If you don’t spend your copious free time paging through the orders and filings in the New York Reforming the Energy Vision (REV) proceeding, it’s possible you may have missed a nugget or two. To help you catch up on what’s arguably the most important regulatory proceeding in the country right now, we’ve pulled forward a few of the key details relating to energy efficiency in particular.
Pressed for time? Here’s the shorthand:
- The Public Service Commission (PSC) fully supports strategic electrification.
- Utilities can now rate-base software leases.
- Energy Efficiency Program targets are due by November 4.
- National Grid will host the first Distributed System Platform in Buffalo.
- Almost every major utility has proposed an “online marketplace” demonstration project in preparation for a statewide marketplace platform.
- Almost every major utility will install advanced meters and embrace Green Button “Connect My Data.”
- Residential time of use rates will remain opt-in pending further study and analysis.
- The major utilities will propose “smart home” rate demonstration projects by February 2017.
- Net-to-gross ratios aren’t as important as they used to be.
- DSIP Investments will not be subject to retrospective review (more or less).
Hungry for a few more details? Read on…
The PSC is fully supporting strategic electrification. Yes, it’s true — as the Commission notes in their Order Adopting a Ratemaking and Utility Revenue Model Policy Framework, “conversion of cars, trucks, and home and water heating systems to highly efficient electric end-uses will have at least two benefits,” including: (1) reduction of carbon emissions “where charging and pre-heating can occur during off-peak times;” and (2) improvement of system load factor by “spreading the cost of the electric system across a greater number of sales units, with resulting savings for customers both in the form of immediate savings and also by reducing long term business risks for utilities.” (p. 90)
Implementing this guidance, both the New York State Energy Research and Development Authority (NYSERDA) and the investor-owned utilities can exercise some degree of fuel neutrality in their programs. The Commission directed that investor owned utilities “may deliver their energy efficiency programs in a fuel neutral fashion as long as an increased benefit can be demonstrated and it does not jeopardize their ability to meet their individual fuel-specific energy efficiency targets.” (p. 47) As for NYSERDA, the Commission directed that they may administer their electric surcharge funded programs “in a fuel-neutral manner as long as an increased benefit can be demonstrated from displacing the alternate fuel as opposed to electricity. (p. 65)
Furthermore, according to the Commission’s Order Adopting Distributed System Implementation Plan (DSIP) Guidance, the joint utilities’ soon-to-be-filed Supplemental Distributed System Implementation plan will also “presents the opportunity for the utilities to collaborate in the development of initiatives that will have the effect of reducing carbon emissions, including de-carbonizing the transportation system.” (p. 25) ConEdison has already demonstrated an interest in this opportunity, announcing they’ll be issuing an RFI for electrification of the transportation sector during the third quarter of 2016. (p. 242). NYSERDA has also expressed an interest in ductless mini-split air source heat pumps via the market characterization and design chapter of their investment plan. (p. 16)
Utilities can now rate-base software leases. Hidden deep within Public Service Commission’s May 2016 Order Adopting a Ratemaking and Utility Revenue Model Policy Framework (“Track II Order”) is a single paragraph directive allowing utilities to earn a rate of return on the unamortized balance of a pre-paid software lease. (p. 104). This means that a utility can earn the same rate of return on contracts leasing software services from third parties as they would on traditional distribution system investments.
This is a big deal for energy efficiency because the move will likely encourage utilities to contract with companies who offer software as a service (SAAS) analytic tools. For more information on these types of companies, see NEEP’s recent report on “The Changing EM&V Paradigm.” Furthermore, allowing utilities to earn a rate of return on software leases will also encourage the embrace of grid architecture companies that provide Advanced Distribution Management Systems (ADMS). These systems will be critical as distribution utilities begin to serve as platform providers, requiring a whole new level of visibility into distributed energy resource (DER) performance and control of DER dispatch.
Energy Efficiency Program targets are due by November 4, 2016. The Track II Order outlined how energy efficiency targets may become an earnings adjustment mechanism as the distribution utilities move incrementally toward performance-based ratemaking (for more info, see NEEP’s Brief of the Order here). More specifically, it directs the Clean Energy Advisory Council (CEAC) to file metrics and targets for energy efficiency by October 1, 2016, with the utilities proposing an EAM based upon with those targets by December 1, 2016 (UPDATE: CEAC targets are now due November 4). (p. 157) The targets will include those prescribed by the ETIPS Order (Appendix B), but will also be supplemented by: (1) Locationally targeted efficiency measures outlined in the DSIPs; (2) Efficiency measures bundles by DER suppliers with other measures to reduce customer bills; and (3) Market transformation efforts in cooperation with NYSERDA and local governments. (p. 81). The Energy Efficiency Procurement and Markets Working Group of the CEAC is responsible for developing these targets, for submission to the CEAC by the end of October.
National Grid will host the first distributed system platform in Buffalo. If you have been following REV, you are probably familiar with the term Distributed System Platform (DSP) Provider, which PSC Chair Zibelman describes as the ‘air traffic controller’ of the distribution grid and envisions as a sources of platform service revenues for utilities who will operate it. As defined in the REV track One Order, a DSP is “an intelligent network platform that will provide safe, reliable, and efficient electric services by integrating diverse resources to meet customers’ and society’s evolving needs.” (pg. 2) The first real-world demonstration of this Distributed System Platform was proposed by National Grid in in July 2015, and was only recently approved after an addendum to their proposal a year later. It’s an interesting project to say the least.
The project will be located in the Buffalo Niagara Medical Campus and will coordinate the economic dispatch of between 20 and 34 MW of distributed energy resources through network connected Points of Control (POCs). National Grid is partnering with Opus One – a software company contributing $2 million of in-kind services — for deployment of an advanced distribution management system which aims to enable this real-time dispatch. The DERs will include diesel generators, natural gas turbines, photovoltaics, battery storage, and building energy management systems. Many of these DERs will serve the dual purpose of providing the DER site host with resiliency benefits and supplemental revenue streams at times when dispatch is economically advantageous.
A major goal of the pilot is to help determine the specific inputs for each DER’s economic dispatch value, which will be a function of the Locational Marginal Price (LMP) provided by NY-ISO via day ahead markets, plus the aggregate of various distribution system benefits (D), plus the value of externalities (E). This methodology (LMP+D+E) aligns directly with a recent agreement between the state’s major utilities and several major DER providers filed in the PSC’s proceeding on the Value of Distributed Energy Resources. At this point in time, the pilot will not place a specific value on externalities (E), however, it will be utilized to develop a more accurate valuation of various distribution systems benefits (D) provided by each DER. These benefits include but are not limited to “energy supply, VAR support, voltage management, peak load modification, and dynamic load management.” (p. 6)
Almost every utility is piloting an “online marketplace” demonstration project in preparation for a statewide platform. As far as energy efficiency is concerned, a key goal of the REV proceeding has always been to animate and transform markets. (p. 80) Utilities have embraced this goal through demonstration project proposals which aim to promote various goods and services relating to energy efficiency through an online marketplace. While the details vary widely, most of the state’s investor owned utilities will pilot their own marketplace: Central Hudson’s CenHub marketplace, Orange and Rockland’s Residential Customer Marketplace, ConEdison’s CONnectED Homes Platform/Building Efficiency Marketplace, and Iberdrola’s Energy Marketplace. The one exceptions to this observation is National Grid, which has not yet proposed a marketplace. It remains to be seen how far the proposed online marketplaces might lower customer acquisition costs, and if they will animate markets for energy efficiency investments in the manner envisioned by the Commission.
Almost every investor owned utility will install advanced meters and embrace Green Button “Connect My Data.” Con Edison was the first distribution utility to have their advanced metering infrastructure (AMI) business plan approved, which included plans for rollout of 4.7 million electric and gas modules. In a statement celebrating the approval, PSC Chair Zibelman commented, “As the first-of-its-kind system in New York State, this is a milestone in Reforming the Energy Vision, Governor Cuomo’s strategy to bring cleaner, more-resilient and affordable energy to all New Yorkers.” Subsequently, Iberdrola (p. 114), National Grid (p. 238), and Orange and Rockland (p. 261) all filed Distributed System Implementation Plans (DSIPs) that include system-wide installation of AMI. Standing apart from the crowd, Central Hudson proposed only an opt-in advanced meter rollout, instead discussing in their DSIP filing how REV markets could function without advanced metering (p. 131). Most of these proposals include an embrace of Green Button “Connect My Data” as a format for exchanging utility data with customers and vendors, with the exception of Central Hudson who will continue their use of Green Button “Download My Data.”
Residential time of use rates will remain opt-in pending further study and analysis. During the early stages of the REV proceeding, there was a great deal of discussion regarding whether opt-out time of use rates might send better price signals to consumers and therefore help to control costs. However, the Commission stopped short of mandating opt-out residential time of use rates, instead directing Staff to work with stakeholders and report to the Commission by October 2017 on “a range of opt-out variable rate scenarios including time-of-use rates, demand charges, and peak-coincident demand charges.” (p. 30)
The major utilities will propose “smart home” rate pilots. In order to advance the adoption of home energy management technologies, the commission directed each utility to work with NYSERDA in developing a smart home rate demonstration project by February 2017. (p. 159) For insights into what this smart home rate might look like, NYSERDA published a whitepaper on Full Value Tariff Design and Retail Rate Choices during April 2016 that may be helpful (p. 137). It describes a smart home rate that could incorporate electric vehicle charging, air source heat pumps, heat pump water heaters, and battery storage (et al.).
Net-to-gross ratios aren’t as important as they used to be. NYSERDA’s Clean Energy Fund Information Supplement outlined a shift away from net-to-gross field verification and attribution, instead addressing market impacts via market progress studies and test/measure/adjust strategies. (p. 178) NYSERDA expects this to be a less resource intensive method than past program evaluations. The Utilities’ Efficiency Transition Implementation Plans (ETIPs) do contain some planning around net-to-gross attributions, but in a less resource intensive manner than in the past.
DSIP Investments will not be subject to retrospective review. If you have made it this far in the article, you are clearly the type of serious policy wonk that might be interested in this last point, as it delves into one of the most fundamental topics at the heart of cost-of-service ratemaking: risk allocation. In their whitepaper on utility business models, Staff proposed that investments needed to build DSP functionalities not be subject to retrospective review (p. 68).The proposal drew criticism from a number of different stakeholders due to its seemingly blanket pre-approval of investments and the likelihood of such approval to shift risk from utilities to consumers.
Yet, in passage that energy law students for decades into the future may likely study, (p. 105-6) the PSC quite elegantly outlines why it might be reasonable not to subject DSP investments to retrospective review, noting that:
“Ratemaking always involves a balance in the allocation of risk. Allocation of risk to utilities does not always benefit ratepayers; the level of utilities’ risk directly affects financing costs, which ultimately are borne by ratepayers. Where risk can be reduced without any substantial negative impact on ratepayers, it should generally be done. In this instance, the Commission has ordered utilities to undertake REV initiatives, some of which involve new directions in system planning and operation. The Commission has also encouraged utilities to be innovative and responsive to the needs of markets in order best to serve customers. Explicit guidance from the Commission will reduce the perception of financial risk and thereby affect the cost of not only DSP investments but all utility investments.”
They continue, “Approval of investment plans in this context is intended to reduce overall risk, not to shift risk. As one expert has stated, ‘assuming a front-end review that is no less rigorous than a back-end review, there is no reason to assume that business risk shifts from shareholders to ratepayers.’ DSIP review will not be equivalent to a retrospective prudence review, but it will not preclude a back-end prudence review if one is warranted.”
As such, it appears that utility investments proposed in their DSIPs — once approved — will have some presumption of reasonableness regardless of outcomes, though they won’t be fully immune from a prudence review, should one be necessary.