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Major Changes for New York’s Utility Revenue Model – REV Takes a Step Forward

New York, NY –  Back in February 2015, New York’s Public Service Commission issued an order “adopting a regulatory policy framework for REV (Reforming the Energy Vision)…to reform the utility business model and to align ratemaking practices with an evolving set of regulatory and policy objectives”.  On May 19th, the Commission issued an order adopting a full suite of ratemaking changes to address these objectives and “enable the growth of a retail market and modernized power system that is increasingly clean, efficient, transactive and adaptable to integrating and optimizing resources in front of and behind the meter.”  These changes address many issues central to real estate owners and managers (e.g. large customer demand charges, standby service, data access) and will affect your utility costs and investment decisions into the future.  Read on to find out why these changes are being made, what exactly is changing, and how it will affect you and your assets.

Why So Many Changes?

In short, the utility of the past can’t be the utility of the future.  The status quo will not allow optimal integration of distributed energy resources, so the way things have always been done (i.e. rates and regulations) needs to change.

(The following is paraphrased from multiple sections of the order)

Traditionally, the ratemaking approach is based on cost-of-service i.e. increasing rate base in the long run through capital investments recognized in rate plans, and decreasing operating expenses in the short run by spending less than the allowance that is built into rates. Under traditional ratemaking, DERs (distributed energy resources) encounter twin barriers: they displace the growth of utility rate base, and they add to operating expenses. After rates are set under a traditional rate plan, if a utility has a choice between an operating expense and a capital solution, it will tend to favor the capital solution.

While cost-of-service ratemaking has served reasonably well for the last century, it was developed under several assumptions that may no longer hold:

  1. customer demand driving capital investment was largely beyond the influence of utilities and regulators
  2. economies of scale almost invariably favored large utility-scale investments
  3. the need to instantaneously balance supply and demand, coupled with the obligation of reliable universal service, inevitably required large expenditures for redundancies throughout the system
  4. end-use customers were the only substantial source from which system costs can be recovered
  5. information regarding cost of service is asymmetrical, i.e. utilities will have a far better understanding than regulators do of actual business costs and potential alternatives

The traditional revenue model encourages investment in a utility system that is based on these assumptions as well as central station generation, unidirectional flows (both of power and transactions) and minimal elasticity of demand.  It fails to provide incentives to innovate and to adjust to rapidly changing market, technology, and environmental factors and discourages numerous activities that utilities need to undertake to implement REV.  The combination of large impending infrastructure needs, decreasing system efficiency, environmental demands, weather and customer driven resilience requirements, and an increasing ability for customers to choose other options, present challenges to utilities and regulators that are both constructive and disruptive.  New earning opportunities for utilities will be a combination of outcome-based performance incentives and revenues earned directly from the facilitation of consumer driven markets. In this manner, regulation will ensure that the utilities have the opportunity to align with the interests of their customers and embrace, instead of resisting, the rapid innovation that is occurring in the sector.  Through this order, utilities will have three new ways to earn revenue (in addition to traditional cost-of-service earnings which will remain integral to stable and reliable electric service):

  1. earnings tied to achievement of alternatives that reduce utility capital spending and provide definitive consumer benefit
  2. earnings from market-facing platform activities
  3. transitional outcome-based performance measures

What’s Changing?

The current regulatory framework disincentivizes utilities from achieving the goals of REV. In order to encourage DER integration and grid modernization rates need to change to incentivize utilities (typically financially) to meet REV objectives while at the same time maintaining the traditional goals of safety, reliability, and affordability.  Interests of consumers, utilities, and their shareholders need to be aligned.

Below are the changes outlined in the order.  While specifics for each of the changes won’t be known until tariffs are filed by each utility, we have an idea of the scope and the timing for each.

  • Earnings Opportunities for Utilities
    • PSRs (Platform Service Revenues)
      • Platform service revenues are new forms of utility revenues associated with the operation and facilitation of distribution-level markets (utilities act as the DSP – Distributed System Platform). In early stages, utilities will earn from displacing traditional infrastructure projects with non-wires alternatives (e.g. BQDM).
      • Timing: Utilities may file tariffs at any time after the Secretary has established a service list to notify potentially interested parties.
    • EAMs (Earnings Adjustment Mechanisms) – basically performance based incentives. “Reward utilities for performance (desired outcomes) instead of capital investment (inputs). In competitive markets, companies are not rewarded for what they spend, but for the value they bring. EAMs are intended to mimic this in monopoly markets.” (The Energy Collective)
      • System efficiency: Each utility will file a proposal including peak reduction and load factor targets by December 1, 2016.
      • Energy efficiency: The Clean Energy Advisory Council will propose metrics and targets by October 1, 2016. Each utility will propose an EAM associated with these metrics and targets by December 1, 2016.
      • Customer engagement: Because customer engagement underlies many other earning opportunities, and because the principal tools are mandated, no general EAM is required.
      • Interconnection: A positive earning opportunity will be developed based on satisfaction surveys of DER providers regarding utilities’ progress in timely and cost-effective interconnection approvals. Each utility will propose a survey process and EAM by August 1, 2016.
      • Clean Energy Standard: Within 90 days of such time as the Commission may adopt a Clean Energy Standard, Staff will initiate a stakeholder process to develop EAMs.
  • Competitive Market-Based Earnings
    • Unregulated utility subsidiaries are authorized to engage in competitive value-added services. To engage in these activities the utilities must have in place standards of conduct to avoid affiliate abuse, to be monitored by the Commission.
  • Data Access
    • Certain basic levels of information will be free of charge (e.g. usage for each applicable rate element at the frequency most commonly measured by the customer’s meter), while utilities may charge a fee for provision of more refined data or analysis.
    • Tariffs for aggregated data will be filed pursuant to the CCA (Community Choice Aggregation) order. Tariffs for other charges described in this order may be filed at any time.
  • Clawback Reform
    • During a rate plan, utilities will be encouraged to displace capital expenditures with third party DER investment where cost-effective.
    • Each utility will propose this in the next rate filing following this order.
  • Standby Service
    • Utilities will establish campus tariffs and reliability credits, and will begin a process to modernize the calculation of standby tariffs to ensure that they do not create an unnecessary barrier to entry.
    • Credit: Each utility other than Con Edison will file tariff revisions to implement the offset tariff and reliability credit provisions as proposed by August 1, 2016.  For Con Edison, such revisions related to the reliability credit will be incorporated into its current rate filing and made effective January 1, 2017.
    • Allocation matrix review: Each utility will file a review and proposed revision by October 1, 2016.
  • Opt-in Rate Design
    • Each utility will include in its next rate filing a proposal to revise its voluntary time-of-use rates for mass market customers, including an analysis of how the proposed rate compares with rates in other jurisdictions as described above. Each filing will also include a promotion and education tool. For utilities with rate plans that expire after January 1, 2018, a filing will be made by June 1, 2017 rather than waiting for the next rate filing.
  • Large Customer Demand Charges
    • Rate cases will examine the existing demand charges applicable to commercial and industrial customers to determine if they can be made more time-sensitive.
    • These will be considered for each utility, either in a pending rate case, or pursuant to a filing by each utility by April 1, 2017.
  • Scorecard Metrics
    • A non-exclusive list of ten scorecard measures is adopted; Staff will initiate a collaborative process and will issue a progress report to the Commission by May 1, 2017.
  • Mass-Market Rate Design
    • Staff will report to the Commission regarding the scope, feasibility, and deliverables of a potential study of bill impacts, by October 1, 2017.

How Will This Affect You?

While specifics are still unknown, such major changes will undoubtedly affect how you operate your facilities and how you evaluate energy investments.  Changes to the standby service rate structure, large customer demand charges, and generally more granularity in rates (both time based and attribute based, e.g. capacity, energy, ancillaries) will affect projects that are already completed and operational, as well as projects that are currently or will be evaluated (projects such as thermal storage, cogen, battery storage, fuel cells, etc.).  It’s important to understand how these rate changes will affect payback, which is why it’s imperative to work with rate experts such as EnergyWatch who have experience modeling and evaluating rate structures, measuring and verifying multi-million dollar projects, and whose principals are intimately involved in the ratemaking process.   With a changing regulatory environment (which will be evolving over the years to come), now more than ever it’s important to have a reputable consultant in your corner to be an unbiased third party evaluator of projects, ensure accurate billing of new rate structures and optimal choice of rate structures, optimization of energy supply contracts considering demand management activities, and overall facility optimization given major changes to tariffs.

Contact Us Now

Andy Anderson, LEED AP O+M, CMVP
Managing Director

EnergyWatch Inc.
1261 Broadway, Suite 510
New York, NY 10001
P 212.616.5198
andy@energywatch-inc.com