STATE OF NEW HAMPSHIRE BEFORE THE PUBLIC UTILITIES COMMISSION Unitil Energy Systems, Inc. Petition for Distribution Rate Increase ) ) ) DE 16-384 ) ~~~~~~~~~~~~~~~~~~~~~) AFFIDAVIT David L. Chong , having been duly sworn, states under oath as follows: 1. I am over eighteen years of age; I am competent to provide this affidavit; and I have personal knowledge of the facts set forth below. 2. I am employed by Unitil Service Corp. ("Service Corp.") as Director of Finance. I am also the Treasurer of Unitil Energy Systems, Inc. ("Unitil Energy"). 3. Service Corp. is a corporation providing managerial, financial, regulatory and engineering services to the subsidiaries of Unitil Corporation, a New Hampshire corporation. 4. Unitil Energy is a wholly owned subsidiary of Unitil Corporation. 5. I am familiar with the facts of this proceeding. 6. With respect to the expenses incurred for the service providers retained by Unitil Energy, I certify that: a. Unitil Energy used a competitive bidding process, and in selecting the winning bidders, considered information concerning the availability, experience, customary fees for similar services, quality, and cost of the service providers; b. A competitive bidding process was not employed by Unitil Energy in the selection by of Attorney Ashley Brown to provide rebuttal testimony on behalf of Unitil Energy in docket DE 16-576. Rather, Unitil !=nergy considered the special expertise and experience of Attorney Brown as a former public utility commissioner for the State of Ohio, his membership on numerous electric industry advisory boards, his authorship or co-authorship of journal articles regarding net metering issues, and, in particular, his recent testimonies and submitted comments on net metering cost recovery in several jurisdictions throughout the country. c. The time spent on the cases by the service providers was undertaken in an efficient and cost effective manner. DATED this 13th day of June, 2017. Witness STATE OF NEW HAMPSHIRE :ss COUNTY OF ROCKINGHAM On this 13th day of June, 2017, then personally appeared before me David L. Chong, the signer of the above instrument, who duly acknowledged to me that he executed the same. Notary Public KA'5TINA . GUAY, NoWy Public S•O#Nitwt.......,._ My CommiM6on .... Mii)' n, I02(.) Residing in Rockingham County My Commission Expires: 2 C C C [iiBiT STATE OF NEW HAMPSHIRE BEFORE THE PUBLIC UTILITIES COMMISSION Development of New Alternative ) Net Metering Tariffs and/or ) Other Regulatory Mechanisms and ) Docket No. BE 16-576 Tariffs for Customer-Generators C REBUTTAL TESTIMONY OF ASHLEY C. BROWN ON BEHALF OF UNITIL ENERGY SYSTEMS, INC. December 21, 2016 C 1 Contents Introduction ..................................................................................................................................... 1 I. Basic Utility Pricing Principles ................................................................................................... 2 II. Retail Net Metering (RNM), Its History, And The Problems Of RNM..................................... 5 III. Why Claims About The "Value Of Solar" Do Not Justify Retail Net Metering .................... 25 IV. Problems With Mr. Beach's New Hampshire "Value Of Solar" Analysis............................. 44 V. How The Three-Part Rate Proposed By Unitil Can Help Address The Inequities And Inefficiencies Of Retail Net Metering............................................................................... 52 Conclusion .................................................................................................................................... 55 2 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 1 of 55 1 INTRODUCTION 2 Q. On whose behalf are you testifying? 3 A. On behalf of Unitil Energy Systems, Inc. 4 Q. What is the purpose of your testimony? 5 A. To rebut certain inaccurate claims and arguments made by witness Mr. R. Thomas Beach, 6 on behalf of The Alliance for Solar Choice, witness Mr. Patrick Bean, of SolarCity, on 7 behalf of the Energy Freedom Coalition of America, witness Mr. Nathan Phelps, on 8 behalf of the New Hampshire Sustainable Energy Association, and witness Mr. Paul 9 Chernick, on behalf of the Conservation Law Foundation. 10 Q. Please describe your background and qualifications. 11 A. I am the Executive Director of the Harvard Electricity Policy Group (HEPG) at the 12 Harvard Kennedy School, at Harvard University. HEPG is a "think tank" on electricity 13 policy, including but not necessarily limited to pricing, market rules, and regulation, as 14 well as environmental and social considerations. HEPG, as an institution, never takes a 15 position on policy matters, so this paper represents solely my opinion, and not that of the 16 HEPG or any other organization with which I may be affiliated. Prior to coming to 17 Harvard, I served 10 years (two full terms) as Commissioner of the Public Utilities 18 Commission of Ohio. During my tenure, I also served as Chair of the NARUC 19 Committee on Electricity, as a member of the Board of the National Regulatory Research 20 Institute, and as a member of the Advisory Board of the Electric Power Research 21 Institute. I am also the co-author of the World Bank's Manual for Evaluating 22 Infrastructure Regulation. My full biography is attached as Appendix A. 23 Q. What is the general outline of your testimony? 24 A. New Hampshire HB 1116 has required the initiation of a proceeding to develop 25 alternative net energy metering tariffs, which should ensure that "costs and benefits are 1 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 2 of 55 1 fairly and transparently allocated among all customers." The New Hampshire Public 2 Utilities Commission has detailed a number of considerations for this proceeding, 3 including the "costs and benefits of customer-generator facilities," "avoidance of unjust 4 and unreasonable cost shifting," and "rate effects on all customers." Initial testimony 5 submitted reflects considerable disagreement about what net energy metering is, what the 6 costs and benefits of current net energy metering arrangements are, and what kind of 7 tariff might be most "fair" and "transparent." The purpose of my testimony is to clarify 8 some key areas of disagreement related to 1) pricing and why three part rates are 9 especially appropriate for distributed generation customers and 2) costs and benefits of 10 distributed solar, as described in HB 1116 (often described as "value of solar," or perhaps 11 ascertainment of "avoided costs"), and why analyses that assign substantial non-energy 12 values to distributed solar generation are seriously flawed. In what follows I review: ? 13 14 Basic utility pricing principles, including the importance of external discipline on pricing and the three types of utility costs (fixed, variable energy, and demand); 15 ? Retail net metering ("RNM"), its history, and the problems of RNM; 16 ? Why claims about the "value" of solar do not justify RNM; 17 ? How the specific analysis of the "value of solar" provided by Mr. Beach 18 exemplifies the common problems of value of solar analysis and does not provide 19 any justification for continuing the burdensome and unfair cross subsidies 20 inherent to retail net metering. ? 21 22 Why the three part rate proposed by Unitil can help address current inequities and inefficiencies of RNM. 23 I. BASIC UTILITY PRICING PRINCIPLES 24 Q. 25 What basic pricing principles should be kept in mind in reviewing the testimony presented related to net metering in New Hampshire? 2 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 3 of 55 1 A. It is a fundamental principle of electricity pricing that prices should always be subjected 2 to external discipline, either the discipline of market competition or, in the absence of 3 meaningful competition, to the discipline of cost-based regulation. To the extent that the 4 rates for distribution utilities cannot always be fully competitive, utility regulators use 5 costs to establish reasonable rate limits. In his seminal 1961 book on utility ratemaking, 6 the economist James Bonbright,1 whose writings on the subject are widely regarded as 7 authoritative, argued for the importance of a "cost of service" standard in setting rates.2 8 Writes Bonbright: 9 [O]ne standard of reasonable rates can fairly be said to outrank all others in 10 the importance attached to it by experts and by public opinion alike--the 11 standard of cost of service, often qualified by the stipulation that the relevant 12 cost is necessary cost or cost reasonably or prudently incurred.3 13 In implementing "cost of service" ratemaking, ratemaking bodies typically follow 14 a two-step process: 1) determining the utility's total costs--including a fair rate of return 15 on capital investments, and 2) setting rates by allocating a share of those costs to different 16 classes of customers and then selecting rate structures to recover sufficient revenue from 17 each class of customer. 18 Q. 19 20 21 Are there different types of costs that utilities face and that should be considered separately in ratemaking? A. Yes. The three most important types of costs for electric utilities are 1) variable energy costs: the total number of kilowatt hours (kWh) used; 2) demand costs: the total capacity 1 Bonbright, who died in 1993, was a long time member of the Business School Faculty at Columbia University and served for some time as Chairman of the New York Power Authority. He is widely regarded as one of the nation's most distinguished writers and commentators on regulations and a most important thought leader on the subject. 2 This view is generally held by others as well. See, e.g., https://mitei.mit.edu/system/files/Electric_Grid_8_Utility_Regulation.pdf. 3 Bonbright, op cit, p. 67. 3 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 4 of 55 1 (kilowatts, or KW) the utility must build and maintain in order to meet peak demand-- 2 generation, transmission, and distribution adequate to supply all the power needed at the 3 moment of the very highest demand (keeping in mind that the obligation to serve is 4 unlimited); and 3) fixed costs: costs that must be incurred regardless of kWh or KW, and 5 which do not vary with demand. Fixed costs are typically thought of as costs that are 6 unaffected by individual customers' changes in energy consumption. Examples include 7 the costs of customer service and billing. 8 Q. How have these three types of costs typically been reflected in rates? 9 A. For residential customers, those three separate kinds of costs have traditionally been 10 bundled together into two-part rates, consisting of a monthly fixed charge and an energy 11 charge (based on total kilowatt hours used). In a two-part rate, "Demand" costs (that is, 12 capacity costs associated with meeting peak demand) are lumped in with the energy 13 charge, rather than being shown separately in the bill--so, effectively, customers who use 14 more kWh during a month pay a correspondingly greater share of demand costs. This 15 results in rough conformity with the "cost causer pays" principle, as long as kWh usage 16 and peak demand (KW) vary together. In addition, the fixed charge on the bill of a 17 residential customer represented only a tiny fraction of the totality of the fixed costs. 18 Thus, the bulk of the fixed costs and all of the demand costs were recovered through 19 volumetric based rates (i.e. on a per kwh basis). 20 Commercial and industrial (C&I) utility customers, in contrast, have long been 21 subject to three part rates, corresponding with the three types of utility costs. Thus, rates 22 for a commercial or industrial customer typically include a fixed charge and two variable 23 charges--an energy charge, based on total kilowatt hours used, and a demand charge, 24 based on how much capacity the utility needs to maintain to meet the customer's peak 4 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 5 of 55 1 demand (measured in kilowatts).4 Accordingly, C&I customers are not only positioned to 2 reduce both system costs and their own costs by getting a discrete demand price signal, 3 but by providing that signal, new market entrants with the capability of managing 4 demand costs could enter the market and provide such services. 5 II. RETAIL NET METERING (RNM), ITS HISTORY, AND THE PROBLEMS OF 6 RNM 7 Q. What were the origins of RNM? 8 A. The initial connection of rooftop solar systems to the grid posed an issue for utilities and 9 regulators. If customers supply power to the grid, how should they be compensated? 10 When rooftop solar systems were first connected to the grid in the 1980s and 1990s, most 11 households had a single meter capable only of running forwards, backwards, and standing 12 still, and utilities and regulators had limited options. Given the very limited amount of 13 rooftop solar market penetration anticipated at the time, and the high cost of rooftop 14 solar, large scale investment in new technology or overall tariff reform was not a 15 priority.5 Many utilities adopted retail net metering. Under a RNM tariff, a single meter 16 for these customers runs forward when solar PV DG customers are purchasing energy 17 from the grid. When those customers produce energy and consume it on premises, the 18 meter simply stops, and when the customer produces more energy than is consumed on 19 premises, the meter runs backwards as the excess energy is exported to the grid. Thus, the 20 solar PV DG customer pays full retail price for all energy taken off the grid, pays nothing 21 for energy or fixed costs such as distribution, transmission, generating capacity, or 4 It is interesting that when talking about the forces that likely would prompt a utility to adopt a demand charge for industrial customers, Bonbright calls out distorting effects caused by industrial customers who provide some of their own generation. (Bonbright, pp. 309-311) 5 Indeed, some utilities, trying to avoid the issue altogether, simply refused to interconnect rooftop solar units to the grid at all. 5 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 6 of 55 1 demand costs when energy is being produced on premises, and is credited the fully 2 delivered retail price (i.e., all energy plus all fixed costs, despite the fact that solar 3 customers incur no such fixed or demand costs) exported into the system. At the end of 4 whatever period is specified, the meter is read and the customer either pays the net 5 balance due or the utility credits the customer for excess energy delivered. 6 Under RNM, therefore, customers produce energy, but are compensated at rates 7 that reflect the full cost of generation and of transmission and distribution. This generous 8 arrangement seemed to make sense originally, at a time when market penetration of 9 rooftop solar was negligible, when rooftop solar systems were far more expensive than 10 they are today, when metering technology was relatively primitive, when wholesale 11 energy and capacity markets did not generate the very sophisticated and unbundled 12 signals they do today, and when the amount of fixed and demand costs that would be 13 bypassed by widespread deployment of rooftop solar were unknown. To the extent that 14 any policy considerations contributed to its adoption, it was that RNM would provide a 15 short-term stimulus to the development of distributed solar technology, at that time a very 16 expensive product. It was never intended to be a long term pricing methodology.6 The 17 notion was that RNM would serve as a short term stimulus to boost rooftop solar into 18 commercial viability. 19 Q. Does the original rationale behind the adoption of RNM still apply today? 20 A. No. Today, the technological limitations that were a primary driver of current net 21 metering policies and tariffs have largely disappeared. "Smart meters," as well as 6 While the full effects of retail net metering were unknown at the time of their adoptions, many jurisdictions, just to be cautious about the unknown, actually hedged against severe distortions by capping the amount of rooftop solar and/or sizes of units that would be on an RNM tariff. A 1996 overview of state net metering programs prepared by NREL found that almost all included individual capacity limits, while three states (including New Hampshire) also had statewide capacity limits. See Yih-hui Wan, Net Metering Programs, NREL Topical Issues Brief (December 1996), Table 1, p. 3. Available online at: http://www.nrel.gov/docs/legosti/old/21651.pdf 6 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 7 of 55 1 internet-based technology, are capable of measuring not only how much electricity 2 consumers use in a month, but when and even how they use it. 3 At the same time that smart meters have become widely deployed, the basic 4 economics of solar panels have changed dramatically. The costs of solar panels have 5 declined enormously. As I argue below, because of net metering, the full benefits of the 6 declining costs are not being passed on fully to customers (solar and non-solar alike)-- 7 indeed, the fact that the costs of rooftop solar panels are significantly lower than they 8 were when regulators initially settled on generous retail net metering schemes as a way of 9 providing a short term boost to enable rooftop solar to attain full commercial viability is a 10 clear demonstration of the fact that such cross-subsidies are now neither necessary nor 11 desirable. In fact, they may well serve as an impediment to the full commercial viability 12 for rooftop solar that is desirable. Now that the costs of rooftop solar have declined, that 13 short term stimulus rationale for tolerating the flaws of net metering no longer applies. 14 Stated succinctly, the underpinnings of net metering: dumb meters, poor energy price 15 signals in the wholesale market, miniscule market penetration by distributed resources, 16 and out of market costs, are all historical relics that decidedly not characteristic of 21st 17 century electricity markets 18 Q. What's wrong with retail net metering? 19 A. The fundamental problem with retail net metering (which is at the root of many other 20 issues) is that under retail net metering, the connection between costs of service to the 21 customer and the price paid by the customer is lost. Through RNM, solar customers have 22 until recently had the same residential tariffs applicable to them as were applied to non- 23 solar residential customers (adapted, of course, to give credit for solar production). 24 However, by the standards of cost-based ratemaking, traditional residential tariffs (i.e., 25 volumetric rates based on kWh, and encompassing charges related to generation, 26 transmission, and distribution), when applied to customers with solar generation, do a 7 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 8 of 55 1 markedly worse job of reflecting actual customer costs than they do when applied to 2 other customers. 3 This breakdown of the relationship between costs and rates has four main 4 consequences: ? 5 6 Cross subsidies. Distributed generation customers are undercharged for their usage, and end up subsidized by customers without distributed generation; ? 7 Inefficiency. Distributed generation customers do not receive price signals that 8 would encourage them to maximize the value of the solar energy they produce; at 9 the same time, the distributed solar industry, shielded from market pressures, fails 10 to maximize efficiencies and savings to customers; 11 ? Unfairness to competing technologies; and 12 ? Undermining the prospects for the long-term sustainability of rooftop solar 13 energy, due to a lack of incentives for productivity gains and inflating prices well 14 above underlying costs. 15 Q. Why do you say that one consequence of RNM is a cross subsidy? 16 A. As discussed above, traditional rate plans, including New Hampshire's existing Net 17 Energy Metering plans, use volumetric rates to recover not only variable costs such as 18 fuel, but also a very substantial part of the fixed and demand costs (transmission and 19 distribution, as well as capacity components of generation). Customers who generate 20 their own energy may purchase less energy from the system, but the fixed costs of service 21 still exist, and, due to both intermittency and non-coincidence with peak demand, the 22 demand costs are also largely unabated.7 The result of linking RNM with a purely 23 volumetric rate structure that makes no distinction between generation energy and 7 For a view of size and scale of the cross subsidy, see Rethinking Rationale for Net Metering | Fortnightly, by Barbara Alexander, Ashley Brown, and Ahmad Faruqui. (www.fortnightly.com/fortnightly/2016/10/rethinking-rationale-net-metering) 8 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 9 of 55 1 capacity costs as well as distribution and transmission costs constitutes a substantial 2 cross-subsidy to rooftop solar customers. The costs of that subsidy are borne by the 3 utility's non-solar customers.8 4 This subsidy does not exist for most residential customer classes. This is because 5 most customers' peak demand (measured in KW) and overall kWh usage typically vary 6 together. (This is true for customers who invest in energy efficiency, as well as other 7 customers). For solar DG customers, however, the traditional relationship between peak 8 demand (KW) and overall kWh usage breaks down. Solar customers can reduce their 9 kWh usage by a lot (especially if they get credit for excess kWh produced) while only 10 slightly, if at all, reducing their peak demand (it is even possible demand could be 11 increased, if solar customers are motivated by their reduced bills to consume more 12 electricity overall).9 13 The fact that customers with rooftop solar may produce energy when the sun is 14 shining does nothing to reduce the utility's fixed per-customer costs and, at least in the 15 short run, has not been reliably shown to reduce the capacity costs the utility must incur 16 in order to make sure that it is prepared to meet all of the electric requirements of the 17 solar customers at all times, including when their panels are either producing insufficient 18 energy to meet all or a portion of their requirements. Indeed, the intermittency of solar 19 means that there must be sufficient capacity to meet demand even at times when one 8 The cross-subsidy discussed in my testimony relates solely to those embedded in utility rates. What is not being discussed in this testimony but must be considered in the overall policy context is that rooftop solar is already heavily subsidized by substantial tax credits, renewable portfolio standards, renewable energy credits, and, perhaps, other programs that are also beyond the jurisdiction or control of utility regulators. Thus, any decision by the Commission to alter net metering will not have the effect of leaving rooftop solar without substantial governmental intervention in the marketplace in its favor. What regulators are deciding is how to send the appropriate price signals for rooftop solar to be deployed in the most cost effective, socially beneficial, and environmentally desirable way, not whether public subsidies should be available. 9 For an example, see the testimony of H. Edwin Overcast in this case. Table 1 on page 19. 9 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 10 of 55 1 might expect solar panels to be producing energy. Thus, when solar DG customers are 2 producing energy and not buying it, the utility only offsets its energy costs, but cannot 3 offset its fixed costs by simply buying or producing less energy. Thus, the utility has a 4 revenue shortfall, which will inevitably be passed on to non-solar customers. 5 Q. 6 7 What is your response to claims that rooftop solar offsets capacity costs, not just energy costs? A. Rooftop solar generation does not appreciably offset a utility's capacity costs for two 8 very basic reasons. The first is that solar production is, with some occasional exceptions, 9 not coincident with system-wide peak demand.10 The second reason is that, even if solar 10 production generally matched the time when demand was projected to be at its peak, 11 solar production is intermittent, indeed, unpredictably so,11 and thus not dispatchable by 12 the grid operator (i.e., the grid operator cannot call upon it to produce to meet peak 13 demand, or stop producing when there is cheaper, excess capacity on the system). For a 14 utility legally obligated to meet all of the electricity demand of customers in their service 15 territory, the existence of rooftop solar therefore does little to avoid the need to incur the 16 costs of meeting all demand and, in effect, providing "battery" service to solar customers. 17 The question before the Commission is who is obligated to pay for this "battery," the 10 As can be seen below, in the charts from ISONE on "Seasonal variation in load profiles," there is zero overlap between solar production in spring and winter. Summer shows a limited amount of overlap, which diminishes with greater levels of solar penetration. In New England, wholesale electricity prices are higher during the winter, so this means solar is not offsetting peak energy costs during the most expensive time of year. (See ISONE, 2016 Regional Electricity Outlook, p. 23, at https://www.isone.com/static-assets/documents/2016/03/2016_reo.pdf) As the testimony of H. Edwin Overcast in this case confirms, New Hampshire is no exception here--there is only a minimal overlap between solar production and peak demand. (Overcast testimony, p. 20). 11 It is important to note that rooftop solar is a double contingency intermittent energy source. It not only depends on the presence of the sun, but also on how much of the energy being produced is consumed on premises by the solar host and is never exported into the system. That constitutes a notable contrast with utility scale solar, which is a single contingency intermittent resource. 10 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 11 of 55 1 solar customers for whom the costs were incurred, or other customers, who had nothing 2 to do with causing "battery" costs to be incurred? 3 In fact, rooftop solar production generally creates a new and challenging daily 4 variation in the net load that must be served by the utility, a pattern that has come to be 5 known as the "duck curve." Briefly stated, the "duck curve" refers to the phenomenon by 6 which rooftop solar generates large amounts of power in the middle of the day, but as 7 solar production declines throughout the afternoon, the corresponding increase in demand 8 must be met by other generation supplied or procured by the utility.12 The "duck curve" 9 phenomenon is illustrated in the chart below (drawn from California), in which the belly 10 of the duck shows the increasingly steep drop off and ramp up of net load that is 11 occurring and expected to increase with greater adoption of solar generation: 12 http://instituteforenergyresearch.org/solar-energys-duck-curve/; https://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf 11 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 12 of 55 1 2 As is dramatically illustrated in the graph, enticed by a number of factors, not the 3 least of which is net metering, substantial investment in the growth of solar capacity in 4 California has enormously magnified the need for additional fossil plants, operating on a 5 ramping basis, to compensate for the drop off in solar production at peak. In that context, 6 the absence of any meaningful signal to make solar more efficient (e.g. directing solar 7 panels to the west, or linking solar production with storage) is simply something that can 8 no longer be tolerated. While New Hampshire's situation is certainly not identical to 9 California's, it would be pure folly for the state not to learn the lesson of what has been 13 10 problematic in a state with heavy solar DG market penetration, and adopt an approach that 11 averts a similar dilemma. 12 Intermittent sources of generation add additional complexity and cost to 13 maintaining the high degree of reliability expected from the system. This is particularly 14 true because the grid was originally designed to accommodate one-way delivery of 15 electricity, not the two-way exchange associated with rooftop solar generation.14 Thus, 16 when rooftop solar penetration increases beyond minimal levels, new investments to the 17 grid are required.15 13 For further discussion of the implications of the duck curve, see What the duck curve tells us about managing a green grid, CAISO, 2013 (http://www.caiso.com/Documents/FlexibleResourcesHelpRenewables_FastFacts.pdf.) 14 The two way flow, particularly since the energy inputs to the distribution system are from diverse and unpredictable places, can fundamentally alter grid dynamics by impacting on such critical elements as voltage support and reactive power. Since location of solar units can be a critical element in how these grid phenomena play out, the inability to plan locations for solar dg, almost inevitably drives up utility costs in accommodating distributed solar. 15 https://mitei.mit.edu/system/files/MIT%20Future%20of%20Solar%20Energy%20S tudy_compressed.pdf at xviii. 12 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 13 of 55 1 Maintaining reliability on a distribution system, particularly where market 2 penetration of rooftop solar has increased significantly, is far more than an engineering 3 challenge. It requires a substantial investment in more modern control and monitoring 4 technology, as well as a substantial rethinking of pricing and the incentives produced 5 from the economic signal produced, in order to move the entire system in directions that 6 will best accommodate all of the changes in the power sector, particularly those related to 7 the increasing deployment of intermittent generating facilities. The complexities 8 associated with solar DG are further compounded by two additional factors. The first is 9 that the locating of solar units is unplanned, and, from a planning perspective, random. 10 That being the case, it is impossible to optimally locate panels to capture system benefits. 11 As long as solar panels are sold or leased on a geographically unplanned basis, there is 12 almost no likelihood that system costs will be systematically reduced by distributed solar. 13 Secondly, distributed solar generation is unseen by ISO New England and is, therefore, 14 not dispatchable. That effectively eliminates the possibility that solar DG makes any 15 contribution to the efficiency of dispatch, enhancement of distribution services, or of the 16 overall energy market in New England.16 17 In the face of concerns about additional ramping and other system management 18 costs required to respond to the new demand patterns created by the adoption of more 19 solar energy, and of cross-subsidies between customers resulting from retail net metering 20 rates, some advocates of RNM call for "value of solar" analyses, in order to claim that 21 additional non-energy attributes of distributed solar generation add substantially to the 16 In fact, witness Mr. Bean references the same issues regarding the lack of planning for distributed solar resources. Indeed, his discussion of those issues directly contradicts the dismissal of those issues by Conservation Law Foundation witness Mr. Chernick as well as the broad claims of value added by solar DG made by Mr. Beach. In essence, Messrs. Chernick and Beach are proposing that solar DG be compensated for services that Mr. Bean effectively conceded may not be provided in the absence of a planning process that currently does not exist. 13 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 14 of 55 1 value provided by solar DG to the utility and other customers. As a result, they argue, 2 concerns about cross-subsidies to solar customers are misplaced. These arguments are 3 discussed in more detail below. However, in order to believe that such cross subsidies 4 among customers are cancelled out by the "value of solar," one would need to believe 5 that the "value of solar" supplied is, ascertainably and quantitatively, worth an amount 6 well in excess of the price of energy in the wholesale market at the time the energy is 7 produced, and, in the case of the Maine Value of Solar study, more than double the 8 delivered price of electricity. I discuss in more detail below why this is simply not 9 credible. 10 Q. 11 12 So, what do you conclude from this about whether cross-subsidies result from RNM? A. The result of the re-allocation of the responsibility for costs is that net metering results in 13 a subsidy from customers without rooftop solar systems to those with solar. These 14 subsidies associated with RNM are particularly hard to defend because, in the aggregate, 15 they benefit wealthier customers at the expense of less affluent customers.17 Less affluent 16 customers lack the means to invest in solar and often do not own their residences, so they 17 are unable to install solar, even if they could afford to do. This gap is exacerbated by the 18 practices of rooftop solar providers like SolarCity, which offer a lease mode for 19 customers without the cash to buy a whole system up front--but the lease product is only 20 available to customers who meet stringent credit requirements.18 17 It is curious that the socially regressive nature of RNM is not identified in any of the cost/benefit considerations of the pro net metering witnesses in this proceeding. It is another example of the cherry picking they engage in in offering up their value of solar contentions. 18 The idea of lowering credit requirements was raised by SolarCity, but there are no immediate plans for doing so: http://www.reuters.com/article/us-solarcity-ficoidUSKCN0T82ZO20151119. 14 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 15 of 55 In addition, RNM encourages rooftop solar providers to "cherrypick" high- 1 2 income, high-energy usage customers. A 2013 study by E3 Consulting clearly shows the 3 socially regressive impact of net metering. The study found that the median income of 4 rooftop solar customers under RNM was 168% of the median California household 5 income.19 A similar analysis of rooftop solar customers in California by Severin 6 Borenstein also found installations, despite some decline in social regressivity recently, 7 "heavily skewed towards the wealthy."20 The Massachusetts DPU only recently made an 8 explicit finding that costs of incentives for on-site generation, such as net metering, 9 disadvantaged the poor and gave the state's low income customers explicit relief from 10 having to subsidize solar DG customers in Massachusetts: "...low-income customers 11 have experienced an increase in bills as a result of the growth of on-site generation."21 12 Q. Are there other negative consequences of RNM? 13 A. Yes. As I mentioned above, other negative consequences that spring from RNM are 14 inefficiency, unfairness to competing technologies, and undermining the long-term 15 prospects of rooftop solar itself. 16 Q. Why do you say that RNM leads to inefficiency? 17 A. RNM encourages inefficient behavior, both on the part of individual customers and the 18 rooftop solar industry as a whole. For individual customers, RNM (especially in 19 conjunction with a flat rate that does not vary with time of day or peak energy demand) 20 fails to provide any incentive to maximize the value (as opposed to the output) of their 19 California Net Energy Metering Ratepayer Impacts Evaluation. Prepared for the California Public Utilities Commission by Energy and Environmental Economics (October 8, 2013). 20 Borenstein, Severin. "Private Net Benefits of Residential Solar PV: The Role of Electricity Tariffs, Tax Incentives and Rebates." Energy Institute at Haas Working Paper. 2015: 26. Paper available online at http://ei.haas.berkeley.edu/research/papers/WP259.pdf. 21 See D.P.U. 15-155, September 30, 2016 at p. 470: http://web1.env.state.ma.us/DPU/FileRoomAPI/api/Attachments/Get/?path=15155%2f15155_Order_93016.pdf. 15 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 16 of 55 1 rooftop solar systems. RNM customers with distributed solar are motivated to produce as 2 many kWh as possible, but not necessarily to target production or manage demand to 3 offset peak consumption. 4 One example of this problem has to do with the orientation of rooftop solar 5 panels. The monetary value of energy provided to the grid by rooftop solar panels varies 6 depending on the time of day. Generally speaking, energy provided at the time of peak 7 usage is the most valuable. That is because the generating fleet is dispatched on the basis 8 that the least expensive plants are generally dispatched first. As demand increases, more 9 and more expensive plants are dispatched until all demand is met.22 However, RNM (in 10 conjunction with flat, time-invariant rates) provides one signal to customers with solar 11 DG systems--the more you produce, the more you are paid, regardless of the energy 12 market prices at the time of production.23 For this reason, as a New York Times article 13 explains, flat RNM pricing has contributed to solar panels generally being installed 14 facing south, to generate the largest total quantity of solar energy over the course of 15 the day (and the greatest savings and/or revenue for homeowners under RNM). If solar 16 rates instead reflected the cost to the grid of the customer's period of highest demand, 17 these panels would be adjusted to capture the most sun during peak hours--for many 18 customers, this would mean aligning panels to face west, generating less total energy, 19 but capturing the late afternoon power of the setting sun. 24 Thus, a customer who works 22 It is worth noting that, in general, the economic order to dispatch power plants also has a salutary environmental effect. That is because, in general, the least expensive plants are either non-emitting of pollutants (e.g. renewables), or low emitting, more efficient plants. 23 Energy prices in the electricity market, as one might expect when supply and demand have to be instantaneously matched, vary widely over the course of every day. Thus, the time at which energy is produced is a critical determinant of the price suppliers are paid. RNM ignores that market place reality and, under RNM, fetches an above market price for solar DG output that is exported onto the grid. 24 Matthew L. Wald. "How Grid Efficiency Went South" New York Times. October 7, 2014. 16 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 17 of 55 1 outside the home and uses air conditioning in the evening during the hot summer months 2 might well offset many (if not all) of his or her kWh of usage through robust rooftop 3 generation--but still might impose a significant peak demand load on the grid when he or 4 she arrives home at 6 or 7pm, when solar production is at or near zero, by turning on air 5 conditioning and other electric appliances. In fact, the savings from solar electricity might 6 even encourage such a user to use more peak electricity than he or she otherwise would-- 7 keeping the house a little cooler, or otherwise being more free with his or her energy use. 8 Indeed, major solar installation company Solar City's own marketing materials, taking 9 advantage of the lack of explicit and transparent demand cost price signals, promote this 10 type of expensive, highly inefficient use of energy.25 Thus, RNM incentivizes 11 production in ways that are optimized for the rooftop solar industry and its customers, 12 not to the system and non-solar customers. 13 Similarly, RNM discourages the adoption of batteries or other forms of storage in 14 conjunction with rooftop solar production. This is because, under an RNM tariff, the 15 utility operates essentially as a giant free battery available for use by DG solar 16 customers--any excess energy they produce is credited back to them at the full retail 17 price, and they can use this credit to import an equivalent amount of energy back from 18 the grid at any time at the full retail price. While at first blush that might seem 19 reasonable, it is not sustainable. Solar production is largely off peak, while substantial 20 imports are required at peak by solar customers. The following three charts show the 21 relationship in New England during different seasons of the year, at a range of different 22 levels of solar penetration. They are copied from the ISO New England's webpage titled 25 A SolarCity advertisement encourages just this behavior: "Go ahead," it reads. "Sleep with the lights on. Solar energy is limitless." https://mobile.twitter.com/solarcity/status/731167148882690048. This advertisement is particularly irresponsible because solar power is not generated at night. 17 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 18 of 55 1 "Solar Power in New: Locations and Impact,"26 and illustrate that facile assumptions 2 made that solar benefits include near-term reductions in peak generation are precisely 3 that.27 26 Page can be found online at https://www.iso-ne.com/about/what-we-do/indepth/solar-power-in-new-england-locations-and-impact 27 Black, John. "Update on Solar PV and Other DG in New England." ISO New England (June 2013). 18 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 19 of 55 1 These three charts dramatically demonstrate that on the days chosen as 19 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 20 of 55 1 representative of summer, winter, and spring in New England, solar PV peak and peak 2 demand are not the same. Solar PV is completely absent during the winter peak and 3 spring peak (however, it is interesting to note that winter solar production suggests the 4 possibility of New England developing its own "duck curve.") During the summer, there 5 is an overlap between solar production and peak demand, but, as can be seen on the chart, 6 and as ISO New England explains in the accompanying text, "Because greater amounts 7 of PV will actually shift the timing of peak demand for grid electricity to later in the 8 afternoon or evening, PV's ability to reduce peak demand will actually diminish over 9 time." It should also be noted that on the days chosen, the sun was shining. The graph, of 10 course, would look very different on cloudy days when solar production is virtually nil. 11 Q. Why do you say RNM is unfair to competing technologies? 12 A. Technologies currently exist that could help customers with rooftop solar to manage their 13 production and consumption so as to maximize the overlap between rooftop solar 14 production and peak demand hours. Possible efficiency enhancers could include simply 15 pointing solar panels to the west, rather than the south, but also using batteries to store 16 off-peak energy, or smart thermostats to optimize energy usage patterns. However, under 17 a flat RNM tariff, DG customers, who would seem to be a natural customer base for 18 energy efficiency and/or capacity savings devices or storage batteries available on the 19 market to better align their energy and capacity demand with system costs, have no 20 incentives to invest in such products, therefore delaying the development of the 21 integrated solar/battery home systems that may be a logical next step for distributed 22 generation. That may be why, for example, Tesla--Solar City's own sister company, run 23 by SolarCity's Chairman Elon Musk, which recently acquired Solar City--reportedly 20 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 21 of 55 1 opposes RNM.28 As this conflict makes clear, RNM removes an incentive for residential 2 customers to deploy batteries and other forms of energy storage. 3 The failure to provide incentives to invest in efficiency-enhancing technologies 4 points to another problem with RNM, which is that it distorts the competitive market for 5 other resources. In seeking cost-effective means of reducing their electricity bills and 6 environmental impact, consumers have a variety of options. Rooftop solar is one 7 possibility, but there are a variety of competing alternatives; many of them provide 8 greater value to the grid, and, absent rooftop solar subsidies, to the customer 9 himself/herself, most notably various energy efficiency programs and means of flattening 10 out their load profile.29 The subsidies associated with RNM, however, substantially bias 11 decisions in favor of rooftop solar over these other options, which would be more 12 efficient, and, in the absence of subsidies, would be the most economic for the customer. 13 Rooftop solar is the most expensive form of commonly deployed renewable 14 generation in the U.S. today. The latest annual update of Lazard's Levelized Cost of 15 Energy Analysis continues to show this, with a levelized cost for rooftop solar ranging 16 from $138-$222 per MWh, higher than all other energy sources analyzed (with the 17 exception of a diesel reciprocating engine), including fuel cell, solar thermal, utility-scale 18 solar, geothermal, biomass, and wind.30 The Lazard analysis goes on to compare the cost 19 of carbon abatement per ton for different alternative energy resources. As one would 20 expect based on its levelized cost, rooftop solar power had the highest cost per ton of 28 "Net Metering vs. Storage Creates Clash Between Some Allies." http://www.eenews.net/stories/1060025111 29 Load profile is the configuration of how much energy a customer consumes (in kilowatt hours (kWh)) and precisely when it is consumed. The time when the demand hits its maximum defines the amount of capacity (in kilowatts (KW)) a utility must have available to serve that customer. 30 Lazard's Levelized Cost of Energy Analysis-Version 10.0. December 2016. Data cited is from p. 2 table, "Unsubsidized Levelized Cost of Energy Comparison." Full report available online at https://www.lazard.com/media/438038/levelized-cost-ofenergy-v100.pdf 21 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 22 of 55 1 carbon emissions avoided ($176 per ton, assuming gas is the comparison generation). In 2 contrast, Lazard's calculations found that utility-scale solar PV could abate the same ton 3 of carbon emissions at a cost of only $1 per ton. The difference here is staggering. 31 4 A recent study by the Brattle Group comparing generation costs of utility-scale 5 and residential-scale PV in Colorado confirms that most of the environmental and social 6 benefits provided by PV systems can be achieved at a much lower cost at utility-scale 7 than at residential-scale."32 RNM, however, operates to make rooftop solar more 8 attractive than other forms of renewable generation via subsidies from non-solar 9 ratepayers, diverting resources away from competing (and, arguably, superior, 10 11 technologies). Q. 12 13 Why do you say RNM undermines the long-term potential of rooftop solar as a competitive energy technology? A. RNM fails to pass on the benefits of the declining costs of solar panels to consumers. 14 The effect of RNM is such that the generous subsidies inherent in the price paid for the 15 energy sold reduces the discipline imposed by having to compete with other energy 16 sources. The result is that the vendors on whom the cross-subsidies are bestowed are 17 relieved of competing for business based on prices and productivity, and are enabled to 18 retain most, if not all, of the benefits of declining costs for themselves rather than passing 19 them on to consumers. In effect, the price of rooftop solar is higher than a competitive 20 market would allow it to be. RNM effectively inflates the price above levels justified by 21 cost or market and reduces the price attractiveness of rooftop solar by extracting dollars 22 from solar customers. This market distorting reality has been shown in recent research. 31 Lazard's Levelized Cost of Energy Analysis-Version 10.0. Data cited is from p. 6 table, "Cost of Carbon Abatement Comparison." Full report available online at https://www.lazard.com/media/438038/levelized-cost-of-energy-v100.pdf 32 Bruce Tsuchida, Sanem Sergici, Bob Mudge, Will Gorman, Peter Fox-Penner, and Jens Schoene, "Comparative Generation Costs of Utility-Scale and Residential-Scale PV in Xcel Energy Colorado's Service Area." The Brattle Group, July 2015, p. 3. 22 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 23 of 55 1 The MIT study, The Future of Solar Energy, observes a "striking differential" between 2 MIT's estimate of the cost of installing residential PV systems (even allowing for a profit 3 margin) and the reported average prices for residential PV systems--actual prices for 4 residential systems were approximately 150% of MIT's cost estimate--a difference 5 between cost and price the MIT researchers did not observe for utility-scale 6 installations.33 Indeed, as documented in the MIT study, there is evidence now that the 7 declining costs of solar panels, which have been quite dramatic in recent years, are not 8 being passed through to consumers, enabling most of the benefits of declining panel costs 9 to be retained by solar vendors, to the detriment of all consumers, solar and non-solar 10 11 alike. A recent study by Lawrence Berkeley National Labs found that out of four 12 countries it compared to the U.S. (Germany, Japan, France, and Australia), the U.S. had 13 the highest prices (per watt of capacity) for installed residential PV systems.34 The 14 reasons for these high U.S. prices are not fully understood--it is something more than 15 market size, since the U.S. market is smaller than the solar pv market in some of the four 16 other countries studied, but larger than others. A 2014 study aimed at better 17 understanding variations in solar pv pricing, involving collaboration between researchers 18 from Yale, Lawrence Berkeley National Laboratory, the University of Wisconsin at 19 20 21 22 23 24 25 26 27 Madison, and the University of Texas at Austin, found a revealing association: "...regions with a higher consumer value of solar, considering retail electricity prices, solar insolation levels, and incentives, tend to face higher prices. This phenomenon may be the result of a shift in consumer demand caused by the presence of rich incentives, enabling entry by higher-cost installers and allowing for higher-cost systems. Alternatively, the results may be a symptom of high information search costs or otherwise imperfect competitions, whereby installers in these markets are able to "value price" their systems, effectively retaining some 33 MIT, The Future of Solar, p. 86. Barbose, Galen and Naim Darghouth. Tracking the Sun IX: The Installed Price of Residential and Non-Residential Photovoltaic Systems in the United States. Lawrence Berkeley National Laboratory (August 2016):22-23. 23 34 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 24 of 55 1 2 3 portion of the incentive offered...In the short-run at least, policies that stimulate demand for PV may have the exact opposite of their intended effect, by causing prices to go up rather than down."35 4 That is, RNM, by effectively shielding rooftop solar suppliers, from both robust 5 competition and from cost-based regulation, may be removing a key incentive for rooftop 6 solar installation companies to pass on declining costs to customers.36 7 8 9 10 11 12 13 14 15 16 17 18 19 In fact, emphasizing this very point, in a recent 10K filing, SolarCity, the nation's largest solar DG company, clearly describes this as its business model: "We compete mainly with the retail electricity rate charged by the utilities in the markets we serve, and our strategy is to price the energy and/or services we provide and payments under MyPower below that rate. As a result, the price our customers pay varies depending on the state where the customer is located and the local utility. The price we charge also depends on customer price sensitivity, the need to offer a compelling financial benefit and the price other solar energy companies charge in the region. Our commercial rates in a given region are also typically lower than our residential rates in that region because utilities' commercial retail rates are generally lower than their residential retail rates."37 From Solar City's perspective, of course, the issue is not whether rooftop solar 20 can be competitive, but whether it can remain so without suppliers like Solar City having 21 to pass on to consumers some of the cost reductions in their supply chain, something that 22 might reduce their profit on a per transaction basis, but make solar more attractive to 23 more customers enabling more sales. In short, Solar City, the leading solar DG provider 24 in the country, has a business model premised on keeping prices high in a declining cost 35 Gillingham, Kenneth, Hao Deng, Ryan Wiser, Naim Darghouth, Gregory Nemet, Galen Barbose, Varun Rai, and C.G. Dong. Deconstructing Solar Photovoltaic Pricing: The Role of Market Structure, Technology, and Policy. (December 2014): 20-21. Available online at: http://www.seia.org/sites/default/files/LBNL_PV_Pricing_Final_Dec%202014.pdf 36 The failure to pass on declining input costs to customers is pricing behavior often considered to be characteristic of monopoly pricing. 37 SolarCity Corp 10K, filed 2/24/15 for period ending 12/31/14, p. 38 (available at http://files.shareholder.com/downloads/AMDA-14LQRE/1445127011x0xS156459015-897/1408356/filing.pdf) 24 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 25 of 55 1 industry, and relying on subsidies and cross-subsidies in lieu of the classic economic 2 formulation that lower prices (in this case enabled from lower costs) stimulate demand. 3 Stated succinctly, the business model articulated by Solar City in its 10K filing, and 4 shared by those solar DG vendors who demand retail net metering, is to chase subsidies 5 and cross-subsidies rather than to compete in the marketplace. 6 This evidence of how major solar installers have a policy of setting prices to 7 capture a maximum share of state incentives suggests that the arguments made by many 8 advocates of continued RNM (for example, this argument is made by Mr. Patrick Bean in 9 his testimony) that limiting DERs will contribute to higher electricity costs. There is no 10 evidence for this--in fact, it is not even clear that lower subsidies for rooftop solar will 11 make it less affordable for homeowners, though it will certainly reduce profit margins for 12 solar installation companies. 13 III. WHY CLAIMS ABOUT THE "VALUE OF SOLAR" DO NOT JUSTIFY 14 RETAIL NET METERING38 15 Q. Witness Mr. Beach and others assert that there are additional "values" provided by 16 rooftop solar that make up for the cross-subsidy inherent in RNM. Does additional 17 "value" provided by rooftop solar change the calculus in establishing rates for 18 distributed generation/partial requirements customer? 19 A. No. In the face of opposition to the substantial cross-subsidies inherent in retail net 20 metering, advocates of RNM, particularly commercial interests who benefit from it, have 21 tried to develop theories as to why the obvious cross-subsidization either does not occur 38 We do not price any other resource in electricity markets based on notions of "value." All other resources are priced by either competition in the marketplace, or based on costs. There is good reason for that. To illustrate what the power sector would look like if we deployed "value" pricing to the entire market, and why we do not use such pricing, I have attached Appendix B, which is an article, The Value of Solar Writ Large, which was recently published by The Electricity Journal. 25 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 26 of 55 1 in RNM, or in some cases have tried to contend that RNM actually constitutes a cross- 2 subsidy from solar customers to non-solar ones. Their line of line of argument is based 3 what has been described as "value of solar" theory, and it is a key area of contention in 4 the testimony on this matter. As I argue below, "value of solar" analysis is inherently 5 problematic, and "value of solar" numbers should be treated with extreme caution. In 6 what follows, I address the following points: ? 7 That "value of solar" harks back to a historically discredited model for pricing 8 resources, which the experience with PURPA in the 1980s has demonstrated is 9 inherently problematic, and that fails to consider the important question of 10 whether claimed benefits can be supplied more cost effectively in other ways; ? 11 That "value of solar" calculations, far from being definitive, are highly subjective, 12 and there is no commonly accepted methodology for conducting such studies, so 13 that not only is every input subject to debates, but there is not even any 14 consensus on what the appropriate inputs are. ? 15 16 That "value of solar" analyses tend to indulge in highly skewed identifications of benefits and costs; ? 17 That a review of the common categories included in "value of solar" analyses 18 show that, with the exception of energy value, most "values" are either imaginary, 19 highly uncertain, arbitrarily fragmented, or more theoretical than real; ? 20 In the case of New Hampshire specifically, as I will go on to explain in more 21 detail, there are a number of significant problems with the analysis presented in 22 The Benefits and Costs of Distributed Solar Generation in New Hampshire report 23 (incorporated into Mr. Beach's testimony as Attachment D) that result in grossly 24 inflated claims of "value" provided by distributed solar energy. 25 Q. Why do you say that "value of solar" is a historically discredited pricing model? 26 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 27 of 55 1 A. "Value of solar" pricing is an attempt to quantify the costs a utility avoids because of the 2 deployment of rooftop solar generation. So-called "avoided cost" pricing has a history in 3 utility regulation. In 1978, Congress enacted PURPA (the Public Utility Regulatory 4 Policies Act). Among other things, PURPA encouraged the development of alternative 5 power, including renewable energy and cogeneration, by requiring utilities to purchase 6 energy and capacity from "qualifying facilities" (QFs) at their incremental or avoided 7 costs. "Avoided costs" was defined as: "[T]he incremental costs to the electric utility of 8 electric energy or capacity or both which, but for the purchase from the QF or QFs, such 9 utility would generate itself or purchase from another source."39 10 There are two fundamentally different methods that have been deployed to 11 ascertain "avoided costs:" an administrative determination or a market based one. Most, 12 if not all of the "value of solar" analyses, including the one conducted in New 13 Hampshire, call for the use of administrative determination. Unfortunately, that 14 methodology has a history that does little to recommend it. 15 After the passage of PURPA in 1978, efforts to calculate "avoided costs" rapidly 16 encountered difficulties. As one article describing avoided cost pricing under PURPA 17 18 19 20 21 22 23 24 25 26 observed: "Errors in the estimation of long-run avoided costs are inevitable. However, as PURPA was implemented by state regulators in the 1980s, a combination of questionable methods of setting avoided cost and/or poor application of these methods led to excessive avoided cost payments and forced utilities to buy QF capacity even when the utilities did not require more capacity. In addition, excessive, non-dispatchable QF output created operating problems for some utilities. Many complaints about PURPA's implementation were raised by electric utilities and others."40 39 18 CRF ?292.101(b)(ii)(6) (Public Utility Regulatory Policies Act of 1978). 40 Graves, Frank, Philip Hanser, Greg Basheda. "PURPA: Making the Sequel Better than the Original." Prepared for the Edison Electric Institute (December 2006). 27 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 28 of 55 1 The results of that experience of administratively determining avoided costs had 2 severe consequences. In those states that, as the quote above suggests, came to inflated 3 conclusions, the result was an oversupply of generation locked into long term contracts 4 that were well in excess of market prices, thereby leaving utilities and their customers 5 stuck with very high prices and stranded assets. The entire situation became so untenable 6 that the FERC had to intervene and compel the states to use competitive mechanisms, 7 rather than administrative means, to determine avoided costs and abandon the 8 arbitrariness and methodologically suspect use of administrative mechanisms along the 9 lines proposed by witness Mr. Thomas Beach and others in this proceeding. As someone 10 who served as a Commissioner in the 1980's and early 1990's when the PURPA avoided 11 cost debate was occurring, Mr. Beach's testimony is eerily familiar to me, as he 12 advocates that we go down a path that we know from history will benefit a few favored 13 developers, in this case solar pv vendors, in the short run, but leave everyone else stuck 14 with a very big bill. As was clearly demonstrated by the PURPA experience, avoided cost 15 analysis is subject to the biases and policy predispositions of the authors and/or sponsors 16 of such studies. 17 Q. Does "Value of Solar" analysis incorporate any competitive metrics? 18 A. No, it most certainly does not. The methodology offered by Mr. Beach and advanced by 19 other Value of Solar advocates makes no effort to ascertain whether the "values" 20 supposedly provided by solar pv might be provided more cost-effectively in some other 21 way. It simply states that they are provided by solar pv, and there is no competitive 22 analysis of whether there are alternative ways of achieving the same results at a lower 23 price. --Thus, there is no guarantee that customers are getting the best value. In fact, as 24 discussed below, unlike in the classic PURPA avoided cost analysis, where the Available online at http://www.eei.org/issuesandpolicy/stateregulation/Documents/purpa.pdf 28 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 29 of 55 1 product/service being offered is, in fact, certain to be delivered, may of the values 2 claimed by VOS advocates, such as Mr. Beach, are more theoretical than real, and in 3 some cases are simply non-existent. Analyzing the "value" of rooftop solar in isolation 4 produces an essentially meaningless number, in the absence of similar "value" analysis 5 for all other competing resources and in the absence of assuring that the values claimed 6 are actually delivered.41 VOS studies are technology-specific (almost always limited to 7 rooftop solar) and almost always ignore market conditions and how the calculated value 8 of rooftop solar compares with the value of competing resources to meet the same 9 objectives. 10 In addition, VOS studies rarely, if ever, look at the opportunity costs associated 11 with spending money on rooftop solar, as opposed to using that money on something that 12 provides any of the products and services being claimed for solar pv, such as energy, 13 capacity, and/or emissions reductions more efficiently (many other major renewable 14 technologies, as discussed above, beat rooftop solar by these measures). This kind of one- 15 dimensional, out-of-context analysis of an extraordinarily complex subject is almost 16 useless as an evaluative tool, much less a rationale to justify administrative extractions of 17 higher rents from consumers. 18 19 Interestingly, VOS studies single out just one technology for "value based" compensation, solar DG. Tellingly, such studies never explore the implications of retail 41 SolarCity witness Mr. Bean, for example, points out that location is very important if solar pv were to provide distribution system benefits. As he points out, that would require a level of planning and coordination between solar developers and utilities that do not currently exist. His basic point, however, is correct. For that reason, distribution benefits are theoretically possible, but, in the current circumstances of no coordination planning and random location of solar DG units, actual delivery is not only highly dubious, it is improbable. In marked contrast to that reality, Mr. Beach, as well as Conservation Law Foundation witness Mr. Paul Chernick, just make a leap of faith that, simply because system benefits are theoretically possible, regulators should deem them delivered and worthy of compensation, thus rendering consumers liable for "phantom" services that never actually materialize. 29 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 30 of 55 1 net metering or any other form of pricing on performance and innovation over time. In 2 short, it is a claim of value out of the context of the market, costs or performance 3 incentives. Most tellingly, every other product and service offered in the electricity 4 marketplace is simply ignored, and it is presumed that they will be priced by either 5 competition in the market, or based on costs. Appendix B, a recent article I published in 6 The Electricity Journal, is a glimpse of what would happen if VOS theory were writ large 7 across the power sector. It is designed to provide a broader perspective on many of the 8 flaws in inherent in "value based" pricing that removes the discipline of either 9 competition or cost based regulation. 10 Q. In his testimony, Mr. Thomas Beach asserts that there are "well accepted 11 techniques" for analyzing the "value" of solar. Do you disagree with the implication 12 that an accepted methodology exists? 13 A. I do disagree. The reality is well illustrated by the extraordinarily wide variance in the 14 conclusions of VOS studies. The range is dramatic, with a VOS study in Louisiana 15 finding a negative value (principally because it considered the cost of other government 16 subsidies already supporting solar, which are usually excluded from such discussions 17 even though they do constitute a social cost), with nearby Maine's VOS having the 18 distinction of being an extreme outlier on the high value side, with a calculated "value" in 19 Maine of 33.7 cents/kWh.42,43,44 Additional disagreement exists over the individual 42 Dismukes, David E. Estimating the Impact of Net Metering on LPSC Jurisdictional Ratepayers. Prepared on behalf of the Louisiana Public Service Commission. Prepared on Behalf of Louisiana Public Service Commission Draft, February 27, 2015. Please see: http://lpscstar.louisiana.gov/star/ViewFile.aspx?Id=f2b9ba59-eaca-4d6f-ac0b-a22b4b0600d5. 43 Grace, Robert C., Philip M. Gruenhagen, Benjamin Norris, Richard Perez, Karl R. Rabago, and Po-Yu Yuen. Maine Distributed Solar Valuation Study. Prepared for the Maine Public Utilities Commission. Revised April 14, 2015. Please see: http://www.maine.gov/mpuc/electricity/elect_generation/documents/MainePUCVOS -ExecutiveSummary.pdf. 44 To put the 33.7 cents /kWh valuation in perspective, that number is more than double the full retail rate of Maine's largest electric utility. In other words, the authors of 30 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 31 of 55 1 components that make up VOS analysis, as well as the correct context within which 2 assessment should be made. For example, even the pro-net energy metering witnesses in 3 this case do not agree on the proper "value of solar" approach. While Mr. Beach suggests 4 that the Commission must review the value from three possible perspectives (the solar 5 rooftop owner, ratepayers in general, and the utility as a whole),45 Mr. Phelps argues that 6 it is the perspective of society as a whole that should be given priority.46 Simply stated, 7 there is no consensus on how such studies should be deployed (e.g., to actually set prices, 8 to justify retail net metering, etc.?), how they should be conducted, how deliverability of 9 value should be judged, how one should define capacity for ratemaking purposes, 10 whether energy prices should be assessed in real time or some other fashion, how 11 employment benefits and costs should be evaluated, how much to rely on forecasts and 12 levelizing costs and benefits, etc. There is almost no component of VOS analysis for 13 which there is any commonly accepted methodology or framework. In short, VOS is 14 subjective analysis subject to the whims and biases of whoever chooses to author such a 15 study, and cannot be relied upon for any serious examination of pricing and ratemaking. 16 Q. 17 18 Why do you say that most "values" asserted for solar in VOS studies are either imaginary or uncertain? A. Even a cursory analysis of the various individual elements generally offered up to 19 calculate the value of solar suggests that, with the exception of avoided short-term energy 20 costs, and perhaps, on a time and location specific basis (as suggested by witness Mr. 21 Bean, but ignored by witnesses Mr. Beach and Mr. Chernick), some savings on 22 transmission congestion (although it is entirely possible there could be congestion costs, 23 rather than savings, depending on circumstances), there is little bankable value there. Few that study calculated that the "value" of the energy produced by each rooftop solar installation is worth double the full delivered cost of electricity. That is the equivalent of saying that the value of a part of a product is worth double the value of the entire product. 45 Beach testimony, 8-9. 46 Phelps testimony, 9. 31 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 32 of 55 1 of the "values" attributed to rooftop solar in New Hampshire's or other VOS studies 2 stand up to scrutiny, and those that do are compensated under appropriate ratemaking, to 3 the extent they are real.47 4 Q. How do you evaluate claims about "levelized" avoided energy costs? 5 A. Rooftop solar generation, when produced, does reduce the amount of energy the utility 6 must provide at the time the solar units are producing. Almost every participant in the 7 conversation about solar DG agrees on this.48 Caution should be exercised, however, 8 when the suggestion is made that the value of the generation to be offset should be 9 calculated on a "levelized" basis--projected for twenty years or so, and then averaged. 10 This "levelized" analysis introduces unnecessary, highly uncertain, and unhelpful 11 speculation about future gas prices and inflation, while doing little to illuminate how 12 actual current cost savings should be considered. A "levelized" value number looks 13 bigger, but caution must be used in understanding what this number means--comparing a 47 An example of appropriate ratemaking compensating rooftop solar for benefits would be to apply the relevant locational marginal price (LMP) to the price paid for rooftop solar exported to the grid. That automatically captures not only the precise avoided energy cost at the same time that the energy is produced, but also captures the transmission congestion benefit (or cost, depending on the circumstances at a given location at a given time). 48 Many value of solar analyses present the avoided energy cost as a "levelized" number, which factors in predictions of increasing energy costs in upcoming years to come up with a "levelized" avoided energy cost which is higher than the actual energy cost today. It is tempting here to focus on the fallibility of making reliable predictions about future energy costs (look at recent trends in natural gas prices. Most people did not foresee recent declines). But the whole issue of prediction is a red herring in this context, because RNM does not provide utilities with ownership of distributed solar resources, and therefore gives it no protection against future energy price increases. If an RNM system of compensation continues, reimbursement rates will always be tied to overall energy price increases. So costs of RNM to the utility will go up right along with savings. Trying to give solar resources credit ahead of time for rising energy costs needlessly complicates the analysis, which would then have to be balanced with appropriately rising net energy metering costs. It is simpler and less misleading to use current avoided energy costs, recognizing that these need to be updated regularly. 32 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 33 of 55 1 larger "levelized" value of solar against current (non-levelized) costs of RNM, for 2 example, is comparing apples and oranges. 3 Q. (generation and transmission)?49 4 5 What is your assessment of the claimed value associated with avoided capacity costs A. The idea that having a lot of distributed solar on the system means that the utility requires 6 less capacity of various kinds is one of the commonly asserted claims made by retail net 7 metering advocates.50 These claims are unfounded. Solar energy is intermittent and only 8 available when the sun is shining, and, in the case of rooftop solar, only available for 9 export to the grid if the sun is shining and if the solar customer is not using the energy 10 produced on his/her rooftop. It is not and cannot be relied upon to produce any energy 11 when called upon to do so, nor to reduce demand reliably, because there is no way to be 12 certain that the conditions necessary for rooftop solar energy to deliver energy when 13 called upon to do so will be met. In fact, since solar DG is not visible to the system 14 operator, it is not dispatchable. Its energy output, whenever it exceeds on-premises 15 demand, simply flows into the system. Thus, unlike every other form of generation, it is 16 not dispatchable. 17 Of course, in their planning, utilities do consider the potential impacts of rooftop 18 solar generation on overall capacity needs, from a probabilistic point of view. However, 49 Capacity in electricity refers to the resource's ability to produce energy (a generating resource) or to deliver energy (a transmission or distribution resource) when called upon to do so. What is produced (or delivered), of course, is energy. 50 The testimony of Patrick Bean in this case is a good example. Mr. Bean suggests that the utility "leverage customer investments" to reduce needed investments in capacity, saving money overall (p. 8). This argument invokes the commonly heard idea that customer money invested in rooftop solar is "free." Under RNM, this is far from the case--RNM payments amount to a much higher cost that a utility would have to pay for any traditional capital investment loan. In fact, Mr. Bean may recognize this, because he goes on (p.8) to suggest a competitive bidding process that has nothing to do with RNM--in fact, RNM itself prevents development of such a process. Why should third parties bid to receive a competitive price, when a generous non-competitive subsidy is available? 33 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 34 of 55 1 as a former regulator, I believe there is an important distinction to be made in thinking 2 about capacity from a ratemaking standpoint, as opposed to a planning standpoint. From 3 a ratemaking standpoint, payments for capacity should depend on performance. 4 In the wholesale market, when a generator obtains a capacity payment, the 5 generator agrees to either deliver the energy when called upon to do so, or assumes 6 liability for supplying replacement energy. In contrast, rooftop solar providers under 7 RNM make no such assurances. If the utility incorporates this "value" into rates, it 8 potentially pays twice--first, in a lower rate for rooftop solar customers, and, second, if 9 the rooftop solar producer fails to deliver, the utility must pay again, this time to an 10 alternative supplier to provide what the solar provider did not. Indeed, given solar's 11 intermittency, it would have to pay not only for the replacement energy that the solar 12 provider failed to deliver, but also, perhaps, have to pay for the capacity required to back 13 up the solar units. It is, quite simply, a "heads I win, tails you lose" proposition. From a 14 consumer perspective, the capacity value claimed by VOS proponents is for phantom 15 capacity, not something real. Consumers should not be obligated for capacity that cannot 16 be relied upon either physically or financially. 17 In regard to transmission capacity, solar DG has virtually no impact whatsoever 18 for a couple of the reasons. The first, as discussed above, is that intermittency requires 19 backup not only in generation but also in terms of the transmission capacity to deliver. 20 The second reason is due to scale. Displacing transmission capacity with distributed 21 energy is not the "just in time" arrangement suggested by Mr. Beach. Rather, it is the 22 result of extensive long term planning on an interactive basis with multiple parties 23 looking out over a long term time horizon. It also involves capturing economies of scale, 24 as well as optimal utilization of scarce right of way. Thus, the small scale of rooftop solar 25 units, coupled with the uncertainty of how much will materialize and over what time 34 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 35 of 55 1 frame, and in the context of intermittency, makes it extraordinarily unlikely that solar DG 2 will have any appreciable impact on displacing the new for transmission capacity. 3 Q. 4 5 What is your view on claims of potential savings related to power flow--savings due to reduced line loss reductions and ancillary services requirements? A. It is true that energy losses occur during transmission and distribution. However, whether 6 or not rooftop solar systems reduce the amount of energy lost in long distance 7 transmission and distribution is a fact-specific question, dependent on an array of 8 variables (including the location and times of generating energy of rooftop solar 9 systems), and the answers may be counterintuitive. Electricity flows on wires according 10 to laws of physics, following the course of least impedance, a natural phenomenon 11 impacting every interconnected wire, regardless of whether the wire is sized to withstand 12 the current.51 As a result, energy flow on the grid is highly dynamic in real time. Every 13 injection or withdrawal of energy impacts the ability to access the grid throughout the 14 system. Maintaining optimal grid functionality requires careful planning, vigilant and 15 prudent dispatchers, and the ability to call upon resources to provide what are called 16 ancillary services, such as voltage support, reactive power, black start, and other very 17 location and time specific service that are essential to grid operations, many of which also 18 affect line losses. 19 Thus, with respect to the distribution grid, the production or non-production of 20 energy affects line losses on a very location- and time-specific basis. While it is true that 21 DG can have a salutary effect on line losses, it is equally correct to say that it could have 22 an adverse effect on line losses. As a matter of physics, there is simply no generic "value" 51 The flows of the high voltage transmission system and the low voltage distribution system are separate and distinct from one another, so the flows according to least impedance are system specific. While demand shifts at any given interconnection point where high voltage is stepped down to low voltage can influence flows on the high voltage system, the actual flows between the two systems are separated by transformers, so the flows between systems are controlled. 35 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 36 of 55 1 associated with rooftop solar reducing line losses on the distribution grid. Indeed, as 2 noted above, given the random, unplanned siting of solar DG units, the likelihood that 3 solar panels will be optimally located and in appropriate configurations to add system 4 value is almost non-existent. Solar City Witness Bean, as noted above, essentially 5 concedes that point. VOS claims of such value are little more than claiming that solar 6 producers are entitled to compensation for system benefits that, perhaps, in theory they 7 could provide, even though they simply cannot be relied upon to deliver, and, given that 8 the siting of solar pv units is unplanned, that they more often than not do not deliver.52 9 With respect to the transmission grid, the issue is a bit different, because rooftop 10 solar is not directly interconnected to the high voltage system. Nonetheless, rooftop 11 solar, simply as a matter of scale, probably has very little impact on transmission line 12 losses. Further, (here the counterintuitive interconnected properties of electricity grids 13 come into play) there is no simple and reliable relationship whereby less power delivered 14 to a certain location guarantees less congestion on the grid, and correspondingly fewer 15 transmission losses. Injections and withdrawals of electricity to and from an 16 interconnected grid impacts the whole grid. Inputs into the grid need to be carefully 17 balanced with withdrawals to avoid overloading any specific wire and to allow for access 18 to the cheapest possible generation. The impact of lessening demand from a particular 19 node on the grid depends on the specific constraints affecting dispatch at a given point in 20 time. Just as in the case of distribution, to the extent that rooftop solar impacts 21 transmission line losses at all, it is very location and time specific, so generic conclusions 22 are simply not reliable.53 If utilities got to select exactly where distributed generation 23 was installed, it might be possible to leverage DG to provide more reliable transmission 52 See Footnote 14 above for more discussion of these issues. For a technical discussion, see M. Rivier, "Electricity Transmission," in PerezArriaga, ed. Regulation of the Power Sector (p. 276, footnote 8), which acknowledges that in some cases, increased demand at a node (a distribution node) can decrease system costs overall. 36 53 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 37 of 55 1 and distribution benefits. But this not currently how distributed generation installations 2 work. 3 For this reason, there is no basis to claim that solar PV systems, ipso facto, reduce 4 losses. Furthermore, additional costs can also be the result of efforts to incorporate new 5 DG. On distribution systems, this point is being debated among experts, and it appears to 6 be that DG could well, in some circumstances, increase losses or cause additional costs to 7 be incurred to cope with the newly bi-directional energy flow on the distribution grid, 8 which was designed and built to accommodate one directional flows. With regard to 9 transmission losses, it is certainly true that distributed solar PV does not rely on high 10 voltage transmission. That, however, is no assurance of value. Rooftop solar can also 11 adversely impact the transmission system because of its intermittent and unpredictable 12 nature, which requires utilities to incur expenses to assure that backup power is available 13 in order to be able to instantaneously call upon other resources. Similarly, even when 14 solar units are producing energy, those flows have the potential to cause changes in the 15 flows on the high voltage transmission in ways that add congestion to the system. Should 16 either such circumstance occur, it is likely that losses would be increased, not decreased. 17 Ancillary services, similarly, can be impacted in both positive and negative ways 18 by distributed solar generation. Certainly, there is the potential for distributed solar 19 installations to include "smart inverters," which have the potential to provide frequency 20 regulation and reactive power even when the sun is not shining--but these are potential 21 capabilities, which RNM does nothing to incentivize, and which should be thought of as a 22 separate product from rooftop solar. To realize the potential benefit here, some form of 23 separate compensation would be needed--and, in my opinion, such compensation should, 24 like compensation for other forms of ancillary services, be provided as a result of services 25 actually provided, not in the hope of services that could potentially be provided at some 26 future date. 37 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 38 of 55 1 Q. 2 3 What about the value attributed to environmental benefits, especially reduced costs for emission mitigation? A. Even the emissions mitigation benefits claimed for rooftop solar are not unquestionable. 4 Rooftop solar may have no emissions when producing energy54--but this is only a 5 benefit if it is displacing fossil fuel generation of electricity, not competing non-carbon 6 resources such as utility-scale solar or wind. It is simply impossible to show that rooftop 7 solar always displaces carbon emitting units, or that it does so in reasonably efficient, 8 cost effective, way.55 The issue is made even more complex by the fact that even when 9 carbon emitting plants are being displaced, those displaced plants are forced to ramp up 10 and down in response to the intermittent flow of the solar produced energy because of the 11 "duck curve" referenced above. Such ramping, in most fossil plants, runs contrary to the 12 design parameters of the plant, therefore causing it to operate on a considerably less 13 efficient basis, a circumstance which is very likely lead to more emissions, not less. It is 14 also true that in New England, off-peak energy such as rooftop solar will not displace 15 high emitting plants, such as coal56 or oil,57 whose operating characteristics and dispatch 54 If one considers the entire cycle of manufacturing solar panels, most of which are made in the world's most carbon intense economy, China, plus the necessity of shipping the panels halfway around the world, it can hardly be argued that solar PV is carbon neutral. 55 Indeed, based on the Lazard study noted earlier, we know for a fact that using rooftop solar to reduce carbon emissions is more expensive and less efficient than using other renewable energy sources for doing so. Similarly, purchasing renewable energy credits in states and/or regions whose power sector is more coal intensive than New England would also be a more cost effective means of reducing carbon emissions. In essence, advocates of prioritizing rooftop solar to reduce carbon emissions are calling for consumers to pay far more to reduce carbon than they would otherwise have to spend. That is not only unfair to consumers, but is also likely to significantly dampen the public appetite for reducing greenhouse gas emissions. For those of us concerned about climate change, that could have highly adverse consequences. 56 It is worth noting in this context that New England has very few coal burning plants and those that remain are slated for retirement fairly soon. Moreover, those that are operating are baseload units which are not designed to ramp up or down depending on the state of solar production. 38 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 39 of 55 1 history demonstrate that they are extremely unlikely to be displaced by rooftop solar. 2 That is because, as noted above, solar DG is almost always off peak, so that oil units are 3 not running, and because the few coal plants remaining in New England tend be baseload 4 and are unlikely to be displaced. What is likely to be displaced are natural gas units, 5 which are low level emitters. Hence using solar to offset low emitting natural gas fired 6 plants is an economically inefficient way to reduce carbon. In fact, given that there is a 7 regional cap on carbon under the Regional Greenhouse Gas Initiative (RGGI), in which 8 New Hampshire participates, any carbon reduction through net metering, a mechanism 9 outside of the RGGI cap, serves to drive down the price of carbon in the marketplace, 10 thereby making carbon reduction less efficient, more expensive, and suppressing the 11 development of more efficient technologies to reduce carbon emissions. Simply stated, it 12 is counterfactual to assume, as a linear proposition, that more rooftop solar means fewer 13 emissions. 14 Q. Is there real value associated with avoided purchased power risk, or "hedging?" 15 A. Not for the utility or its non-solar customers. Many "value of solar" advocates suggest 16 that distributed solar power should get credit for being a hedge against increasing natural 17 gas costs. This claim does not make sense in the context of RNM and the value 18 distributed solar offers to the system as a whole. Solar power potentially has value as a 19 hedge against natural gas, but only for the owner of the solar panels, or for an entity with 20 a guarantee that it can obtain reliable energy supply from the panels at a fixed, 21 unchanging price. For a utility that will be buying power from solar panel owners, and 22 the customers those costs will be passed on to, without a long term fixed price contract 23 (as is the case under RNM, which varies with the retail rate) the hedge value under net 24 metering is nonexistent. More important, however, is the fact that the RNM price to be 57 To the extent that oil fired plants are still utilized in New England, they are generally peaking units. Given that solar production in the region is almost entirely off peak, oil plants are not displaced by solar DG. 39 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 40 of 55 1 paid by the utility for power from rooftop solar will include all of the elements included 2 in the monthly electric utility bill, including the full cost of energy. When gas is 3 expensive, the price paid by non-solar customers will be higher; when it is cheaper, it will 4 be lower. Given that the retail rate paid for rooftop solar includes the cost of energy, it is 5 literally impossible for solar DG to serve as a fuel hedge for non-solar customers. So, if it 6 is worth hedging against variations in the price of natural gas, the utility should buy the 7 same hedge against variations in the price of rooftop solar power sold under RNM. From 8 the utility's and the non-solar customer's point of view, the two costs will vary together. 9 Thus, the hedge value is not only zero; any consideration paid for such a hedge would be 10 more expensive than incurring the risk from which protection is sought--this is like 11 paying for vacation insurance that costs more than the trip itself. 12 Q. What about the value of "market price mitigation"? 13 A. Another supposed value attributed to rooftop solar in many VOS studies is that by 14 reducing demand, rooftop solar will suppress the market price for energy. This argument 15 is seriously flawed in more than one way. 16 In the first place, under RNM, the price of rooftop solar is not market-based, or 17 even cost-based. In fact, where there is RNM, the rooftop solar price is unreasonably and 18 arbitrarily linked to the full retail price of delivered electricity, as opposed to the level of 19 energy prices, where it should be. While, arguably, the availability of highly-subsidized 20 rooftop solar could have the effect of reducing demand for wholesale energy (although 21 considering the scales involved it seems improbable that the reduction would materially 22 impact wholesale energy prices), there would be no price benefit for consumers since 23 rooftop solar, priced at full retail levels, or at the levels dictated by the inflated claims of 24 many VOS papers, would consume all of the savings and leave little or no benefit for 25 customers. 40 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 41 of 55 Setting aside the high price customers are being asked to pay for this "savings," 1 2 the second problem to flag here has to do with the different market effects of a low-priced 3 competitive resource and a low-priced subsidized resource. If a competitively priced, not 4 heavily subsidized, source of energy caused prices to decline, that would be a good thing, 5 but that is not at all what VOS studies are suggesting will happen with rooftop solar. 6 Rooftop solar is subsidized by tax credits, REC/SREC markets, and by the cross-subsidy 7 inherent in net metering and volumetric rate design. It is hard to find any economic logic 8 to support the notion that markets are well served by using heavily subsidized products, 9 such as rooftop solar, to drive down prices in the competitive marketplace. 10 To the extent that highly subsidized products compete with unsubsidized products 11 in the marketplace, this distorts the market, rather than strengthens it, making it hard for 12 otherwise competitive energy generators to stay in business. In the long run, this 13 distortion exacerbates the capacity issues that many markets struggle to correct through 14 capacity payments. Thus, if one assumes that rooftop solar somehow suppresses prices in 15 the energy market, this would be highly unfortunate--it could do very serious damage to 16 the power sector. The claimed price suppression "value" is not a value at all. 17 Q. 18 19 Is there real value associated with avoided distribution grid costs, resulting from rooftop solar? A. While it is theoretically possible that there could be benefits for the low voltage grid as a 20 result of distributed solar generation, it is also possible that there will be more costs than 21 benefits. Distributed generation imposes costs and burdens on the grid by adding 22 transaction costs and, in many cases, by compelling substantial changes in local networks 23 to reflect the fact that the flow of energy is being changed from one directional to 24 bidirectional. Significant geographic concentration of solar PV may cause the utility to 25 have to make very substantial capital investment to upgrade the grid to accommodate the 26 new flows put on the system. In California and New York, in fact, serious consideration 41 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 42 of 55 1 is being given to totally restructuring distribution grids in order to effectively manage the 2 new flows, both physical and financial.58 While such accommodations can be made, 3 policy makers do need to understand that there are costs associated with making them and 4 should be mindful of who must bear responsibility for those costs. 5 Part of the problem is that, unlike all of other energy resources whose siting is 6 part of a carefully planned integrated process, in which the connecting infrastructure is 7 often dealt with concurrently, or is capable of anticipation, distributed generation is 8 completely unplanned. In fact, since the installation of rooftop solar is the result of an 9 individual's decision, there is no possibility to plan. The result is that the operator of the 10 low voltage grid has to constantly play "catch up," a process which can be time 11 consuming and costly.59 Moreover, even in cases where a rooftop facility does reduce 12 distribution costs, that is a specific function of location and time, something which may 13 not be true of a neighbor's facility, much less one located across town. Thus, any generic 14 claim that the installation of rooftop solar adds value to the grid simply cannot be 15 regarded as credible. 16 Q. 17 18 19 Should value be attributed to rooftop solar based on its impact on economic development and jobs? A. No. Advocates of subsidies for distributed solar generation often point to supposed economic benefits--particularly job creation in the solar installation field.60 But claims 58 Southern California Edison recently put forward a rate case which included $2.3 billion for changes to the grid to accommodate distributed energy resources. See September 21, 2016 Utility Dive article: http://www.utilitydive.com/news/how-southerncalifornia-edisons-new-rate-case-would-transform-the-grid/426493/ 59 Mr. Patrick Bean, as noted elsewhere, in fact recognizes, in his testimony, that problems are created by lack of control over siting, suggesting a system of incentives for siting generation in higher-value locations. (Bean, p. 11). 60 There may be some question as to the quality of at least some of the jobs the solar witnesses claim will be gained. In its most recent 10K filing with the SEC, Solar City, the largest vendor/lessor of solar DG, acknowledges a pending investigation by the U.S. Department of Labor (Solar City 10K Annual Report, Feb. 2016, p. 33, available online at: https://www.last10k.com/sec-filings/scty#Item_1A). 42 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 43 of 55 1 about a positive impact on job creation are one-sided--they count new jobs created in 2 solar--but if the cost of electricity is higher, jobs are likely to be lost elsewhere in the 3 economy--there is no reason to assume that the net job impact of distributed solar power 4 is positive. In fact, a recent study by Tim James, Anthony Evans, and Lora Mwaniki- 5 Lyman of Arizona State University used an Arizona-specific regional economic model (a 6 REMI model), balancing the costs of installed rooftop capacity (and related financing 7 costs) against what APS estimates to be the related savings on generation purchases and 8 generation capacity investment over thirty years (and their related customer savings), 9 based on different levels of investment in solar DG that might be made in the APS 10 service territory. This study models the complexity of judging the economic and job 11 impacts of a particular policy or subsidy--of course, there is an immediate positive 12 impact on some jobs from additional solar employment, but, over time, taking into 13 account the effects of lost spending power by consumers who have to pay more for their 14 electricity, the projected impacts on jobs and on the gross state product of the Arizona 15 economy are decidedly negative (for example, the model shows cumulative losses in 16 gross state product, over time, in the multiple billions of dollars).61 17 The argument that solar DG creates jobs is not only wrong on the facts; it sets a 18 disturbing precedent. In essence, the argument that inequitable solar DG cross-subsidies 19 must be continued because of the potential impact of any change on solar jobs is the same 20 one dimensional, simplistic, and, frankly, irrelevant argument as that made by the coal 21 industry against carbon controls--that coal mining and related jobs may be lost. This is 22 not a good argument applied to coal, and it is not a good argument applied to solar DG. 61 James, Tim, Anthony Evans, and Lora Mwaniki-Lyman. "The Economic Impact of Rooftop Solar in the APS Service Territory, 2016-2035." Report, L. William Seidman Research Institute, W.P. Carey School of Business, Arizona State University, February 16, 2016. (available online at: http://seidmaninstitute.com/wpcontent/uploads/2016/03/ASU-Seidman-study-2016_FINAL.pdf) 43 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 44 of 55 1 Before leaving the topic of jobs, it is worth remembering that most solar panels 2 sold or leased in the U.S. are manufactured in China. In all likelihood, more American 3 jobs are associated with other forms of generation. 4 IV. PROBLEMS WITH MR. BEACH'S NEW HAMPSHIRE "VALUE OF SOLAR" 5 ANALYSIS 6 Q. Hampshire presented by Mr. Beach in his testimony? 62 7 8 9 Do these general objections apply to the analysis of the value of solar in New A. Yes. Mr. Beach's analysis is unusual only in that it is particularly difficult to follow, due mostly to Mr. Beach's insistence that the Commission must consider value from multiple 10 perspectives, though also to a system of results reporting that switches between $/kWh 11 and $/mWh, and that doesn't always make clear the results of which of the four tests Mr. 12 Beach uses are being reported. My analysis, below, focuses on Mr. Beach's "ratepayer 13 impact measure" test, which is the only test relevant to the question of the existence of 14 cross-subsidies. I examine some of the key value categories and explain what is wrong 15 with the methodology and findings of the study in these areas. 16 Overall, Mr. Beach's "ratepayer impact measure" barely breaks even for 17 residential ratepayers (it does a little better for the commercial sector). As I argue in what 18 follows, when you consider all the costs that Mr. Beach omits and all of the benefits he 19 unjustifiably includes, it is clear that this apparent narrow ratepayer benefit is non- 20 existent and that, in fact, a significant cross subsidy is occurring under New Hampshire's 21 current net energy metering rates.63 62 Although Mr. Chernick also addresses the issues discussed by Mr. Beach, I am largely ignoring his comments on the subject, in part because that would be repetitive, but also because, unlike Mr. Beach, Mr. Chernick makes no effort to substantiate his claims. 63 Mr. Beach himself does not seem to be convinced by his own analysis that there is no cross subsidy. Though his analysis asserts that ratepayers are benefiting, or at least breaking even, under current net energy metering rates, elsewhere in his testimony he 44 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 45 of 55 1 Q. 2 3 Do you agree with the criteria Mr. Beach suggests should be used for evaluating changes to rate design applicable to net-metered customers? A. No. Mr. Beach states that any new design "should be tested to ensure that, after it is 4 applied, DG will remain a viable economic proposition for participating ratepayers."64 I 5 strongly disagree. The Commission has no obligation to ensure that rooftop solar 6 customers must be able to make money from their investment, particularly if (as is the 7 case), keeping rooftop solar customers "in the money" requires significant subsidies from 8 customers without rooftop solar. It is interesting to note that this proposed criterion puts 9 zero pressure on rooftop solar companies to reduce costs and perhaps to accept lower 10 profit margins, or even pass on the declining costs of solar panels in order to keep rooftop 11 solar investments appealing. Profitable rooftop solar investment may well be possible 12 under a fair approach to energy billing--but this may require a re-negotiation of terms 13 between rooftop solar customers and rooftop installation companies. It is in no way the 14 responsibility of the Commission to guarantee that these systems will be profitable. It is 15 the responsibility of the industry, under fair pricing and open competition, to demonstrate 16 to potential rooftop solar customers that it can provide real value. For this reason, I 17 suggest that the time and attention Mr. Beach spends in his analysis of the value of solar 18 to rooftop solar customers under current net energy metering programs is irrelevant to the 19 question of whether such rates should be changed. Finally, Mr. Beach's basic premise is 20 that the design of rooftop solar rates should be focused on maximizing the number of 21 units sold. In my view, that may be the commercial objective of his clients, but it is 22 decidedly not the type of balanced and nuanced public policy one would expect from 23 regulators and policymakers. argues for the benefits of a minimum bill based on the likelihood that it will reduce the size of DG rooftop installations, "thus reducing the cost of net metering for other ratepayers." (Beach testimony, p. 37). Beach's argument here is not consistent with his claim that rooftop solar is a net benefit on all his measures. 64 Beach testimony, 29. 45 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 46 of 55 1 Q. Are there any major ratepayer impacts omitted by Mr. Beach in his analysis? 2 A. Yes, absolutely. First, in his testimony, Mr. Beach notes that the cost-benefit analysis of 3 solar DG he performs "focuses on generation exports."65 This means that, from the point 4 of view of analyzing cross-subsidies among ratepayers, he omits any consideration of the 5 costs a rooftop solar customer avoids paying when he or she produces electricity for his 6 or her own consumption. Mr. Beach sets up this approach by arguing that a rooftop solar 7 customer producing for his or her own consumption is equivalent to a customer taking 8 energy efficiency measures to reduce consumption. However, as explained above, it is 9 important to understand here that rooftop solar customers producing for their own 10 consumption are importantly different from energy efficiency customers--their overall 11 energy consumption (kWh) goes down significantly, but their peak demand (KW) does 12 not. For example, a customer who improves energy efficiency by installing LED bulbs 13 throughout his or her house presumably reduces both the total kWh of energy used and 14 the peak demand in the house. In this case, the standard residential two part rate, which 15 varies only with kWh usage, is a reasonable way to approximate the costs customers 16 impose on the system. A rooftop solar customer can reduce kWh consumption 17 significantly, while reducing peak demand very little, or even not at all, if peak demand 18 occurs after sundown (not uncommon, in working families whose members return to the 19 house in the evening). Such customers pay much less to support the same peak demand-- 20 and other customers must make up the difference. There is a real "ratepayer impact," 21 here, but it is one that Mr. Beach omits entirely from his ratepayer impact analysis. Even 22 so, his analysis of ratepayer impact for residential customers barely breaks even for all 23 three utilities he analyzes.66 It is also important to note that energy efficiency results tend 65 66 Beach testimony, 26. Beach testimony, Table 4, p. 27. 46 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 47 of 55 1 to be more predictable than is possible in terms of what can be expected from an 2 intermittent resource. 3 Q. 4 5 Do you agree that 25 year "levelized cost" analysis is an appropriate way to review the costs and benefits of rooftop solar? A. I do not agree. In his analysis, Mr. Beach suggests that "levelized" cost analysis should 6 be used for rooftop solar, in the same way that utilities use such analysis to evaluate 7 potential capital investments in new plants.67 However, as discussed above, in relation to 8 the approach to valuing energy provided by rooftop solar, since utilities do not 9 themselves own the rooftop solar facilities, conducting an analysis identical to that 10 undertaken for a capital investment does not make sense and introduces needless 11 complexity. There is no 25 year ownership right (for the utility) to the rooftop solar 12 power to be provided, so traditional analysis of whether an asset is worth investing in 13 does not apply. Mr. Beach further suggests that levelized analysis is needed because there 14 are benefits from rooftop solar that can only be realized over time (primarily, capacity 15 benefits). His analysis insists that such benefits be included; however, he does not 16 endorse equal foresight about potentially growing costs. For example, increases in 17 distribution costs or costs of coping with variability that Mr. Beach acknowledges may 18 come along with growing levels of solar penetration are not considered in his "levelized" 19 analysis; rather, Mr. Beach says, "further analysis may be needed" in the future, once 20 penetration levels increase.6869 A "levelized" analysis that considers all hypothetical 67 Beach testimony, 10. While Mr. Beach acknowledges that further analysis may be required, by levelizing prices into a long term arrangement, he precludes the possibility of revising rates to reflect more sophisticated and updated analysis. 69 Beach testimony, p. 15. Similar discussion of variability on p. 17. 68 47 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 48 of 55 1 changes in benefits over 25 years but omits hypothetical changes in costs is misleading, 2 and only adds to the difficulty of appropriately assessing the "value" analysis presented.70 3 Q. Q: In addition to the general concerns with "Value of Solar" analysis described 4 above, are there any particular issues with this analysis for New Hampshire that 5 should be mentioned? 6 7 A. A. Yes. With respect to the category of "societal benefits," a few items should be noted: ? Mr. Beach includes a value for the avoided social cost of carbon.71 However, 8 given New Hampshire's participation in RGGI, there should be no additional 9 value at all attributed to the social cost of carbon, beyond the RGGI values 10 incorporated in the energy cost analysis. The reason for this is that RGGI is a cap 11 and trade system. Under this system, additional measures to lower carbon 12 emissions do not result in lower emissions overall (they do nothing to change the 13 "cap")--what they do instead is to undermine the value of carbon credits under 14 the RGGI system, make the whole system less efficient, and direct a greater share 15 of the cost of compliance with RGGI onto New Hampshire ratepayers, as opposed 16 to ratepayers in other states, without lowering total carbon emissions for the 17 RGGI states overall. Although, as a Massachusetts resident, and a homeowner in 18 Maine as well, I benefit from New Hampshire taking on additional costs in order 70 An example of the kind of difficulty introduced by levelized analysis can be seen in the use of EPA AVERT data for estimating the value of various avoided pollutants. The EPA itself warns that the AVERT data "should not be used to examine the emission impacts of ... changes extending further than five years from the baseline year." (see https://www.epa.gov/statelocalclimate/avoided-emissions-and-generationtool-avert#when). It is not clear how Mr. Beach handles this, exactly, but calculations of the 25 year "levelized" value of avoided emissions are certainly included in his final figures. 71 Mr. Beach also includes the market value of carbon under the Regional Greenhouse Gas Initiative (RGGI) in the category of avoided energy costs. These energyrelated values are subtracted from the calculated social cost of carbon (presumably, to avoid double counting). Beach testimony, p. D-10. 48 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 49 of 55 1 to lower the cost of RGGI compliance for Massachusetts, I cannot advise this 2 policy as one that is a good investment for New Hampshire ratepayers or that has 3 any benefit for the climate or for society as a whole. Moreover, it violates a basic 4 principle in regulation, namely, that the cost causer should pay (or, in a variation 5 of that principle, the polluter must pay). Thus, all "societal benefits" associated 6 with carbon emissions should be eliminated from the analysis. 7 ? Avoided SO2 and NOx costs. The New Hampshire study shares with the Maine 8 study the methodological problem of using the EPA's Northeast AVERT data as a 9 source for calculating the avoided emissions from rooftop solar generation.72 The 10 Maine study, however, notes that the AVERT data used to calculate emissions 11 "includes New York, which is not part of the ISO-NE control area."73 The Maine 12 study's appendix goes on to clarify that if the authors had in fact limited the 13 analysis to "FTA rates"--emissions rates for units fueled with oil and natural gas 14 (closer to what the Maine study authors assume is being displaced in their 15 marginal cost analysis) emissions rates would have been radically lower. 74 What 16 this boils down to, is an admission that the "value" attributed to SO2 and NOx 17 emission reduction is a complete fiction, based on a calculation that rooftop solar 18 in Maine (or in New Hampshire, in the current example) would somehow reduce 19 coal plant emissions in New York. This is ridiculous. Coal is at all times unlikely 20 to be used as a marginal resource--and these coal plants are not even part of the 21 same dispatch system as New Hampshire. It is hard to know what the true values 72 Grace, Robert C., Philip M. Gruenhagen, Benjamin Norris, Richard Perez, Karl R. Rabago, and Po-Yu Yuen. Maine Distributed Solar Valuation Study. Prepared for the Maine Public Utilities Commission. Revised April 14, 2015. Please see: http://www.maine.gov/mpuc/electricity/elect_generation/documents/MainePUCVOSExecutiveSummary.pdf 73 74 Id. at 83 Id. at 84. 49 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 50 of 55 1 for SO2 and NOx should be, but it is unlikely that they are as high as those 2 included in the New Hampshire study.75 ? 3 Another critique of Mr. Beach relates to his assertion that the investment in 4 rooftop solar relieves the utility of having to raise more capital. That is incorrect 5 for three very basic reasons. The first is that, as already noted, solar's 6 intermittency means that a utility will have to incur obligations for transmission 7 and generation backup capacity. Second, the accounting results may well compel 8 the utility to treat that obligation on its books as debt, thereby having implications 9 for the company's debt-equity ratio. Finally, there will be lead/lag implications, 10 because new solar customers will be paying less of their fixed costs, and 11 companies will be unable to recover those foregone revenues until their next rate 12 case where they can shift those cost to other customers, thereby exacerbating the 13 cross-subsidy inherent in RNM. ? 14 There is a general concern about relying on long term fuel price forecasts. While 15 utilities and regulators might have to do so for purposes of planning, it is an 16 entirely different proposition to use such notoriously inaccurate forecasts for 17 purposes of long term contracts. There is a lot of history relating to the 18 consequences of what can go wrong when one relies on long term forecasts to 19 lock in long term prices. As a regulator, I had to deal with these problems, and I 20 do not wish to see them revisited on consumers of New Hampshire. 21 Q. Given your global critiques of the "value of solar" analysis presented by Mr. Beach 22 and your critiques specific to New Hampshire, where does this leave us in terms of 23 likely ratepayer impact of net energy metering in New Hampshire? 75 I believe the same problem impacts estimates of avoided CO2 emissions--once again, the report relies here on annual avoided emissions calculated from AVERT-- which includes coal plants, whose CO2 emissions are significantly higher than natural gas plants. 50 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 51 of 55 1 A. Focusing on the Rate Impact Measure analysis conducted by Mr. Beach (which excludes 2 societal benefits), the apparent balance found by Mr. Beach disappears when appropriate 3 adjustments are made: 4 ? Eliminate (or greatly reduce) "generation capacity" and "generation capacity 5 reserve" savings (based on the lack of coincidence with peak discussed above, a 6 problem only expected to increase with increasing penetrations of rooftop solar); 7 ? 8 9 Eliminate savings related to transmission and distribution (as discussed above, these are highly time and location specific, and far from guaranteed); ? Eliminate savings attributed to "market price response" (in the long run, market 10 price suppression distorts the market and leads to capacity problems that can be 11 expensive in their own right); 12 ? Eliminate savings attributed to "avoided fuel price uncertainty" (as discussed 13 above, under net energy metering, prices paid for rooftop solar power by utilities 14 vary right along with fuel prices--so rooftop solar, under NEM arrangements, 15 does not provide utility customers with a meaningful hedge against price 16 uncertainty); 17 ? Include additional costs identified in the testimony of Thomas P. Meissner in this 18 case, related to investments needed to preserve the stability of the distribution 19 system given the new, two-way power flow enabled by rooftop solar.76 20 Without significant additional analysis, and relying on Mr. Beach's estimates of 21 "levelized" cost and value of the energy itself, it is clear that the "value of solar" that 22 remains is far less than the ratepayer cost of the current net energy metering subsidy. For 23 example, the analysis of the impact of current net energy metering for Unitil (residential 24 and commercial) goes from a small net positive to a large negative--if per kWh energy 76 Meissner testimony, 10. 51 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 52 of 55 1 avoided costs ("levelized") are taken to be represented by Beach's estimate of 2 $0.06/kWh77, they clearly fail to balance the lost revenues estimated by Beach to be 3 $0.19/kWh78--and this is without taking into account any of the additional distribution 4 costs that Mr. Meissner's testimony notes will be necessary. As this rough analysis makes 5 clear, a more accurate assessment of the "value of solar" shows that solar falls far short of 6 providing a "value" equivalent to the net energy metering subsidy. 7 Q. 8 9 Mr. Nathan Phelps and/or Mr. Patrick Bean? A. 10 11 Yes. Both testimonies rely on Mr. Beach's analysis to support their claims about the value of solar. Q. 12 13 Does your critique of Mr. Beach's testimony have implications for the testimony of Nathan Phelps also presents a "value of solar" analysis. Does his analysis offer any additional values that are significant? A. No. Mr. Phelps argues that the Commissioners should focus on the "societal cost test," 14 the most global, all-encompassing standard for evaluating the value of solar, including 15 value provided to society and the environment.79 His analysis, however, is subject to the 16 same objections as the Beach analysis, and does not provide any new reason to attribute 17 additional value to rooftop solar power. 18 V. HOW THE THREE-PART RATE PROPOSED BY UNITIL CAN HELP 19 ADDRESS THE INEQUITIES AND INEFFICIENCIES OF RETAIL NET 20 METERING 21 Q. 22 What is the national context for New Hampshire's current review of net energy metering? 77 See Beach's Table D-12. For the sake of clarity in comparing this number with the cost number Beach presents in Table D-17, I have converted the per MWh figure presented in Table D-12 into a per kWh figure. 78 See Beach Table D-17, page D-16 of Beach testimony. 79 Phelps testimony, 9. 52 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 53 of 55 1 A. Unsurprisingly, given the problems with RNM explained above, many policy makers, 2 regulators, and utilities are examining how to better structure rates for distributed 3 generation customers. There is a robust debate occurring across the nation regarding the 4 appropriate rate mechanisms for addressing the issues raised by distributed generation 5 technologies, with a growing recognition throughout the United States that traditional 6 RNM is not sustainable as a pricing methodology. For example, in 2015, 46 out of 50 7 states had ongoing studies, proposals, or enactments relating to "net metering, valuation 8 of distributed solar, fixed or solar charges, third-party or utility-led rooftop solar 9 ownership, or community solar."80 These states stretched from coast to coast, including 10 Nevada, Ohio, Pennsylvania, Virginia, Connecticut, and Maine.81 In the first quarter of 2016, thirty-nine states took some action related to "net 11 12 metering, rate design, and solar ownership," according to the NC Clean Energy 13 Technology Center's report (p.9). The report describes a continuing "trend" of fixed 14 charge increase requests by utilities, with 19 such requests pending at the end of March 15 2016 (50). Proposed changes are often controversial. Florida has seen dueling proposed 16 ballot initiatives. Hawaii recently ended its RNM program. In Nevada, RNM reform has 17 attracted considerable national attention. Other states (in addition to New Hampshire) 18 which are at various stages of review and revision include Kansas, Arizona, 19 Massachusetts, Vermont, California, Wisconsin, Mississippi, Ohio, Maine, Maryland, 20 Louisiana, and recently Colorado. The old national status quo of net metering is being 21 reexamined in a growing number of jurisdictions across the country. In some 22 jurisdictions, utilities are moving to replace RNM with a three part rate including a 23 demand charge, under which customers pay a monthly charge based on their peak 80 North Carolina Clean Energy Technology Center & Meister Consultants Group, The 50 States of Solar: 2015 Policy Review and Q4 Quarterly Report, February 2016: 11. 81 Ibid, p. 40. 53 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 54 of 55 1 demand for that month. Such a charge can be optimized by setting "peak hours" when it 2 applies. This three part rate structure corresponds to Unitil's proposal to the Commission. 3 Q. 4 5 Is Unitil's proposal for a three part rate a good approach to net energy metering reform? A. Yes. The appeal of a three part rate is its promise of fully implementing the principle of 6 setting rates in accordance with cost causation for each of the three kinds of costs (fixed, 7 demand, and energy) customers impose on the system. What this means is that under a 8 well-structured three part rate, cross subsidies from non-solar to solar customers would 9 be eliminated. Under a three part rate, rooftop solar customers can be charged accurately 10 based on the utility's cost of providing service, in conformity with the most basic and 11 important principles of utility ratemaking.82 12 Such a three part rate can be complemented by other measures designed to further 13 refine and sharpen price signals, including time and location-based incentives for siting 14 rooftop solar advantageously, and time of use rates to incentivize customers to consume 15 more when rates are lower and produce more when rates are higher. In this respect, I 16 agree with the testimony of Mr. Bean, who recommends these measures.83 82 Mr. Bean raises the concern that demand charges might increase overall energy use, since breaking such charges out separately would result in lower per kWh rates. What is important to note here, however, is that, because this moves the rate close to reflecting actual customer costs imposed on the system, the end result will be more efficient for both customers and utilities. Similarly, if demand charges, for example, motivate some customers to convert to natural gas-fired appliances, this is not a bad thing, if it is an overall more efficient result. And because the new rate would be an accurate reflection of customer costs imposed on the system, such a conversion would not, as Bean suggest, leave other customers "on the hook" for more system costs. The three part rate, properly structured, eliminates the concern that my actions to save money on my bill will negatively impact other customers. (See Bean testimony, 15). I would also note that having transparent, unbundled demand charges will enable readily available technology to help customers control the demand characteristics to enter the market and provide consumers with another option for controlling their bills. 83 Bean testimony, 11. 54 NHPUC Docket No. DE 16-576 UES Rebuttal Testimony of Ashley C. Brown Page 55 of 55 1 CONCLUSION 2 Q. Do you have any concluding remarks? 3 A. Yes. The inequities and inefficiencies of existing retail net metering rates across the 4 country are increasingly being recognized as both unjustifiable and unsustainable in a 5 world in which rooftop solar power is no longer an infant industry, but rather a growing a 6 robust part of the energy sector. The long-term success of distributed solar as an energy 7 resource must depend on its becoming truly cost competitive with other resources, and 8 rate reforms to more realistically compensate distributed solar are an important part of 9 making this transition. Unitil's proposal to revise the current Net Energy Billing make it 10 consistent with its name ("net energy billing," not "net energy, transmission, and 11 distribution billing) would establish the conditions necessary for fair competition, and the 12 potential for market forces to drive increasing efficiencies and set the stage for rooftop 13 solar to compete on a level playing field with other forms of energy generation, 14 eliminating the cross subsidies that currently distort prices and unfairly burden non-solar 15 customers. 55