How New York is incentivizing utilities to interconnect DERs under REV

Regulators want to reward utilities for better performance on key tasks like DER interconnection — the question is how

An order released last month from New York regulators aims at perfecting a mechanism to reward the state’s utilities for the accelerated interconnection of distributed energy resources.

If regulators and stakeholders can come to a consensus, it could mark a big step forward in evolving how utilities make money in the Empire State.

The directive from the New York Public Service Commission (PSC) came as a part of the state’s Reforming the Energy Vision initiative, which aims to remake the utility business model.

Streamlined interconnection of DERs is one area regulators identified early in the process as an opportunity for utilities to make extra revenue based on their performance. The March order aims to make that new ratemaking a reality, weighing input from utilities and DER providers on how to measure utility performance.

In their order, the regulators rejected elements of proposals from utilities and solar advocates. Instead, they directed the parties to resubmit better ideas about Earning Adjustment Mechanism (EAM) metrics to reward utilities for getting distributed resources online faster (Case 16-M-0429).

Interconnection performance is the first EAM topic to be tackled by New York stakeholders, but regulators said in earlier orders that other performance incentives will involve data sharing, customer engagement, efficiency offerings and more.  

“EAMs are a recognition that utilities’ incentives do not align with customers’ needs or with the state’s policy objective of moving to a renewables- and distributed energy-based future,” Sky Stanfield, attorney at the Interstate Renewable Energy Council told Utility Dive.

“With them, a utility will be able to add earnings from distributed resources to its traditional earnings from building infrastructure,” Stanfield said. “This new business model will allow it to take on a new role as a distribution system operator."  

In response to a 2016 commission order, the state’s utilities proposed metrics and a survey of developer satisfaction to measure performance on the interconnection of DER projects.

But regulators, in their new ruling, said the plan for the survey and metric “does not go far enough,” and ordered the utility to revise it.  

Despite important parts of the proposal having been rejected by the PSC, the state’s utilities still see merit in the concept.

“Making the solar installation process as easy as possible for customers is consistent with the Reforming the Energy Vision initiative,” said Allan Drury, spokesperson for Consolidated Edison, the utility that serves New York City.

Solar developers agree, said Valessa Souter-Kline, policy coordinator for the New York Solar Energy Industries Association (NYSEIA). Performance rewards that offer utilities a benefit for serving their customers “make sense to the developer world.”

While utilities and solar advocates agree on the idea of performance rewards, the PSC must resolve the parties’ differences on the metrics. Without sound EAM metrics, rewards won’t drive utility behavior, resulting in less work for developers and lower revenues for utilities. 

The big picture on performance

The commission’s order recognized that EAMs “offer the utilities diverse, balanced financial incentives” that allow them to help meet “the demands of the modern electric grid and the desired REV outcomes.”

The objective, the commission’s order said, is EAMs for DG Interconnection for meeting two standards.

One is “the timeliness requirements established in the Standard Interconnection Requirement (SIR).” The other is “a positive adjustment” of utility earnings “based on an evaluation of application quality and the satisfaction of applicants with the process.”

The applicants are DER developers. Their satisfaction with the interconnection process is to be measured by a survey of their experience and by “a periodic and selective third party audit of failed applications to assess accuracy, fairness, and key drivers of failure in order to support continual process improvement," according to the commission's order.

In New York, the state’s utilities – Central Hudson Gas and Electric, Consolidated Edison, New York State Electric & Gas, National Grid New York, Orange and Rockland Utilities, and Rochester Gas and Electric – typically file unified statement as the Joint Utilities (JU).

The JU filing argued that timeliness metrics and incentive levels be set “on a utility-specific basis as part of rate or other utility-specific filings.” It proposed a survey of developers who completed their interconnections. “Failed applications” identified by the independent audit should be reclassified as “withdrawn or abandoned” and should not be included in the EAM calculation.

NYSEIA’s Souter-Kline said she knows of no stakeholder who objects to rewarding utilities for streamlining their handling of interconnection applications. For the fees developers pay utilities to manage the applications, she said, they deserve "a good customer experience."

Unlike the utilities, solar advocates argue there should also be penalties for falling short on performance.

“From the developer perspective, it is not ideal to have only rewards for meeting performance standards,” Souter-Kline said. Both she and IREC’s Stanfield endorsed the “Massachusetts Timeline Enforcement Mechanism” that includes both rewards and penalties.

The commission’s ruling accepted that position. One of the objectives of the EAM proceeding, it wrote, is that “negative earning adjustments will be considered by the Commission for a utility not meeting established standards.”

The ruling called for a JU response by mid-May. ConEd’s Drury declined to comment on the subject except to say the EAM “is being finalized.”

Time is money

The JU proposed an EAM for meeting a minimum target of performance on three SIR timeliness over which they have direct control of the outcome.

“If performance is equal to or below this minimum target, no incentive would be paid,” the JU filing explains.

The first of those three timeliness requirements is the obligation to determine the completeness of a developer’s application within ten business days. The second is to complete a preliminary screening within 15 business days, and the third is to deliver the complete interconnection assessment — dubbed the Coordinated Electric System Interconnection Review (CESIR) — within 60 to 80 business days.

ConEd’s Drury agreed that timeliness is an "appropriate metric" for the EAM. The utility is already seeing fewer complaints because it is working “to make the interconnection process as quick as possible.”

New timelines introduced through a recent “queue management agreement” between the JU and solar advocates “will help further in this area,” he added.

But there are parts of the interconnection process over which only the developer has control, Drury said. Construction is often the longest part of the process and can vary because of a range of factors which are entirely developer concerns.

“We do not believe a project should be considered late for EAM purposes if the developer needs extra time to construct.”

John Maserjian, media relations manager for Central Hudson, agreed. His utility is in compliance with SIR timelines and has engaged an ombudsman to resolve disputes. Even so, he said, “there are many variables in any project, including delays on the part of the developer.”

National Grid declined to comment on the new ruling.

The PUC’s order made no changes to the SIR timelines, but explicitly required the JU response to also include “satisfaction surveys of DER providers” as part of the “positive earning opportunity.”

At the same time, commissioners ruled that they would not consider the Massachusetts TEM model — which includes both incentives and penalties — because a recently-implemented queue management process remains uncertain.

IREC’s Stanfield said this is a reasonable reasonable decision. “The utilities are not necessarily slow-walking interconnection applications."

New policies and other factors led to a dramatic increase in New York’s solar penetration in the 2015 to 2016 period, she said. Like utilities in other states where there was a solar boom, the New York utilities fell behind on their interconnection obligations.

But there can be a lot of moving parts in a utility review of an interconnection application, Stanfield added. Some big ones are whether system upgrades are needed, what the costs for those will be, and whether the utility or the developer will be responsible for those costs.

It is not a complete solution to evaluate utility performance based on selected timelines “because the project could get stuck at any point in the process,” she said. Tracking only selected timelines “does not show whether the utility is completing its review on time.”

Two alternatives are to track other important timelines or to track the overall timeliness of the process, Stanfield suggested. “From the developer’s point of view, though there are parts of the process on which financing or other important things depend, it is the overall time that must be as fast as possible.”

Stanfield’s concern is that utilities will shift resources to meet the timelines required by the order, but fall short in other areas.

NYSEIA’s Souter-Kline voiced similar concerns.

“There is no real benefit or reason to selective tracking of timelines and developers are certainly concerned about utilities meeting their obligations,” she said. “The ruling is a good and important step, but we would like to see all the timelines tracked. Why have a timeline if you’re not going to track it?”

Another missing piece in the ruling is the absence of any requirement for accountability, transparency, and standardization in the review process, Souter-Kline said.

There is much variability across utilities in the information included in interconnection reports, she added. “The utilities collect the information. It’s just a matter of standardizing what they share with developers, especially because it is the developers who are paying for the reports.”

Surveys – what to leave in, what to leave out

The JU filing proposed using a survey developed by ICF Resources “to measure the DG applicant’s satisfaction with the DG interconnection process.”

The ICF survey addresses “all important stages of the DG interconnection process,” according to the JU filing.

The utilities want a monthly survey of project managers with DG who submitted interconnection applications that resulted in projects coming online.

“Only those applicants can be expected to have knowledge of the entire process,” according to the JU filing.

The survey would have questions in five categories and be field-tested according to recognized social science standards. The project managers would be carefully selected to be representative. A utility’s performance “will need to be based on a survey of at least 100 project managers,” the JU added.

Controversially, the JU would reclassify failed applications as “withdrawn,” if they leave the queue after contacting the utility, or as “abandoned,” if dropped from the queue for missing an SIR required milestone. The reclassification “is more aligned with current practice,” according to the JU.

For withdrawn and abandoned applications, the JU would exercise a "closeout" process through which they would identify the business reasons behind the termination. The JU filing also proposed a stakeholder process to further develop that closeout process so that it would reveal ways interconnections can be improved.

But while the JU claims the ICF survey is comprehensive, regulators ordered several changes to the developer satisfaction surveys.

The JU revision must include a proposal for weighting the importance of each survey question and for weighting “mid-point surveys versus completed application surveys.” They must also propose both a web-based plan and a phone survey plan and a determination of when to use each.

The commission did not require a survey of interconnection applicants who drop out of the process. But the JU are directed to further inform the commission about how and when they close out incomplete applications, about what they know about the causes of withdrawn and abandoned applications, and about how the JU can better collect, and assess data on failed applications.

Finally, the JU revision must describe “a collaborative process within the context of their individual utility proceedings to obtain stakeholder input on the DG interconnection survey metric.”

ConEd’s Drury declined to comment on the PSC's restructuring of the JU's survey proposal.

Central Hudson’s Maserjian pointed out that the commission affirmed the JU position by not requiring a survey of applicants who drop out. He said the mid-point survey will “address projects that may fall out of the queue after that point.”

IREC’s Stanfield argued that the REV Track two order requires “a third party audit of failed applications to assess accuracy, fairness, and key drivers of failure in order to support continual process improvement.”

Compliance with timelines is objective and measurable “but there are subjective elements in the interconnection process, too,” she argued. Her biggest concern is that applicants who drop out be surveyed.

“They drop out for many reasons that may have nothing to do with the utilities but they also may drop out from frustration with the utility process,” Stanfield said.

The order does not require the JU revision to include a survey of dropouts, Stanfield acknowledged. But the PSC indicated it may revisit the question. “If projects keep dropping out or getting stalled, the commission may reconsider surveying those applicants to make sure they understand what is working and what is not.”

NYSEIA’s Souter-Kline agreed. "This order is the first step in getting needed data,” she said. "But we need to understand what’s happening with projects that have interconnection applications but do not interconnect if we are going to improve the process."

The PSC order makes it clear that the EAM must be tied to developer satisfaction as well as to timeline compliance, she said. Developers want to understand why a project proceeds, is delayed, or fails. “Not including failed applications is going to skew the results.”

Surveying developers whose projects are interconnected will offer some understanding of “the bumps along the way,” Souter-Kline said. “But a developer with a failed application may have a really different experience and we would be selling ourselves short not to collect that information.”

Coming attractions

The PSC left several questions open to being revisited.

It rejected solar advocates’ proposal to track timeline compliance for projects of 50 kW or smaller because it has not seen evidence they face the same issues as larger projects. “But we will continue to monitor this project group and will re-visit this determination if problems arise,” the order reported.

It also “encouraged” the JU to track and survey smaller projects “for informational purposes.”

IREC’s Stanfield noted that as the first of the REV’s EAMs to move through the rulemaking process to the verge of implementation, this EAM will allow the commission to develop important insights. “Interconnection is a good case for EAMs because there are specified steps and timelines in the process.”

The commission is correct that the utilities are doing well with smaller project interconnections, she acknowledged. “We want them to continue to do a good job as penetrations rise. Measuring performance and putting incentives in place is a way to do that. It is not satisfactory to assume their performance will be as good if there is a small system boom."

Stanfield applauded the PSC for encouraging the JU to voluntarily track and survey the smaller systems. “Tracking alone is likely to have a good effect on performance because it has an effect on transparency.”

NYSEIA’s Souter-Kline highlighted what probably the most important question the commission left open.

“The utilities now have 60 days to come back with an improved proposal and it will be interesting to see what that is,” she observed. “I think we may see something a little bit better in 60 days because the PSC specifically told them they didn’t go far enough on a number of these things.

Filed Under: Transmission & Distribution Solar & Renewables Energy Storage Distributed Energy Regulation & Policy
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