 2006 least-cost procurement and energy efficiency mandates, has led to a “very rarely antagonistic and often collaborative” relationship between the stakeholder groups and National Grid, said Abigail Anthony, executive director of the Acadia Center.

The energy efficiency law requires them to reach a settlement outside the regulatory process and go to the commission only when there is agreement, Anthony said. “I would speculate the utility finds working with us rather annoying and would rather do their jobs without stakeholder involvement, and I understand that. But we end up with more stable decisionmaking and a better product.”

The 4600 docket is “an investigation,” said Scudder Parker, director of policy at the Vermont Energy Investment Corporation (VIEC). “It is the PUC saying the questions are too big for a litigated proceeding.”

As the docket representative for Rhode Island’s EERMC, Parker and other stakeholders have been through decades of debate and discussion with national grid over efficiency programs and rebates.

This is the PUC “moving out of regulatory reactive mode and making a creative response to the stall out of 4568,” Parker said. The 4600 docket does not have a very specific “defined objective,” but it could produce “guidelines for future commission decisions” on a range of regulatory responsibilities including efficiency, DERs and demand response.

Parker sees a deeper consideration of demand response as potentially especially valuable. “It is where energy efficiency was years ago,” he told Utility Dive.

If stakeholders take up the question of DER valuation, Parker would urge them to remember that Rhode Island’s energy system is not complete. “It is a system that is changing, so the present value of DER and the potential future value of DER should both be on the table.”

The docket is also an opportunity to ensure an intelligent rollout and adoption of AMI, Parker said. “I want a rate design focused on time varying rates and a system that rewards the utility for incorporating DER intelligently and dynamically."