New York Regulators Issue Three Milestone REV Orders, but More Work Remains

Three interlocking blocks of the Jenga-like tower that is New York’s utility regulatory reform moved forward last week with the issuance of three commission orders. 

The orders, part of the Reforming the Energy Vision docket, included the Value of Distributed Energy Resources, the Distributed System Implementation Plans, and the Interconnection Earnings Adjustment Mechanisms.

While all are notable milestones in the lengthy, multi-pronged proceeding, the latter two orders, which address grid planning and operations, fall short of the detailed blueprints needed to build the grid of the future.

As an active intervenor in the Distributed System Implementation Plan (DSIP) and Earnings Adjustment Mechanism (EAM) proceedings, the Interstate Renewable Energy Council offers a deeper dive and insight into why they matter.

Distributed System Implementation Plans

As set forth in Track 1 of the REV proceeding, the commission’s overarching goal is to “transition from the historic model of a unidirectional electric system serving inelastic demand, to a dynamic model of a grid that encompasses both sides of the utility meter and relies increasingly on distributed resources and dynamic load management.”

The central vehicle to effectuate changes to improve the planning and operations of the grid was through the utilities’ DSIPs. The DSIPs are the utilities’ blueprints to determine how to plan for, manage and operate the grid with increasing penetrations of customer-sited distributed energy resources (DERs). 

The commission’s order on the DSIPs only touches on a few of the topics addressed in the proceeding and lacks more explicit guidance on the issues it did address. Across the board, additional detail is needed to better define what the DSIPs will do and how they will set forth changes to achieve the REV vision. We’ve observed the following.

Hosting capacity analyses: Hosting capacity analyses are the comprehensive modeling and mapping exercises used to assess how many DERs can be accommodated on the grid, down to the circuit level. Ideally, HCAs enable enhanced planning and operational capabilities of the grid, while also streamlining the interconnection of DERs on the grid to avoid costly, inefficient processes and projects. However, the latter outcomes are contingent upon the HCA methodology selected and its ability to provide accurate and actionable information. In order to assess the adequacy of the methodology, it needs to be clear how the HCA is intended to be used (i.e., defined use cases).

The Interstate Renewable Energy Council (IREC) urged the commission to clearly identify both planning and interconnection use cases for the HCA and to ensure that the utilities’ selected methodology would adequately serve those priority use cases before proceeding further. Our work in California on similar efforts has revealed the importance of the HCA methodology and use cases to make them meaningful. Ideally, HCA mapping and modeling exercises should be used to help automate the interconnection of DERs on the grid (which has been a growing problem in New York). 

The commission unfortunately failed to identify how it expects the HCA to be used, while also aptly acknowledging that the HCA methodology selected “is not perfect.” However, it is concerning that the commission order asserts, without basis, that the limitations “can be managed” such that “relatively” accurate hosting capacity information can be provided. It is not clear what underlies the commission’s assessment here or how it plans to “manage” the inaccuracies.

The commission goes on to say that as more accurate methods are established, the utilities should incorporate them into their practices. However, shifting methodologies midstream is not only impractical from a time standpoint, but would likely be costly for ratepayers. Despite the recognized limitations, the commission orders the utilities to complete an HCA on all of their 12 kV circuits by October 2017, about a year faster than the utilities had proposed.

While a more accelerated timeline is possible, it would be preferable to have assurance that the results will be accurate and useful before authorizing what could be a time- and resource-intensive process for the utilities.  

In addition, the commission permits the utilities to update the HCA annually, but indicated that their maps should be updated monthly. It remains unclear how meaningful map updates can be done more frequently than the analyses are conducted, but perhaps the insights on this will emerge as the utilities get the process underway.  

While IREC is concerned about elements of the HCA, we are glad to see that the commission agreed that the utilities’ current “red-zone” maps (which are a precursor to actual hosting capacity maps) should be improved to provide more “basic” information about the feeder in a useable format, providing suggestions of what else the maps should include and asking the utilities to work with stakeholders on this.

All in all, we found that the order fell short on this important tool in the grid modernization toolbox, and we hope the commission will continue to work toward more clearly defined objectives and details for the HCA effort going forward. 

Electronic interconnection applications: In its original DSIP guidance, the commission required the utilities to complete online interconnection portals to allow for electronic applications. Since the utilities mostly failed to meet this requirement, the commission reiterated that the utilities must complete work on the first phase of the portal by October 2017. Electronic interconnection applications are key to enabling more streamlined and efficient interconnection processes, and it’s good to see this requirement being reiterated.

Non-wires alternatives: In its consideration of how the utilities are to pursue and acquire "non-wires” alternatives (i.e., distributed solar, demand response, energy storage), the commission determined that the utilities’ “suitability criteria” framework for identifying NWAs was inadequate and that it unreasonably limited NWA options. The commission also noted that it is unclear how the NWA criteria would be incorporated into utility planning, or how and when it would be applied to projects in their current capital plans.

The commission directed the utilities to file additional information in 60 days’ time and to make publicly available the selected NWA projects in their capital plans. This important guidance will ensure the pursuit of more efficient and cost-effective NWAs.

Energy storage: The commission acknowledges that the utilities have done little to invest in energy storage or show how they plan to in the future; however, the commission still declines to deal with energy storage more comprehensively and instead just requires each utility to deploy a mere two energy storage projects on substations or feeders.

While energy storage is one of many issues on the commission’s very full plate, the time to consider the potential and opportunities for the technology to help meet the REV goals is arguably now. It would be helpful for the commission to take the reigns and provide clearer regulatory guidance to forge a pathway for energy storage markets in New York, and beyond. 

In summary, though many issues were brought before the commission through multiple rounds of comments and workgroup meetings, ultimately the DSIP order only required a few meaningful changes to the way utilities currently operate. The commission took a few steps in the right direction, but gaps remain that will impact the integration of DERs on the grid as part of the utilities’ long-term plans and interconnection procedures.

Additional guidance remains paramount for creating a long-term glidepath for optimizing DERs on the grid. 

Interconnection Earnings Adjustment Mechanisms

The second commission order on the Interconnection Earnings Adjustment Mechanisms deals with adopting performance-based incentives for utilities to improve their interconnection processes (as part of the broader reforms to the utility business model). The incentive is based on how well, or how poorly, the utilities execute their interconnection processes. However, the metrics used to determine performance should be impartial, lest they skew the evaluation of the utilities’ performance. The commission set forth modest guidance on the EAM, with a few primary areas of interest.

Interconnection customer satisfaction surveys: The utilities will conduct a customer satisfaction survey to assess the current and future state of the interconnection process. While this is a seemingly innocuous issue, the design details of this performance metric will impact how utilities fare in the assessment. As with any survey, a representative sample and an objective approach are important; however, the order is a mixed bag on these principles.

The commission declined to adopt IREC’s suggestion that the utility interconnection survey track projects below 50 kilowatts, or to include them in the financial penalties at this time. As an important and growing segment of the market, leaving these smaller systems out of the review process provides an incomplete picture of the interconnection experience for all customers. There is value in the utilities gaining a more thorough assessment of the diversity of projects connecting to the grid, and it would be wise for the commission to include these projects in the EAMs in future iterations.

The commission also declined to require the utilities to survey failed and withdrawn interconnection applicants, noting that the imminent implementation of a queue management process will result in several withdrawn applications. However, it hinted that this may be revisited after the first queue clearing is done. 

The commission order does acknowledge the limitations of surveying only “completed” applications, and thus requires the utilities to survey applicants twice, once during the process and once at the end, ensuring they get some feedback from projects that may drop out before they finish the process. The midpoint applicants will also increase the likelihood that utilities will have a sufficiently large sample size to be meaningful. This compromise approach represents an improvement over the original proposal. 

Lastly, the commission requires the utilities to further refine the questions in their customer satisfaction surveys, several of which will be used to determine the utilities’ earnings adjustment, and then to submit them for review by the staff prior to implementation. They require the utilities to do web-based and phone surveys to allow more anonymous feedback and options for customers to provide that feedback.   

Interconnection timeline tracking: The order directs the utilities to track three core timelines relating to the interconnection process. Unfortunately, despite our suggestion, the commission did not add more interconnection timelines for the utilities to track and declined to follow the Massachusetts timeline tracking model (which provides an easy template for New York to adopt).

As a result, tracking only three steps in a multi-step process means others could be allowed to slip. In addition, it remains unclear if the other timelines will be tracked in a manner that will enable the public to monitor utilities’ performance in this area. Transparency and the availability of robust tracking data will help ensure this performance metric is consistently reflective of performance.

Consistency among utilities: The commission order allows each utility to have a different interconnection performance metric target, rather than making the metrics consistent among them. While initial work to get all utilities on the same page may take some time, holding all of the utilities to the same performance criteria would help set a high bar for all New York utilities, compelling each to improve their interconnection processes and creating greater consistency statewide. Unfortunately, the commission failed to heed this ripe opportunity for more sweeping statewide reform. 

Going from the grand vision of REV to implementation is a process replete with innumerable decisions and nitty-gritty details that must each be considered carefully and thoughtfully. Critical grid planning and operations details must remain in focus if REV is to ultimately be successful. Indeed, the strength of its foundation and details of its architecture will determine how well market reforms withstand the test of time. 

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Sara Baldwin Auck is regulatory director of the Interstate Renewable Energy Council.

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