On November 1st, New York’s six investor owned utilities filed a joint plan on how they aim to transition to utilities of the future and enable consumers to make better and more informed energy choices, enable the development of new energy products and services, protect the environment and create new jobs and economic opportunity. This plan provides the industry with an insight into how utilities can coordinate plans, agree standards and forge new opportunities. In conjunction with the individual distributed system implementation plans (DSIPs) filed in June, the coordinated plan provides a transformative roadmap for the electric grid in New York over the next five years (to learn more on the utilities individual plans see Indigo Advisory Group’s insights into the technology roadmaps that New York’s major utilities are perusing)

The joint plan follows a phased approach to developing a Distributed System Platform (DSP) for New York and while the goal of coordinating the effort is to ensure consistency and standardization across the utilities, it must be recognized that the power companies are diverse in their service territories, grid configurations, data availability, and the degree of development of existing capabilities, and as such that is reflected in their roadmaps. As a whole however the initial and Supplemental DSIPs represent, “the first steps toward establishing a grid that can support increasing levels of DERs into the future and ultimately, achieving REV-related goals and objectives". Looking across the plan from a technology perspective we see how the utilities investments will support the State goals of a 40% reduction in greenhouse gas emissions, a 50% of target of energy generation from renewable energy sources and a 23% decrease in building energy consumption.

Individual Technology Plans Integrated Through Standards

In order to facilitate the grid of the future each utility requires investment in management systems, technologies, and processes to augment their future capabilities as a DSP. While each utility’s approach is somewhat unique, the table below illustrates the management systems and field technologies that the utilities plan to invest in to support operations in an environment with increasing DER penetration.

Table – Technology Investments – Joint Utilities Supplemental DSIP, 2016

Currently the utilities are reviewing their energy management systems and developing roadmaps and requirements to meet the evolving demands of the DSP role and focusing on “no regrets” investments.  The utilities suggest that at very high levels of DER adoption, they would need to invest in capabilities like DERMS, as they begin to see substantial interactions with markets. To that end, over the 2017-2021 timeframe, the utilities plan to improve upon and implement new technologies in their service territories to support DSP integration. The filing suggests that by 2021, the utilities also plan to either deploy, partially deploy, or test the deployment of a DMS in their service territories (consisting of DSCADA and ADMS), including the communication and IT infrastructure investment framework that would support the integration of the different components of the DMS and ADMS. The utilities expect ADMS to increase situational awareness and the usability of monitored system metrics, and help mitigate real-time and predicted emergency system conditions. Additionally, locational deployment of DER could be facilitated with the improved system visibility arising from the DMS.  In terms of coordination with NYISO / DSP in the medium term, the utilities expect to align on information sharing on resource aggregation, dispatch protocols and dispatch interface development. The plan goes on to suggest that the Joint Utilities and NYISO will need to develop an operating interface that matches the need for market coordination.

While there are technology investment variations across the utilities, due to unique utility characteristics (customers, connected generators, load and population density), the joint plan does converge importantly on a set of common monitoring and control standards to facilitate uniform participation of DER across the utility territories in the future. These standards include:

  1. Polling Frequency - DER will require monitoring at regular polling frequency, with near constant communication between the DER and the applicable monitoring system.
  2. Communication Protocols - DER will communicate with utility communications systems by means of generally accepted, industry-established communications protocols such as Distributed Network Protocol (“DNP”), Modbus, IEC 61850, and others.
  3. Circuit Parameters -DER will be subject to monitoring of circuit parameters. The Joint Utilities currently require, and will continue to require, information on DER and circuit parameters such as but not limited to power factor, real power, reactive power, phase current and voltage, hot line tags, and device status (open, close, or lock-down).
  4. VAR Support -The utilities are currently providing, and will continue to provide, reactive power or VAR support to the distribution grid. In the future, as technology and market evolution occurs, DER may also provide VAR support on a dynamic basis as requested by the utility.
  5. Curtailment - For DER 50 kW or above (standalone or in aggregate), the utility may limit the operation, or disconnect, or require the disconnection of the DER from a utility's distribution or transmission system at any time, with or without notice, in the event of real or predicted abnormal operating conditions, so that the safety and reliability of the system is preserved
  6. Notification of DER Connection and Disconnection – The utilities suggest that in order to maintain a safe and reliable system, they need to be informed of the current and forecasted operating status of a DER. To that, DER sized 50 kW or greater (standalone or an aggregate) shall notify the utility when disconnecting/reconnecting to the distribution system, regardless of enrollment in NYISO-administered wholesale markets.
  7. DER Performance Forecasting - Utilities may require a short-term (e.g., week-ahead, day-ahead, real-time) forecast for individual facilities’ expected output for use as an input to the day-ahead planning process to secure the distribution systems for local reliability.
  8. Advanced Function Support - The utilities will support advanced DER functions, such as smart inverter functionality and electricity market participation, in the future. The utilities will set monitoring and control standards and requirements for enabling such advanced functionality, as needed.
  9. Worker Safety -The utility and field crews will have the option to take any DER offline (irrespective of the size) with or without notice to the DER provider in order to establish clearances and to prevent back feeding or inadvertent energization of elements being maintained or repaired.

The Joint Utilities expect that these standards will be reflected in the relevant monitoring and control related documents at the individual utility level in the next 12-15 months.

Components to Facilitate the Grid of The Future

Overall, the joint plan from the Utilities recognizes that the evolution of the distribution market will require investments in infrastructure, processes, systems, and people to integrate DER and to facilitate value optimization for all customers. To that, the power companies have laid out foundational analysis, a series of frameworks and next steps across distribution system planning, load and DER forecasting, load flow analysis, NWA suitability criteria, hosting capacity, interconnection, distribution grid operations, market operations, DER sourcing, EV infrastructure and data collection and access. From a technology perspective, these key investment areas are summarized below.

  • Distribution System Planning - The Supplemental DSIP provides an initial view of the enhanced planning tools and methodologies that will form the basis of distribution planning in the future and allow for the development of DSP capabilities and integration of higher levels of DER. In particular, the plan outlines a load and DER forecasting stakeholder engagement process, a process for coordination with NYISO on short- and long-term forecasting, an NWA suitability framework and forthcoming implementation matrices, a detailed roadmap for hosting capacity; and an interconnection data platform and process roadmap.
  • Load and DER Forecasting - As NY’s utilities increasingly apply the more granular approaches in load and DER forecasting, location-specific forecasts they may begin to crosscheck this against system-wide forecasts so that all methodologies are consistent and to further enhance the accuracy of these more granular forecasts. However, the filing does note that to fully transition to locationally-specific DER forecasts, spatially-based software tools will need to mature in parallel with incorporation of the new inputs to allow for consideration of land- and roof-based potential. The filing does go further however suggesting that efforts to enhance existing forecasting capabilities and tools could also extend beyond more granular forecasts and include the development of new approaches such as scenario analysis and probabilistic planning.
  • Load Flow Analysis - The joint plan acknowledges that as the distribution system planning process evolves, load flow analysis will be a critical input for processes such as the identification of beneficial locations and determination of NWA suitability to defer or replace a traditional utility investment to meet system needs. For the utilities, investment in load flow analysis and tool development will be a critical enabler of hosting capacity because this analysis requires the development of a low-load case to investigate voltage impacts of solar PV.
  • NWA (Non-Wire Alternatives) - The plan suggests that upon completion of load flow analysis, distribution planners consider alternatives, identify solutions, and recommend projects for capital budget approval to meet identified needs. The Joint Utilities have proposed a common framework to identify those projects that are most suitable for NWA to provide greater clarity, certainty, and long-term visibility to the market and to promote an efficient allocation of time and resources for both developers and utilities. The framework primarily focuses on three factors: project type, timeline, and cost. These criteria reflect the goals of: (1) identifying the projects that are best suited for competitive procurement of an NWA; (2) giving developers the greatest opportunity to compete; and (3) providing the greatest opportunities for success of the process. In terms of project types and NWA Applicability the primary utility capital investment project categories and characterizes the potential applicability of each for NWA solutions, with load relief and reliability being the project categories most applicable for NWA.
  • Hosting Capacity - In order to effectively integrate DER, the utilities agree that it is necessary to understand the distribution system’s ability to host DER. Hosting capacity is defined as the amount of DER that can be accommodated without adversely impacting power quality or reliability under existing control configurations and without requiring infrastructure upgrades to the primary line voltage and/or secondary network system. To that end, published hosting capacity maps will guide project developers to interconnect DER where interconnection costs are likely to be lower, with increasing granularity over time. Overall, the Joint Utilities are adopting a four-stage approach for developing hosting capacity analysis capabilities in order to provide information to the extent possible as tools, models, and processes evolve. These stages include stage 1: Distribution Indicators, stage 2: Hosting Capacity Evaluations, stage 3: Advanced Hosting Capacity Evaluations and stage 4: Fully Integrated Value and Hosting Evaluations.
  • Interconnection - To further facilitate efforts to automate the DG interconnection process, the utilities suggest that they continue to engage with vendors as to the current state-of-the-art software capabilities and software integration requirements. They also suggest that although some of the functionality requirements present challenges for the utilities in the near term, the utilities have begun efforts on nearly all of the functionality requirements. These requirements include application submittal, validation and approval (utility facing) and tracking, user restrictions (limited public facing), cost estimates, status of payments, and pay on-line (limited public facing), viewing maps (public facing), reporting capability and options (utility facing), Interoperable with utility systems (utility facing), and expandable portal architecture that is flexible, scalable, and transparent (both public and utility facing). The utilities’ phased roadmap for achieving the various functionality requirements follows: phase 1: Automate Application Management (scheduled for completion by 2017), phase 2: Automate SIR Technical Screening (scheduled for completion by 2017) and phase 3: Full Automation of All Processes (scheduled for completion by 2019)
  • Market Operations - The plan outlines that a long-term objective of REV is to animate markets at the retail level. These markets are intended to promote innovation, value creation, and more efficient investment. As the DSP, utilities will play a leading role in animating markets by creating consistent platforms for the buying and selling of products and services among a broad set of market actors. As the framework for calculating the total value of DER as it evolves, as part of their DSP role, the utilities will develop the tools, processes, systems, and other capabilities to reveal this value and develop the market. Although the transition to potential transactional markets is a long-term consideration, the Joint Utilities understand that NYISO’s ongoing pilot project on sub-zonal pricing may inform and advance this transition. As the framework for calculating the total value of DER as it evolves, as part of their DSP role, the utilities will develop the tools, processes, systems, and other capabilities to reveal this value and develop the market.
  • Electric Vehicle Supply Equipment (EVSE) - The EV market in New York is currently supported by a variety of measures, including state and federal policies, research and development initiatives, public-private partnerships, private investment, and utility pilot and demonstration projects. The Joint Utilities acknowledge that strategically deploying EV charging infrastructure in key areas can increase EV adoption, and over time will develop approaches for determining the prudency and market impact of potential deployment approaches. In general, over the five-year Supplemental DSIP time horizon, current and expected near-term levels of EV adoption do not significantly impact utility system planning scenarios and related distribution system investment plans. The Proposed EV Readiness Framework includes a Service Connection Requirements and Processes, Local Ordinances, Building Codes and Design Guidelines and Interoperability and Standardization.

Data Sharing and the Grid of The Future

As outlined earlier, each utility’s individual DSIP proposes roadmaps for investing in the enabling technologies and data necessary for reliability and efficiency of operations in a proliferated DER future and also to enable future market development. While each utility’s approach is somewhat unique, the figure below illustrates the management systems and field technologies that are needed to support operations in an environment with increasing DER penetration. Overall, these new investments are part of a phased approach to increase operational capabilities, particularly through enhanced visibility, analytics, and operational control. To that end a key component of the joint utilities plan is how they intend to collect, aggregate and share data. System data, customer data and the framework of basic data and value add data the utilities have outlined form the beginning of an approach to managing data in a utility of the future environment.  

Figure - Enabling Technologies – Joint Utilities Supplemental DSIP, 2016

In terms of system data, the plan acknowledges that DER providers rely on certain elements of system data to help decide whether and how to respond to an NWA solicitation. To that, the Joint Utilities will work within 12 months to include a common set of system data points in NWA solicitations in order to facilitate more informed bid responses from the market. Types of system data will include, size of the need e.g. 1 MW, seasonality e.g. June – August, temporal profile of need e.g. between the hours of 1 and 4 PM, for no more than three consecutive days, duration of deferral e.g. 5 years, geographical characterization of need area e.g. a map showing the approximate boundaries of the need area, perhaps labeled with zip code information and customer characterization of need area e.g. approximately 2,000 customers, split 80 percent residential and 20 percent commercial and industrial. With regards to performance attributes, the Joint Utilities have identified several performance attributes that are indicative of criteria that utilities could each use to evaluate potential NWA solutions, these include availability, intermittency, dispatchability and coincidence.

Overall, the Joint Utilities suggest that they support the sharing of useful information to support DER market growth. The plan outlines that the utilities are taking steps to offer enhanced access to more granular customer usage data, including the development of AMI business cases and common data sharing practices. With this in mind, the Joint Utilities have developed a common framework for distinguishing basic data from value-added data for system and customer data. The plan suggests that while there are some nuances unique to the type of data being considered, the following general framework applies.

  • Basic Data - The Joint Utilities propose that basic data will be available to the requestor at no charge beyond the costs that are already included in base rates and includes data that is readily available, in the public domain, and provided without additional analysis or processing. For system data, this includes, but is not limited to, capital investment plans and reliability assessment reports. For customer data, the definition of basic data is “the usage for each applicable rate element, including usage bands specified in the applicable tariff.”
  • Value-added Data- Value-added data will be available for a fee determined through utility-specific fee structures. These fees may vary by each utility tariff based on its value to the consumers and market. Value-added data goes beyond basic data by having one or more of the following characteristics: is not routinely developed or shared, has been transformed or analyzed in a customized way (i.e., aggregated customer data), is delivered more frequently than basic data, is requested and provided on a more ad hoc basis; and/or is more granular than basic data. Examples of value-added system data may include forecasted load data, voltage profiles, and power quality data.

In addition to this framework, the plan addresses grid information such as real and reactive power consumption, power quality, and reliability, which can be collected at various levels including the feeder, substation, and system level. This data has value to DER providers, who can use it as an input to their technical and business decisions, such as where to market services or locate resources to support grid needs, and how to best respond to NWA solicitations. The Joint Utilities propose to reduce the information gap for several of these currently available data sets to make them more accessible to third parties by enhancing the transparency of modeling or planning methodologies Overall, the Joint Utilities have begun to explore alternative means of utilizing fee-based structures for value-added data services. In terms of data streaming - identified use cases for real-time data include device monitoring and control at the meter premise, demand response, DER dispatch, and settlement. In terms of streaming usage data from the utility meter for the purposes of interfacing with on-premise devices (e.g., building management systems) or offering energy management and related services in order to optimize energy consumption and lower energy bills, the utilities are evaluating several possible methods (e.g. ZigBee or similar protocol, HAN, BAN). Additionally, as number of use cases for aggregated data exist today and others are expected to develop over time and to meet the needs of stakeholders such as academic institutions, state agencies, city governments, and market entities that use aggregated energy usage for policy and planning purposes, the Joint Utilities are proposing to provide a uniform level of aggregated data. For aggregated Customer Data Privacy, the Joint Utilities propose the adoption of a 15/15 privacy standard for aggregated data provided by utilities to third parties, other than utility vendors or contractors or required by law or Commission order.

Looking Ahead

As with the individual DSIP’s, it must be acknowledged that across all of the REV technology roadmaps, these plans are subject to change and modification as time and circumstances evolve in this new utility environment. In terms of specific investments plans, these will be part of upcoming rate requests, which will further clarify the pace, timing and scope of DSP development. What is clear however is that as a group of utilities operating in a coordinated market, we will see further collaboration as a group, including continued development of common standards, protocols, and processes.  From a technology perspective, what we are continuing to see is New York’s utilities embark on ambitious, holistic and transformative technology journeys. 

Read the Joint Utilities DSIP here