Why the power grid of the future is in California and New York
New York and California are working to position the electric system to succeed in an environment of changing technology costs and capabilities, Crosby and Cross-Call write.
In The Tipping Point Malcolm Gladwell popularized the process—first described by Everett Rogers—by which innovative ideas, policies, and products start with a small but influential minority of early adopters and then spread rapidly to a much wider segment of the market. The planning and design of the electric grid could be at just such a tipping point, with New York and California leading the chargeon how to integrate significantly higher amounts of distributed energy resources (DERs) onto a grid historically built around centralized assets like large power plants.
While New York and California have different existing levels of DER adoption, electricity policy objectives, history, and market structures, the two initiatives share common drivers. Both states recognize the importance of fundamental changes to the regulated investor-owned utility business model and distribution planning process. Both processes are designed to position the electric system to succeed in an environment of changing technology costs and capabilities, improve system resilience and customer opportunities, and address the electric system’s impact on climate.
NY AND CA’S INITIATIVES AT A GLANCE
In April 2014, the New York Public Service Commission launched the Reforming the Energy Vision (REV) proceeding. The ambitious initiative is the first in the nation to propose an entity to perform the role of a “distributed system platform (DSP) provider.” The DSP model gives life to a new market for distributed resources to provide energy services, similar to a distribution-level independent system operator (ISO) but focused on DERs rather than central grid assets.
The DSP in NY will interface between the bulk power system, utilities, DER providers, and retail customers. While much is yet to be decided, the REV proceeding envisions DSPs as platforms for innovation and market-based deployment of DERs.
California launched a rulemaking proceeding in July 2014 pursuant to Assembly Bill 327, which requires the state’s investor-owned utilities to develop distribution resources plans (DRPs) to better integrate DERs onto the grid. California is the national leader in installed capacity of solar PV, and therefore faces unique challenges related to an existing, scaled deployment of DERs that has not yet materialized in New York. Moreover, due to the California statutory requirement to focus on DRPs, the process is focused on technical matters related to DER integration, and does not explicitly explore how utility business models may need to change to better integrate DERs. The California initiative does not create a new distributed resource market like the one envisioned in NY. However, like NY, the California process intends “to mov(e) the IOUs towards a more full integration of DERs into their distribution system planning, operations and investment.”
FOUR BIG QUESTIONS
To understand where each state may be headed, we focus on four key questions:
- What is the role of markets versus mandates in creating the future system?
- What does distribution system planning look like in a high-DER future?
- What is the best market structure and regulatory framework to attract data-driven innovation and new energy services?
- What are the roles of the customer and the utility in the future system?
MARKETS VS. MANDATES
The proceedings are notable for the degree to which each envisions markets versus mandates to characterize future distribution system planning and investment.
California has historically relied on innovative policy mandates to achieve energy system goals. While California led the initiative in the 1990s to deregulate retail electricity markets, the electricity price disruptions and associated utility financial impacts in early 2000s led to strong corrective mandates that remain influential in the policy landscape. The current DRP process scope is directly tied to AB 327, the legislative mandate directing the utilities to develop distributed resource plans.
New York has also relied on targets and mandates to guide energy policies related to energy efficiency goals, DER integration, and renewable power procurement. However, in contrast to California, New York’s deregulated retail electricity market remains in place and has resulted in energy cost savings for many large commercial and industrial customers.
New York’s electricity policy direction is explicitly market-oriented. Richard Kauffman, New York’s chairman of energy and finance, notes the need for clean energy markets, not programs or mandates. “There are a growing number of people across political boundaries that are seriously looking at these issues,” Kaufman states. “We need to get to that system not by creating more programs, but by animating markets."
DISTRIBUTION SYSTEM PLANNING
Both states recognize that, to make a more distributed, efficient grid work, regulators and utilities need to plan ahead. Historically, the electricity system has not fully valued DERs in distribution system planning and investment, despite potential benefits of DERs to the grid. While some utilities have employed DERs to modify peak loads and reduce wholesale peak costs, DERs can provide other services that may not been fully accounted for in existing tariffs. In fairness, utility companies may not have fully leveraged DERs in part because the regulatory framework guiding utilities’ business model did not explicitly orient the utility to recognize that value. Now that is changing. Due to cost reductions and accelerating adoption curves, DERs matter, and states and utilities are taking DERs more seriously in business model development and planning.
Pursuant to the regulatory compact, utilities have long maintained a monopoly control of the distribution network. This allows for reliable system planning, but has also resulted in a “black box” around distribution system planning and costs. Both states have the opportunity to shed light into the distribution system planning processes and costs. One way to achieve this would be for utilities to file resource plans to make public where grid constraints exist and investments required, and to shift planning and investments toward integration of DERs.
In consideration of these and related issues, the NYDPS Staff Straw Proposal proposes that utilities should file near-term “distributed system implementation plans” (DSIPs), in which utilities will describe how they plan to transition to being a DSP provider, and how they will recognize DER contributions that might otherwise compete against traditional infrastructure investments.
In California, AB 327 requires IOUs to file DRPs that include scenario-based planning as well as integration analyses. Scenario-based planning accounts for different DER adoption scenarios, as well as other factors that might impact the need for DERs, such as retirement of large power plants. The CA IOUs are required to define the criteria for determining what constitutes an optimal location for DER deployment, and then identify values for the deployment via online mapping tools. The IOUs are also required to conduct integration analyses to measure the threshold integration of DERs, based on assumptions related to DER impacts on electric system reliability and safety.
The proposed CA approach is different from the NY approach because the utility, rather than the market, is in an active position to define the DER valuation and criteria for determining how much DERs can safely be added to the system (although both analyses are subject to public processes).
DATA-DRIVEN INNOVATION AND NEW ENERGY SERVICES
The pace and scale of DER deployment in both NY and CA will rest, in part, on the breadth and depth of system and customer data and the availability of that data to customers (to manage their use), as well as to DER service providers (to develop new services and target those to locations most in need). For example, combined with a price signal, system data (such as metering at substation or other system nodes) exposes areas on the system where DERs can provide the most value, for example by alleviating congestion in load pockets. Customer usage data reveals the largest users of power, and therefore those most likely to be interested in DER solutions that can reduce their bills.
California has the head start in metering data collection due to roll-out in advanced metering infrastructure (AMI), as well as pioneering data-sharing tools such as Green Button, Green Button Connect, as well as other data-sharing mechanisms to make DER valuation more transparent that are considered in the DRP process.
However, NY has the potential to leapfrog CA on data in novel ways. The NYDPS straw proposal envisions a two-way data exchange, where DER providers are required to provide DER size and load reduction data to the DSP (like a generator would to a bulk system operator), and utilities would share system and customer data to the DER providers. Also, while AMI is an important enabler of measurement, verification, and communication, alternative metering and communication solutions such as revenue-grade metering and communication chips embedded in smart devices may offer more advanced features than existing AMI functionalities, particularly where metering is a challenge in environments such as New York City.
Additionally, in NY, the REV proceeding seeks to create a distributed system platform that allows customers, third-party service providers, and energy service aggregators to interact, not unlike otherplatform markets such as computer operating systems and smartphones. For example, the Apple iOS and iPhone serve as the platform on which other services are available, linking data and algorithms to devices that perform countless tasks, such as car sharing.
While it may take time to get there, an energy platform model could similarly allow DER service providers (e.g., solar companies) to link specialized electric grid distribution data with customer-facing technologies and applications.
For example, electric system data such as wholesale electricity prices and distribution node data, combined with other relevant information such as building footprint and weather, may allow developers to build new load management products that go beyond traditional utility electricity services, appeal to and pay customers, and have the added benefit to help make the system more balanced and efficient.
ROLE OF THE CUSTOMER AND THE CHANGING ROLE OF THE UTILITY
In both states, the customer is central to the adoption and integration of DERs, as well as the future business model of the utility. While utilities have established trust with many of their customers and provide safe and reliable service, there is an opportunity to let other companies offer more innovative customer solutions integrated with our online, digital lives. JD Power recently found that while overall customer satisfaction with utilities has improved, utilities are not keeping pace with other tech companies such as Google, Facebook, and Amazon that are positioned to disrupt the residential electric utility business models.
Both states have an opportunity to open the DER market to providers that have direct access to customers, with new products and services that attract and excite customers to adopt DERs and actively manage them. New York has clearly stated its intent to change the utility’s role from commodity service provider (kWh) into a platform for an untold number of new energy services and service providers.
DON’T CHANGE THAT DIAL
The fundamental distinction at this point in the proceedings is that while in CA utilities must consider privately financed DERs in their planning, the process is technically focused, and still largely utility-directed. In NY, by contrast, REV seeks to enable market forces to influence customer and third-party DER deployment and valuation, which utilities would therefore have to take into account in the marketplace.
It is too early to say where exactly these reform proceedings will settle on these important issues, as both states are just out of the starting blocks in their respective efforts. A year from now (and certainly in five or ten), we will likely look back on this point as marking a major shift in electricity market design, when the first of many states undertook major reforms to create the clean electricity system that we deserve.
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