Re: Case 14-M-0101 Proceeding on the Motion of the Commission in Regard to Reforming the Energy Vision Track 2 Questions and Responses

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1 VIA ELECTRONIC FILING 18 July 2014 Hon. Kathleen H. Burgess Secretary to the Commission New York State Public Service Commission Empire State Plaza Agency Building 3 Albany, New York Re: Case 14-M-0101 Proceeding on the Motion of the Commission in Regard to Reforming the Energy Vision Track 2 Questions and Responses Dear Secretary Burgess: On behalf of the New York Battery and Energy Storage Technology Consortium ( NY-BEST ) please find enclosed for filing with the New York State Public Service Commission, our responses to the questions posed by Administrative Law Judges Eleanor Stein in Case 14-M Ruling Issuing Track 2 Questions and Establishing a Response Schedule, commonly referred to as commonly referred to as Track 2 Questions. NY-BEST and our 135 member organizations from across New York State and beyond view this matter as critical to making energy efficiency and distributed energy resources, such as energy storage, a primary tool in the planning and operation of an interconnected modernized power grid. If you have any questions or require additional information regarding these comments, please contact me at (518) Respectfully, William P. Acker Executive Director Enclosure

2 NY-BEST RESPONSES TO QUESTIONS RAISED IN CASE 14-M-0101 (PROCEEDING ON THE MOTION OF THE COMMISSION IN REGARD TO REFORMING THE ENERGY VISION) RULING ISSUING TRACK 2 QUESTIONS AND ESTABLISHING A RESPONSE SCHEDULE INTRODUCTION The New York Battery and Energy Storage Technology Consortium ( NY-BEST ) is a notfor-profit industry trade association that serves as the voice of the industry for over 135 member organizations on matters related to advanced batteries and energy storage technologies. Our membership covers the full span of activities related to research, development, production and deployment of energy storage devices, and currently includes technology developers ranging in size from small start-up companies to global leaders such as General Electric, leading research institutions and universities, Brookhaven National Lab and numerous companies involved in the electric and transportation sectors. Our mission is to catalyze and grow the energy storage industry and establish New York State as a global leader in energy storage. We do this by: (1) serving as a center for communication, education and interaction amongst stakeholders; (2) leveraging New York s world-class intellectual and manufacturing capabilities and market leadership; (3) supporting and accelerating the commercialization process from research and development to products and widespread deployment; and (4) advocating for policies that promote the energy storage industry. As noted in the Commission Order, the goals of REV include improvements in system efficiency, greater customer choice, greater penetration of clean generation and energy efficiency technologies, and reduction in air pollution and greenhouse gas emissions. An important component of REV is the Distribution System Platform Provider (DSPP). The role of the DSPPs will be to create markets, tariffs, and operational systems to enable Distributed Energy Resource (DER) providers to monetize products and services that will provide value to the utility system and thus to all customers. Resources provided could include energy efficiency, predictive demand management, demand response, distributed generation, energy storage, building management systems, microgrids, and more. The end vision of REV is a fully animated market for DERs which allows the DSPPs to optimize operations and planning of the electric distribution system. However, this optimization is contingent on the availability of adequate DERs and the proper valuation of

3 such resources. To achieve the minimum level of DER penetration to create a functional DER market, barriers to entry must be eliminated and proper regulatory incentives must be established. The following are answers and observations on the questions provided for Track II of the REV proceeding. I. Outcomes-based Ratemaking Questions 1 and 2 1. Incentives and disincentives in current ratemaking and 2. New Outcomes/metrics In today s world of severe weather events, aging infrastructure, increasing levels of distributed and variable renewable generation and rising concerns about cyber and physical attacks, traditional cost-of-service regulation is no longer adequate and offers a utility little incentive to improve operational efficiency or service quality beyond the minimum levels set by regulators. The traditional utility volumetric rate structure is increasingly ineffective as a means to compensate the utility since it is based on a variable metric. The investments that utilities make into the local infrastructure are fixed-cost investments and thus should be recovered using a capacity-type charge. Rocky Mountain Institute ( RMI ) discusses utility rate structures in the context of the rapid growth of DERs and believes that existing rates and incentives fail to provide accurate economic signals to align distributed generation investment with system costs and benefits over the long term. It further argues that they need to more accurately reflect the costs and values associated with each particular resource, which in its estimation will require some degree of price unbundling (i.e., charging separately for different cost components). The goal of any new pricing structure should be to ensure that customers pay fairly for what they use and receive fair payment for what they provide. In addition, given the right price signals, distributed generators can adapt over the long term to provide new sources of value to the utility system, which will still have a critical and valuable role as enablers and integrators in the deployment, operation and maintenance of distributed resources. To fully adapt to this new role, utilities must be able to develop new ways of pricing the network services they provide and of promoting value creation through distributed-

4 resources development. RMI offers two approaches for utilities to move toward for achieving this: 1. An incentive regulation approach that would allow the utility a more expansive role in managing and, potentially, investing in distributed resources as a tool for reducing costs and 2. A network utility approach under which the utility would provide highly differentiated price signals to incent customers to provide the highest value energy supply, load management, or ancillary services to the utility system. Note that it is important that approach #1 is not at the exclusion of third party providers. The four overarching steps to effective utility price unbundling are as follows: Separate what is used from what is provided; Within those used vs. provided buckets, disaggregate cost/value components; Determine the appropriate recovery mechanism for disaggregated components; and If appropriate, add an incentive to recognize additional value not captured in utility pricing. RMI recommends that regulators and policymakers redesign the structure and form of utilities to provide a platform for the economic and operational integration of distributed resources. The platform should be a system that supports: Value-based interactions among multiple parties and a set of rules including protocols, rights and pricing terms that standardizes and facilitates transactions amongst multiple parties; Fosters network efficiency, resilience, and reliability; Create a level playing field between all resources; foster innovation in energy services delivery; Provides transparent incentives for energy resources; minimize complexity;

5 Enable a workable transition from traditional business models to new structures; and Supports the harmonization of business models of regulated and non-regulated service providers. Finally, NY-BEST recommends the Commission consider the approach described above because it addresses utility issues of rate recovery for new investments, rate structures, avoided costs, etc. head-on and provides some recommendations of how utilities should participate in the distributed energy environment. RMI makes specific proposals on how to reduce disincentives and reward performance with respect to distributed resource deployment, including new pricing models and methods of cost allocation to realign resource investments with system costs and benefits over short-term (operational) and long-term (planning) horizons. Examples include: Unbundled pricing for reliability, standby, and power quality services; Temporally or locationally differentiated prices for energy or distribution services; price structures that reflect how costs are incurred (e.g., demand-based, fixed, energy-based, etc.); and Incentive payments for dispatchable demand response or ancillary services to the grid. Thus, in our estimation, existing rates and policies generally obscure the costs and benefits of various resources to the grid, limit the ability to add better integration technologies that could add value and restrict signals to customers that would enable them to make mutually beneficial decisions. In the future, prices and/or incentives of all forms should reflect the actual costs and benefits and values of resources in the electricity system and should fairly compensate them in terms of their contributions. Ultimately, actual products and services should properly capture and promote value to the system and be implemented costeffectively, with the ability to accommodate further market changes. As the grid evolves, the key drivers will continue to alter revenue streams, sources of value and operational requirements for both utilities and DERs alike. There a range of different business models that exist today and ones that are emerging and likely to grow rapidly in

6 the future. The respective roles of utilities, third-party aggregators, competitive retail suppliers and the like are in transition, and we need to discuss openly and forthrightly what is the best course of action going forward to support a competitive environment but allows for the development of a dynamic, flexible 21 st century power system. In assessing various business models, we need to examine how each approach is able to optimize resources economically and flexibly for the grid across the range of potential ownership models. A key to this is what structures enable the maximization of value creation and financeability. There are several critical pieces of infrastructure which need to be in place to successfully implement new performance-based mechanisms for rewarding, as well as penalizing, utilities (two faces of the same coin): 1) utility integrated resource planning and 2) automated metering infrastructure. Integrated Resource Planning An integrated resource plan ( IRP ) is a utility plan for meeting forecasting peak and energy demand, plus some established reserve margin, through a combination of supplyside and demand-side resources over a specified future period. (Best Practices in Electric Utility Integrated Resource Planning, Synapse Energy Economics, Inc., June 2013). Steps taken in the creation of an IRP include: Forecasting future loads; Identifying potential resource options to meet those future loads; Determining the optimal mix of resources based on the goal of minimizing future electric system costs; Receiving and responding to public participation where applicable; and Creating and implementing the resource plan. NY-BEST believes that in this new world of distributed energy resources and a grid of everincreasing complexity but an array of available flexible resources to enable utilities and grid operators to balance the grid and provide high levels of reliability and power quality, integrated resource planning will be a condition precedent to success. In the long-run markets will determine the optimal resource mix if benefits are fully monetized. However, to get to that point, it is important to use planning tools to transparently work toward the desired REV end state. In addition, it provides a framework for developing and

7 implementing a new set of rate-making methodologies based on a clear understanding of a utility s operational and strategic business model based on performance, which should include metrics to measure the integration of higher levels of DERs, including energy storage. It is critical that the planning process takes into the account the pace of change technology and does not inhibit the adoption of new technology. In practicing risk-aware regulation, there are seven essential strategies for state regulators to adopt, which in turn, informs the adoption of new rate-setting methodologies (Practicing Risk-Aware Electricity Regulation, RAP, April 2012): Diversifying utility supply portfolios, with an emphasis on low-carbon sources; Utilizing robust planning process for all utility investment (e.g., generation, transmission, distribution and distributed energy resources); Employing transparent and standardized ratemaking practices that focus on riskreduction objectives; Using financial and physical hedges, including long-term contracts; Holding utilities accountable for their obligations and commitments; Operative in active, legislative mode, continually seeking out and addressing risk as it emerges and changes; Reforming and re-investing ratemaking policies as appropriate. NY-BEST believes that there are key underlying conditions which need to be addressed and implemented before regulators and utilities are able to address issues associated with specific rates, incentives and penalties. The most critical ones in our estimation are the following: Mandated integrated resource planning The adoption of standardized and transparent cost/benefit and valuation methodologies for all energy resources across the grid, including distributed energy resources, which form the coherent and justifiable basis for the development of new rate-setting and other compensation mechanisms such as special tariffs, bilaterally negotiated contracts, competitive bids and new grid services to be developed in the future

8 A recent SmartGridNews Article summarizes the importance of these underlying approaches succinctly: In our experience, by optimizing both supply side value buckets (e.g., energy, capacity, ancillary services) simultaneously with grid-based value buckets (e.g., improved reliability, voltage reduction, line loss mitigation, deferral of distribution assets, and dynamic dispatching of DG against intermittent wind/sun), utility pilot examples have already shown two to fivefold increases in cost savings from optimally tapping into the right mix of resources at a more granular level. (Osterhus, 2014) Thus, Osterhus argues that there is an optimal mix of demand-side and supply-side resources for each circuit and a significant opportunity to yield a more valuable bang for the buck by intelligently targeting the right mix of resources to each circuit. There is an emerging regulatory model called results-based or performance-based regulation. Performance-based regulation ( PBR ) is designed to support investments that delivery long-term value to customers; reward utilities for exceptional performance; and remain affordable by encouraging operational efficiencies and sharing the cost savings with customers. Goals include minimizing costs, maximizing reliability, maximizing environmental performance and enhancing the value of customer service. In general, PBR adds performance outputs by function to basic cost-of-service regulatory design, values risk management and focuses on the longer term. Ideally, PBR presents utilities with a coherent set of positive and negative incentives, replacing the disjointed and often conflicting set of incentives that has grown up in many regulatory jurisdictions.

9 The following is an illustration of performance-based regulation. In general, instead of being tied to annual rate cases, performance-based approaches are multi-year to allow a period of time to accommodate risk now carried by ratepayers in return for new opportunities. States could pursue an incremental approach that builds performance-based ratemaking earnings mechanisms over time. Metrics could then be broadened either through increasing performance incentives or increasing utilities returns on existing performance incentives. We believe that by allowing regulators and utilities to pay for value instead of capital investment, well-designed performance-based ratemaking will drive important societal outcomes as well as create new business opportunities for innovative utilities and third-party players while retaining low costs, reliability, environmental performance and customer service.

10 The following is an approach to how a performance-based rate-setting methodology can look: A discussion of performance-based cost recovery naturally leads to a conversation about how performance should be measured and what measures should be used. The variation by state is quite significant. For example, Maryland developed 90 implementation metrics and 36 on-going performance metrics to evaluate IOU smart-grid deployment status and value creation. Regulators in other states need to develop their own performance measures based on their specific goals and objectives, e.g., for distributed energy resource deployment, meeting RPS standards, carbon emissions reductions, etc. Targeted utility activities which can be linked to performance include the following metrics: Reliability Quality of service Customer satisfaction Safety Implementation metrics (e.g., meeting schedules, deployment costs relative to capital budgets or operating and/or long-term plans)

11 Resource utilization Operational cost savings On-going performance metrics o Social goals o Meeting energy efficiency goals o Customer generation o DER penetration levels o DR/TOU participation o Resource diversity o Competitive activity o Environmental performance o Cybersecurity Innovation Flexibility incentives in short term and over long-term With improved monitoring and metering technologies, there will be more opportunities to measure performance, which can then be turned into a PBR metric (data to customers; responsive, integrated customers; targeted customers for specific offers, etc.) The Regulatory Assistance Project observes that a state would be serious about PBR if a significant share of utility earnings were based on performance. RAP defines significant as enough to neutralize the urge to invest in assets and put performance on the same tier of priority as hard assets. An example of such as approach is the UK s RIIO model (or Revenue set to deliver strong incentives, innovation and output). Its major components include: Revenues set based on the regulator s review of a forward-looking utility business plan; A multi-year revenue cap that provides an incentive for cost reductions; An earnings-sharing mechanisms that enables customers to benefit from utility cost savings; Clearly defined performance metrics and incentives for delivering value to customers; and Funding set aside for innovative projects. The following are NY-BEST s recommendations for the Commission:

12 New York State needs to mandate the development and implementation of Utility Integrated Resource Planning. This planning should be different from the current state, taking into account all energy resources integrates them into capital expenditure plans based on true cost-benefit valuations of all resources. On this basis, metrics should be developed that ensure that assets with less than 10% utilization rates are not built (e.g., building peaker plants). All DERs need to be included in utility resource planning processes, regional reliability plans and transmission planning. Each DER should be defined as an eligible class for RPS purposes. Least-cost planning and ratemaking for transmission and distribution investments in New York State and in the NYISO regional markets will be most effective if utilities demonstrate rigorous consideration of all alternative energy-resource approaches, using the RMI model or modified VOST approach as a prototype. Long-term planning by utilities and the NYISO need to be closely coordinated going forward to ensure that energy-resource assets are maximized and costs and benefits allocated appropriately. Each DER should receive a fair, transparent and standardized cost-benefit analysis, including time- and location-sensitive factors, in system planning. Utility network planning models and analyses can influence valuation factors and should be made available to DER developers for real-options valuation analysis. When DERs are developed in a utility s service territory, utility s costs associated with integrating them should be considered in the context of overall grid modernization and resource planning by that utility rather than as isolated end points connected to the existing grid. Investments and policies regarding interconnection and control systems should be planned as part of an integrated, modern, 21 st century utility operating model, which includes both utilities and the NYISO. As NYISO and transmission owners consider investment needs for reliability and market enhancements, non-transmission alternatives ( NTAs ) can offer solutions that cost less, intrude less on landowners and the environment, and raise fewer siting conflicts. DERs, most particularly energy storage, can serve as NTAs if they are designed and planned to address transmission system and market constraints. FERC Order 1000 established NTAs as a category of assets that merits consideration in

13 regional planning. To date, NYISO has not provided guidance regarding processes for proposing, evaluating or developing regional system requirements. 4. Accommodating Bridge Investments Clearly there has to be a transition period to the ultimate goal of a utility business model dominated by earnings driven by performance metrics. Transformations do not occur over night, and utilities, regulators, rate payers and other stakeholders will need time to adjust to new market realities. There are numerous examples around the country of regions that have successfully tested and adopted new rate-setting approaches, and we believe that, once standardized and transparent cost-benefit and valuation methodologies are developed and used for valuing all energy resources, compensation mechanisms will be able to be tailored to the particular circumstances of a utility. Some states such as Vermont and Minnesota have been successful at adopting controversial energy policies with significant stakeholder approval. a) Yes. Incentivizing utilities to make bridge investments for projects that require more than one year to develop would stimulate a much higher level of investment in DERs, especially for larger projects. However, the PSC should go well beyond incentivizing utilities to make bridge investments (and full project investments). The PSC should also send strong signals to the private capital market (i.e., non-utility investors) that their investments can also qualify for investment recovery/monetization mechanisms for qualified projects, including milestonebased incentives for multi-year projects. b) An incentive system that allows for incentives to be monetized upon the achievement of milestones (rather than all at once upon project completion) will stimulate much more investment in DERs, particularly large, multi-year projects. This should apply to utility investments and private investments alike. c) Bridge investments that do not produce complete results during the incentive period should have their recovery/monetization level reduced effectively, a penalty for nonperformance. 6. Benchmarking

14 NY-BEST envisions over the longer term the electric grid to be a bidirectional, transactive, and situationally-aware system that supports: Transactive nodes across the grid, with bidirectional interconnections and prosumers (producer-consumers) buying and selling energy products and services; The elimination of barriers to entry, allowing new technologies to participate in the electric grid and ensuring that the batteries and energy storage are not excluded; The valuation of products and services based on transparent and standardized methodologies, procedures and processes through the unbundling of the costs and benefits of energy resources in providing products and services to the grid, ensuring that each DER s value streams are appropriately and fairly captured; and The elimination of competitive barriers so that each resource can participate on a level playing field. NY-BEST believe that the REV vision requires a framework and methodology for developing a long-term implementation plan that is built on a robust, secure, real-time transactive-energy platform, which is able to create value streams systematically and transparently for all distributed energy resources based on detailed costs/benefits analyses that level the playing field. The methodology should be based on sound financial and technical planning principles; is able to be phased in over time; and provides a means for distributed energy resources ( DERs ) to participate in all products and services based on their capabilities, performance and other attributes, not on artificially created support mechanisms or penalties, which advantage or disadvantage certain technologies over others. A key concept emerging around DERs is demand-side flexibility, which is defined as the capacity to change electricity usage by end-use customers (residential, commercial, industrial, institutional, etc.) from their normal or current consumption patterns in response to market signals such as time-variable electricity prices, wholesale market prices or incentive payments, or in response to acceptance of a consumer s bid, alone or through aggregation, to sell demand reduction/increase at a price in organized electricity markets. Values in transactive-energy environments can be represented in traditional currency form, but an important distinction is that economic signals do not necessarily have to be in

15 currency to be economic or value-based. The key to a transactive energy model is that it enables value unlocking in general, regardless of the business model or market structure. There is a clear need to align value streams for all parties with incentives for participation in an actively managed system. In turn, this requires agreeing on key characteristics of value as a set of economic and control mechanisms that allows the dynamic balance of supply and demand across the entire electrical infrastructure using value as a key operational parameter. (GWAC) In its simplest terms, value equates to a price whether it is the market price of generating, transporting and consuming power across the system or the price of maintaining, protecting and optimizing the power lines and transformers, energy storage and demand response assets and other equipment that aids the task. Value realization can take place through a variety of market-based approaches including: Organized markets Procurements Competitive RFPs Tariffs (FITs, specialized tariffs for solar, energy storage, microgrids, etc.) Over-the-counter bilateral contracts A customer s or other entity s self-optimization process. NY-BEST supports the development and implementation of a variety of approaches as long as they are based on standardized and transparent valuation methodologies and documentation adhered to by utilities and which inform the development and implementation of all compensation mechanisms and retail rates. Thus, NY-BEST urges the development and adoption of standardized, transparent, replicable and scalable processes, procedures, methodologies in the valuing of costs and benefits of DERs to enable the development of compensation mechanisms that are consistently applied and allow any resource to participate at the level appropriate to its abilities. We believe that, by adopting standardized, transparent processes, procedures and documentation, all energy resources will benefit and all stakeholders will be able to assess the validity, equity, fairness and applicability of the assumptions underlying the models to their particular issues and requirements. We also adhere to the principle of technology agnosticism and that with the development of open, standardized costs/benefits analyses underpinning value streams for products and services created as part of a transactive energy framework, all stakeholders will benefit.

16 7. Utility as DSPP and As DER owner: neutralizing incentives a) Utilities and non-utility entities (whether utility affiliates or unaffiliated third-parties) should be equally incentivized to invest in power storage assets. Utilities (which already serve the ratepayers directly) are often in the best position to harvest the many forms of economic value that power storage assets deliver not just for themselves but also on behalf of their ratepayer customers. However, under today s regulatory system, utilities are often prevented from owning/investing in power storage assets, because storage assets can be interpreted as providing power generation, which deters utilities from pursuing storage investments. Removing this current roadblock would be a substantial driver of investment in storage assets. On the other hand, there are currently very few monetization mechanisms through which merchant (non-utility) storage asset owners can achieve a return on their investment, despite the substantial value that such storage (if deployed) would deliver to ratepayers. New policies should be adopted such that merchant power storage owners/developers have clear and reliable incentives that will stimulate them to invest in such assets. One way to achieve this is by providing a $/kw or $/kwh financial incentives to merchant owners (or utility owners), which could be based on prior NYSERDA studies which placed a $ value on each of some 20 distinct economic values that power storage can deliver. The merchant storage owner s total $/kw or $/kwh payments would be based on how many of these 20 value categories are met with appropriate weighting/value for each. b) For reasons cited in the response above, utilities should be allowed to monetize their investments in power storage through a rate base. However, this should not be the only means through which a storage investor (whether a utility or a non-utility) can achieve a return on their investment, particularly because the rate case process can be slow, and will typically delay needed investments by 1-2 years. Alternative incentives and monetization mechanisms (as described above) should also be made available to merchant storage owners. c) Utilities should be allowed to recover their upfront investments in legitimate DSPP assets through a rate base or other recovery mechanism. The PSC (and NYS government at large) should signal strongly to utilities that they expect well-designed storage projects to

17 be part of utilities DSPP responsibilities, because of the many forms of value storage assets can deliver to ratepayers. Allowing recovery of upfront costs is one method of doing that. 8. Removing Bias toward increasing capital expenditures a) Incentives to invest in DER assets (or DSPP infrastructure) should be based on the net economic value that such assets deliver to the system/ratepayers (e.g., $/kw or $/kwh of savings from power storage assets), leaving it to the project developer/owner to determine the optimal mix of capital expenditure and operating expenses. b) The Commission should address the bias toward deploying utility capital in optimizing the T&D system. Clearly a reward framework that drives utilities toward capital intensive solutions, for example expanding a substation rather than utilizing third-party energy storage, does not align motivating influences with desired outcomes. Capital savings should be treated the same as operating expense savings. Favoring one category of expenses over another can create perverse incentives and distort market forces i.e., it may prevent the most valuable and cost-effective DERs (or DSPP infrastructure) from being deployed. The benefits delivered to the ratepayers should trump the particular methods by which they are achieved. c) Utilities and non-utility entities should be incentivized to invest in assets based on the economic value that such assets deliver to the system/ratepayers, instead of tying incentives to the amount of infrastructure investment. This would incentivize smarter investments that yield the greatest (and most cost-effective) benefits to the ratepayers. Therefore, the current ratemaking paradigm should be fundamentally reformed. II. Long Term Rate Plans 1. Pros and Cons of Long-term rate plans NY-BEST acknowledges that long term rate plans may allow for longer periods over which capital investments may be amortized and as such we believe they may be helpful to achieving the goals of REV. However, we believe it is important to note that technology is evolving at a rapid rate and this needs to be

18 factored into discussions and considerations of long term rate plans in such a way that innovation continues to be incentivized. III. Rate Design 2. Tarriffs for DSPP products a. How should non-monetized benefits and costs be accounted for in rate, if at all? b. Which monetized benefits should be accounted for? As background, NY-BEST would like to first highlight for the Commission the full range of benefits energy storage can provide. Energy storage technologies and applications enable all generation sources on the grid to operate more efficiently, flexibly, and resiliently; increase system efficiency and utilization; facilitate integration of renewable energy resources on the grid; reduce greenhouse gas emissions, other air pollutants and limit environmental impacts; and lower costs for consumers. Energy storage resources are currently operating on the nation s grid and are used in a variety of applications to balance generation and load in an efficient and costeffective manner. Energy storage technologies are ideally suited to assist with grid resiliency and increased reliability. Storage provides the flexibility to integrate renewables into the electric grid without consuming additional fossil fuels needed to meet the ramping requirements of renewable energy generation resources. Analytical Framework to Assessing Benefits and Costs As part of the move toward standardized, transparent processes, procedures and methodologies for valuing distributed energy resources, NY-BEST believes there is a clear, identified need to build a framework that allows energy resources to be compared on an equal footing and to have each distributed energy resource valued based on its actual costs and benefits to the grid. In this way, new pricing and compensation mechanisms can be developed that allow for economic value creation

19 proportional to a particular DER s contributions to the grid. When examining the benefits and cost of DER devices such as storage, NY-BEST recommends that the Commission consider two primary components. First, devices need to be evaluated at the stand-alone, project level, ensuring that all benefits that are potentially offered by the devices are allowed to be accrued. Secondly, the analysis should assess at the system level, overall benefits that can be provided when the DER devices are considered in terms of aggregated assets that will contribute to overall system operation and contributions to the State goals of increased renewable production and cleaner energy. In the early stages of the REV process, NY-BEST asserts that it is important to model the benefits of the system as a stand-alone device, ensuring that it has access to benefits on the customer side, distribution level, and market opportunities. In the later stages of the REV process, systems such as storage need to be considered for the system level benefits the devices can provide as aggregated, distributed bulk systems. The modeling methodologies in each case differ, but do require a level of sophistication and complexity to accurately assess. When assessing the early stage accounting of benefits of storage, NY-BEST believes it is important to ensure that all capabilities of application provided are accounted for and accrued to the system. Using storage as an example, when considered as a stand-alone unit, consideration will need to be made for: a. Standard, project level benefits of the device to include reliability, peak shaving capabilities, load shifting capabilities; b. Benefits to the feeder itself, to include benefits such as deferral, feeder level protection against intermittency of variable renewable devices; c. Benefits from participating in market opportunities, such as customer side access to market products such as regulation, spinning reserve, or potential new products offered to support grid operation; and d. Societal benefits such as emission reduction, though better suited to be examined in the system analysis due to the cause-effect issues Methodology

20 When examining DER devices at this level, simulation approaches need to be considered. DER devices will be performing multiple roles and tapping into multiple benefit streams. The devices themselves will be governed by controls and optimization routines that will make simple accounting of how units operate difficult. The best means to assess such scenarios is through actual simulation of operation of the devices. Examples of this have been seen in the California AB 2514 evaluation process where tools and methodologies were incorporated that simulated the grids and how the devices operate in performing specific roles or use cases. When assessing later stage applications, the benefits need to focus more on the grid operation where improvements in efficiency, cost savings from visualization of the DER devices on the system, and aggregated bulk assets being incorporated into system planning activities. The methodologies have again been demonstrated in prior studies, but analysis will need to incorporate: a. Better understanding of the value and cost of self-optimizing behavior b. Modeling and analysis of the likely behavior of self-optimizing customers enabled by technologies such as storage and weighed against the economics of New York tariffs and market signals c. Understanding of the likely load and profile changes that will occur due to adoption of the DER devices For the long term incorporation of the benefits, a more holistic understanding of the likely scenarios will need to be considered but the benefits such as improvement in efficiencies, cost reductions, potential improvements in emissions will need to be assessed, extracted, and accrued to owners of DER systems.

21 A summary of the potential benefits that need to be accounted for in assessing DER systems in shown in the chart below: End Use Distribution/Trans Wholesale/Markets System Local Reliability Reactive supply and Voltage control Regulation (ISO product) Criteria air pollutants (SO2, NOx, PM) Load management T&D capacity upgrade deferral Flexible resource adequacy Carbon Emissions Energy time shift T&D reliability upgrade deferral System resource adequacy Security & Resiliency Local Resiliency and leveraging renewable assets Intermittency mitigation of variable renewable resource Local resource adequacy Cost reductions due to utilization of aggregated DER (storage) asset Peak Load Reduction Black start capability Over-generation and curtailment support Distribution System Reliability Market energy (day-ahead/realtime) Efficiency improvement of fossil generation (hybrid application) Transmission & Distribution Capacity Flexible ramping product (Future ISO product) Fuel Price Hedging Frequency response (inertia) (Future ISO product/standard) Generation Capacity Spinning/non-spinning reserve (ISO products) Capacity Market

22 3) For each of the products and services to be procured by the DSPP, how should the pricing be determined? (If the answers differ by product, please specify to the extent possible) a. Should pricing be based on embedded cost of service? NY-BEST believes that the markets for DERs should be open and competitive, encouraging competition to increase efficiency, reduce both cost and price allowing participants to profit from superior performance. As such, pricing should be based on the value of the services provided rather than on cost. Furthermore pricing should be for the service performed and not be different for different technologies performing the same service unless those technologies are provide other benefits that differentiate them. b. Should pricing be determined through a market mechanism which might reflect locational based marginal pricing? The value of energy and capacity is highly related to location. It is therefore important that market mechanisms are created that value locational benefits. Note that this applies to both load reductions and providing energy and capacity. In the long-run we should achieve competitive, transactive markets that fully value all of the benefits associated with local and temporal energy and capacity. Initially, prior to sufficient DER penetration to establish robust markets, other pricing mechanisms that incorporate locational and temporal value should be adopted. For instance, the PSC could allow utilities, DSPP, or NYISO to create sub-zonal capacity premiums/discounts that highlight the benefit of delivering capacity into a specific area. This multiplier would be designed to incorporate the cost of a distribution or sub-transmission level investment that does not get included into the capacity values. For example, if a utility identifies a $20 million upgrade to a transmission line (100MVA), they could offer DER resources a prorated multiplier during evaluation or an additional payment ($200,000/MVA) for locating within this specific area that in aggregate would alleviate the need for the upgrade. This example does not capture all of the values associated with DER and thus could be further developed to monetize those other benefits.

23 c. Should pricing be determined via request for proposals and individually negotiated contracts? Should individually negotiated contracts be made available for public inspection? Contracts are part of an efficient market. From a buyer perspective, they receive visibility into their future costs and often receive the lowest possible cost while hedging their exposure. On the seller side, contracts enable new technologies to enter the market and compete with existing assets. To develop sufficient penetration of DERs to have viable local markets, in the near term contracts and incentives will be particularly important. Contracts need to be of sufficient duration to justify private investment. d. Should pricing be administratively determined to provide an incentive to achieve a predetermined outcome? If so, what level of granularity is needed (e.g., peak/offpeak vs. hourly) In the long-run, pricing should be determined by markets rather than administratively. However, to develop sufficient penetration of DERs to have viable local markets and to advance solutions that provide desired benefits that are presently not monetized in the markets, in the near term incentive programs will be important. These programs should have pre-determined goals for DER penetration (by DER type, i.e. solar, energy storage, etc.). Since system constraints vary geographically and temporally, with local peak demand times not necessarily coincident with system peaks or other locations, granularity is important. Local hourly pricing is preferable to a simple peak/off-peak determination. e. Should the pricing vary by time and / or geographic location? Both value and cost are strongly dependent on time and location. Pricing should reflect these market realities and vary by time and geographic location. f. Should the pricing be differentiated for products related to reliability, economics, or public policy? It is important to value and monetarily reward products for all to the benefits they deliver. If these benefits are not recognized in the market place, then there will not be an incentive to provide them.

24 Energy storage systems can provide a broad array of benefits simultaneously from the same system as discussed above. There are a number of potential market mechanisms for valuing these multiple benefits. Long-term contracts are a good policy mechanism that allows utilities and 3rd parties to value other benefits. For example, a solicitation for capacity projects can put a value on CO2 emissions in their evaluation. A thermal generator with a lower price but higher emissions might have a higher total evaluation price than a demand response bid with no emissions. More broadly, an entity, for instance the DSPP with PSC approval or the PSC itself could function like a mini PSC could develop appropriate valuation mechanisms. 7. Standby rates Standby rates can be a barrier to adoption of DERs and are a manifestation of a system view that DERs must be fully backed up at all times. At the heart of the REV process is a transformation of this system view to consider DERs assets integral to the system as opposed to removable appendages. It is critical that the reliability of DERs is properly assessed from a system perspective and that full backup is not requires, otherwise we will continue to have to overbuild the grid with further DER penetration. As such, the question of DER reliability should not be address by standby charges, but instead DERs should be fully considered in planning and IRM/LCR studies. NY-BEST recommends that tariff structures be reassessed in the REV process to address the multiple benefits of DERs and to properly compensate utilities for the value of the interconnection to the grid.

25 NY-BEST appreciates the opportunity to provide these comments and we stand ready to assist the Commission as the REV proceeding continues. Respectfully submitted, William P. Acker Executive Director NY-BEST 1450 Western Ave, Suite 101 Albany NY 12203