If 2015 was the year that New York’s Reforming the Energy Vision (REV) initiative captured the imagination of the utility sector, 2016 could be the year some of its dreams start to materialize.
In April 2014, the New York Public Service Commission kicked off the REV proposal with a groundbreaking straw proposal. In it, the staff of the regulatory body laid out a vision for the regulated utility as a “Distribution System Platform (DSP) Provider” — akin to an air traffic controller that coordinates and facilitates the deployment of various distributed energy resources (DERs) on the grid.
The idea, at its base, is to reform the utility business model and practices so that planning for and integrating DERs from third party providers is a central focus, and to ensure that utility companies are incentivized to consider DER solutions as an alternative to traditional grid and generation investments. Critical to that aim is the creation of vibrant markets for DERs on the distribution system.
“Under the customer-oriented regulatory reform envisioned here, a wide range of distributed energy resources will be coordinated to manage load, optimize system operations, and enable clean distributed power generation,” the staff of the PSC wrote in the straw proposal for Track 1 of the proceeding. “Markets and tariffs will empower customers to optimize their energy usage and reduce electric bills, while stimulating innovation and new products that will further enhance customer opportunities.”
As the statement indicates, creating value for customers is a central goal of the REV initiative. As open markets are designed for resources on the distribution system, customers of all sizes will be able to choose from a wide array of distributed resources to produce and store their own power, as well as reduce their usage.
Virtually all of the energy stakeholders in New York are on board with that vision, including the state’s regulated electric utilities. The challenge, however, remains in how to properly structure markets on the distribution system so both DER providers and the incumbent utilities can thrive.
“There's a lot in what [regulators] are looking at, a lot of stakeholders involved in the process,” said Matthew Ketschke, vice president of distributed resource integration at Consolidated Edison, the electric utility that serves New York City. “Between New York and California, those are probably the two places where you are at the leading edge of the evolution of the industry.”
To realize their expansive vision, New York regulators separated the REV docket into two tracks. Track 1 focuses on the development of distributed resource markets and the utility as the DSP providers. Track 2 focuses on reforming utility ratemaking practices and revenue streams to accommodate the DSP provider model. Throughout the process, pilot projects proposed by the state’s utilities will test various aspects of DER integration, customer data sharing, third party partnerships, and more.
With the exception of those pilots, most of the action in the REV docket has been preparatory up to this point — the commission issues a guidance, stakeholders file comments, and then respond to each other in reply comments.
But, barring significant delays in the process, 2016 will see each utility file its first Distribution Service Implementation Plans (DSIPs) — frameworks for how the utility will encourage DER deployment and coordination with third party providers on the distribution system. While utilities probably won’t shift to new revenue and business models under REV this year, the coming months will likely result in a much clearer picture of what those new models could look like in the future.
Here’s a look at where the REV initiative stands today — and where it is headed.
Track 1: Formation of DSIPs
Last February, New York regulators laid out the expectations for utility DSIPs in their order initiating Track 1 of the REV docket.
“[The DSIP] will serve as a source of public information regarding DSP plans and objectives, including specific system needs allowing market participants to identify opportunities. It will also serve as the template for utilities to develop and articulate an integrated approach to planning, investment and operations,” regulatory staff wrote. “And it will enable the Commission to supervise the implementation of REV in the context of system operations.”
To achieve that goal, staff wrote in an October 2015 guidance proposal, the DSIPs will need to contain certain information, including how utilities are “working with, and intend to further stimulate the involvement of, current and would be market participants.”
Utilities will also have to show how their plans will align with eventual “Earning Impact Mechanisms” (EIMs) — monetized performance metrics proposed under Track 2 and linked to utility practices such as peak load reduction, energy efficiency, and customer engagement and information access. Such metrics are intended to move the utilities toward performance-based regulation and mitigate for revenue losses resulting from DER proliferation and enhanced efficiency.
In the October 2015 guidance, the staff proposed a two-phase approach to the first DSIP filings. The Initial DSIP, due June 30, 2016, “shall focus on the information each utility presently possesses, and initial changes that may be necessary to conduct a more comprehensive and transparent planning process.”
That, regulators wrote, should include sections on distribution system planning (such as forecasting demand growth and identifying beneficial locations for DERs), distribution grid operations (like volt/VAR optimization and interconnection), and distribution system administration system data sharing, customer engagement and the like).
After that, the commission recommends that utilities jointly file a Supplemental DSIP to specify tools, processes and protocols that will allow them to plan and operate a modern grid, as well as support “retail markets that coordinate significant DER investment and efficiently manage resources.”
In the supplemental filing, the commission expects utilities to include information on distribution planning and grid operations, granularity of pricing, data access to facilitate market formation, and joint system planning, among other details. The Supplemental DSIP is due September 1, 2016.
Track 1: Utility DSIP response
On January 6, 2016, the Joint Utilities filed reply comments with regulators on the proposed DSIP guidance and other stakeholder responses to it. The group includes regulated utilities in the state — Central Hudson Electric & Gas, Consolidated Edison, New York State Electric & Gas, National Grid, Orange and Rockland Utilities, and Rochester Gas and Electric.
More than 200 stakeholders are involved in the REV docket — though far fewer filed comments on the DSIP proposal — but for the sake of brevity, this article will focus on the utility responses. And in this case, the utilities and other stakeholders were largely supportive of the regulatory guidance on DSIPs.
“Notably, the overwhelming majority of parties that submitted initial comments on the Proposed DSIP Guidance support the two-phased approach to DSIP filings,” the Joint Utilities wrote. “The two-phased approach is also most likely to yield the desired REV implementation outcomes in an efficient and expedient manner, with meaningful progress to be reported in each subsequent DSIP filing.”
Beyond the broad two-phase framework, however, some sticking points emerged between the stakeholders. Some environmentalists and DER providers, the Joint Utilities noted, want to accelerate the DSIP process. The Northeast Clean Heat and Power Initiative, for instance, filed comments saying, “there is an apparent underlying belief by the utilities that they have three to five years before serious distributed resource planning will be needed,” but that actual planning should begin sooner.
Other qualms from the alternative energy community relate to how much information would be included in the Initial and Supplemental DSIPs. SolarCity, the Joint Utilities noted, filed comments requesting that utilities file more comprehensive Initial DSIPs that address many of the topics originally envisioned for the supplemental filings. SolarCity wrote that it is worried that leaving too many details to the jointly-filed supplemental plans will result in proposals that cater to “the lowest common denominator,” rather than the needs and abilities of each utility.
The intent behind the company’s comments was echoed by the Clean Energy Organizations Collaborative (CEOC), a group of alternative energy and research organizations filing jointly in the REV docket. In their reply comments, they argue that much of the “basic factual information” on distribution system usage and operations that regulators requested in the DSIPs should be provided in advance of the plans themselves, writing that it should be “viewed as a key input, rather than an output of the DSIPs.”
CEOC recommended that this information should be vetted by stakeholders in technical conferences this winter and spring, and that it should be supplemented by potential estimates for various types of DERs.
“Together, this information will provide a foundation for the actual plans that will comprise the utilities’ DSIP and their subsequent DER procurement plan,” CEOC wrote.
The Joint Utilities’ response to such concerns was that the framework proposed by regulators for the drafting and publication of DSIPs will answer the critics’ concerns. Rather than resulting in a “lowest common denominator” approach to distribution planning, the Joint Utilities argued that the stakeholder process will beget innovation, and the joint nature of the supplemental plans will ensure continuity in distribution market rules and practices throughout the state.
The City of New York and NRG Energy advocated for a more deliberate approach to DSIP planning, arguing the utilities should establish market rules and governance provisions for distributed energy markets before their DSIPs. But that would be putting the cart before the horse, the utilities wrote, and in the near term, they are focusing on “actions that test market concepts and lay the foundation for the development of distribution markets.”
“These actions include developing system planning capability and process development, customer and system information sharing, and requests for proposals ("RFPs") for non-wires alternatives ("NWAs") as well as testing market-pricing concepts through demonstration projects,” the utilities wrote. “It is premature to devote utility, Staff, and stakeholder resources now to the development of distribution market rules and governance provisions, as the City and NRG proposed.”
Other points of contention in the DSIP proceeding include interconnection procedures, hosting capacity and system data sharing, among others. But by and large, the Joint Utilities argued that qualms were either being addressed already, would be addressed by the two-part DSIP process, or were outside the purview of Track 1 of the REV docket.
“The Joint Utilities endorse the Initial DSIP filing objectives, broadly support the specific requirements of the Proposed DSIP Guidance, and offer some suggestions to improve the REV implementation process,” they wrote in conclusion. “In particular, the Joint Utilities endorse the Proposed DSIP Guidance approach to REV implementation because it is consistent with the evolutionary and incremental nature of REV, including the benefit of prioritizing topics to be addressed in the Supplemental DSIP filing.”
Track 2: Ratemaking reforms to support REV
While Track 1 of the REV docket focuses on the technical and planning necessities of converting traditional utilities into DSP providers, Track 2 aims to align financial and ratemaking incentives so both utilities and third parties benefit from providing customers enhanced value through DERs.
At present, those incentives aren’t properly aligned, regulators wrote in a July 2015 white paper providing guidance for Track 2. While the state’s decoupled utility revenues make power companies less sensitive to higher DER penetrations, “there remain significant disincentives for utilities to take affirmative actions to increase the development and use of third-party capital and services that support DER penetration and system value.”
Utilities’ long-term health, even under a decoupled revenue scheme, depends on the “assumption of a growing or stable rate base,” regulators wrote, and they cannot earn a return on operating expenses except by cutting them.
“Optimally integrating DERs may, though, require increases in utility operating expenses and decreases in capital spending,” they continued. “Consequently, there is a financial misalignment between the utilities’ economic interest, the interest of third-party DER providers and other service providers, and customers.”
To align those incentives, regulators proposed a slate of reforms to how utilities make money. They fall into three categories: Business model reforms including the opportunity for market based earnings (MBEs), incremental ratemaking reforms to the utility revenue model, and rate design reforms to reflect the needs of the evolving marketplace.
Market based earnings
As the model of the utility as a DSP provider becomes reality, utilities will have the chance to “increase revenues earned from serving as a platform for customers and DER providers to employ DERs and manage customer bills,” regulators wrote.
As markets develop, regulators expect utilities to derive an increasing amount of their revenues from MBEs, especially “platform service revenues” (PSRs) — the earnings utilities will collect in their capacity as DSP providers. Many of the demonstration projects showed early examples of how New York utilities plan to collect these revenues, but regulators point out that they aren’t new for utilities in other states.
“For example, Georgia Power offers bundled communication services, and Con Edison and Pacific Gas & Electric offer co-location with wireless facilities. Green Mountain Power offers a number of advanced energy options including heat pump services,” regulators wrote. “These innovative types of revenue streams allow utilities to use their assets for the benefits of both shareholders and customers.”
What will change under REV is the “diversity and scale” of the earnings available from MBEs, regulators said, and the increased role of MBEs will facilitate market entry for DER providers, offset rate impacts of DSP capital, supplement utility revenues as DER market share increases, and provide incentives for utilities to innovate, among other benefits.
MBEs won’t be enough to fully realize the goals of REV, regulators wrote. Utilities must also have earnings incentives that prompt them to invest in DERs rather than more traditional, capital-intensive grid projects, such as building new transmission lines, generation, or substations.
One approach regulators offered is to modify “clawback” provisions typical in current rate cases that typically refund unspent amounts of a utility’s capital budget to customers. Instead, regulators wrote that the clawback should be revised so that the money that would have been spent on a project in the utility’s capital budget can be retained by the company if DERs supplant the need for the project.
For instance, if a utility spends from its operations account to integrate rooftop solar onto its system instead of spending from its capital budget for a new plant, it could retain at least the amount of earnings lost from its operations account in its capital account. If the clawback is modified properly, regulators wrote, the “utility and customers [will] share an interest in maximizing efficient third-party investment in DER to supplant capital spending.”
Additionally, regulators wrote, utilities should have the opportunity to earn revenue on operating expenses that enable DER integration, but do not offset capital spending. “If utilities are able to see operating resources as an earning opportunity on a par with capital spending, they will have no disincentive to procure DER.”
On top of the MBEs and altered clawback mechanisms, regulators envision moving utilities away from traditional cost-of-service ratemaking and toward performance-based rates. They propose to do this through EIMs — the monetized performance metrics mentioned above. Through them, utilities could earn revenue for functions like peak demand reduction, efficiency, customer engagement and the like. Over time, regulators envision market-based incentives — the MBEs — supplanting some or all of the EIMs, as part of an overarching REV goal to shift utilities toward economic incentives, rather than regulatory ones.
For performance outcomes that cannot be directly monetized — such as system utilization and efficiency, time of use rate efficacy, use of MBEs, carbon reduction, customer satisfaction, and more — commissioners proposed using regulatory scorecards to provide transparency into progress on important outcomes, information for system planning, and future EIM use.
Rate design reforms
In addition to instituting MBEs and new ratemaking procedures, regulators envision wholesale changes to rate design as well. While advanced metering infrastructure in New York is likely not widespread enough currently to adopt all of the proposed changes, regulators expect that its proliferation will “enable movement beyond the historical dispute between fixed customer charges and volumetric rates.”
Instead of relying on fixed charges to cover grid costs, regulators wrote that demand charges provide a better revenue collection method because they coincide with peak usage on the grid — the “most accurate measure of system costs.” And because demand charges can be managed by the end user through demand response, efficiency, or distributed generation and storage, they provide an added incentive for the deployment of these resources.
In the same vein, regulators pushed utilities to increase participation levels in existing time-of-use (TOU) rates and study them more through their demonstration projects. As they build out AMI infrastructure, utilities should focus on distributing information and tools on TOU rates and possible savings from combining them with DERs.
Regulators also offered ideas for more sophisticated rates, such as a “smart home rate” in which “granular price signals are unbundled to reflect costs associated with underlying dimensions of electricity, including commodity energy delivery costs, and possibly certain ancillary services, and have significantly more temporal granularity.” Such a rate structure could allow customers with DERs of their own to respond to day-ahead or other price signals, regulators wrote.
In addition to these reforms, regulators pushed for improvements to rates for commercial and industrial customers, such as more precise demand charges that reflect the time of day in which costs are incurred. Rates for low-income customers with DERs and reforms to standby service tariffs were also proposed.
Many of the rate design changes envisioned would not be possible right away, regulators conceded. Demand charges and TOU rates require upgraded metering infrastructure and revised utility billing practices. Consequently, the regulatory staff recommended the commission adopt the rate design proposals described, but also order follow-on processes “leading to the adoption of rate design proposals at the appropriate times,” such as when AMI infrastructure is built out.
Track 2: Utility responses
While the Joint Utilities endorsed the overarching aims of Track 2 of the REV docket, they expressed concerns about its implementation in initial comments filed in October, and again in reply comments filed November 23.
First and foremost, the utilities stressed that the wholesale changes to the utility revenue model envisioned by REV should not impede the ability of the state’s power companies to collect earnings from traditional cost-of-service ratemaking while the new market mechanisms are designed and implemented.
“The Commission should continue cost-of-service ratemaking and reject any approach that replaces any portion of the cost-of-service by a projected amount of uncertain market-based earnings,” the utilities wrote in their reply comments.
In both sets of comments, the utilities stressed that the potential utility revenues from MBEs are still uncertain, and should not be substituted for traditional revenue sources or be expected to have an impact on consumer rates in the short term. They also shed doubt on whether MBEs could ever come to replace or supplement traditional utility revenues to the extent regulators envision.
“[T]he Staff White Paper envisions MBEs as an element of a fully realized REV environment, not as part of the initial and transitional states of REV. The Joint Utilities do not agree with this approach,” they wrote. “Moreover, the concept of MBEs themselves is uncertain. It is unknown whether and/or when MBEs will actually begin to be realized. MBEs, should they develop, are likely to be uncertain and inherently difficult to reasonably estimate.”
The uncertainty inspired by pushing a long-term vision of MBEs is “unnecessary to introduce” at this stage in the docket, they continued, “because utilities can capture the benefits of MBEs for customers by recording them as and when they are realized and making them available to offset future costs.”
Other parties, even those pushing for more DERs on the grid, support that conclusion, the utilities noted. The CEOC, in its initial comments, wrote that its organizations do not expect MBEs to be significant in the “near to mid-term” and that the “Commission should not rely on these MBEs to replace ratepayer funds until experience demonstrates that MBEs can be relied upon as a stable funding source.”
Retail electric providers and energy service companies in the state filed with the commission as well, arguing that third parties may be able to provide certain MBEs to a wider audience and at a lower cost than the regulated utilities. But, the Joint Utilities responded, “the Commission has already resolved this issue by recognizing that the Joint Utilities may offer services that will facilitate the development of the DER market.”
“While it is unclear which of the MBE services listed in the Staff White Paper will become competitive, it is premature and inconsistent with the public interest to preclude the DSP from offering such services in a nascent market,” they wrote.
EIMs and ratemaking
While the Joint Utilities endorsed the establishment of “meaningful incentives to promote important REV-related outcomes,” they argued in the initial comments that “[m]any of the EIMs and scorecard metrics discussed in the Staff White Paper are inappropriate because they are not within the control or meaningful influence of the utilities, and may not be cost effective for utility customers.”
Instead, they proposed an Incentive Framework to “address, design and implement REV-related performance incentives,” along with an initial set of REV incentives to promote the goals of reform.
The Incentive Framework includes two distinct categories: broad-based EIMs and more targeted “programmatic incentives.”
“Broad-based EIMs are appropriate for REV outcomes that utilities pursue through a variety of central business activities,” the utilities elaborated in their reply comments. “Programmatic incentives are appropriate for outcomes that relate to specific utility programs (i.e., energy efficiency and [non-wires alternatives]).”
At the outset, the utilities argued that both EIMs and programmatic incentives should have only positive incentives, and no penalties, so that the financial health of the utility is not jeopardized by their implementation. To evaluate new incentives, the utilities proposed a four-part evaluation and implementation process:
Key elements of this framework were elaborated in the utilities’ reply comments:
Criteria for identifying metrics based on the utilities’ ability to control or meaningfully influence the outcome being measured;
Initial incentive metrics that would be limited to the most important outcomes, such as cost-effective deferral of distribution infrastructure;
The development of metric targets that are realistic and reasonably achievable without requiring uneconomic levels of spending;
EIMs would be established for outcomes dependent on a variety of utility central business activities while programmatic incentives would be established for outcomes produced by specific utility programs; and
Scorecard elements would be established for metrics that are within utility control or meaningful influence, but are not sufficiently developed to be included as an incentive with monetary consequences.
A number of parties, including the GridWise alliance and CEOC, broadly support the use of incentives based only on items within the utility’s control, the utilities noted in their reply comments. Several others argued that all incentive metrics should be symmetrical — involving penalties as well as rewards.
The Joint Utilities support symmetrical incentives when they have direct control over the outcome, a track record exists to establish a metric, and the metrics are economically achievable. However, they note, “most REV metrics that would qualify as incentives or Scorecard items under the proposed Incentive Framework are not within direct utility control,” meaning that “utilities should not be subject to negative adjustments that could occur under symmetrical incentives.”
As for the “clawback” mechanism, the utilities broadly supported the proposed changes in investment structures.
“The Joint Utilities agree that utilities should be indifferent as to whether a traditional infrastructure investment or a third party alternative solution is selected to meet local needs,” they wrote in initial comments. “Utilities should retain some or all of the net benefits over the life of the deferred project that extends beyond the primary term of the rate plan.”
Rate design reform
The Joint Utilities broadly supported the commission’s call for net rate designs to achieve more DER penetration and unlock value for customers, as well as the gradual nature of their proposed study and implementation. But, they stress, more study and understanding of the value of distributed resources will be needed.
While the staff white paper assumes that DERs will lower system-wide costs, the Joint Utilities stress that this is not a given. The “value of D” — the name regulators gave to the value of a distributed resource at a certain point on the grid — could possibly be negative, the utilities wrote.
Utilities disagreed with the commission that retail rate net metering should be retained under REV, and argued that the “value of D” as a pricing mechanism will be efficient only if it is properly developed and prevents DER customers from “bypassing responsibility for the fixed costs of distribution service.”
“The “value of D” should reflect the planning and operational value that DERs provide to the distribution system,” they wrote in reply comments. “It should be computed in a fair, objective, and replicable manner that is applied consistently and recognizes that in many cases this value could be zero or even negative.”
As for TOU rates and demand charges, the utilities broadly supported the continued study of such rate structures through their demonstration projects, but stressed that favorable outcomes for the new rates should not be assumed.
“[D]emonstration projects will provide insights into policy design and development, and valuable experience to utilities, customers, and market participants,” they wrote in initial comments. “It is premature at this time to implement these programs on a larger scale. It is possible that demonstration project experience will indicate that an entirely different approach should be taken to large-scale implementation.”
The utilities also noted that moving to more sophisticated rate structures would necessitate the upgrading of metering infrastructure in the state, a point echoed by ConEd’s Ketschke.
“Utilities in New York state do not currently in any large degree have the metering infrastructure to do more complex rate design at the residential or retail level,” he told Utility Dive in a November interview. “We have proposed a rollout for our whole system of AMI and that's part of our current proceedings with the commission and we think full deployment of AMI will give us the ability to have that sort of granular information that will allow us to develop more complex rate structures that customers may find more attractive.”
But even with those caveats, the Joint Utility comments broadly support the push to study new rate structures and devise programs that can better meet the goals of REV.
“The Joint Utilities continue to support moving to rates that more accurately reflect the inherently fixed nature of distribution service costs,” they wrote in reply comments. “Ideally, utility rates should convey fixed costs in the customer charge, the infrastructure costs to meet maximum customer demand in the demand charge, and variable costs in the kWh charge.”
What’s next in 2016
While 2016 will likely be the year that some of the broad market structures and utility roles under REV are designed, analysts don’t expect the state’s power companies to begin incorporating the new revenue opportunities like MBEs and EIMs into their business models quite yet.
“Will it be this year? I can say with near certainty no,” Kristie Deiuliis, a senior principal consultant at DNV-GL who’s been tracking REV, told Utility Dive. “There is a transition period, and it has an economic element, an implementation element … a set of filing and paperwork and data requirements. All those things happen when you have a proceeding where there's sunlight.”
What makes the REV docket different from reforming market structures in other industries is the critical nature of the utility company throughout the effort. But Deiuliis said that the state has gone through something similar before — when it deregulated the state’s vertically-integrated utilities and gave control of the transmission system over to the New York Independent System Operator.
“Unlike other competitive industries, utilities are obligated to provide reliable service and they have a number of mandates that competitive players don't have,” Deiuliis said. “So, some of those same questions were absolutely in the public debate when the state deregulated, and this just so happens to take that kind of concept and add numerous other complexities to it.”
But even with those complexities and the hundreds of stakeholders involved in the process, the DNV GL consultant said the focus of the proceeding has not been lost.
“What I like about the REV proceeding is they're very crystal clear that customer value is at the fulcrum of why they're pursuing the initiative, and, in a way, how [they are proceeding,]” she said. “I think the discussions keep returning to that.”
ConEd, for its part, remains focused on gleaning lessons from its demonstration projects that will help it form its Initial DSIP, set to be filed in June. The utility has three projects — a connected home platform, an efficiency marketplace for large customers, and a clean virtual power plant, which aims to test value chains around aggregated residential solar and storage.
“The goal of the demonstration projects is to test business principles and concepts, potential value chains, and value acquisition costs to determine if this is legitimately a viable opportunity for participants in this space,” Ketschke said.
As ConEd and other utilities study their projects, other filing deadlines in the REV docket will continue to shape future utility practices throughout 2016. Just last week, stakeholders filed initial comments regarding customer and aggregated data provisions, available on the PSC website. Public hearings are scheduled for Jan. 26 on the REV docket, with technical conferences on MBEs and EIMs scheduled for the 28th and 29th.
And throughout the process, Ketschke said helping to shape the REV reforms will be a top priority ConEd and the other utilities in the state.
“We are fully focused on the activities that are going here,” he said. “I don't know exactly where we're going to end up, but we're going to continue to evolve and things are going to continue to move along in this process.”