by Katherine Tweed
July 14, 2016

For many people, summer reading is paperback page-turners or fluff-filled magazines. For a handful of New York regulatory staffers and energy geeks, it is more than 1,500 pages of utility filings from New York’s regulated distribution utilities.

If your summer has been more about beach time than utility briefings and you’re feeling a bit behind, fear not. The regulatory tomes are informative, but not radical. They can be digested slowly. For those who have followed the investments California utilities have made in the past six years, you may notice a similar pattern to those investments taking off in New York.

The distributed system implementation plans, or DSIP filings as they’re known in wonky utility parlance, are both a current assessment of the utility’s system and a five-year roadmap.

Although New York’s Reforming the Energy Vision proceeding has a bold goal of transitioning the utilities into distribution system platform (DSP) providers to manage a distributed energy resource marketplace in the future, the first DSIP filings stopped short of imagining that future.   

The DSIP filings will be updated every two years. The initial ones do not even identify what sort of technology layers the utilities need to truly transact real-time energy markets at the distribution level. The cost of the foundational technology investments needed -- such as AMI, DERMS, ADMS, GIS and more -- are just the beginning when it comes to managing the coming surge of distributed resources.

Most of the utilities have similar plans, although the timeline and layering of such technology investments vary slightly. The utilities are, for the most part, grappling with the same issues: huge increases in applications for solar PV coupled with overall flat demand in coming years.

A recent report from the New York Independent System Operator found that although electricity use has flattened, peaks are still growing -- albeit at a slower pace than previously forecasted due to energy efficiency and solar PV. Efficiency alone is expected to reduce peak demand on the bulk power system by 1,800 megawatts in 2026.

The need to better address those distributed resources on the system for future planning is a near-term challenge for local utilities and the transmission grid operator, even if the penetration of renewables on the system is still not nearly as high as it is in states like California and Hawaii.

As for short-term challenges, including woefully inadequate interconnection processes, data-access issues, and a lack of hosting capacity analyses, those will be addressed in a joint utility filing in late November.

The individual DSIP filings provide a comprehensive picture of how the utilities are progressing toward the future. That future is still far off.

Orange & Rockland

Orange & Rockland is a subsidiary of Consolidated Edison. It serves about 230,000 people in three counties of New York, just north of New Jersey. 

O&R’s approach to a technology roadmap is based on linking its Integrated System Model (ISM) and a still-to-come advanced distribution management system (ADMS). The ISM currently brings together geographic information system (GIS) data, customer data and system operational data.

But the ISM is just the beginning. O&R envisions its ADMS as bringing together the information from the ISM, as well as data from distribution automation devices, substation information, metering data, customer data and distributed generation asset information. “ADMS is at the heart of how leading utilities presently are or are planning to monitor and control their distribution grids,” O&R wrote in its filing.

Although these filings are meant to look five years out, O&R focused on the near term. It acknowledged the ADMS will allow for more distributed resources on the system and more granular data, but will not necessarily get it to the transactive energy future envisioned by REV’s architects.

O&R already has many elements that would go into an ADMS, including GIS, a growing distribution automation program, a network backbone to support an ADMS, and a pending smart meter rollout to all customers. The utility is currently doing a scoping study for an ADMS, which will be filed with a request for proposals from vendors.

O&R expects a three-year planning and deployment period for the ADMS at a capital cost of $13 million. The smart meter rollout will begin in 2017, with Silver Spring Networks as the network provider and Aclara as the meter provider at a capital cost of $98 million. 

As with other utilities, O&R has a short-term vision of gaining greater visibility and control on the system while also better incorporating distributed energy resources into long-term planning. Eventually, O&R will model distributed energy resources at the circuit level, but not until after 2020.

“As the amount of information that is being gathered grows, the need for a system that will aggregate, analyze, validate, and display the information to the operator will become a necessity,” O&R acknowledges. “Information will be required to move between systems on a common information model as it becomes increasingly integrated with data sources, historical measurements, and advanced applications.”

As for what that common information model will be, and what those advanced applications are, that’s all remains to be hashed out in the future.

Central Hudson

Central Hudson serves about 300,000 people in the Mid-Hudson Valley stretching up toward Albany.

Central Hudson is investing in distribution automation (DA). But it is not as far along with other integrated systems as is O&R. Central Hudson is in the process of installing about 900 DA devices, which will be integrated into an advanced distribution management system along with its enterprise GIS.

Central Hudson sees its ADMS as the brains of a distributed energy system, with DA devices providing data and control capability into that system. Central Hudson evaluated advanced meters, but found that any smart meter rollout, whether targeted or across its entire territory, did not meet the minimum threshold of economic attractiveness in its cost-benefit analysis. It is the only regulated distribution utility in New York avoiding investment in smart meters.

While some New York utilities will use smart meters for volt/VAR optimization (VVO), Central Hudson will use its DA platform to perform this function. The cost of DA across its five operating regions will be $44 million and will go on past 2020. The utility will also upgrade its network to support DA and its ADMS at a cost of about $4 million.

Central Hudson has already chosen Schneider Electric for its ADMS, which will cost nearly $7 million. The initial applications will be VVO and fault location, isolation and service restoration, but it will eventually be used for real-time control of distributed energy resources.

The ADMS is expected to go live in March 2017. To give greater visibility across its five regions, the utility will establish a distribution system engineer that will control operations across all of the operating districts rather than keeping each operating in separate silos.

National Grid

National Grid owns the Niagara Mohawk Power Corporation, which serves about 1.6 million electric customers in upstate New York. National Grid first outlined some of the advanced capabilities it needed in a smart grid roadmap released in 2014, but none of those elements have been put forward in a rate case yet.

Much like all of the other utilities, National Grid touted the need for real-time control and visibility on the distribution network and bringing together siloed systems into a single architecture.  

“An architectural framework that can deliver the 'right data, right service, anytime' is a fundamental enabler of the DSP,” National Grid wrote in its filing. The utility sees a modular, service-driven architecture as the foundation for becoming a DSP.

National Grid envisions a “comprehensive integration services” platform that can move data between systems and enable real-time integration. It also sees an API framework as key to allow third parties to layer on applications.

The utility is also investing in GIS, ADMS and other technologies, most of which won’t see initial investments until 2018-2019.

National Grid currently does not have any type of monitoring and situational awareness on about half of its distribution feeders, but all will have it by 2024. Its investment in DA will come at a cost of about $69 million over the next five years.

Its ADMS, an upgrade of its current ABB DMS, will have a capital cost of about $14 million. Its full advanced metering deployment will begin in 2019, at an expected 10-year capital cost of $450 million, and will take six years for installation.


Iberdrola is the parent company of Avangrid, which covers the U.S. operations for both grid-scale renewable energy and distribution utilities. In New York, Avangrid owns New York State Electric & Gas (NYSEG), which has about 880,000 electric customers in the central southern portion of New York around Ithaca. Further west, Avangrid also owns Rochester Gas & Electric, with about 370,000 electric customers.

No matter what sort of DSP Avangrid’s two utilities eventually evolve into, Avangrid should be lauded for delivering the most reader-friendly DSIP report.

Avangrid defines its DSP role as a combination of grid operator, integrated system planner and market enabler. Avangrid acknowledges that the latter is outside the scope of this first DSIP.

The Avangrid utilities see four foundational technologies as key to being a DSP: advanced metering, distribution automation, sophisticated system analysis and planning tools, and upgraded technology networks.

Avangrid has already started with the first phase of DA and upgrading its backend networks. The next stages of its DA plan, including substation and capacitor automation, will cost about $190 million.

It will upgrade its Siemens’ distribution management system to an ADMS at a cost of nearly $25 million, which will allow for distributed energy visibility and controls that will lay the foundation for market transactions in the future. Its GIS grid model will also be enhanced, costing about $27 million.

Like most other New York utilities, Avangrid will also have a system-wide deployment of smart meters for gas and electric customers, at a capital cost of about $500 million. For NYSEG, the meter installation will start in 2018. Meter rollout will begin in 2019 in Rockland’s territory, with both utilities’ meter installations being completed by 2022.

The utilities are also planning for an enterprise analytics platform that would bring together all of the granular system and customer data that will be needed as a DSP. But the initial cost is only about $11 million. It will essentially be a prototype of the sort of system Avangrid thinks it will need as a DSP.

By comparison, Southern California Edison (which serves 14 million electric customers) could spend between $300 million and $575 million on technology platforms and applications between now and 2020 to support distributed energy resources.

Con Edison

Consolidated Edison is New York’s largest utility, serving 3.4 million customers in New York City and parts of Westchester County just north of the city.

The utility got a jump on one of the earliest tenets of REV, which is to employ more demand-side resources instead of putting money toward traditional grid upgrades, such as replacing transformers or substations.

Con Edison’s Brooklyn Queens Demand Management project is the largest and most comprehensive modern non-wires alternative (NWA) distribution project in the nation. The utility wants to delay a $1 billion substation, largely with demand-side resources such as energy efficiency and demand response. The auction for those resources will happen at the end of July. Some of the payments for BQDM could be an order of magnitude higher than what the utility currently pays for its traditional demand response programs.

Con Edison, because of its size and location, is also considering far more NWAs than are the other utilities in New York, all of which are required to file at least one with regulators. Con Edison expects slow growth in coming years, but some other utilities in New York have slightly negative load growth across their entire territories.

The utility is also first in line to deploy smart gas and electric meters across its territory starting in 2017 at a capital cost of about $470 million. The project will be complete by 2022. The utility already has distribution automation systems on some of its feeders and will be able to leverage its smart meter network for further distribution automation. 

Con Edison knows it will need a distributed energy resource management system (DERMS) and an enterprise-wide GIS. Currently Con Edison has no single point of information for distributed energy assets on its system.

It also acknowledges it will eventually need a communications network on top of its smart meter network to truly meet the requirements of being a DSP. The utility already has distribution automation systems on some of its feeders and will be able to leverage its smart meter network for further distribution automation. 

The utility expects to spend about $20 million on its DERMS platform over the next five years, and $133 million overall on technology it sees as fundamental to becoming a DSP. Implementing Green Button Connect, for instance, is expected to cost about $15 million.

A small portion of the $133 million -- about $1 million per year -- is for data analytics, a figure that will likely balloon in coming years. “This category is one of the less developed categories in terms of guidance and market experience,” Con Edison wrote in the filing, “Nonetheless, the Company envisions a possible need for data analytics early in the process.”

For all of the New York utilities, the learning curve around data analytics and technology platforms will be steep. The need (and price tag) for market-enabling technology should be clearer in the DSIP filings in 2018 and 2020 if the distribution markets start to materialize.


To learn more about near-term technology investments in New York's energy sector, join REV's major stakeholders in Brooklyn from September 27-28 at GTM's New York REV Future conference. GTM Squared members receive a $200 discount on registration with the code SQUARED.