New York distribution utilities have a lot on their plates.
They are expected to continue with their demonstration projects that test new business models, while also planning for the major investments that will allow them to operate as utilities of the future. They must do this while keeping the lights on, as they always do.
And they have to engage in countless working groups while also filing reams of reports to regulators to show how it’s all coming along.
The latest major filing that is part of New York’s Reforming the Energy Vision proceeding is the joint utilities supplemental distribution system implementation plan. The supplemental DSIP filing came after the utilities each submitted hundreds of pages as part of their individual DSIPs this summer. REV has a goal of making New York’s energy system more efficient and cleaner, while turning the distribution utilities into platform providers for a more distributed energy system.
The supplemental DSIP is more than 150 pages and clearly written, but like the individual plans, they are hardly revolutionary or inspired reading. There are just so many considerations to REV that it is hard to assess whether New York is actually in the midst of a transformation of the utility business model, or just on the cusp of a massive rate-based technology investment that still might not really turn utilities into a new type of business.
Even so, the collaborative process among utilities and with stakeholders is something of a revolution in the business. Also, with so many parts to REV, it is hard for one part of the process, like future utility planning, to move forward without another piece, such as new rate designs.
In the short term, the New York utilities are trying to untangle some current bottlenecks, such as interconnection queues, non-wires alternative criteria, a lack of hosting capacity analyses and a lack of rules around customer data sharing.
“Rome was not built in a day,” said Rory Christian, director of New York clean energy at the Environmental Defense Fund, which has been actively involved in various working groups. “This filing does a pretty good job of setting expectations.”
The supplemental DSIP addresses all of these issues and offers a very rough framework for how to move forward. That framework mostly consists of another series of working groups with stakeholders and the joint utility group that will stretch through next year -- if everyone doesn’t drop out due to working-group fatigue by then.
There are few things that distributed energy developers are more frustrated by than the lack of information available on the distribution grid. Stakeholders have asked utilities to prioritize near-term progress over more complex, long-term goals.
The first effort is red zone maps, which show where interconnection costs may be higher for larger systems, usually above 300 kilowatts. However, some of the maps take into account everything sitting in the interconnection queue, most of which won’t get built. (For more on New York’s messy interconnection queue and when it will be cleared up, read this.)
With all of that misleading information, circuits can look overloaded when they actually are not. Real progress is coming, however. The utilities are working toward a common analysis for hosting capacity and are expected to have completed those analyses on half of each of their circuits by the end of next year.
The issue of data sharing has been another hot-button issue both in New York and California. For customer data, the utilities will provide data to third parties via Green Button Connect, expect for Central Hudson, which is not deploying advanced metering; it will use Green Button downloads instead.
“The Joint Utilities' filing cedes leadership in customer data-sharing policy to other states and organizations, including the [U.S. Department of Energy] and [the California Public Utilities Commission],” said Ben Kellison, director of grid research at GTM Research. “The utilities propose instead to adopt a wait-and-see stance that incorporates a legacy Green Button Connect standard in data sharing."
The utilities have also proposed a standard of 15/15 for aggregated data, which means the data has to be drawn from a minimum of 15 accounts, and any single account can only be 15 percent of the data pool. That is in line with Southern California Edison’s standard, although some stakeholders have argued it is too conservative, especially for small commercial accounts. The joint utilities have said it is a starting point and can be revised as the market matures.
The New York regulators have demanded that utilities now consider non-wires alternatives. NWAs use demand-side resources to defer or negate the need for expensive grid equipment such as conductors, transformers and substations. Most of the New York utilities have at least one such project in the works, the largest of which is Con Edison’s Brooklyn Queens Demand Management project.
To make NWA projects more feasible, the utilities are working together on a basic criteria matrix that can evolve over time. In particular, the utilities have found that NWA projects are best suited to provide load relief. The full criteria matrix will be published within four months.
Future projects will be the best way for utilities to evolve and update the criteria, but the first iteration will likely be very conservative. For instance, as of this filing, the utilities said a large NWA project could take 60 months from solicitation to implementation, although most distributed energy resources (DERs) could get up and running much more quickly to provide load relief.
Another potential issue is that, for now, NWAs will be driven by utility requests for proposals, rather than customer-driven, market mechanisms, says Christian. “I see a future where the market really drives those solutions,” he added.
The REV process asks utilities to better incorporate DERs into their long-term load forecasting. The utilities all have different approaches today, some top-down, some bottom-up.
The utilities have a task force for this issue and will have meetings through 2018 with a group of stakeholders. In particular, they are evaluating the need for hourly data throughout the year. Currently, only Central Hudson is using hourly data at the substation level, although not all of those substations are providing data with that granularity.
While increased granularity is the primary focus, there is also a consideration for more probabilistic forecasts, according to the filing. To really get to location-based forecasts, the utilities have also called for more data from developers.
At the same time, stakeholders want more utility data to help them decide on project development. In some cases the data is available, the joint utilities argue, but not readily accessible. In this filing, they say they are working on collecting that data into more user-friendly, accessible formats for developers and third parties.
One data platform for all?
Finally, it would seem as though some of these data and grid platforms would be more cost-effective if shared among the utilities in the state, especially when building common templates for data structures. Not so, they say. “The incremental benefits arising from a common platform may not be commensurate with the efforts that need to be undertaken to develop, maintain, and enhance the platform,” the joint utilities argued.
“It is interesting to see all of the utilities come to conclusion that a single grid data-sharing platform would likely not create the value necessary to justify its cost in the long term,” said Kellison. This filing, however, is the first word -- not the final one. As with all moving parts of REV, EDF's Christian said the utilities’ aversion to a single platform could evolve as the program's complexity increases.