CONSUMERS ENERGY Electric Distribution Infrastructure Investment Plan ( ) Draft Report filed pursuant to Case No. U-17990

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1 Ms. Kavita Kale Executive Secretary Michigan Public Service Commission 7109 West Saginaw Highway Post Office Box Lansing, MI September 6, 2017 Re: CONSUMERS ENERGY Electric Distribution Infrastructure Investment Plan ( ) Draft Report filed pursuant to Case No. U Dear Ms. Kale: The Michigan Energy Innovation Business Council (Michigan EIBC) is pleased to submit comments in response to Consumers Energy Company s (CECO) draft Electric Distribution Infrastructure Investment Plan ( ) (Draft DIIP), filed pursuant to Case No. U Comprised of a membership of more than 100 companies doing business in Michigan, Michigan EIBC s mission is to grow Michigan s advanced energy economy by fostering opportunities for innovation and business growth and offering a unified voice in creating a business-friendly environment for the advanced energy industry in Michigan. In its February 28, 2017 Order in CECO s most recent general rate case, the Commission directed CECO to submit a draft distribution investment and maintenance plan by August 1, 2017, with a final plan due no later than January 31, Michigan EIBC commends the Commission for directing the utilities to modernize their distribution systems, including providing greater insight into the distribution planning process. This is a very timely discussion, with a number of other states actively engaged in grid modernization efforts. This increased focus on utility distribution planning should position the state to reduce the number and duration of outages, take better advantage of advanced energy options, and ultimately provide greater value for ratepayers. Following the filing of CECO s Draft Distribution Plan, the Commission issued a Notice of Opportunity to Comment on August 4, 2017, in which it sought comment from interested parties on the draft distribution investment and maintenance plans submitted by both CECO and DTE Electric Company, and specifically invited interested persons to address the following questions: 1) Does the company s draft distribution planning report provide a transparent review to identify and make cost-effective grid

2 modernization and aging infrastructure investments necessary to support improved reliability, power quality, and future growth? Do the proposed investments provide a clear strategic path to address resiliency, reliability, and grid modernization, consistent with the Commission s stated goals as outlined in recent electric rate case orders? 2) Do the plans identify system upgrades or investment strategies and concrete, measurable performance targets and timeliness in areas such as safety and reliability? 3) Are there longer term enhancements to the plan or the planning process that the Commission, utilities, and stakeholders should be considering in future rounds? 4) Any other feedback for the Commission s or Commission Staff s consideration. In its Order, the Commission directed CECO to submit the following information as part of its distribution investment and maintenance plan: a detailed description, with supporting data, on distribution system conditions, including age of equipment, useful life, ratings, loadings, and other characteristics; system goals and related reliability metrics; local system load forecasts; maintenance and upgrade plans for projects and project categories including drivers, timing, cost estimates, work scope, prioritization and sequencing with other upgrades, analysis of alternatives (including advanced metering infrastructure (AMI) and other emerging technologies), and an explanation of how they will address goals and metrics; and benefit/cost analyses considering both capital and operations and maintenance (O&M) costs and benefits. CECO s Draft DIIP includes many of these items. CECO also places this Draft DIIP in the context of what CECO describes as an ambitious, 15-year vision [that] centers on five primary objectives for ensuring that our distribution system remains customer-driven: Optimizing system cost over the long-term Improving reliability and resiliency Enhancing cybersecurity and physical security and safety Reducing carbon footprint Enabling greater customer control Draft DIIP, p. 5. In addition to this longer-term plan, CECO also articulates a five-year plan with a narrower focus of building a more modern electric distribution system that integrates greener, more distributed sources of electric supply with grid enhancements that are engineered for customer value. Id. at 7. CECO also highlights a number of steps it has already taken to improve distribution performance, including deployment of distribution automation loops, near- 2

3 universal AMI deployment, and upgrading capacitor bank controller equipment with 4G cellular technology. Id., at 17. Taken together, these upgrades represent most of what CECO describes as Phase 1 of its 15-year plan. The five-year Draft DIIP represents the transition from Phase 1 to Phase 2. Id., at 8-9. CECO describes Phase 2 as [b]uilding upon the foundation laid in Phase 1, the focus will shift to enhancing our communications network and critical system planning capabilities and expanding our use of automation and conservation applications required to better optimize the design and operation of the electric distribution system. Additional pilots will be launched to test a greater suite of non-wires alternatives along with more modern opportunities to maintain the system (e.g. LiDAR for tree trimming, drones for pole inspections) in a lower cost way. Id. at 9. Notably, CECO places this effort in a context in which [c]ustomer expectations are quickly evolving, requiring CECO to adapt to ensure that we can meet those expectations. Id., at 5. Indeed, the Draft DIIP is drawn from a vision in which Id., at 6. the electric grid is evolving ever faster as technological advances and financial innovations allow customers to change their electricity usage in new, meaningful, and sometimes unexpected ways. Customer expectations are becoming more varied and complex, which requires the system to become increasingly adaptable. For the residential segment, one customer may want to install distributed solar, while another may desire greater certainty in his/her monthly bill. For the commercial and industrial (C&I) segment, we are experiencing greater demand for a variety of options from lowering cost (e.g. demand response for peak shaving) to creating a brand that is more environmentally conscious (e.g. 100% renewable energy). More broadly, customers want some combination of the following objectives: lower cost, improved reliability and resiliency, enhanced security and safety, reduced carbon footprint, and more control over energy supply and consumption. CECO further notes that these changes drive new planning realities. In the future, planning will require significant changes to account for two-way power flows, widespread integration of distributed energy resources, dynamic changes that result from advanced automation and control schemes, and other emerging technologies. New tools, analysis methods and models with circuit-level data are critical for maximizing customer value and control, increasing reliability, and reducing our carbon footprint. Integrating these over the coming decade will provide immense planning benefits. Id., at 21. 3

4 Michigan EIBC applauds CECO s awareness of the changing nature of customer demands and the fact that these changes will dramatically affect the operation of the distribution grid, requiring new methods of distribution planning. That said, the Draft DIIP lacks a number of elements that are regularly included in distribution system planning among leading utilities, and which are central to the goals articulated by CECO. These elements include consideration of a broader range of probabilistic distributed energy resources (DER) and load growth scenarios, greater transparency and sharing of data relating to distribution grid planning and operations, and fuller consideration of how DERs, including distributed generation (DG) and battery energy storage, and other alternatives can meet distribution network needs. To fully leverage the opportunities of a changing energy system, we recommend greater attention to these items and fuller inclusion within CECO s distribution planning process. The focus of any distribution planning exercise and the standard for regulatory review of proposed investments should be on (1) prioritizing investments that avoid or defer other, more costly investments by fully evaluating non-wires alternatives (NWAs), (2) avoiding investments with the potential to become redundant and result in stranded costs in a future in which DERs feature more prominently, and (3) avoiding courses of action that inhibit DER deployment. Better integrating these recommendations can enable CECO to identify appropriate investment strategies consistent with the emerging needs of the system and of customers, and to defer or avoid unnecessary and costly expenditures. As noted in the recent NARUC DER rate design manual, this is consistent with mitigating the potential higher system costs by allowing the utility to better target necessary upgrades, avoiding unnecessary investments and utilizing [distributed energy resources] to make more efficient use of existing assets. National Association of Regulatory Utility Commissioners (NARUC) Staff Subcommittee on Rate Design, Distributed Energy Resources Rate Design and Compensation, Nov. 2016, p ) Does the company s draft distribution planning report provide a transparent review to identify and make costeffective grid modernization and aging infrastructure investments necessary to support improved reliability, power quality, and future growth? Do the proposed investments provide a clear strategic path to address resiliency, reliability, and grid modernization, consistent with the Commission s stated goals as outlined in recent electric rate case orders? As noted above, CECO provides significant detail on its current distribution system in its Draft DIIP, and places this effort in the context of both ongoing utility investments in its distribution system as well as rapid change in technology, customer preferences, and cost curves for distributed energy resources. 4

5 Yet, as the National Association of Regulatory Utility Commissioners (NARUC) Staff Subcommittee on Rate Design noted in a recent Manual on Distributed Energy Resources Rate Design and Compensation, [t]he required level of transparency and detail for the operations and physical characteristics of a utility s distribution system may be significantly more than may have been employed in the past, due in part to the fact that the value of distribution resources may not vary only from state to state and utility to utility, but also from feeder to feeder or circuit to circuit. National Association of Regulatory Utility Commissioners (NARUC) Staff Subcommittee on Rate Design, Distributed Energy Resources Rate Design and Compensation, Nov. 2016, p. 58. CECO seems to appreciate the importance of improving its own data sets. For example, the Draft DIIP states that [o]ur traditional database systems are not suited to the volume, variety, and velocity of the data sets that are provided by smart meters and grid devices. Draft DIIP, p. 22. This reflects a firm realization that CECO s customers have a growing amount of data at their fingertips and increasingly leverage that data to make new, ever more powerful, real-time decisions. Customers can actively engage with the [distribution] system via energy efficiency and demand response programs, and have the potential to control distributed generation and energy storage devices. Further into the future, this could unlock the potential for a more interactive relationship between utilities and their customers, supported by expanded data and the analytics to drive new insights and decision-making. Just as past technological innovations rapidly penetrated the market over the course of a single generation, these grid edge data-driven technologies are expected to become deeply integrated in the electric distribution system over the next two decades. Id., at 7. Reflecting this emerging reality, CECO includes data transparency as one of the pillars of a dynamic distribution system, seeing its role as [p]roviding customers with education on energy usage and DER technologies along with access to AMI information to support informed decision-making Id., at 8. Despite its recognition of the role of data in grid modernization efforts, however, it seems that CECO intends to take an overly utility-centric approach to how that data is ultimately used. As it notes in the Draft DIIP, the growth of data will require a more robust communications network to facilitate two-way flows of information and further improve our own systems to gather more data and translate that data into information useful to our customers, our regulators, and ourselves. Id (emphasis added). In addition to leaving out third-parties among the groups for whom this distribution data would be useful, the idea that CECO alone can make sense of the various data derived from rate-based investments in distribution grid communications such as AMI and Supervisory Control and Data Acquisition (SCADA) and that it is the role of the utility to translate that data into information useful to its customers and others ignores the growing participation of third-parties in developing solutions for customers and for distribution system needs. Indeed, as was recently noted in a white paper published by a group of technology firms and investors, [t]he practice of grid 5

6 design and planning is no longer the sole expertise of utilities, and with broader stakeholder engagement comes the potential for increased innovation and new solutions to meet grid needs. TechNet, SunSpec Alliance, and DBL Partners, Unlocking Grid Data: Enabling Data Access and Transparency to Drive Innovation in the Electric Grid, Dec. 2016, p. 2. Instead, there is good reason for the Commission to establish data access protocols as part of this distribution planning process that allow third parties to readily access data on an ongoing basis, subject to appropriate grid security and customer privacy protections. This should include the underlying data on which CECO s distribution plan is based, including circuit- and substation-level detail, data collected from AMI, and other raw data sets. Greater access to distribution system data could potentially unlock a wide range of benefits, including increased customer and third-party engagement in developing cost-effective solutions, enabling the development of non-wires alternatives, facilitating DER compensation models, speeding up the pace of innovation, and improving outcomes for all participants. In addition to broader access to grid data, the Draft DIIP would benefit from consideration of a broader range of scenarios, including accelerated adoption of DERs. Indeed, the Draft Distribution Plan contains very little in the form of local load forecasts or descriptions of the various scenarios, sensitivities, or other variables that might impact CECO s distribution plans and investments. In describing the assumptions and analysis on which its distribution investments are based, CECO states that the process relies on load forecasts, which have traditionally been the primary input in system planning. While the usage of load forecasts will likely continue, the way in which we create and use our forecasts will change as technologies and capabilities change, so that we keep up with significant and accelerating evolution in customer electricity usage. Draft DIIP, p. 20. More specifically, CECO begins its process by building a forecast of future peak electric demand for our entire system, based on historical data, economic forecasts, industrial load forecasts, and weather data. We use a 65% confidence interval for our system-wide peak load forecast to incorporate any potential unanticipated load changes. Id. Finally, CECO states that [a]s the investment phase continues, we will develop a framework to identify the benefits of pursuing a more aggressive modernization strategy. Id., at 19. The fact that CECO is using just a 65% confidence interval and its acknowledgement that it may need to adjust its forecasts as technologies and capabilities change highlights the difficulties in predicting the future, as well as underscoring the need for consideration of a broader range of possibilities. As Governor Snyder noted in his 2015 Energy Message, we need to be adaptable, since we don t know which future we will actually come to see. Governor Rick Snyder, A Special Message from Gov. Rick Snyder: Ensuring Affordable, 6

7 Reliable, and Environmentally Protective Energy for Michigan s Future, March 2015, p. 16. The danger, of course, is that basing large investments on incorrect assumptions and projections could limit CECO s options and hinder its ability to correct. In a number of states, growth of DERs accelerated far faster that was originally anticipated, putting additional strain on the distribution grid, requiring additional expenditures to adjust to these new realities, and generating frustration among utility customers. One goal of this process is to avoid replicating these missteps from other states, an objective that requires broader consideration of high-der growth scenarios. Finally, in addition to the need for a broader range of forecasts, a number of forward-looking states and utilities are also switching to probabilistic in contrast to deterministic scenario planning. While deterministic forecasting relies on an assumption of full information and control, there is a growing understanding that these conditions no longer exist (to the extent they ever did), and the rise in distributed generation, electric vehicle adoption, and other DERs reinforces this truth. Shifting to probabilistic planning will be critical to avoiding costly mistakes and missed opportunities. 2) Do the plans identify system upgrades or investment strategies and concrete, measurable performance targets and timeliness in areas such as safety and reliability? Following on the need for a more probabilistic approach to distribution planning, the system upgrades and investment strategies contained in CECO s Draft Distribution Plan are too quick to dismiss non-wires solutions as an alternative to improvements to the physical architecture of the distribution system. For example, the Draft DIIP states that [w]ith reliability concerns, non-wires alternatives are not yet considered a viable option. NWAs are typically located at customer homes or businesses and are often unable to correct distribution reliability issues that occur (e.g. animal-related damage, pole failure). Draft DIIP, p. 24. While non-wires alternatives cannot fully address animal-related damage 1 and some other issues, a more fully integrated process of considering NWAs to reduce or eliminate need for load-based upgrades has real potential. Indeed, on the same page in which CECO categorically states that non-wires alternatives are not yet considered a viable option, it also notes that, [i]n general, the greater the projected load over equipment s peak capability, the higher the priority is for upgrade. Id. Yet there is no suggestion that such considerations are being fully integrated into decision-making process. 1 According to the Low Voltage Distribution Outage Summary contained in Table 26, animalrelated damage was the cause for less than 1% of outage duration for both average and Draft DIIP, p

8 One reason may be that while CECO s analysis of NWAs includes consideration of battery storage, demand response, and energy efficiency, it notably ignores distributed generation. (See, e.g., CECO s comment that [o]ur non-wires alternatives have focused on two programs: Demand Response and Energy Efficiency. Id., at 26; see also contents of Appendix D.4 Non-Wires Alternatives Overview, which includes only demand response and energy efficiency. Battery storage is also considered as CECO-owned resources as part of two pilot programs.) Such a view is not only inconsistent with the realities of double-digit growth in distributed solar deployment over each of the last several years in Michigan, it also is in conflict with the definition of Non-Wires Alternative (or Non-Wires Solution) CECO quotes in the Draft DIIP, which defines a non-wires alternative as [t]echnologies that use non-traditional [transmission and distribution] T&D solutions, such as distributed generation, energy storage, energy efficiency, demand response, and grid software and controls, to defer or replace the need for specific equipment upgrades, such as T&D lines or transformers, by reducing load at a substation or circuit level. Id., at 24 (citing Navigant Research). Even leaving aside the inclusion of distributed generation as a grid resource, in two of the three examples of planned substations rebuilds, expansions, or additions, non-wires alternatives were not even considered. In the one example in which it was considered, it was deemed not viable to achieve peak load reduction. Id., at 27. Indeed, of the 76 identified substations with capacity or reliability challenges that require new investments between 2018 and 2022, all but one area (Swartz Creek) will be addressed through traditional assets. Id., 28. What s more, an analysis of the 75 cases in which CECO intends to deploy traditional assets finds that 52 of them more than two-thirds of the total will be constructed when an actual overload occurs, for a reliability improvement, or for a combination of the two. Draft DIIP, Appendix D.5 - TABLE 35 NEW SUBSTATION BUILDS AND UPGRADES ( ). These conditions seem similar to the Swartz Creek substation that will be upgraded through aggressive marketing of energy efficiency, rate design options, and demand response programs, yet it is unclear to what extent (if any) non-wires solutions were even considered to address some or all of the reliability and load issues that could trigger the need for substation construction. Finally, non-wires solutions have the potential to generate significant savings for ratepayers when deployed appropriately. While the reported operation and maintenance costs for the non-wires alternatives are higher, given the difference in utility incentives for capital expenditures versus O&M expenditures, it will be important to ensure that non-wires solutions are maximized as part of distribution plans to match the opportunity for ratepayer value. To address this issue, the Commission should establish incentives beyond those currently available to encourage utilities to consider and ultimately incorporate NWAs. The inclusion of 8

9 expanded incentives for consideration of energy waste reduction opportunities in 2016 PA 341 could serve as a useful template for such an approach. 3) Are there longer term enhancements to the plan or the planning process that the Commission, utilities, and stakeholders should be considering in future rounds? Michigan EIBC applauds CECO for specifically integrating a Distributed Energy Resource Management System (DERMS) as part of its investment in its Advanced Distribution Management System (ADMS) on a single platform, along with SCADA, a Distribution Management System, and an Outage Management System. This is the type of proactive integration of technology that can pave the way for a successful transition to a fully modernized distribution grid, avoiding the need for duplicative future investments, as well as avoiding delays and customer frustration, and maximizing the value of DER to the system to the benefit of all customers. For future planning, we encourage CECO to integrate its distribution planning processes with other planning processes, including the integrated resource plans required under Section 6t of 2016 PA 341, MCL 460.6t. In addition, the Commission should also work to integrate the various proceedings both formal and informal that touch upon the distribution grid, including, among others, the Code of Conduct rulemaking process called for under Section 10ee of 2016 PA 341, MCL ee; the proceeding in Case No. U establishing the method and avoided cost calculation for CECO to fully comply with the Public Utilities Regulatory Policy Act (PURPA) of 1978, 16 USC 2601 et seq.; the development of a tariff for customers with a distributed generation system as required under Section 6a of 2016 PA 341 and Section 173 et seq. of 2016 PA 342, MCL 460.6a and MCL et seq.; the proceeding in Case No. U to consider issues related to the deployment of plug-in electric vehicle charging facilities, including the recent Commission-sponsored technical conference on alternative fuel vehicles; efforts to promote voluntary load management programs as called for in Section 95 of 2016 PA 342, MCL ; and the study on performance-based regulation of public utilities required under Section 6u of 2016 PA 341, MCL 460.6u. In the near term, the Commission should work to harmonize key input assumptions across the various proceedings, including macroeconomic trends, population tends, load growth, and DER costs and performance. Finally, it is critical that distribution planning in the short term anticipate longer term enhancements in order to avoid large investments that could ultimately prove unnecessary. Integrating NWAs today can provide for greater optionality in the medium- to long-term, saving money for ratepayers. Traditional distribution solutions are one-size-fits-all with available options coming in block sizes. In the current environment where load growth is largely flat, it may be more prudent to utilize DERs that enable greater adaptability. As demonstrated by the figure 9

10 below, rightsizing the upgrades needed today by fully integrating battery energy storage and DG also have the potential to save ratepayers money by enabling smaller-scale, more adaptable solutions for grid upgrades. However, to ensure full consideration of DERs and other NWAs, the gap between the distribution planning taking place today and longer-term planning horizons need to be condensed. 4) Any other feedback for the Commission s or Commission Staff s consideration. The history of distribution system planning over the last ten years is characterized by utilities that underestimated the pace of growth of non-utility resources, overestimated their level of control in shaping customer demand for these resources, and waited too long to respond. To avoid repeating these patterns, a forward-looking distribution planning process should better account for all distribution resources and invite the development of solutions by the full range of utility and non-utility players. In conclusion, there is much to admire in the Draft DIIP. As CECO notes, [d]eveloping advanced planning capabilities goes beyond deploying devices and purchasing software licenses. Investments must be made in an informed optimal sequence, building a network of devices, applications, and capabilities. Our roadmap aims to do this in a way that also balances the proactive modernization of our grid infrastructure and the dispersal of infrastructure investment costs over multiple years to mitigate major rate changes and technology risks. Draft DIIP, p

11 Consideration of a broader range of potential scenarios, increasing customer and third-party access to grid data, fuller consideration of non-wires solutions into the decision-making process, and integration of the distribution planning process with the forthcoming integrated resource planning process and other Commission proceedings will be necessary for CECO to meet its lofty goals. Michigan EIBC applauds the Commission for taking initial steps towards ensuring greater transparency and value for ratepayers in utility distribution planning, and appreciates the opportunity to provide these initial comments on the CECO Draft DIIP. Respectfully submitted, Liesl Eichler Clark President Michigan Energy Innovation Business Council 11