AHMAD FARUQUI
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1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Docket No. 15_____ 3 Net Metering and Distributed Generation Cost of Service and Tariff Design
4 Prepared Direct Testimony of
5 Ahmad Faruqui 6
7 I. INTRODUCTION OF WITNESS
8 1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS
9 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
10 A. My name is Ahmad Faruqui. I am a Principal with the Brattle Group. My
11 business address is 201 Mission Street, Suite 2800, San Francisco, California 12 94105. I am filing testimony on behalf of Nevada Power Company d/b/a NV 13 Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV d/b/a NV Energy ada Power Company 14 Energy (“Sierra” and, together with Nevada Power, “NV Energy” or the ev N 15 “Companies”). and Sierra Pacific Power Company
16
17 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
18 EXPERIENCE. 19 A. I have 35 years of consulting and research experience. During my career, I 20 have advised several dozen utilities, private energy companies, technology 21 providers, transmission system operators, regulatory commissions and 22 government agencies in the United States and in Australia, Canada, Egypt, 23 Hong Kong, Jamaica, Philippines, Saudi Arabia, South Africa and Vietnam
24 on a wide range of customer-side issues including sales and peak demand 25 forecasting, demand response, energy efficiency, rate design, integrated 26 resource planning, and the use of demand-side resources to facilitate the 27
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1 integration of retail and wholesale markets. I have testified or appeared
2 before a dozen state and provincial regulatory commissions and legislative 3 bodies. I have authored or co-authored more than one hundred papers on rate 4 designs and related issues and co-edited three books on pricing and customer
5 choice. 6 7 More details regarding my professional background and experience are set 8 forth in my Statement of Qualifications, included as Exhibit Faruqui-
9 Direct-1.
10
11 3. Q. WHAT ARE YOUR RESPONSIBILITIES AS PRINCIPAL WITH 12 THE BRATTLE GROUP? 13 A. In my current position, I lead the firm’s practice in understanding and d/b/a NV Energy ada Power Company 14 managing the changing needs of energy consumers. This work encompasses ev N 15 rate design, distributed generation, energy efficiency, demand response, and Sierra Pacific Power Company
16 demand forecasting and cost-benefit analysis of emerging technologies such 17 as advanced metering, energy storage, rooftop solar, smart thermostats and 18 electric vehicles. 19 20 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 21 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
22 A. No, I have not. 23
24 II. OVERVIEW AND TESTIMONY ORGANIZATION 25 5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT 26 TESTIMONY IN THIS CASE? 27
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1 A. The purpose of my testimony is to review the new rate designs that Nevada
2 Power and Sierra are submitting to the Commission for net energy metering 3 (“NEM”) customers in Nevada. 4
5 6. Q. PLEASE SUMMARIZE YOUR TESTIMONY. 6 A. I have reviewed the three-part rate designs for new NEM customers that are 7 being proposed by Nevada Power and Sierra Pacific. The rates are based on 8 marginal cost of service studies. The three-part rates include a monthly
9 service charge, a demand charge and an energy charge. Two choices are
10 being offered to NEM customers, one of which does not have time variation
11 in the demand and energy charges, and one of which does have time 12 variation in these charges. I have calibrated NV Energy’s rates against the 13 Bonbright principles of rate design, which can be distilled into five d/b/a NV Energy ada Power Company 14 principles: economic efficiency, equity, bill stability, revenue stability and ev N 15 customer satisfaction. I have found the NV Energy rates to be consistent with and Sierra Pacific Power Company
16 those principles. Finally, I have calibrated their numerical values against the 17 three-part rate designs that are being offered by other utilities in the US and 18 found them to be broadly in line with those of the sampled utilities. 19 20 7. Q. HOW IS YOUR TESTIMONY ORGANIZED? 21 A. It is organized into several sections. Section III reviews the principles of rate 22 design. Section IV presents NV Energy’s rate design proposal, and compares 23 it to similar rates or rate proposals of other U.S. utilities. Section V
24 concludes the testimony. 25 26 8. Q. ARE YOU SPONSORING ANY EXHIBITS? 27 A. Yes, I sponsor the following exhibits to my testimony:
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1 . Exhibit Faruqui Direct-1: Statement of Qualifications
2 . Exhibit Faruqui Direct-2: Summary of Residential Three-Part Tariffs 3 . Exhibit Faruqui Direct-3: Summary of Utility Distributed Generation 4 (“DG”) Rate Reform
5 6 III. PRINCIPLES OF RATE DESIGN 7 9. Q. PLEASE PROVIDE A HISTORICAL PERSPECTIVE ON THE 8 THEORY OF ELECTRIC RATE DESIGN.
9 A. The principles that guide electric rate design have evolved over time. Many
10 authorities have contributed to their development, beginning with the
1 11 legendary rate engineer John Hopkinson in the late 1800’s. His thinking on 12 the subject led him to propose a three-part tariff, consisting of a fixed service 13 charge a demand charge and an energy charge. The demand charge was d/b/a NV Energy ada Power Company 14 based on the maximum level of demand which occurred during the billing ev N 15 period. In some versions of the Hopkinson tariff, as the demand, fixed and Sierra Pacific Power Company
16 service fee and energy charge tariff came to be called, also feature seasonal 17 or time-of-use (“TOU”) variation corresponding to the variations in the costs 2 18 of energy supply. 19 20 British, French and American economists have made further enhancements 21 to the original three-part rate design. These include: Maurice Allais, Marcel 22 Boiteux, Douglas J. Bolton, Ronald Coase, Jules Dupuit, Harold Hotelling, 23 Henrik Houthakker, W. Arthur Lewis, I. M. D. Little, James Meade, Peter
24 Steiner and Ralph Turvey. In 1961, Professor James C. Bonbright coalesced
25 1 See, for example, D.J. Bolton, Electrical Engineering Economics, and Vol. 2: Costs and Tariffs in Electricity Supply, (London: Chapman & Hall, Ltd., 1951), at p. 190. 26 2 See, for example, Michael Veall, “Industrial Electricity Demand and the Hopkinson Rate: An Application of the Extreme Value Distribution,” Bell Journal of Economics, Vol. 14, Issue No.2 (1983). 27
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3 1 economists’ thinking in his canon, Principles of Public Utility Rates, which
2 was reissued in its second edition in 1988. Some of these ideas were further 3 expanded upon by Professor Alfred Kahn in his widely cited treatise, The 4 4 Economics of Regulation.
5 6 10. Q. WHAT ARE THE GENERALLY ACCEPTED RATE DESIGN 7 PRINCIPLES? 8 A. Professor Bonbright developed 10 Principles of Rate Design that are widely
9 used as a foundation in designing rates. We have distilled these 10 principles
10 into five Core Principles of Rate Design.
11 1. Economic efficiency: this principle ensures that price acts as a signal 12 ensuring resources are not wasted. If a price is set to the incremental cost 13 of providing a kWh, customers who value the kWh more than the cost d/b/a NV Energy ada Power Company 14 will use it and customers who value it less will not. ev N 15 2. Equity: no customer should unintentionally subsidize another customer. and Sierra Pacific Power Company
16 For example, under flat rate pricing, different load profiles mean that 17 “peaky” customers are using electricity when it is most expensive and 18 they are subsidized by less “peaky” customers who overpay for cheap 19 off-peak electricity. Note that equity is not the same as social justice. 20 3. Revenue adequacy and stability: theoretically, all pricing schemes can be 21 implemented to be revenue neutral within a class, but this would require 22 perfect foresight of the future. Changing technologies and customer 23 behaviors make load forecasting more difficult and increase the risk of
24 the utility either under-recovering or over-recovering costs when rates are 25 not cost reflective.
26 3 James C. Bonbright, Albet L. Danielsen, and David R. Kamerschen, Principles of Public Utility Rates, 2d ed. (Arlington, VA: Public Utility Reports, 1988). 27 4 Alfred Kahn, The Economics of Regulation: Principles and Institutions, rev. ed. (MIT Press, June 1988).
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1 4. Bill stability: rates should be stable and predictable. Rates that are not
2 cost reflective are less stable over time, since both costs and loads are 3 changing over time. For example if you spread a fixed charge over a 4 certain number of kWh’s and the next year the number of kWh’s halves,
5 then the price per kWh will double even though there is no change in the 6 underlying fixed cost. 7 5. Customer satisfaction: for a rate to work as planned, customers need 8 “buy in” for the rate. Because residential customers consider electricity to
9 be a relatively low priority, rates need to be relatively simple to
10 understand and simple to respond to. Providing choices to customers can
11 also help, because it allows customers to better answer varying needs and 12 risk tolerances. 13 d/b/a NV Energy ada Power Company 14 Figure 1 shows the mapping between Bonbright’s original 10 principles and the ev N 15 Five Core Principles defined above. and Sierra Pacific Power Company
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1 Figure 1: Deriving the Five Core Principles of Rate Design 2 3 4
5 6 7 8
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11 12 13 d/b/a NV Energy ada Power Company 14 ev N 15 and Sierra Pacific Power Company
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18 11. Q. HOW DO THESE PRINCIPLES ACCORD WITH THE WIDELY 19 ACCEPTED NOTION OF COST CAUSATION IN RATE DESIGN?
20 A. Economic efficiency and equity relate directly to the notion of cost 21 causation. Economic efficiency is achieved by having cost-reflective prices. 22 This ensures that products are only consumed by those customers who value 23 them at more than they cost to produce. Pricing below cost is wasteful
24 because customers will purchase and consume products that they would not 25 choose to consume if faced with paying full cost. Similarly, pricing above 26 cost is wasteful because customers, who would get a net benefit from 27
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1 consuming the product over its cost of production, lose out on that
2 enjoyment. Respecting the equity principle requires that the tariff’s design 3 not result in one customer unintentionally subsidizing another customer. This 4 differs from social justice, which would be an intentional subsidization
5 among customers through the tariff. Prices that are cost reflective minimize 6 unintentional subsidies. Cost causation may need to be balanced against the 7 other Core Principles such as customer satisfaction or bill stability. 8
9 12. Q. PLEASE SUMMARIZE THE STRUCTURE OF UTILITY COSTS?
10 A. In order to provide electricity to a customer, a utility must bear – directly or
11 indirectly – costs related to energy, generation, transmission, distribution, 12 metering and customer service (billing, customer inquiry, etc.). Generation 13 energy costs vary directly with electricity consumption, while distribution d/b/a NV Energy ada Power Company 14 and transmission costs vary with demand. Generation capacity costs vary ev N 15 with demand. Metering and customer services are a fixed cost per each and Sierra Pacific Power Company
16 customer. Some of these costs vary across time. Generation costs will vary 17 from hour to hour depending on the marginal generation source. Distribution 18 and transmission networks, while used year round, are sized to meet peak 19 demand. This system peak will be split across a limited number of hours 20 throughout the year. 21 22 13. Q. HOW DO THESE COSTS TRANSLATE INTO RATES? 23 A. According to the notion of cost causation, rates structure should match the
24 nature of the costs and have a fixed service charge, a demand charge and an 25 energy charge. The demand charge and the energy charge might vary with 26 the time of use of electricity and have different seasonal and/or peak/off-peak 27 charges.
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1 14. Q. HAVE THESE COST CAUSATION PRINCIPLES BEEN APPLIED IN
2 PRACTICE? 3 A. Yes, most commercial and industrial customers across the U.S. are served 4 under cost-reflective three-part rate structures.
5 6 15. Q. HAVE THESE COST CAUSATION PRINCIPLES BEEN APPLIED 7 TO RESIDENTIAL CUSTOMERS? 8 A. Historically they have not, however this is changing rapidly due to several
9 technological advances that have emerged in the last several years. As
10 described in the Summary of Residential Three-Part Tariffs that is attached
11 as Exhibit Faruqui Direct-2, at least 19 utilities in 14 states are currently 12 offering three-part rates to residential customers. Exhibit Faruqui Direct-3 13 discusses rate reforms which for the most part aim at modifying rates to d/b/a NV Energy ada Power Company 14 make them more cost-reflective. For instance, as shown in Table 1 of ev N 15 Exhibit Faruqui Direct-3, most of the rate changes discussed in other US and Sierra Pacific Power Company
16 jurisdictions include an increase in fixed the charge or minimum bill, 17 proposed to better reflect the utilities’ costs in the rates. 18 19 16. Q. WHAT TECHNOLOGICAL ADVANCES HAVE LEAD TO 20 INCREASED USE OF THREE-PART RATE STRUCTURES FOR 21 RESIDENTIAL CUSTOMERS? 22 A. Smart meters are capable of recording advanced billing functions such as 23 incremental consumption and demand, thereby removing a large barrier/cost
24 to the dissemination of cost-reflective rates (since additional specialized 25 meters are no longer required). In addition, smart meters can provide 26 feedback to customers on their electricity usage in real or near-real time and 27 also communicate with devices in the home. This allows a customer to
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1 clearly understand their electricity usage and manage their bills in a way that
2 was not widely available before. 3 4 The introduction of renewable DG, coupled with the two-part rate structure,
5 has resulted in the shifting of costs and revenue requirement. Utilities receive 6 less revenue from customers who pay two-part rates after the customer 7 installs renewable DG; yet, fixed and demand costs incurred to serve the 8 customer are largely not reduced. Responsibility for these costs is then
9 shifted to other customers, thereby shifting costs from customers who install
10 renewable DG to other customers. In short, customers who install renewable
11 DG are subsidized by customers who do not when a simple two-part rate 12 design that relies primarily on volumetric rates to recover demand and fixed 13 costs continues to be used. In these circumstances, the benefits of cost- d/b/a NV Energy ada Power Company 14 reflective rates (due to decreases in equity and efficiency) are larger than ev N 15 before. and Sierra Pacific Power Company
16 17 17. Q. WHY IS THERE A COST SHIFT? 18 A. The cost shift occurs because the current flat/volumetric rate includes several 19 fixed cost and demand-based elements. Customers who self-generate can 20 reduce the amount of energy that they receive from the utility and thereby 21 avoid paying for these fixed and demand elements. 22 23 IV. THE RATE DESIGN PROPOSAL
24 18. Q. WHAT ARE THE CURRENT RATE DESIGNS FOR NV ENERGY’S 25 NEM CUSTOMERS? 26 A. Residential NEM customers at Nevada Power and Sierra currently pay the 27 same rate as their otherwise applicable tariff schedule. This includes a
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Page 226 of 284 1 monthly service charge (called the Basic Service Charge or “BSC”) and a
2 volumetric rate. Customers have a choice of a flat volumetric rate or a TOU 3 volumetric rate. Both are described for Nevada Power and Sierra in Table 1. 4 It is important to note that 99% of residential customers have chosen the flat 5 rate and 1% have chosen the TOU rate.
6 Table 1: Current Residential Rate Design 7
8 Variable Charge ($/kWh) Fixed 9 Charged TOU rate ($/kW) Flat rate Summer Winter Winter Summer On Summer Off 10 Mid On Off
Sierra Flat rate 15.25 0.09842 11 Sierra TOU rate 15.25 0.41175 0.20562 0.06735 0.08465 0.06735 12 Nevada Flat rate 12.75 0.11642 13 Nevada TOU rate 12.75 0.36709 0.06314 0.04857 0.04857 d/b/a NV Energy ada Power Company 14 Source: NVE Net metering proposal July 16, 2015 presentation ev
N Notes: Chart excludes Generation Meter Charge that is waived for Solar Generations customers 15 and Sierra Pacific Power Company
16 Any excess production from the customer’s self-generation facility is subject 17 to the NEM arrangement. Under this arrangement, the customer is credited 18 for the excess kWh production on the otherwise applicable tariff schedule. 19 This credit goes into a “bank” account which will be used to pay for kWh
20 consumption either in the current or future billing period. 21
22 19. Q. WHY IS IT NECESSARY TO CHANGE THE CURRENT RATE 23 STRUCTURE FOR NEM CUSTOMERS?
24 A. The current two-part NEM rate structure has two shortcomings – it shifts 25 revenue requirements (and therefore electricity costs) from NEM to non- 26 NEM customers, thereby raising the bills for non-NEM customers, and it 27
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1 does not account for any incremental costs that NEM customers may place
2 upon the system, which again means that bills for non-NEM customers are 3 raised. 4
5 20. Q. PLEASE DESCRIBE THE COST SHIFT CAUSED BY THE 6 CURRENT RATE STRUCTURE FOR NEM CUSTOMERS. 7 A. The standard two-part residential rate consists largely of a volumetric rate 8 which covers several cost elements, some of which are volumetric and some
9 of which are not. Energy costs are volumetric, while distribution,
10 transmission and the capacity component of generation costs are not. NEM
11 customers will upload power to the grid in some periods and offload power 12 in others, sometimes even within a single hour. Even though their net energy 13 consumed may be zero, they have still been using the grid extensively in d/b/a NV Energy ada Power Company 14 aggregate. Under the current NEM rate structure, any electricity exported ev N 15 onto the grid will earn a credit at the full retail rate which includes the cost of and Sierra Pacific Power Company
16 the grid as well as the cost of energy. 17 18 These credits reduce the contribution that NEM customers make toward the 19 costs of transmission and distribution assets, but do not proportionately 20 reduce the costs that they impose on the grid. For example, if the volumetric 21 rate is 10 cents, and the cost of energy (scaled to recover revenue) is four 22 cents, then the remaining six cents will be used to cover the costs of the grid 23 and customer services. On a particular day, if a NEM customer exports five
24 kWh of energy onto the grid, the NEM customer will receive a credit for 25 each kWh, totaling 50 cents. However, the NEM customer would not have 26 reduced the costs the utility incurs by 50 cents, but only by 20 cents (five 27 kWh times four cents). This creates a revenue shortfall of 30 cents which
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1 then must be recovered from the non-NEM customers, thereby creating a
2 cost shift from non-NEM customers to NEM customers. 3 4 21. Q. WHO PAYS FOR THIS COST SHIFT?
5 A. Currently, all non-NEM customers pay for the NEM cost shift. 6 7 22. Q. PLEASE DESCRIBE THE POTENTIAL INCREMENTAL COSTS 8 THAT NEM CUSTOMERS IMPOSE ON THE UTILITY?
9 A. Serving and signing up NEM customers requires additional support staff to
10 activate the new NEM accounts, answer customer inquiries and handle the
11 advanced billing required due to the NEM credits. Other costs such as 12 integrating renewables into the grid may also be applicable, but are not 13 included in the current rates calculations. d/b/a NV Energy ada Power Company 14 ev N 15 23. Q. WHAT NEW RATE DESIGNS FOR NEM CUSTOMERS ARE THE and Sierra Pacific Power Company
16 COMPANIES PROPOSING? 17 A. Two new rate designs are being proposed. The first one is a three-part rate 18 where the demand and energy charges do not have a time-of-use component. 19 The second one is also a three-part rate, but its demand and energy charges 20 have a TOU component. These rates are shown in Table 2. 21 Table 2: Proposed Residential NEM rate Designs
Coincident Demand 22 Max Variable Charge ($/kWh) Fixed ($/kW) Demand Charged Charge TOU rate 23 ($/kW) Summer On Winter On ($/kW) Flat rate Summer Summer Winter Winter Peak Peak Summer On Mid Off On Off 24 Sierra Flat rate 24.50 8.63 0.04749 Sierra TOU rate 24.50 4.46 14.66 1.43 0.08694 0.05934 0.04302 0.05036 0.04302 25 Nevada Flat rate 18.15 14.33 0.0547 26 Nevada TOU rate 18.15 4.04 22.15 0.09147 0.05016 0.04727 Source: Rate Summary_SPPC and NPC.xlsx 27 Notes: Chart excludes Generation Meter Charge that is waived for Solar Generations customers 28 Faruqui-DIRECT 13
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1 24. Q. WILL THE NEM RATES BE MODIFIED OVER TIME?
2 A. All rates are subject to change as the underlying cost drivers and load 3 changes. The numerical parameters of the rates, such as the basic service 4 charge, the demand charge and the energy charge, should be updated
5 periodically in a general rate case to reflect changes in the marginal costs and 6 loads that determine the rates. Structurally, the rates should remain 7 unchanged unless it is shown that the three-part rate no longer adequately 8 reflects the underlying cost elements.
9
10 25. Q. HAVE YOU SEEN THE RESULTS OF THE MARGINAL COST OF
11 SERVICE STUDIES FOR NEM CUSTOMERS FILED BY THE 12 COMPANIES? 13 A. Yes, I have seen the results of the studies. d/b/a NV Energy ada Power Company 14 ev N 15 26. Q. ARE THE RATES DEVELOPED BY NV ENERGY CONSISTENT and Sierra Pacific Power Company
16 WITH THE RESULTS OF THE COST OF SERVICE STUDIES? 17 A. Yes, the three-part rates developed directly reflect the different cost elements 18 from the cost of service studies, scaled so as to recover the revenue 19 requirement. 20 21 27. Q. HAVE YOU SEEN THE RESULTS OF THE JULY 2014 COST- 22 BENEFIT ANALYSIS (CALLED “NEVADA NET ENERGY 23 METERING IMPACTS EVALUATION”) PREPARED BY E3?
24 A. Yes, I have seen the results of that analysis. 25 26 27
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1 28. Q. WHAT IS THE PURPOSE OF A MARGINAL COST OF SERVICE
2 STUDY WHEN SUCH A COST-BENEFIT ANALYSIS IS 3 AVAILABLE? 4 A. Prices send signals to customers about what actions to take and to the utility
5 about what investments to make. If these price signals are cost reflective, 6 then optimal decisions will be made that raise economic efficiency and 7 enhance customer well-being, making society better off. Marginal cost of 8 service studies establish a measure of long-run marginal costs for various
9 aspects of utility costs. If these costs are then passed on to customers with
10 minimal distortions (distortions are needed for revenue recovery), then
11 customers will pay cost-reflective prices that enable them to make optimal 12 decisions. A cost-benefit study does not estimate marginal costs or prices of 13 any kind. Rather, it focuses on whether a specific investment, policy or d/b/a NV Energy ada Power Company 14 program is desirable or not. For these reasons, cost-benefit studies are not ev N 15 suitable for determining rates. and Sierra Pacific Power Company
16 17 29. Q. ARE THE NEWLY DESIGNED RATES CONSISTENT WITH THE 18 COMPANIES’ COST OF SERVICE STUDIES? 19 A. Yes, the rates are based on their cost of service studies. 20 21 30. Q. HAVE YOU REVIEWED SENATE BILL 374 FROM THE 2015 22 SESSION OF THE NEVADA LEGISLATURE (“SB 374”)? 23 A. Yes, I have.
24 25 31. Q. WHAT ARE THE RELEVANT ASPECTS OF SB 374 WITH 26 RESPECT TO NEM RATE DESIGN? 27
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1 A. SB 374 directs the Commission to develop new NEM rules and rates that
2 ensure that costs are not shifted from NEM customers to non-NEM 3 customers. Section 2.3.e of SB 274 states that the Commission shall not 4 authorize
5 6 “Any rates or charges for net metering that unreasonably shift costs from 7 customer-generators to other customers of the utility.” 8
9 Section 4.5 of SB 374 states that the proposed NEM rate may include:
10
11 “(a) A basic service charge that reflects marginal fixed costs incurred by the 12 utility to provide service to customer-generators; 13 (b) A demand charge that reflects the marginal demand costs incurred by the d/b/a NV Energy ada Power Company 14 utility to provide service to customer-generators; and ev N 15 (c) An energy charge that reflects the marginal energy costs incurred by the and Sierra Pacific Power Company
16 utility to provide service to customer-generators.” 17 18 32. Q. IS THE THREE-PART RATE DESIGN PROPOSED BY THE 19 COMPANIES CONSISTENT WITH THE REQUIREMENTS OF SB 20 374? 21 A. Yes, it is. The Companies have conducted marginal cost of service studies 22 for NEM customers by treating them as their own customer class, both in 23 terms of costs incurred to serve them and load shapes used to derive marginal
24 cost revenue. These cost of service studies were then used to derive class- 25 specific factors for several NEM-only customer classes. The proposed NEM 26 rates provide NEM customers a choice between a simple three-part rate and a 27 time varying three-part rate. It is my belief that the proposed rates are
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1 consistent with the principles of cost-causation and that they largely
2 eliminate subsidies from non-NEM to NEM customers as required by SB 3 374 section 2.3e. In accordance with section 4.5, the rates include a basic 4 service charge that reflects marginal fixed costs incurred by the Companies
5 to serve NEM customers; a demand charge that reflects the marginal demand 6 costs incurred by the Companies to serve NEM customers; and an energy 7 charge that reflects the marginal energy costs incurred by the Companies to 8 serve NEM customers.
9
10 33. Q. HAVE THREE-PART RATES BEEN PROVIDED TO RESIDENTIAL
11 NEM CUSTOMERS IN OTHER U.S. JURISDICTIONS? 12 A. Yes, at least three U.S. utilities are currently offering three-part rates to 13 residential NEM customers in three different states, as described in Exhibit 5 d/b/a NV Energy ada Power Company 14 Faruqui-Direct-2. These three-part rates include a fixed charge, a demand ev N 15 or capacity charge and a variable energy charge. All three rates are (or will and Sierra Pacific Power Company
16 be) applicable to all customers who elect to install a new grid-connected 17 NEM system. These utilities are Salt River Project in Arizona, South 18 Carolina Public Service Authority in South Carolina and We Energies in 19 Wisconsin. Other utilities have proposed a three-part rate specific to NEM 20 customers, such as UNS Energy in Arizona, but these rates have not been 6 21 approved yet. Three-part rates have a long history for larger commercial and 22 industrial customers, including NEM customers. 23
24 Furthermore, Exhibit Faruqui Direct-3 gives an overview of the current 25 DG related reform landscape in the U.S. Several other U.S. jurisdictions and
26 5 WE Energies has published its new NEM specific rates but will these will only be applicable after January 1, 2016. 27 6 See Exhibit Faruqui Direct-3.
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1 utilities are proposing to change their rates. Some utilities only apply fixed
2 charge increases for all residential customers (including DG customers), 3 some design a three-part rate structure specific to NEM customers, while 4 other utilities design a buy-sell arrangement through which the utility pays
5 the customer-generator a volumetric rate for the electricity generated by the 6 customer-generator that is different than the rate the customer-generator pays 7 the utility for bundled electric service. Table 1 in Exhibit Faruqui Direct-3 8 attempts to give an overview of these proposed changes. All rate proposals
9 discussed are driven by a similar cost recovery issue and aim at
10 implementing a rate structure that better reflects cost causation.
11 12 34. Q. HAVE TIME-VARYING CHARGES OR CHARGES VARYING BY 13 SEASON BEEN INCLUDED IN RATES OFFERED BY OTHER d/b/a NV Energy ada Power Company 14 UTILITIES FOR NEM CUSTOMERS? ev N 15 A. Yes, time-varying demand and energy charges are not uncommon for rates and Sierra Pacific Power Company
16 offered to NEM customers. For instance, the Salt River Project offers a rate 17 to NEM customers with time-varying demand and time-varying energy 18 charges that also vary seasonally (Winter, Summer and Summer Peak). 19 South Carolina Public Service Authority, often known as Santee Cooper, 20 also offers energy charges that vary with both the season and the time of day. 21 Exhibit Faruqui Direct-3 also discusses several examples of proposed rates 22 with time-varying charges for NEM customers. 23
24 25 26 27
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1 35. Q. IS IT POSSIBLE TO COMPARE NV ENERGY’S PROPOSED
2 THREE-PART RATE TO THOSE OFFERED BY UTILITIES IN 3 OTHER STATES? 4 A. Yes, but any such comparison should recognize the fact that different utilities
7 5 have different costs to serve and thus different overall rate levels. 6 Figure Figure 2 shows the average volumetric rate in 2014 for all residential 7 customers (NEM and non-NEM) for utilities offering three-part rates. The 8 average rate is derived by dividing residential class revenue requirements by
9 class sales. Figure 2 shows a circumscribed set of these utilities, limited to
10 the 18 (out of 28) utilities for whom average volumetric rate data was readily
8+9 11 available. Although both Nevada Power’s and Sierra Pacific’s average 12 residential rates are generally in line with the U.S. average rate of 12.5 10 13 cents/kWh, they are at the higher end relative to the comparison group of d/b/a NV Energy ada Power Company 14 utilities that offer three-part rates and have data readily available. This ev N 15 indicates that Nevada Power and Sierra Pacific are most likely in the higher and Sierra Pacific Power Company
16 range of the spectrum in terms of costs of service compared to the rest of the 17 comparison group. This context should be recognized in the rate 18 comparisons.
19 20 21 22 23
24 7 Not only do the utilities have different costs to serve, but they also base their rates on different kinds of cost 25 of service studies, some of which are marginal cost studies and some of which are embedded cost studies. 8 Only those utilities whose rates were included in the Edison Electric Institute (EEI) Typical Bills and 26 Average Rates Report Winter 2015 were included. 9 If no separate DG class is defined, these rates will also apply to DG customers. 27 10 U.S. Energy Information Administration (EIA) 2015: “Electric Power Monthly”, Table 5.3.
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1 Figure 2: Comparison of Average Residential Rates for 2014 between Utilities 2 3 4
5 6 7 8
9
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11 12 13 d/b/a NV Energy ada Power Company 14 ev N 15 and Sierra Pacific Power Company
16 36. Q. HOW DO NV ENERGY’S PROPOSED THREE-PART RATES 17 COMPARE TO THREE-PART RATES OFFERED BY UTILITIES IN 18 OTHER STATES? 19 A. Figures 3 through 7 hereafter compare the fixed charge, the demand charge 20 and the energy charge offered by Nevada Power and Sierra to three-part rates 21 offered by other utilities. Both the flat and the three-part TOU rates are 22 shown in all instances. All figures differentiate rates offered only to NEM 23 customers (grey) from rates offered to all customers. All Nevada Power and
24 Sierra rates are shown in as diagonal stripes.
25 26 27
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1 Figure 3 shows NV Energy’s proposed fixed charges for their residential
2 three-part NEM rates compared to those from other utilities offering three- 3 part rates. These charges are at the higher end of the spectrum, but do not 4 stand out as outliers. They are significantly lower than some of the NEM-
5 only fixed charges being offered by other utilities. 6 Figure 3: Comparison of Fixed Charges between Utilities 7 8
9
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11 12 13 d/b/a NV Energy ada Power Company 14 ev N 15 and Sierra Pacific Power Company
16 17 18 19
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21 In Figure 4 and Figure 5, we compare NV Energy’s set of proposed demand charges 22 to those from other utilities offering three-part rates. In general, none of the 23 components of NV Energy’s proposed rates are materially out of bounds with the
24 other utilities’ demand rates. Demand charges vary along a number of dimensions 25 including the length of the demand charge period and whether the demand charge is 26 coincident with the utility’s peak demand or based on the customer’s maximum 27
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1 demand regardless of time of occurrence. Some of these rates are explored in more
2 detail in Exhibit Faruqui Direct-2. The basic three-part rate structure proposed by 3 NV Energy has a non-coincident demand charge, while the TOU rate schedule has 4 both a non-coincident and coincident demand charge. For ease of comparison, we
5 have separated coincident and non-coincident (max demand) demand charges in 6 both Figure 4 and Figure 5. Figure 4 shows the summer demand charge. The 7 maximum demand charges for the flat three-part rates are on the higher end of the 8 spectrum, but are not outliers. The maximum demand charges for the TOU rates are
9 very low, but the rates also include a coincident demand charge. The coincident
10 demand charge for the TOU rates is again on the higher end of the spectrum, but in
11 line with other NEM-only coincident demand charges. Figure 5 shows the winter 12 demand charge. The maximum demand charges for the flat three-part rates are again 13 on the higher end of the spectrum, but are not outliers, while the winter coincident d/b/a NV Energy ada Power Company 14 peak charge for the TOU rate is by far the lowest (Nevada Power has a zero winter ev N 15 coincident peak charge). and Sierra Pacific Power Company
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1 Figure 4: Comparison of Summer Demand Charges between Utilities
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1 Figure 5: Comparison of Winter Demand Charges between Utilities
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16 17 Figure 6 and Figure 7 show summer and winter energy charges respectively. 18 Nevada Power’s and Sierra’s energy charges appear to be in the middle of 19 the spectrum.
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Figure 6: Comparison of Summer Energy Charges between Utilities 1
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1 Figure 7: Comparison of Winter Energy Charges between Utilities 2 3 4
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16 V. CONCLUSION 17 37. Q. WHAT ARE YOUR CONCLUSIONS ABOUT NV ENERGY’S RATE 18 PROPOSAL FOR NEM CUSTOMERS 19 A. I find that NV Energy’s proposed NEM rates meet the widely held principles 20 of rate design and are reasonable in magnitude compared to similar rates in 21 other jurisdictions. NV Energy’s rates are derived from marginal cost of 22 service studies and are consistent with the principles of economic efficiency 23 and equity (no unintentional subsidization). Compared to the existing NEM
24 rate, which is mostly a volumetric rate, the fixed charge and the demand 25 charge of the new NEM rate offer month-to-month bill stability for 26 customers and revenue stability for the utility. Since the rate is only 27 applicable to new NEM customers, there are no issues with bill shocks or
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1 need for transition to the new rate. NEM customers are offered a choice of
2 two rates and a simple and clear rate design meeting the principle of 3 customer satisfaction. 4
5 38. Q. DOES THIS COMPLETE YOUR TESTIMONY? 6 A. Yes, it does. 7 8
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STATEMENT OF QUALIFICATIONS DR. AHMAD FARUQUI
Dr. Ahmad Faruqui leads a consulting practice focused on understanding and managing the way customers use energy. His clients include utilities, commissions, equipment manufacturers, technology developers, and energy service companies. The practice encompasses a wide range of activities:
Rate design. The recent decline in electricity sales has generated an entire crop of new issues that utilities must address in order to remain profitable. A key issue is the under-recovery of fixed costs and the creation of unsustainable cross-subsidies. To address these issues, we are creating alternative rate designs, testing their impact on customer bills, and sponsoring testimony to have them implemented. We are currently undertaking a large-scale project for a large investor-owned utility to estimate marginal costs, design rates, and produce a related software tool, working in close coordination with their internal executives. We have created a Pricing Roundtable which serves as virtual think tank on addressing the risks of under-recovery in the face of declining growth. About 18 utilities are a part of the think tank.
Demand forecasting. We help utilities to identify the reasons for the slowdown in sales growth, which include utility energy efficiency programs, governmental codes and standards, distributed general, and fuel switching brought on by falling natural gas prices and the weak economic recovery. We present widely on the issue and are researching new methods for forecasting peak demand, such as the use of quantile regression.
Demand response. For several clients in the United States and Canada, we are studying the impact of dynamic pricing. We have completed similar studies for a utility in the Asia-Pacific region and a regulatory body in the Middle East. We also conduct program design studies, impact evaluation studies, and cost-benefit analysis, and design marketing programs to maximize customer enrollment. Clients include utilities, regulators, demand response providers, and technology firms.
Energy efficiency. We are studying the potential role of combined heat and power in enhancing energy efficiency in large commercial and industrial facilities. We are also carrying out analyses of behavioral programs that use social norming to induce change in the usage patterns of households.
New product design and cost-benefit analysis of emerging customer-side technologies. We analyze market opportunities, costs, and benefits for advanced digital meters and associated infrastructure, smart thermostats, in-home displays, and other devices. This includes product design, such as proof-of-concept assessment, and a comparison of the costs and benefits of these new technologies from several vantage points: owners of that technology, other electricity customers, the utility or retail energy provider, and society as a whole.
In each of these areas, the engagements encompass both quantitative and qualitative analysis. Dr. Faruqui’s reports, and derivative papers and presentations, are often widely cited in the media. The Brattle
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Group often sponsors testimony in regulatory proceedings and Dr. Faruqui has testified or appeared before a dozen state and provincial commissions and legislative bodies in the United States and Canada.
Dr. Faruqui’s survey of the early experiments with time-of-use pricing in the United States is referenced in Professor Bonbright’s treatise on public utilities. He managed the integration of results across the top five of these experiments in what was the first meta-analysis involving innovative pricing. Two of his dynamic experiments have won professional awards, and he was named one of the world’s Top 100 experts on the smart grid by Greentech Media.
He has consulted with more than 50 utilities and transmission system operators around the globe and testified or appeared before a dozen state and provincial commissions and legislative bodies in the United States and Canada. He has also advised the Alberta Utilities Commission, the Edison Electric Institute, the Electric Power Research Institute, FERC, the Institute for Electric Efficiency, the Ontario Energy Board, the Saudi Electricity and Co-Generation Regulatory Authority, and the World Bank. His work has been cited in publications such as The Economist, The New York Times, and USA Today and he has appeared on Fox News and National Public Radio.
Dr. Faruqui is the author, co-author or editor of four books and more than 150 articles, papers, and reports on efficient energy use, some of which are featured on the websites of the Harvard Electricity Policy Group and the Social Science Research Network. He has taught economics at San Jose State University, the University of California at Davis and the University of Karachi. He holds a an M.A. in agricultural economics and a Ph. D. in economics from The University of California at Davis, where he was a Regents Fellow, and B.A. and M.A. degrees in economics from The University of Karachi, where he was awarded the Gold Medal in economics.
AREAS OF EXPERTISE
Innovative pricing. He has identified, designed and analyzed the efficiency and equity benefits of introducing innovative pricing designs such as dynamic pricing, time-of-use pricing and inclining block rates.
Regulatory strategy. He has helped design forward-looking programs and services that exploit recent advances in rate design and digital technologies in order to lower customer bills and improve utility earnings while lowering the carbon footprint and preserving system reliability.
Cost-benefit analysis of advanced metering infrastructure. He has assessed the feasibility of introducing smart meters and other devices, such as programmable communicating thermostats that promote demand response, into the energy marketplace, in addition to new appliances, buildings, and industrial processes that improve energy efficiency.
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Demand forecasting and weather normalization. He has pioneered the use of a wide variety of models for forecasting product demand in the near-, medium-, and long-term, using econometric, time series, and engineering methods. These models have been used to bid into energy procurement auctions, plan capacity additions, design customer-side programs, and weather normalize sales.
Customer choice. He has developed methods for surveying customers in order to elicit their preferences for alternative energy products and alternative energy suppliers. These methods have been used to predict the market size of these products and to estimate the market share of specific suppliers.
Hedging, risk management, and market design. He has helped design a wide range of financial products that help customers and utilities cope with the unique opportunities and challenges posed by a competitive market for electricity. He conducted a widely-cited market simulation to show that real-time pricing of electricity could have saved Californians millions of dollars during the Energy Crisis by lowering peak demands and prices in the wholesale market.
Competitive strategy. He has helped clients develop and implement competitive marketing strategies by drawing on his knowledge of the energy needs of end-use customers, their values and decision-making practices, and their competitive options. He has helped companies reshape and transform their marketing organization and reposition themselves for a competitive marketplace. He has also helped government-owned entities in the developing world prepare for privatization by benchmarking their planning, retailing, and distribution processes against industry best practices, and suggesting improvements by specifying quantitative metrics and follow-up procedures.
Design and evaluation of marketing programs. He has helped generate ideas for new products and services, identified successful design characteristics through customer surveys and focus groups, and test marketed new concepts through pilots and experiments.
Expert witness. He has testified or appeared before state commissions in Arkansas, California, Colorado, Connecticut, Delaware, the District of Columbia, Illinois, Indiana, Iowa, Kansas, Michigan, Maryland, Ontario (Canada) and Pennsylvania. He has assisted clients in submitting testimony in Georgia and Minnesota. He has made presentations to the California Energy Commission, the California Senate, the Congressional Office of Technology Assessment, the Kentucky Commission, the Minnesota Department of Commerce, the Minnesota Senate, the Missouri Public Service Commission, and the Electricity Pricing Collaborative in the state of Washington. In addition, he has led a variety of professional seminars and workshops on public utility economics around the world and taught economics at the university level.
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EXPERIENCE
Innovative Pricing
Report examining the costs and benefits of dynamic pricing in the Australian energy market. For the Australian Energy Market Commission (AEMC), developed a report that reviews the various forms of dynamic pricing, such as time-of-use pricing, critical peak pricing, peak time rebates, and real time pricing, for a variety of performance metrics including economic efficiency, equity, bill risk, revenue risk, and risk to vulnerable customers. It also discusses ways in which dynamic pricing can be rolled out in Australia to raise load factors and lower average energy costs for all consumers without harming vulnerable consumers, such as those with low incomes or medical conditions requiring the use of electricity.
Whitepaper on emerging issues in innovative pricing. For the Regulatory Assistance Project (RAP), developed a whitepaper on emerging issues and best practices in innovative rate design and deployment. The paper includes an overview of AMI-enabled electricity pricing options, recommendations for designing the rates and conducting experimental pilots, an overview of recent pilots, full-deployment case studies, and a blueprint for rolling out innovative rate designs. The paper’s audience is international regulators in regions that are exploring the potential benefits of smart metering and innovative pricing.
Assessing the full benefits of real-time pricing. For two large Midwestern utilities, assessed and, where possible, quantified the potential benefits of the existing residential real-time pricing (RTP) rate offering. The analysis included not only “conventional” benefits such as avoided resource costs, but under the direction of the state regulator was expanded to include harder-to-quantify benefits such as improvements to national security and customer service.
Pricing and Technology Pilot Design and Impact Evaluation for Connecticut Light & Power (CL&P). Designed the Plan-It Wise Energy pilot for all classes of customers and subsequently evaluated the Plan-It Wise Energy program (PWEP) in the summer of 2009. PWEP tested the impacts of CPP, PTR, and time of use (TOU) rates on the consumption behaviors of residential and small commercial and industrial customers.
Dynamic Pricing Pilot Design and Impact Evaluation: Baltimore Gas & Electric. Designed and evaluated the Smart Energy Pricing (SEP) pilot, which ran for four years from 2008 to 2011. The pilot tested a variety of rate designs including critical peak pricing and peak time rebates on residential customer consumption patterns. In addition, the pilot tested the impacts of smart thermostats and the Energy Orb.
Impact Evaluation of a Residential Dynamic Pricing Experiment: Consumers Energy (Michigan). Designed the pilot and carried out an impact evaluation with the
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purpose of measuring the impact of critical peak pricing (CPP) and peak time rebates (PTR) on residential customer consumption patterns. The pilot also tested the influence of switches that remotely adjust the duty cycle of central air conditioners.
Impact Simulation of Ameren Illinois Utilities’ Power Smart Pricing Program. Simulated the potential demand response of residential customers enrolled to real- time prices. Results of this simulation were presented to the Midwest ISO’s Supply Adequacy Working Group (SAWG) to explore alternative ways of introducing price responsive demand in the region.
The Case for Dynamic Pricing: Demand Response Research Center. Led a project involving the California Public Utilities Commission, the California Energy Commission, the state’s three investor-owned utilities, and other stakeholders in the rate design process. Identified key issues and barriers associated with the development of time-based rates. Revisited the fundamental objectives of rate design, including efficiency and equity, with a special emphasis on meeting the state's strongly-articulated needs for demand response and energy efficiency. Developed a score-card for evaluating competing rate designs and applied it to a set of illustrative rates that were created for four customer classes using actual utility data. The work was reviewed by a national peer-review panel.
Developed a Customer Price Response Model: Consolidated Edison. Specified, estimated, tested, and validated a large-scale model that analyzes the response of some 2,000 large commercial customers to rising steam prices. The model includes a module for analyzing conservation behavior, another module for forecasting fuel switching behavior, and a module for forecasting sales and peak demand
Design and Impact Evaluation of the Statewide Pricing Pilot: Three California Utilities. Working with a consortium of California’s three investor-owned utilities to design a statewide pricing pilot to test the efficacy of dynamic pricing options for mass- market customers. The pilot was designed using scientific principles of experimental design and measured changes in usage induced by dynamic pricing for over 2,500 residential and small commercial and industrial customers. The impact evaluation was carried out using state-of-the-art econometric models. Information from the pilot was used by all three utilities in their business cases for advanced metering infrastructure (AMI). The project was conducted through a public process involving the state’s two regulatory commissions, the power agency, and several other parties.
Economics of Dynamic Pricing: Two California Utilities. Reviewed a wide range of dynamic pricing options for mass-market customers. Conducted an initial cost- effectiveness analysis and updated the analysis with new estimates of avoided costs and results from a survey of customers that yielded estimates of likely participation rates.
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Economics of Time-of-Use Pricing: A Pacific Northwest Utility. This utility ran the nation’s largest time-of-use pricing pilot program. Assessed the cost-effectiveness of alternative pricing options from a variety of different perspectives. Options included a standard three-part time-of-use rate and a quasi-real time variant where the prices vary by day. Worked with the client in developing a regulatory strategy. Worked later with a collaborative to analyze the program’s economics under a variety of scenarios of the market environment.
Economics of Dynamic Pricing Options for Mass Market Customers - Client: A Multi-State Utility. Identified a variety of pricing options suited to meet the needs of mass-market customers, and assessed their cost-effectiveness. Options included standard three-part time-of-use rates, critical peak pricing, and extreme-day pricing. Developed plans for implementing a pilot program to obtain primary data on customer acceptance and load shifting potential. Worked with the client in developing a regulatory strategy.
Real-Time Pricing in California - Client: California Energy Commission. Surveyed the national experience with real-time pricing of electricity, directed at large power customers. Identified lessons learned and reviewed the reasons why California was unable to implement real-time pricing. Catalogued the barriers to implementing real-time pricing in California, and developed a program of research for mitigating the impacts of these barriers.
Market-Based Pricing of Electricity - Client: A Large Southern Utility. Reviewed pricing methodologies in a variety of competitive industries including airlines, beverages, and automobiles. Recommended a path that could be used to transition from a regulated utility environment to an open market environment featuring customer choice in both wholesale and retail markets. Held a series of seminars for senior management and their staffs on the new methodologies.
Tools for Electricity Pricing - Client: Consortium of Several U.S. and Foreign Utilities. Developed Product Mix, a software package that uses modern finance theory and econometrics to establish a profit-maximizing menu of pricing products. The products range from the traditional fixed-price product to time-of-use prices to hourly real-time prices, and also include products that can hedge customers’ risks based on financial derivatives. Outputs include market share, gross revenues, and profits by product and provider. The calculations are performed using probabilistic simulation, and results are provided as means and standard deviations. Additional results include delta and gamma parameters that can be used for corporate risk management. The software relies on a database of customer load response to various pricing options called StatsBank. This database was created by metering the hourly loads of about one thousand commercial and industrial customers in the United States and the United Kingdom.
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Risk-Based Pricing - Client: Midwestern Utility. Developed and tested new pricing products for this utility that allowed it to offer risk management services to its customers. One of the products dealt with weather risk; another one dealt with risk that real-time prices might peak on a day when the customer does not find it economically viable to cut back operations.
Demand Response
National Action Plan for Demand Response: Federal Energy Regulatory Commission. Led a consulting team developing a national action plan for demand response (DR). The national action plan outlined the steps that need to be taken in order to maximize the amount of cost-effective DR that can be implemented. The final document was filed with U.S. Congress in June 2010.
National Assessment of Demand Response Potential: Federal Energy Regulatory Commission. Led a team of consultants to assess the economic and achievable potential for demand response programs on a state-by-state basis. The assessment was filed with the U.S. Congress in 2009, as required by the Energy Independence and Security Act of 2007.
Evaluation of the Demand Response Benefits of Advanced Metering Infrastructure: Mid-Atlantic Utility. Conducted a comprehensive assessment of the benefits of advanced metering infrastructure (AMI) by developing dynamic pricing rates that are enabled by AMI. The analysis focused on customers in the residential class and commercial and industrial customers under 600 kW load.
Estimation of Demand Response Impacts: Major California Utility. Worked with the staff of this electric utility in designing dynamic pricing options for residential and small commercial and industrial customers. These options were designed to promote demand response during critical peak days. The analysis supported the utility’s advanced metering infrastructure (AMI) filing with the California Public Utilities Commission. Subsequently, the commission unanimously approved a $1.7 billion plan for rolling out nine million electric and gas meters based in part on this project work.
Smart Grid Strategy
Development of a smart grid investment roadmap for Vietnamese utilities. For the five Vietnamese power corporations, developed a roadmap to guide future smart grid investment decisions. The report identified and described the various smart grid investment options, established objectives for smart grid deployment, presented a multi-phase approach to deploying the smart grid, and provided preliminary recommendations regarding the best investment opportunities. Also presented
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relevant case studies and an assessment of the current state of the Vietnamese power grid. The project involved in-country meetings as well as a stakeholder workshop that was conducted by Brattle staff.
Cost-Benefit Analysis of the Smart Grid: Rocky Mountain Utility. Reviewed the leading studies on the economics of the smart grid and used the findings to assess the likely cost-effectiveness of deploying the smart grid in one geographical location.
Modeling benefits of smart grid deployment strategies. Developed a model for assessing benefits of smart grid deployment strategies over a long-term (e.g., 20- year) forecast horizon. The model, called iGrid, is used to evaluate seven distinct smart grid programs and technologies (e.g., dynamic pricing, energy storage, PHEVs) against seven key metrics of value (e.g., avoided resource costs, improved reliability).
Smart grid strategy in Canada. The Alberta Utilities Commission (AUC) was charged with responding to a Smart Grid Inquiry issued by the provincial government. Advised the AUC on the smart grid, and what impacts it might have in Alberta.
Smart grid deployment analysis for collaborative of utilities. Adapted the iGrid modeling tool to meet the needs of a collaborative of utilities in the southern U.S. In addition to quantifying the benefits of smart grid programs and technologies (e.g., advanced metering infrastructure deployment and direct load control), the model was used to estimate the costs of installing and implementing each of the smart grid programs and technologies.
Development of a smart grid cost-benefit analysis framework. For the Electric Power Research Institute (EPRI) and the U.S. DOE, contributed to the development of an approach for assessing the costs and benefits of the DOE’s smart grid demonstration programs.
Analysis of the benefits of increased access to energy consumption information. For a large technology firm, assessed market opportunities for providing customers with increased access to real time information regarding their energy consumption patterns. The analysis includes an assessment of deployments of information display technologies and analysis of the potential benefits that are created by deploying these technologies.
Developing a plan for integrated smart grid systems. For a large California utility, helped to develop applications for funding for a project to demonstrate how an integrated smart grid system (including customer-facing technologies) would operate and provide benefits.
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Demand Forecasting
Comprehensive Review of Load Forecasting Methodology: PJM Interconnection. Conducted a comprehensive review of models for forecasting peak demand and re-estimated new models to validate recommendations. Individual models were developed for 18 transmission zones as well as a model for the RTO system.
Analyzed Downward Trend: Western Utility. We conducted a strategic review of why sales had been lower than forecast in a year when economic activity had been brisk. We developed a forecasting model for identifying what had caused the drop in sales and its results were used in an executive presentation to the utility’s board of directors. We also developed a time series model for more accurately forecasting sales in the near term and this model is now being used for revenue forecasting and budgetary planning.
Analyzed Why Models are Under-Forecasting: Southwestern Utility. Reviewed the entire suite of load forecasting models, including models for forecasting aggregate system peak demand, electricity consumption per customer by sector and the number of customers by sector. We ran a variety of forecasting experiments to assess both the ex-ante and ex-post accuracy of the models and made several recommendations to senior management.
U.S. Demand Forecast: Edison Electric Institute. For the U.S. as a whole, we developed a base case forecast and several alternative case forecasts of electric energy consumption by end use and sector. We subsequently developed forecasts that were based on EPRI’s system of end-use forecasting models. The project was done in close coordination with several utilities and some of the results were published in book form.
Developed Models for Forecasting Hourly Loads: Merchant Generation and Trading Company. Using primary data on customer loads, weather conditions, and economic activity, developed models for forecasting hourly loads for residential, commercial, and industrial customers for three utilities in a Midwestern state. The information was used to develop bids into an auction for supplying basic generation services.
Gas Demand Forecasting System - Client: A Leading Gas Marketing and Trading Company, Texas. Developed a system for gas nominations for a leading gas marketing company that operated in 23 local distribution company service areas. The system made week-ahead and month-ahead forecasts using advanced forecasting methods. Its objective was to improve the marketing company’s profitability by minimizing penalties associated with forecasting errors.
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Demand Side Management
The Economics of Biofuels. For a western utility that is facing stringent renewable portfolio standards and that is heavily dependent on imported fossil fuels, carried out a systematic assessment of the technical and economic ability of biofuels to replace fossil fuels.
Assessment of Demand-Side Management and Rate Design Options: Large Middle Eastern Electric Utility. Prepared an assessment of demand-side management and rate design options for the four operating areas and six market segments. Quantified the potential gains in economic efficiency that would result from such options and identified high priority programs for pilot testing and implementation. Held workshops and seminars for senior management, managers, and staff to explain the methodology, data, results, and policy implications.
Likely Future Impact of Demand-Side Programs on Carbon Emissions - Client: The Keystone Center. As part of the Keystone Dialogue on Climate Change, developed scenarios of future demand-side program impacts, and assessed the impact of these programs on carbon emissions. The analysis was carried out at the national level for the U.S. economy, and involved a bottom-up approach involving many different types of programs including dynamic pricing, energy efficiency, and traditional load management.
Sustaining Energy Efficiency Services in a Restructured Market - Client: Southern California Edison. Helped in the development of a regulatory strategy for implementing energy efficiency strategies in a restructured marketplace. Identified the various players that are likely to operate in a competitive market, such as third- party energy service companies (ESCOS) and utility affiliates. Assessed their objectives, strengths, and weaknesses and recommended a strategy for the client’s adoption. This strategy allowed the client to participate in the new market place, contribute to public policy objectives, and not lose market share to new entrants. This strategy has been embraced by a coalition of several organizations involved in the California PUC’s working group on public purpose programs.
Organizational Assessments of Capability for Energy Efficiency - Client: U.S. Agency for International Development, Cairo, Egypt. Conducted in-depth interviews with senior executives of several energy organizations, including utilities, government agencies, and ministries to determine their goals and capabilities for implementing programs to improve energy end-use efficiency in Egypt. The interviews probed the likely future role of these organizations in a privatized energy market, and were designed to help develop U.S. AID’s future funding agenda.
Enhancing Profitability Through Energy Efficiency Services - Client: Jamaica Public Service Company. Developed a plan for enhancing utility profitability by
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providing financial incentives to the client utility, and presented it for review and discussion to the utility’s senior management and Jamaica’s new Office of Utility Regulation. Developed regulatory procedures and legislative language to support the implementation of the plan. Conducted training sessions for the staff of the utility and the regulatory body.
Advanced Technology Assessment
Competitive Energy and Environmental Technologies - Clients: Consortium of clients, led by Southern California Edison, Included the Los Angeles Department of Water and Power and the California Energy Commission. Developed a new approach to segmenting the market for electrotechnologies, relying on factors such as type of industry, type of process and end use application, and size of product. Developed a user-friendly system for assessing the competitiveness of a wide range of electric and gas-fired technologies in more than 100 four-digit SIC code manufacturing industries and 20 commercial businesses. The system includes a database on more than 200 end-use technologies, and a model of customer decision making.
Market Infrastructure of Energy Efficient Technologies - Client: EPRI. Reviewed the market infrastructure of five key end-use technologies, and identified ways in which the infrastructure could be improved to increase the penetration of these technologies. Data was obtained through telephone interviews with equipment manufacturers, engineering firms, contractors, and end-use customers
TESTIMONY California
Rebuttal Testimony before the Public Utilities Commission of the State of California, Pacific Gas and Electric Company Joint Utility on Demand Elasticity and Conservation Impacts of Investor- Owned Utility Proposals, in the Matter of Rulemaking 12-06-013, October 17, 2014. Prepared testimony before the Public Utilities Commission of the State of California on behalf of Pacific Gas and Electric Company on rate relief, Docket No. A.10-03-014, summer 2010. Qualifications and prepared testimony before the Public Utilities Commission of the State of California, on behalf of Southern California Edison, Edison SmartConnect™ Deployment Funding and Cost Recovery, exhibit SCE-4, July 31, 2007. Testimony on behalf of the Pacific Gas & Electric Company, in its application for Automated Metering Infrastructure with the California Public Utilities Commission. Docket No. 05-06-028, 2006. Colorado
Rebuttal testimony before the Public Utilities Commission of the State of Colorado in the Matter of Advice Letter No. 1535 by Public Service Company of Colorado to Revise its Colorado PUC No.7 Electric Tariff to Reflect Revised Rates and Rate Schedules to be Effective on June 5, 2009. Docket No. 09al-299e, November 25, 2009.
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Direct testimony before the Public Utilities Commission of the State of Colorado, on behalf of Public Service Company of Colorado, on the tariff sheets filed by Public Service Company of Colorado with advice letter No. 1535 – Electric. Docket No. 09S-__E, May 1, 2009. Connecticut
Testimony before the Department of Public Utility Control, on behalf of the Connecticut Light and Power Company, in its application to implement Time-of-Use , Interruptible Load Response, and Seasonal Rates- Submittal of Metering and Rate Pilot Results- Compliance Order No. 4, Docket no. 05-10-03RE01, 2007. District of Columbia
Direct testimony before the Public Service Commission of the District of Columbia on behalf of Potomac Electric Power Company in the matter of the Application of Potomac Electric Power Company for Authorization to Establish a Demand Side Management Surcharge and an Advance Metering Infrastructure Surcharge and to Establish a DSM Collaborative and an AMI Advisory Group, case no. 1056, May 2009. Illinois
Direct testimony on rehearing before the Illinois Commerce Commission on behalf of Ameren Illinois Company, on the Smart Grid Advanced Metering Infrastructure Deployment Plan, Docket No. 12-0244, June 28, 2012. Testimony before the State of Illinois – Illinois Commerce Commission on behalf of Commonwealth Edison Company regarding the evaluation of experimental residential real-time pricing program, 11-0546, April 2012. Prepared rebuttal testimony before the Illinois Commerce Commission on behalf of Commonwealth Edison, on the Advanced Metering Infrastructure Pilot Program, ICC Docket No. 06-0617, October 30, 2006. Indiana
Direct testimony before the State of Indiana, Indiana Utility Regulatory Commission, on behalf of Vectren South, on the smart grid. Cause no. 43810, 2009. Kansas
Direct testimony before the State Corporation Commission of the State of Kansas, on behalf of Westar Energy, in the matter of the Application of Westar Energy, Inc. and Kansas Gas and Electric Company to Make Certain Changes in Their Charges for Electric Service, Docket No. 15-WSEE-115-RTS, March 2, 2015. Maryland
Direct testimony before the Public Service Commission of Maryland, on behalf of Potomac Electric Power Company and Delmarva Power and Light Company, on the deployment of Advanced Meter Infrastructure. Case no. 9207, September 2009. Prepared direct testimony before the Maryland Public Service Commission, on behalf of Baltimore Gas and Electric Company, on the findings of BGE’s Smart Energy Pricing (“SEP”) Pilot program. Case No. 9208, July 10, 2009.
Minnesota Rebuttal testimony before the Minnesota Public Utilities Commission State of Minnesota on behalf of Northern States Power Company, doing business as Xcel Energy, in the matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota, Docket No. E002/GR-12-961, March 25, 2013.
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Direct testimony before the Minnesota Public Utilities Commission State of Minnesota on behalf of Northern States Power Company, doing business as Xcel Energy, in the matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota, Docket No. E002/GR-12-961, November 2, 2012. New Mexico
Direct testimony before the New Mexico Regulation Commission on behalf of Public Service Company of New Mexico in the matter of the Application of Public Service Company of New Mexico for Revision of its Retail Electric Rates Pursuant to Advice Notice No. 507, Case No. 14- 00332-UT, December 11, 2014. Pennsylvania
Direct testimony before the Pennsylvania Public Utility Commission, on behalf of PECO on the Methodology Used to Derive Dynamic Pricing Rate Designs, Case no. M-2009-2123944, October 28, 2010.
REGULATORY APPEARANCES Arkansas
Presented before the Arkansas Public Service Commission, “The Emergence of Dynamic Pricing” at the workshop on the Smart Grid, Demand Response, and Automated Metering Infrastructure, Little Rock, Arkansas, September 30, 2009. Delaware
Presented before the Delaware Public Service Commission, “The Demand Response Impacts of PHI’s Dynamic Pricing Program” Delaware, September 5, 2007. Kansas
Presented before the State Corporation Commission of the State of Kansas, “The Impact of Dynamic Pricing on Westar Energy" at the Smart Grid and Energy Storage Roundtable, Topeka, Kansas, September 18, 2009. Ohio
Presented before the Ohio Public Utilities Commission, “Dynamic Pricing for Residential and Small C&I Customers" at the Technical Workshop, Columbus, Ohio, March 28, 2012.
Texas
Presented before the Public Utility Commission of Texas, “Direct Load Control of Residential Air Conditioners in Texas,” at the PUCT Open Meeting, Austin, Texas, October 25, 2012.
PUBLICATIONS
Books
“Making the Most of the No Load Growth Business Environment,” with Dian Grueneich. Distributed Generation and Its Implications for the Utility Industry. Ed. Fereidoon P. Sioshansi. Academic Press, 2014. 303-320.
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“Arcturus: An International Repository of Evidence on Dynamic Pricing,” with Sanem Sergici. Smart Grid Applications and Developments, Green Energy and Technology. Ed. Daphne Mah, Ed. Peter Hills, Ed. Victor O. K. Li, Ed. Richard Balme. Springer, 2014. 59-74. “Will Energy Efficiency make a Difference,” with Fereidoon P. Sioshansi and Gregory Wikler. Energy Efficiency: Towards the end of demand growth. Ed. Fereidoon P. Sioshansi. Academic Press, 2013. 3-50. “The Ethics of Dynamic Pricing.” Smart Grid: Integrating Renewable, Distributed & Efficient Energy. Ed. Fereidoon P. Sioshansi. Academic Press, 2012. 61-83. Electricity Pricing in Transition. Co-editor with Kelly Eakin. Kluwer Academic Publishing, 2002. Pricing in Competitive Electricity Markets. Co-editor with Kelly Eakin. Kluwer Academic Publishing, 2000. Customer Choice: Finding Value in Retail Electricity Markets. Co-editor with J. Robert Malko. Public Utilities Inc. Vienna. Virginia: 1999. The Changing Structure of American Industry and Energy Use Patterns. Co-editor with John Broehl. Battelle Press, 1987. Customer Response to Time of Use Rates: Topic Paper I, with Dennis Aigner and Robert T. Howard, Electric Utility Rate Design Study, EPRI, 1981.
Technical Reports
Quantifying the Amount and Economic Impacts of Missing Energy Efficiency in PJM’s Load Forecast, with Sanem Sergici and Kathleen Spees, prepared for The Sustainable FERC Project, September 2014. Structure of Electricity Distribution Network Tariffs: Recovery of Residual Costs, with Toby Brown, prepared for the Australian Energy Market Commission, August 2014. Impact Evaluation of Ontario’s Time-of-Use Rates: First Year Analysis, with Sanem Sergici, Neil Lessem, Dean Mountain, Frank Denton, Byron Spencer, and Chris King, prepared for Ontario Power Authority, November 2013. Time-Varying and Dynamic Rate Design, with Ryan Hledik and Jennifer Palmer, prepared for RAP, July 2012. http://www.raponline.org/document/download/id/5131 The Costs and Benefits of Smart Meters for Residential Customers, with Adam Cooper, Doug Mitarotonda, Judith Schwartz, and Lisa Wood, prepared for Institute for Electric Efficiency, July 2011. http://www.smartgridnews.com/artman/uploads/1/IEE_Benefits_of_Smart_Meters_Final.pdf Measurement and Verification Principles for Behavior-Based Efficiency Programs, with Sanem Sergici, prepared for Opower, May 2011. http://opower.com/uploads/library/file/10/brattle_mv_principles.pdf Methodological Approach for Estimating the Benefits and Costs of Smart Grid Demonstration Projects. With R. Lee, S. Bossart, R. Hledik, C. Lamontagne, B. Renz, F. Small, D. Violette, and D. Walls. Pre-publication draft, prepared for the U. S. Department of Energy, Office of Electricity Delivery and Energy Reliability, the National Energy Technology Laboratory, and the Electric Power Research Institute. Oak Ridge, TN: Oak Ridge National Laboratory, November 28, 2009. Moving Toward Utility-Scale Deployment of Dynamic Pricing in Mass Markets. With Sanem Sergici and Lisa Wood. Institute for Electric Efficiency, June 2009. Demand-Side Bidding in Wholesale Electricity Markets. With Robert Earle. Australian Energy Market Commission, 2008. http://www.aemc.gov.au/electricity.php?r=20071025.174223
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Assessment of Achievable Potential for Energy Efficiency and Demand Response in the U.S. (2010-2030). With Ingrid Rohmund, Greg Wikler, Omar Siddiqui, and Rick Tempchin. American Council for an Energy-Efficient Economy, 2008. Quantifying the Benefits of Dynamic Pricing in the Mass Market. With Lisa Wood. Edison Electric Institute, January 2008. California Energy Commission. 2007 Integrated Energy Policy Report, CEC-100-2007-008- CMF. Applications of Dynamic Pricing in Developing and Emerging Economies. Prepared for The World Bank, Washington, DC. May 2005. Preventing Electrical Shocks: What Ontario—And Other Provinces—Should Learn About Smart Metering. With Stephen S. George. C. D. Howe Institute Commentary, No. 210, April 2005. Primer on Demand-Side Management. Prepared for The World Bank, Washington, DC. March 21, 2005. Electricity Pricing: Lessons from the Front. With Dan Violette. White Paper based on the May 2003 AESP/EPRI Pricing Conference, Chicago, Illinois, EPRI Technical Update 1002223, December 2003. Electric Technologies for Gas Compression. Electric Power Research Institute, 1997. Electrotechnologies for Multifamily Housing. With Omar Siddiqui. EPRI TR-106442, Volumes 1 and 2. Electric Power Research Institute, September 1996. Opportunities for Energy Efficiency in the Texas Industrial Sector. Texas Sustainable Energy Development Council. With J. W. Zarnikau et al. June 1995. Principles and Practice of Demand-Side Management. With John H. Chamberlin. EPRI TR- 102556. Palo Alto: Electric Power Research Institute, August 1993. EPRI Urban Initiative: 1992 Workshop Proceedings (Part I). The EPRI Community Initiative. With G.A. Wikler and R.H. Manson. TR-102394. Palo Alto: Electric Power Research Institute, May 1993. Practical Applications of Forecasting Under Uncertainty. With K.P. Seiden and C.A. Sabo.TR- 102394. Palo Alto: Electric Power Research Institute, December 1992. Improving the Marketing Infrastructure of Efficient Technologies: A Case Study Approach. With S.S. Shaffer. EPRI TR- I 0 1 454. Palo Alto: Electric Power Research Institute, December 1992. Customer Response to Rate Options. With J. H. Chamberlin, S.S. Shaffer, K.P. Seiden, and S.A. Blanc. CU-7131. Palo Alto: Electric Power Research Institute (EPRI), January 1991.
Articles and Chapters
“The Emergence of Organic Conservation,” with Ryan Hledik and Wade Davis, The Electricity Journal, Volume 28, Issue 5, June 2015, pp. 48-58. http://www.sciencedirect.com/science/article/pii/S1040619015001074 “The Paradox of Inclining Block Rates,” with Ryan Hledik and Wade Davis, Public Utilities Fortnightly, April 2015. http://www.fortnightly.com/fortnightly/2015/04/paradox-inclining-block-rates “Smart By Default,” with Ryan Hledik and Neil Lessem, Public Utilities Fortnightly, August 2014. http://www.fortnightly.com/fortnightly/2014/08/smart- default?page=0%2C0&authkey=e5b59c3e26805e2c6b9e469cb9c1855a9b0f18c67bbe7d8d4ca08a 8abd39c54d “Quantile Regression for Peak Demand Forecasting,” with Charlie Gibbons, SSRN, July 31, 2014. http://papers.ssrn.com/sol3/papers.cfm?abstract_id=2485657 “Study Ontario for TOU Lessons,” Intelligent Utility, April 1, 2014.
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http://www.intelligentutility.com/article/14/04/study-ontario-tou- lessons?quicktabs_11=1&quicktabs_6=2 “Impact Measurement of Tariff Changes When Experimentation is Not an Option – a Case Study of Ontario, Canada,” with Sanem Sergici, Neil Lessem, and Dean Mountain, SSRN, March 2014. http://ssrn.com/abstract=2411832 “Dynamic Pricing in a Moderate Climate: The Evidence from Connecticut,” with Sanem Sergici and Lamine Akaba, Energy Journal, 35:1, pp. 137-160, January 2014. “Charting the DSM Sales Slump,” with Eric Schultz, Spark, September 2013. http://spark.fortnightly.com/fortnightly/charting-dsm-sales-slump “Arcturus: International Evidence on Dynamic Pricing,” with Sanem Sergici, The Electricity Journal, 26:7, August/September 2013, pp. 55-65. http://www.sciencedirect.com/science/article/pii/S1040619013001656 “Dynamic Pricing of Electricity for Residential Customers: The Evidence from Michigan,” with Sanem Sergici and Lamine Akaba, Energy Efficiency, 6:3, August 2013, pp. 571–584. “Benchmarking your Rate Case,” with Ryan Hledik, Public Utility Fortnightly, July 2013. http://www.fortnightly.com/fortnightly/2013/07/benchmarking-your-rate-case “Surviving Sub-One-Percent Growth,” Electricity Policy, June 2013. http://www.electricitypolicy.com/articles/5677-surviving-sub-one-percent-growth “Demand Growth and the New Normal,” with Eric Shultz, Public Utility Fortnightly, December 2012. http://www.fortnightly.com/fortnightly/2012/12/demand-growth-and-new- normal?page=0%2C1&authkey=4a6cf0a67411ee5e7c2aee5da4616b72fde10e3fbe215164cd4e5d bd8e9d0c98 “Energy Efficiency and Demand Response in 2020 – A Survey of Expert Opinion,” with Doug Mitarotonda, March 2012. Available at SSRN: http://ssrn.com/abstract=2029150 “Dynamic Pricing for Residential and Small C&I Customers,” presented at the Ohio Public Utilities Commission Technical Workshop, March 28, 2012. http://www.brattle.com/_documents/UploadLibrary/Upload1026.pdf “The Discovery of Price Responsiveness – A Survey of Experiments Involving Dynamic Pricing of Electricity,” with Jennifer Palmer, Energy Delta Institute, Vol.4, No. 1, April 2012. http://www.energydelta.org/mainmenu/edi-intelligence-2/our-services/quarterly-2/edi-quarterly- vol-4-issue-1 “Green Ovations: Innovations in Green Technologies,” with Pritesh Gandhi, Electric Energy T&D Magazine, January-February 2012. http://www.electricenergyonline.com/?page=show_article&mag=76&article=618 “Dynamic Pricing of Electricity and its Discontents” with Jennifer Palmer, Regulation, Volume 34, Number 3, Fall 2011, pp. 16-22. http://www.cato.org/pubs/regulation/regv34n3/regv34n3-5.pdf “Smart Pricing, Smart Charging,” with Ryan Hledik, Armando Levy, and Alan Madian, Public Utility Fortnightly, Volume 149, Number 10, October 2011. http://www.fortnightly.com/archive/puf_archive_1011.cfm “The Energy Efficiency Imperative” with Ryan Hledik, Middle East Economic Survey, Vol LIV: No. 38, September 19, 2011. “Are LDCs and customers ready for dynamic prices?” with Jürgen Weiss, Fortnightly’s Spark, August 25, 2011. http://spark.fortnightly.com/sitepages/pid58.php?ltemplate=intro_archive&pageId=58&lcommtyp eid=6&item_id=33
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“Dynamic pricing of electricity in the mid-Atlantic region: econometric results from the Baltimore gas and electric company experiment,” with Sanem Sergici, Journal of Regulatory Economics, 40:1, August 2011, pp. 82-109. “Better Data, New Conclusions,” with Lisa Wood, Public Utilities Fortnightly, March 2011, pp. 47-48. http://www.fortnightly.com/archive/puf_archive_0311.cfm “Residential Dynamic Pricing and ‘Energy Stamps,’” Regulation, Volume 33, No. 4, Winter 2010-2011, pp. 4-5. http://www.cato.org/pubs/regulation/regv33n4/v33n4.html “Dynamic Pricing and Low-Income Customers: Correcting misconceptions about load- management programs,” with Lisa Wood, Public Utilities Fortnightly, November 2010, pp. 60- 64. http://www.fortnightly.com/archive/puf_archive_1110.cfm “The Untold Story: A Survey of C&I Dynamic Pricing Pilot Studies” with Jennifer Palmer and Sanem Sergici, Metering International, ISSN: 1025-8248, Issue: 3, 2010, p.104. “Household response to dynamic pricing of electricity–a survey of 15 experiments,” with Sanem Sergici, Journal of Regulatory Economics (2010), 38:193-225 “Unlocking the €53 billion savings from smart meters in the EU: How increasing the adoption of dynamic tariffs could make or break the EU’s smart grid investment,” with Dan Harris and Ryan Hledik, Energy Policy, Volume 38, Issue 10, October 2010, pp. 6222-6231. http://www.sciencedirect.com/science/article/pii/S0301421510004738 “Fostering economic demand response in the Midwest ISO,” with Attila Hajos, Ryan Hledik, and Sam Newell, Energy, Volume 35, Issue 4, Special Demand Response Issue, April 2010, pp. 1544- 1552. http://www.sciencedirect.com/science/article/pii/S0360544209004009 “The impact of informational feedback on energy consumption – A survey of the experimental evidence,” with Sanem Sergici and Ahmed Sharif, Energy, Volume 35, Issue 4, Special Demand Response Issue, April 2010, pp. 1598-1608. http://www.sciencedirect.com/science/article/pii/S0360544209003387 “Dynamic tariffs are vital for smart meter success,” with Dan Harris, Utility Week, March 10, 2010. http://www.utilityweek.co.uk/news/news_story.asp?id=123888&title=Dynamic+tariffs+are+vital +for+smart+meter+success “Rethinking Prices,” with Ryan Hledik and Sanem Sergici, Public Utilities Fortnightly, January 2010, pp. 31-39. http://www.fortnightly.com/uploads/01012010_RethinkingPrices.pdf “Piloting the Smart Grid,” with Ryan Hledik and Sanem Sergici, The Electricity Journal, Volume 22, Issue 7, August/September 2009, pp. 55-69. http://www.sciencedirect.com/science/article/pii/S1040619009001663 “Smart Grid Strategy: Quantifying Benefits,” with Peter Fox-Penner and Ryan Hledik, Public Utilities Fortnightly, July 2009, pp. 32-37. http://www.fortnightly.com/pubs/07012009_QuantifyingBenefits.pdf “The Power of Dynamic Pricing,” with Ryan Hledik and John Tsoukalis, The Electricity Journal, April 2009, pp. 42-56. http://www.sciencedirect.com/science/article/pii/S1040619009000414 “Transition to Dynamic Pricing,” with Ryan Hledik, Public Utilities Fortnightly, March 2009, pp. 26-33. http://www.fortnightly.com/display_pdf.cfm?id=03012009_DynamicPricing.pdf “Ethanol 2.0,” with Robert Earle, Regulation, Winter 2009. http://www.cato.org/pubs/regulation/regv31n4/v31n4-noted.pdf
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“Inclining Toward Efficiency,” Public Utilities Fortnightly, August 2008, pp. 22-27. http://www.fortnightly.com/exclusive.cfm?o_id=94 “California: Mandating Demand Response,” with Jackalyne Pfannenstiel, Public Utilities Fortnightly, January 2008, pp. 48-53. http://www.fortnightly.com/display_pdf.cfm?id=01012008_MandatingDemandResponse.pdf “Avoiding Load Shedding by Smart Metering and Pricing,” with Robert Earle, Metering International, Issue 1 2008, pp. 76-77. “The Power of 5 Percent,” with Ryan Hledik, Sam Newell, and Hannes Pfeifenberger, The Electricity Journal, October 2007, pp. 68-77. http://www.sciencedirect.com/science/article/pii/S1040619007000991 “Pricing Programs: Time-of-Use and Real Time,” Encyclopedia of Energy Engineering and Technology, September 2007, pp. 1175-1183. http://www.drsgcoalition.org/resources/other/Pricing_Programs_TOU_and_RTP.pdf “Breaking Out of the Bubble: Using demand response to mitigate rate shocks,” Public Utilities Fortnightly, March 2007, pp. 46-48 and pp. 50-51. http://brattlegroup.com/_documents/uploadlibrary/articlereport2438.pdf “From Smart Metering to Smart Pricing,” Metering International, Issue 1, 2007. http://www.brattle.com/_documents/UploadLibrary/ArticleReport2439.pdf “Demand Response and the Role of Regional Transmission Operators,” with Robert Earle, 2006 Demand Response Application Service, Electric Power Research Institute, 2006. “2050: A Pricing Odyssey,” The Electricity Journal, October, 2006. http://www.puc.nh.gov/Electric/06061/epact%20articles/EJ%202050%20%20A%20Pricing%20 Odyssey.pdf “Demand Response and Advanced Metering,” Regulation, Spring 2006. 29:1 24-27. http://www.cato.org/pubs/regulation/regv29n1/v29n1-3.pdf “Reforming electricity pricing in the Middle East,” with Robert Earle and Anees Azzouni, Middle East Economic Survey (MEES), December 5, 2005. “Controlling the thirst for demand,” with Robert Earle and Anees Azzouni, Middle East Economic Digest (MEED), December 2, 2005. http://www.crai.com/uploadedFiles/RELATING_MATERIALS/Publications/files/Controlling%2 0the%20Thirst%20for%20Demand.pdf “California pricing experiment yields new insights on customer behavior,” with Stephen S. George, Electric Light & Power, May/June 2005. http://www.elp.com/index/display/article-display/229131/articles/electric-light-power/volume- 83/issue-3/departments/news/california-pricing-experiment-yields-new-insights-on-customer- behavior.html “Quantifying Customer Response to Dynamic Pricing,” with Stephen S. George, Electricity Journal, May 2005. “Dynamic pricing for the mass market: California experiment,” with Stephen S. George, Public Utilities Fortnightly, July 1, 2003, pp. 33-35. “Toward post-modern pricing,” Guest Editorial, The Electricity Journal, July 2003. “Demise of PSE’s TOU program imparts lessons,” with Stephen S. George. Electric Light & Power, January 2003, pp.1 and15. “2003 Manifesto on the California Electricity Crisis,” with William D. Bandt, Tom Campbell, Carl Danner, Harold Demsetz, Paul R. Kleindorfer, Robert Z. Lawrence, David Levine, Phil McLeod, Robert Michaels, Shmuel S. Oren, Jim Ratliff, John G. Riley, Richard Rumelt, Vernon L. Smith, Pablo Spiller, James Sweeney, David Teece, Philip Verleger, Mitch Wilk, and Oliver Williamson. May 2003. Posted on the AEI-Brookings Joint Center web site, at http://www.aei-brookings.org/publications/abstract.php?pid=341
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“Reforming pricing in retail markets,” with Stephen S. George. Electric Perspectives, September/October 2002, pp. 20-21. “Pricing reform in developing countries,” Power Economics, September 2002, pp. 13-15. “The barriers to real-time pricing: separating fact from fiction,” with Melanie Mauldin, Public Utilities Fortnightly, July 15, 2002, pp. 30-40. “The value of dynamic pricing,” with Stephen S. George, The Electricity Journal, July 2002, pp. 45-55. “The long view of demand-side management programs,” with Gregory A. Wikler and Ingrid Bran, in Markets, Pricing and Deregulation of Utilities, Michael A. Crew and Joseph C. Schuh, editors, Kluwer Academic Publishers, 2002, pp. 53-68. “Time to get serious about time-of-use rates,” with Stephen S. George, Electric Light & Power, February 2002, Volume 80, Number 2, pp. 1-8. “Getting out of the dark: Market based pricing can prevent future crises,” with Hung-po Chao, Vic Niemeyer, Jeremy Platt and Karl Stahlkopf, Regulation, Fall 2001, pp. 58-62. http://www.cato.org/pubs/regulation/regv24n3/specialreport2.pdf “Analyzing California’s power crisis,” with Hung-po Chao, Vic Niemeyer, Jeremy Platt and Karl Stahlkopf, The Energy Journal, Vol. 22, No. 4, pp. 29-52. “Hedging Exposure to Volatile Retail Electricity Prices,” with Bruce Chapman, Dan Hansen and Chris Holmes, The Electricity Journal, June 2001, pp. 33-38. “California Syndrome,” with Hung-po Chao, Vic Niemeyer, Jeremy Platt and Karl Stahlkopf, Power Economics, May 2001, Volume 5, Issue 5, pp. 24-27. “The choice not to buy: energy savings and policy alternatives for demand response,” with Steve Braithwait, Public Utilities Fortnightly, March 15, 2001. “Tomorrow’s Electric Distribution Companies,” with K. P. Seiden, Business Economics, Vol. XXXVI, No. 1, January 2001, pp. 54-62. “Bundling Value-Added and Commodity Services in Retail Electricity Markets,” with Kelly Eakin, Electricity Journal, December 2000. “Summer in San Diego,” with Kelly Eakin, Public Utilities Fortnightly, September 15, 2000. “Fighting Price Wars,” Harvard Business Review, May-June 2000. “When Will I See Profits?” Public Utilities Fortnightly, June 1, 2000. “Mitigating Price Volatility by Connecting Retail and Wholesale Markets,” with Doug Caves and Kelly Eakin, Electricity Journal, April 2000. “The Brave New World of Customer Choice,” with J. Robert Malko, appears in Customer Choice: Finding Value in Retail Electricity Markets, Public Utilities Report, 1999. “What’s in Our Future?” with J. Robert Malko, appears in Customer Choice: Finding Value in Retail Electricity Markets, Public Utilities Report, 1999. “Creating Competitive Advantage by Strategic Listening,” Electricity Journal, May 1997. “Competitor Analysis,” Competitive Utility, November 1996. “Forecasting in a Competitive Environment: The Need for a New Paradigm,” Demand Forecasting for Electric Utilities, Clark W. Gellings (ed.), 2nd edition, Fairmont Press, 1996. “Defining Customer Solutions through Electrotechnologies: A Case Study of Texas Utilities Electric,” with Dallas Frandsen et al. ACEEE 1995 Summer Study on Energy Efficiency in Industry. ACEEE: Washington, D.C., 1995. “Opportunities for Energy Efficiency in the Texas Industrial Sector,” ACEEE 1995 Summer Proceedings. “Study on Energy Efficiency in Industry,” with Jay W. Zarnikau et al. ACEEE: Washington, D.C., 1995. “Promotion of Energy Efficiency through Environmental Compliance: Lessons Learned from a Southern California Case Study,” with Peter F. Kyricopoulos and Ishtiaq Chisti. ACEEE 1995 Summer Study on Energy Efficiency in Industry. ACEEE: Washington, D.C., 1995.
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“ATLAS: A New Strategic Forecasting Tool,” with John C. Parker et al. Proceedings: Delivering Customer Value, 7th National Demand-Side Management Conference. EPRI: Palo Alto, CA, June 1995. “Emerging Technologies for the Industrial Sector,” with Peter F. Kyricopoulos et al. Proceedings: Delivering Customer Value, 7th National Demand-Side Management Conference. EPRI: Palo Alto, CA, June 1995. “Estimating the Revenue Enhancement Potential of Electrotechnologies: A Case Study of Texas Utilities Electric,” with Clyde S. King et al. Proceedings: Delivering Customer Value, 7th National Demand-Side Management Conference. EPRI: Palo Alto, CA, June 1995. “Modeling Customer Technology Competition in the Industrial Sector,” Proceedings of the 1995 Energy Efficiency and the Global Environment Conference, Newport Beach, CA, February 1995. “DSM opportunities for India: A case study,” with Ellen Rubinstein, Greg Wikler, and Susan Shaffer, Utilities Policy, Vol. 4, No. 4, October 1994, pp. 285-301. “Clouds in the Future of DSM,” with G.A. Wikler and J.H. Chamberlin. Electricity Journal, July 1994. “The Changing Role of Forecasting in Electric Utilities,” with C. Melendy and J. Bloom. The Journal of Business Forecasting, pp. 3-7, Winter 1993–94. Also appears as “IRP and Your Future Role as Forecaster.” Proceedings of the 9th Annual Electric Utility Forecasting Symposium. Electric Power Research Institute (EPRI). San Diego, CA, September 1993. “Stalking the Industrial Sector: A Comparison of Cutting Edge Industrial Programs,” with P.F. Kyricopoulos. Proceedings of the 4CEEE 1994 Summer Study on Energy Efficiency in Buildings. ACEEE: Washington, D.C., August 1994. “Econometric and End-Use Models: Is it Either/Or or Both?” with K. Seiden and C. Melendy. Proceedings of the 9th Annual Electric Utility Forecasting Symposium. Electric Power Research Institute (EPRI). San Diego, CA, September 1993. “Savings from Efficient Electricity Use: A United States Case Study,” with C.W. Gellings and S.S. Shaffer. OPEC Review, June 1993. “The Trade-Off Between All-Ratepayer Benefits and Rate Impacts: An Exploratory Study,” Proceedings of the 6th National DSM Conference. With J.H. Chamberlin. Miami Beach, FL. March 1993. “The Potential for Energy Efficiency in Electric End-Use Technologies,” with G.A. Wikler, K.P. Seiden, and C.W. Gellings. IEEE Transactions on Power Systems. Seattle, WA, July 1992. “The Dynamics of New Construction Programs in the 90s: A Review of the North American Experience,” with G.A. Wikler. Proceedings of the 1992 Conference on New Construction Programs for Demand-Side Management, May 1992. “Forecasting Commercial End-Use Consumption” (Chapter 7), “Industrial End-Use Forecasting” (Chapter 8), and “Review of Forecasting Software” (Appendix 2) in Demand Forecasting in the Electric Utility Industry. C.W. Gellings and P.E. Lilbum (eds.): The Fairmont Press, 1992. “Innovative Methods for Conducting End-Use Marketing and Load Research for Commercial Customers: Reconciling the Reconciled,” with G.A. Wikler, T. Alereza, and S. Kidwell. Proceedings of the Fifth National DSM Conference. Boston, MA, September 1991. “Potential Energy Savings from Efficient Electric Technologies,” with C.W. Gellings and K.P. Seiden. Energy Policy, pp. 217–230, April 1991. “Demand Forecasting Methodologies: An overview for electric utilities,” with Thomas Kuczmowski and Peter Lilienthal, Energy: The International Journal, Volume 15, Issues 3-4, March-April 1990, pp. 285-296. “The role of demand-side management in Pakistan’s electric planning,” Energy Policy, August 1989, pp. 382-395. “Pakistan’s Economic Development in a Global Perspective: A profile of the first four decades, 1947-87,” with J. Robert Malko, Asian Profile, Volume 16, No. 6, December 1988.
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“The Residential Demand for Electricity by Time-of-Use: A survey of twelve experiments with peak load pricing,” with J. Robert Malko, Energy: The International Journal, Volume 8, Issue 10, October 1983, pp. 781-795. “Time-of-Use Rates and the Modification of Electric Utility Load Shapes,” with J. Robert Malko, Challenges for Public Utility Regulation in the 1980s, edited by H.M. Trebing, Michigan State University Public Utilities Papers, 1981. “Implementing Time-Of-Day Pricing of Electricity: Some Current Challenges and Activities,” with J. Robert Malko, Issues in Public Utility Pricing and Regulation, edited by M. A. Crew, Lexington Books, 1980. “Incorporating the Social Imperatives in Economic Structure: Pakistan in the years ahead,” The Journal of Economic Studies, Volume 1, No. 1, Autumn 1974.
Page 264 of 284 Summary of Residential Three-Part Tariffs
Demand Charge Demand Charge Peak Applicable Residential Effective Fixed Timing of Combined Utility ($/kW-month) Demand Hours Residential # Utility State Customers Date of charge demand with Energy Ownership interval Customer Served Rate ($/month) Summer Winter measurement Summer Winter TOU? Segment [1] Nevada Power (3 Part Rate) Investor Owned NV 757,698 Proposed 18.15 14.33 14.33 Any time 15 min NA NA No DG Only 26.19 peak or 4.04 Any time or [2] Nevada Power (TOU 3 Part Rate) Investor Owned NV 757,698 Proposed 18.15 4.04 15 min 13:00 - 19:00 NA Yes DG Only off-peak Peak Coincident [3] Sierra Pacific Power (3 Part Rate) Investor Owned NV 281,282 Proposed 24.50 8.63 8.63 Any time 15 min NA NA No DG Only Sierra Pacific Power (TOU 3 Part Rate) 19.12 peak or 4.46 5.89 peak or 4.46 Any time or [4] Investor Owned NV 281,282 Proposed 24.50 15 min 13:00 - 18:00 17:00 - 21:00 Yes DG Only off-peak off-peak Peak Coincident [5] Alabama Power Investor Owned AL 1,241,998 10/1/2011 14.50 1.50 1.50 Any time 15 min NA NA Yes All [6] Alaska Electric Light and Power Investor Owned AK 13,968 9/2/2011 11.49 6.72 11.11 Any time Unknown NA NA No All [7] Arizona Public Service Investor Owned AZ 1,019,292 7/1/2012 16.96 13.50 9.30 Peak Coincident 60 min 12:00 - 19:00 12:00 - 19:00 Yes All [8] Black Hills Power Investor Owned SD 54,617 4/1/2015 13.00 8.10 8.10 Any time 15 min NA NA No All [9] Black Hills Power Investor Owned WY 2,153 10/1/2014 15.50 8.25 8.25 Any time 15 min NA NA No All [10] City of Fort Collins Utilities Municipal CO 60,464 1/1/2015 5.37 2.40 2.40 Any time Unknown NA NA No All [11] City of Kinston Municipal NC 9,776 5/1/2005 14.02 9.43 7.33 Peak Coincident 15 min 13:00 - 19:00 7:00 - 9:00 No All [12] City of Longmont Municipal CO 34,697 1/1/2014 15.40 5.75 5.75 Any time 15 min NA NA No All [13] Dakota Electric Association Cooperative MN 94,924 9/11/2014 11.00 12.90 9.30 Any time 15 min No All 6:30 - 12:00 & [14] Dominion Investor Owned NC 101,158 1/1/2015 16.53 8.32 4.87 Peak Coincident 30 min 13:00 - 21:00 Yes All 17:00 - 21:00
7:00 - 11:00 & [15] Dominion Investor Owned VA 2,105,500 5/1/2015 12.00 5.68 3.95 Peak Coincident 30 min 11:00 - 22:00 Yes All 17:00 - 21:00 [16] Duke Energy Carolinas, LLC Investor Owned NC 1,608,151 7/1/2015 13.38 7.77 3.88 Peak Coincident 30 min 13:00 - 19:00 7:00 - 12:00 Yes All [17] Duke Energy Carolinas, LLC Investor Owned SC 460,178 11/1/2014 9.93 8.15 4.00 Peak Coincident 30 min 13:00 - 19:00 7:00 - 12:00 Yes All [18] Fort Morgan Municipal CO 5,273 2/1/2015 6.13 10.22 10.22 Any time Unknown NA NA No All [19] Georgia Power Investor Owned GA 2,072,622 4/1/2015 10.00 6.53 6.53 Any time 30 min NA NA Yes All [20] Midwest Energy Inc Cooperative KS 29,951 7/1/2015 22.00 6.40 6.40 Any time 15 min NA NA No All [21] Otter Tail Power Company Investor Owned MN 47,699 10/1/2011 16.00 6.08 5.11 Any time 60 min NA NA No All [22] Otter Tail Power Company Investor Owned ND 44,910 12/1/2009 18.38 6.52 2.63 Any time 60 min NA NA No All [23] Otter Tail Power Company Investor Owned SD 8,648 6/1/2011 13.00 7.05 5.93 Any time 60 min NA NA No All 9.59 up to 3 kW; 3.55 up to 3 kW; 17.82 up to 10 5:00-9:00 & [24] Salt River Project Political Subdivision AZ 891,668 4/1/2015 32.44 or 45.44 5.68 up to 10 kW; Peak Coincident 30 min 13:00 - 20:00 Yes DG only kW; 34.19 over 10 17:00-21:00 9.74 over 10 kW kW 11.34 peak or 11.34 peak or [25] South Carolina Public Service Authority State SC 140,126 2/1/2014 24.00 Peak Coincident 30 min 13:00 - 19:00 6:00 - 10:00 No DG only 4.85 off-peak 4.85 off-peak [26] South Carolina Public Service Authority State SC 140,126 12/1/2013 22.00 17.19 17.19 Any time Unknown No All [27] Swanton Village Electric Department Municipal VT 3,208 9/1/2014 26.57 6.77 6.77 Any time Unknown NA NA No All Exhibit FaruquiDirect-2 6.00 up to 7 kW; 6.00 up to 7 kW; [28] UNS Energy Investor Owned AZ 81,399 Proposed 20.00 Any time 60 min NA NA No DG only 9.95 over 7kW 9.95 over 7kW [29] We Energies Investor Owned WI 984,860 1/1/2016 17.86 3.79 3.79 Any time Unknown No DG only [30] Westar Energy Investor Owned KS 323,581 Proposed 15.00 10.00 3.00 Any time 15 min NA NA No All [31] Xcel Energy (PSCo) Investor Owned CO 1,182,093 7/1/2012 12.25 8.57 6.59 Any time 15 min NA NA No All Pa Page g e 1of2 265 of 284 Sources: Utility's tariffs and “Form EIA-861 2013 data files, EIA_861_Retail_Sales_2013.xls”(for Utility, State, and Residential Customers Served columns) Notes: Peak periods are applicable from Monday through Friday excluding following holidays : New Year's Day, Memorial Day, Independence Day, Labor Day, Thanksgiving Day, and Christmas. For some utilities, the monthly fixed charge has been calculated by multiplying a daily charge by 30.5. Rates that are applicable to DG customers only are for the most part mandatory and applicable only to new customers after the rates come into effect. If max demand in summer occurs during the Coincident Peak period then the max demand charge (4.04 dollars per kW) and coincident demand charge (22.15 dollars per kW) are added together to make the demand charge: 26.19 dollars per kW. [2]: Otherwise the demand charge is simply equal to the max demand charge. If max demand occurs during the Coincident Peak period then the max demand charge (4.46 dollars per kW) and coincident demand charge (14.66 dollars per kW in summer and 1.43 dollars per kW in winter) are added together to make the [4]: demand charge: 19.12 dollars per kW in summer and 5.89 dollars per kW in winter. Otherwise the demand charge is simply equal to the max demand charge. The rate also includes a summer mid-peak period for energy. [5]: Rate also includes a three month shoulder period during which the energy charge is always equal to the 5.8049 cents per kWh off -peak rate (months of October, April, & May). [6]: Mandatory if customer consumes more than 5,000 kWh per month for three consecutive months or has a recorded peak demand of 20 K W for three consecutive months. [3]: The monthly fixed charge is a daily basic service charge multiplied by 30.5 days. [8]-[9]: Blacks Hills also offers an optional time of use rate that includes both energy and demand charges for customers owning demand controllers, these are smart home energy controllers that limit maximum demand. Demand charge is the sum of the distribution demand charge and the generation demand charge. Energy charges are the sum of the generation kWh charge, transmission kWh charge, and distribution kWh charge. The distribution demand [15]: charge is 1.612 dollars per kW and the generation demand charge is 4.070 dollars per kW for the summer and 2.334 dollars per kW for the winter. The transmission charge is .970 cents per kWh and the distribution charge is .892 cents per kWh. The generation charge is 2.843 cents per kWh for peak and 0.915 cents per kWh for off-peak hours. [18]: Demand period is not explicitly identified and it is assumed to be maximum demand. [20]: The demand charge is based on the higher of maximum demand or 80% of the average maximum demand for the last three summer months. [21]-[23]: Demand is measured as the maximum winter demand for the most recent 12 months. New customers have an assumed demand of 3 kW for their first year. Fixed charge for MN is customer charge per month plus facilities charge per month. The demand charge is tiered and applies to demand with thresholds of the first 3 kW, the next 7kW, and all remaining kW. Energy and demand charges vary across three seasons: Winter, Summer (May, June, September, and October), and On- [24]: Peak Summer (July and August). All energy and demand charges shown here apply for the On-Peak Summer period. The utility is experimentally offering the rate plan to a limited number of non-DG customers. [27]: Demand will be the greater of the measured demand for the current month or 85% of the highest recorded demand established during the preceding eleven months. [28]: This rate plan is proposed and pending approval. The proposed rate is mandatory for new DG customers and optional for other residential customers. For the energy charge, the option to have a time of use feature is also proposed. The rate is mandatory for DG customers with an aggregate nameplate rating of less than 300 kW. The monthly fixed charge is the daily generation facilities charge plus a DG rider multiplied by 30.5 days. If exports to the grid exceed delivered [29]: energy in a particular month then the difference is credited at 4.245 cents per kWh. [30]: Westar Energy's rate has been proposed by the utility in an ongoing regulatory proceeding but has not yet been approved. Exhibit FaruquiDirect-2 Pa Page g e 2of 266 of 284 Exhibit Faruqui Direct-3 Page 1 of 17
Summary of Utility Distributed Generation (“DG”) Rate Reform
This exhibit summarizes recent activity to reform residential rates primarily in response to or in anticipation of inequities created by DG adoption and declining sales growth. A summary of the state-level activity in seventeen different states is provided in, Table 1, followed by descriptions of activities on a state by state basis.
Table 1: Recent Rate Reform Options by State
Table 1: Recent Rate Reform Options by State
Increase of Seasonal or Streamlined Seasonal or Demand Fixed Monthly Fixed Charge Capacity Buy-Sell DG-Specific TOU Demand Tiered Rate TOU Energy Charge Charge or Minimum Charge Arrangement Rate Charges Structure Charges State Utility Bill
[1] Arizona Arizona Public Service 8989 [2] Arizona Salt River Project 9999 9 9 [3] Arizona UNS 999 99 [4] California Investor Owned Utilities 89 99 [5] California Sacramento Municipal Utility District 99 9 [6] Colorado Statewide 9 [7] Connecticut Connecticut Light and Power 99 [8] Georgia Georgia Power Co. 888 [9] Hawaii Hawaiian Electric Co. 9 999 [10] Idaho Avista 9 [11] Idaho Idaho Power Co. 88 8 [12] Illinois Statewide 9 [13] Minnesota Xcel Energy 999 [14] Missouri Ameren 88 [15] Missouri Empire District Electric Co. 88 [16] Missouri KCP&L 99 [17] Oklahoma Statewide 9 9 [18] South Carolina South Carolina Public Service Authority 9999 9 9 [19] Texas Austin Energy 99 [20] Utah PacifiCorp (Rocky Mountain Power) 99 8 [21] Washington Avista 9 9 [22] Washington PacifiCorp (Pacific Power) 89 [23] Wisconsin WE Energies 999999
Key 9 Approved 9 Proposed (decision pending) 8 Proposed & rejected or withdrawn Notes: This table shows changes in rate structure as an evolution to existing rates. Common features between new and proposed as well as existing rate structures are not reflected here. Streamlined Tiered Rate Structure refers to energy charges. The Capacity Charge column refers to a charge based on the capacity of the solar pannels installed. An increase in the fixed charge was approved in December 2014. However, Senate Bill 570, which would result in a decrease in the fixed charge, has passed in the Senate and failed upon adjournment in the [7] House. The capacity charge proposed was to be calculated on the basis of the customer's peak demand over the past twelve months. Unlike other reforms refered to in the capacity charge column, this capacity charge [11] does not depend on the size of the solar panel installation. [12] A proposed senate bill aims at adding a demand charge in the current residential rate design. [14] Xcel Energy offers subscribers of its “Solar Rewards Community Garden” program a buy-sell arrangement type of contract. [17] State legislation allows for an increase in the fixed monthly charges for DG customers, but we have not found an example of a utility who has adopted this practice yet.
Page 267 of 284 Exhibit Faruqui Direct-3 Page 2 of 17
1. Arizona
In July 2013, Arizona Public Service (“APS”) proposed a new net metering policy for DG owners.
APS proposed two rate options: the first option would put DG owners on a three-part rate and continue to compensate them for their generation at the full retail rate; the second option was a buy-sell arrangement under which DG owners would have all consumption billed under one of the existing rate options, but they would be paid a lower wholesale rate for the total amount of electricity that they generate. In November 2013, the Arizona Corporation Commission (“ACC”) instead voted to implement a $0.70/kW charge on installed solar PV capacity, equating to a surcharge of roughly
$5/month for a typical residential rooftop solar installation.1 In April 2015, APS requested an increase in this charge to $3.00/kW or $21/month for a typical residential rooftop solar installation.2 The request is currently pending. However, the ACC staff has asked the Commission to reject the increase and ask the company to include it in its next general rate case application.3
APS offers the most highly subscribed three-part rate in the United States. Offered on an opt-in basis since the early 1980’s, approximately 10 percent of APS’s residential customers are enrolled in the rate, representing roughly 20 percent of residential sales.4 Participants face a demand charge of
$13.50/kW in the summer and $9.30/kW in the winter, as well as a $16.96/month fixed charge and an
1 APS’s Proposal to Change Net-Metering, ASU Energy Policy Innovation Council, Published October 2013, updated December 2013, p. 2, 3 and 5. 2 “APS asks to reset grid access charge for future solar customers.”, APS, accessed on July 20, 2015,
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energy charge that varies with the season and time of day (peak versus off-peak).5 The rate option is available to all residential customers including DG owners.
Salt River Project (“SRP”) offers a rate for DG customers different from the rates offered to other residential customers. This rate was approved by SRP’s Board of Directors in February 2015.6 It is a three-part rate which only applies to DG customers.7 The fixed charge varies by a customer’s amperage and ranges from $32.44/month to $45.44/month (both higher than the charge to non-DG customers).8 It is meant to recover the costs of billing and metering, customer service and distribution facilities. The variable charge varies by time of day and by season. The demand charge also varies by season and increases with a customer’s demand, ranging in the peak summer months of July and
August from $9.59/kW-month for a customer’s first 3 kW of demand, to $17.82/kW-month for the next 7 kW of demand, to $34.19/kW-month for demand in excess of 10 kW (with different, lower prices during other times of year).9 The standard rate for non–DG residential customers is a two-part rate with a fixed charge and a volumetric charge (with an optional Time-of-Use (“TOU”) feature). A three-part rate is also being offered experimentally to a limited number of non–DG customers through the “Pilot Price Plan For Residential Demand Rate Service”10. The rates offered by this plan are identical to the three-part rate offered to DG customers.
5 APS Rate Schedule ECT-2, Residential Service Time-of-Use with Demand Charge, Revised on July 1, 2012, page 1. Note: daily rate = $0.556 * 30.5 days. 6 SRP News release on February 26, 2015, accessed on July 1, 2015,
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UNS Energy Corporation (the Arizona-based parent company of Tuscon Electric Power and
UniSource Energy Services) asked the ACC to approve a three-part rate for DG customers who submit connections to new DG facilities after June 1, 2015. The fixed rate would be $20/month while the residential rate currently has a $10/month fixed charge.11 The demand charge proposed has a tiered structure. An optional TOU feature would be offered for the energy charge. This new three-part rate would also be proposed as an optional rate to non DG residential customers beginning May 1, 2016.12
Additionally, the utility is proposing to purchase excess energy from new rooftop systems using the
Renewable Credit Rate (that would be set on the market price of power generated by large solar arrays).13 This will initially be set at 5.84 cents per kWh and updated on an annual basis.14 Currently, residential customers are offered a two-part rate with a fixed rate and an energy charge (with the option of a TOU feature). Currently, DG customers can participate in a Net Metering program in which excess generation is credited at the the standard retail rate.15
11 “UES seeks new electric rates to reflect higher costs.”, UniSource Energy Services Updates, Accessed on July 10, 2015,
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2. California
In October 2013, California Assembly Bill 327 (“AB 327”) was enacted, directing the California Public
Utility Commission (“CPUC”) to reform residential rates including minimum bill and customer charges up to $10/month and develop a new rate for DG customers by December 31, 2015.16 This state legislation requires deriving a new framework from the analysis of the benefits and costs that distributed generation produces for the grid and for the public. The rates will be derived using a marginal cost based cost of service study. This initiative is called “NEM 2.0”.17
Concerning residential rates applicable to all customers, two of the three investor owned utilities
(“IOUs”) currently do not have a fixed charge (San Diego Gas & Electric and Pacific Gas and Electric) and the third (Southern California Edison) has a nominal fixed charge of $0.94/month.18 All three utilities have minimum bill requirements ranging from $2/month and $5/month.19 On July 3, 2015, the CPUC voted unanimously to make two structural changes to the rate design: requiring the utilities to implement default TOU rates by January 2019 and reducing the number of rate tiers from four to two. This decision also postponed consideration of levying a monthly fixed charge until at the earliest 2018, when default
TOU rates have been put in place.20 However, in the CPUC’s NEM 2.0 proceeding, utilities may propose fixed charges that would apply to residential net metering customers.21 In addition, the CPUC decision raised the maximum fixed charge included on the minimum bill to $10/month for non-CARE (California
16 Assembly Bill No. 327, California State Assembly, approved October 7, 2013.
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Alternate Rates for Energy)22 customers and $5/month for CARE customers.23 The decision states this rate design change “will allow for more accurate allocation of costs and for energy rates to more fairly reflect the cost of service”.24
Sacramento Municipal Utility District (“SMUD”) has a default two-part rate for all of its residential customers a consisting of a volumetric charge (which varies with season) and a $16/month fixed charge.25
This rate also has an optional TOU feature. In 2013, the Board approved a transition plan to eliminate the tiered structure of the volumetric charge by 2017.26 At the start of 2015, SMUD increased its fixed charge from $14/month to $16/month,27 and going forward, SMUD’s fixed charge will increase to $18/month in
2016 and to $20/month in 2017, as established by the Board in 2011. SMUD has also proposed a new optional rate for residential customers beginning in 2016. This proposed rate includes only three volumetric charges, year round peak and off-peak prices and a summer super peak price. This proposed
TOU rate moves SMUD closer to what it expects to propose as the standard residential rate design for its customers in 2018.28
22 The CARE program provides lower rates to low-income customers. 23 Decision on residential rate reform for Pacific Gas And Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company and transition to time-of-use rates – before the CPUC, on Rulemaking 12-06-013, issued July 3, 2015, page 227.
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3. Colorado
As part of an investigation on DG related issues opened by the Public Utilities Commission of
Colorado in March 2014,29 the staff said in July 2014 that the Commission has the authority to create separate rate classes for DG customers.30 In the June 2015 staff comments, the staff recommended that customer’s excess energy rate credit be less than the retail rate they pay for electricity. The staff also recommended including a TOU rate to all residential customer rates and a minimum bill charge for
DG customers that would be set at an amount that will ensure that the utility is revenue neutral.31
4. Connecticut
Connecticut Light and Power (CL&P), a subsidiary of Northeast Utilities, requested an increase in its fixed charge from $16.00 to $25.50 in its 2014 rate case.32 A December 2014 decision by the Public
Utilities Regulatory Authority (“PURA”) approved a smaller increase, raising the fixed charge to
$19.25/month. More recently, in June 2015, the Senate passed33 Senate Bill 570, which caps the fixed charge that residential customers pay at $10/month.34 Although the bill passed unanimously in the
Senate, it failed upon adjournment in the House.35
29 Details of Decision C14-0294, Proceeding No. 14M-0235E, issued March 18, 2014. 30 Trial staff’s initial brief in response to the Commission’s questions regarding Net Metering, Proceeding No. 14M-0235E, July 31, 2014. 31 Trial Staff’s Reply Comments to Comments Filed By Other Participants in Response to Decision No. C15- 0815-I, Colorado Public Utilities Commission, Proceeding No. 14M-0235E, pages 1 and 2, June 5, 2015. 32 Doug Stewart, “PURA proposal cuts CL&P customer increase by $7/mo.,” FOX CT, accessed on December 14, 2014,
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5. Georgia
In its 2013 rate case, Georgia Power proposed a rate specific to DG customers, referred to as
“Supplemental Power Service”. The utility proposed to introduce a monthly charge of $5.56/kW of installed solar PV capacity to be added as a surcharge to existing residential rates.36 However, in
November 2013, Georgia Power withdrew its proposal as part of a settlement agreement with interveners, approved by the Commission in December 2013.37 Residential rooftop solar owners continue to be billed under the utility’s current tiered rate structure available for all residential customers, which has inclining tiers in the summer and declining tiers in the winter, and includes a
$10/month fixed charge.38 The DG specific rate was rejected, but Georgia Power received approval for an optional three-part tariff with a TOU energy charge for residential customers in that same rate case.39
Georgia Power filed an update to the 2013 Rate Case Order and Settlement Agreement in October 2014, proposing to adjust the traditional base tariffs but with no change to the rate design. This was approved in
December 2014 and came into effect in January 2015.40
6. Hawaii
Hawaiian Electric Company (“HECO”) filed a Power Supply Improvement Plan (“PSIP”)41 and a
Distributed Generation Improvement Plan (“DGIP”)42 before the Hawaii Public Utilities Commission
36 Direct Testimony of Karl R. Rabago, October 18 2013, Page 7.
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on August 26, 2014 with several possible new rate design scenarios for DG customers. The filing also describes a “gross export purchase model” which compensates net energy metered customers at wholesale rates for the power they contribute to the grid.43 In January 2015, HECO proposed to the
Commission to repeal net energy metering and replace it with a transition tariff (“TDG”) that would cut the rate credit for power sold back to the grid by a factor of about 50%. The proposal also mentioned implementing a monthly fixed charge of $55/month for all residential customers and an additional $16/month charge for DG owners. The Commission judged HECO’s proposal as
“insufficiently supported” and refused to rule at this time.44
On June 29, 2015, HECO submitted another request to the Hawaii Public Utilities Commission in which they asked again to withdraw their current net metering program in favor of a smaller energy credit that would be assigned a dollar value, which could be used to offset monthly bills.45 Rather than a fixed charge, this proposal includes a $25 minimum monthly bill for all future residential PV customers to all islands. Currently, the minimum monthly bill is $17.00 on O‘ahu, $18.00 on Maui, and $20.50 on Hawaii Island.46 HECO also recommends a pilot TOU rate, which would be a voluntary program to new DG customers.
41 Hawaiian Electric Power Supply Improvement Plan, Hawaii Public Utilities Commission, Docket No. 2011-0206, issued August 26, 2014.
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7. Idaho
In late 2012, Idaho Power proposed to increase the fixed charge for residential net metering customers from $5.00/month to $20.92/month. With this proposal, Idaho Power would have also established a
“basic load capacity charge” of $1.48 per kilowatt to “reflect the full cost-of-service associated with their use of the distribution system”.47 These new charges would be offset by a reduction in the energy rates paid by net metering customers. The Idaho Public Utilities Commission rejected the rate design proposal in July 2013, stating these changes could be raised again in the context of a general rate case.48
Avista filed a Rate Case in May 2015 in which it asked Idaho Public Utilities Commission (IPUC) to increase its fixed and variable rates. The proposed fixed charge increase would be from $5.25 to $8.00 per month.49
8. Illinois
In March 2015, SB 1879 and HB 3328 were introduced in Illinois’ state Senate and Assembly and proposed, among a number of items concerning Illinois’ electric grid, to add a demand charge to the current residential rates design.50 HB 3328 missed its legislative deadline and is re-referred back to the
47 Final Order No. 32846, Idaho Public Utilities Commission, Case No. IPC-E-12-27, pages 1 and 2, July 3, 2013.
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House Rules Committee51 while SB 1879 passed the Senate Energy and Public Utilities Committee but is awaiting action on the Senate floor.52
9. Louisiana
Entergy proposed to reduce the net metering payment to DG owners for their excess generation, in recognition that solar-powered homes aren’t paying for their full use of the grid. The Louisiana Public
Service Commission rejected the proposal in June 201353, but agreed to conduct a detailed study on the costs and benefits of solar, and to revisit the issue when the enrollment cap on the state’s net metering policy is reached.54 The Commission released the study in March 2015, stating that net metered solar owners pay only a portion of what they cost to utilities although Entergy has not yet made a follow-up proposal request to the Commission.55
10. Minnesota
In March 2014,56 Minnesota passed legislation that will allow its utilities to use a “Value of Solar”
(“VOS”) tariff (type of buy-sell arrangement) as an alternative to traditional net metering. The measures of value that will ultimately determine the payment to DG generators are energy and “its delivery,
51 Bill Status of HB3328, Illinois General Assembly,
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generation capacity, transmission capacity, transmission and distribution line losses, and environmental value.”57 Minnesota’s VOS policy will have a fixed price (or will have a set inflation rate over time) for the electricity the customer generates, set by a 25-year contract between the solar generator and the utility
. The electricity generated would be credited at this rate on the customer’s bill.58 In Xcel Energy’s testimony to the Public Utilities Commission in February 2014, the utility estimated that the VOS energy charge would be 14.5 cents per kWh, which was higher than its residential rate at the time (11.5 cents per kWh).59 Xcel Energy updated their estimate of the VOS energy charge in April 2015 to a lower rate of
13.6 cents/kWh. The VOS energy charge would be adjusted for inflation using either a long term fixed rate or the Urban Consumer Price Index (CPI).
Utilities have the possibility to offer both options (VOS and traditional net metering) to their customers, but, according to a report published by Environment America in June 2015, “not a single Minnesota utility opted into the value-of-solar program.”60
As of December 2014, Xcel Energy offers to subscribe to its shared “Solar Rewards Community Garden
“on a 25-year contract basis which allows them to receive credits on their bill for their share of the electricity output. The credits are based on the wholesale "applicable retail rate"61 rather than the Value of
Solar rate.
57 Minnesota Value of Solar Tariff Methodology, Prepared for Minnesota Dept. of Commerce,
60 “Shining Rewards,” Environment America, Published June 2015,
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11. Missouri
In October 2014, Kansas City Power & Light (“KCP&L”) submitted a proposal requesting an increase in its fixed charge from $9/month to $25/month. In August 2014, the Empire District Electric Co. also requested an increase in its fixed charge from $12.52/month to $18.75/month.62 In June 2015, the
Missouri Public Service Commission decided the fixed monthly customer charge for Empire District
Electric Co. would stay at $12.52/month.63
In July 2014, Ameren Missouri also requested to increase their fixed charges from $8.00 to
$8.77/month. In April 2015, the Missouri Public Service Commission approved a smaller rate increase with no increase in fixed charge.64
12. Oklahoma
In April 2014, Oklahoma passed Senate Bill 1456, which allows regulated utilities to charge DG customers a separate rate, effective November 2014. The separate DG rate includes a fixed charge, which may be higher than the fixed charge allowed for customers within the same class who do not have distributed generation. The law does not apply to customers who installed solar panels prior to
November 2014.65 Oklahoma Gas & Electric (“OG&E”) and Public Service Company of Oklahoma
62 “As in Wisconsin, Missouri utilities seek to raise fixed charges,” Midwest Energy News, Accessed on July 24, 2015,
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(“PSO”) both plan to include a Distributed Generation Tariff to their rate cases expected by the end of
2015.66 A demand charge is also being considered by both utilities, although this type of charge is currently not allowed by the legislation, so would be more difficult to implement.67 OG&E cites that they “would prefer to deal with a distributed generation tariff as part of its upcoming rate case.”68
13. South Carolina
South Carolina Public Service Authority currently offers its DG customers a three-part rate which includes a fixed charge of $24/month, demand charges that vary for On-Peak and Off-Peak hours, and base energy charges that vary on both the time of year and time of day.69 The utility also has a net- metering program in which it offers its customers credits “based on the net On-Peak and net Off-Peak kilowatt hours purchased from or delivered to the Authority for the billing month.” Non-DG customers are also offered a similarly structured three-part rate, however they are charged a lower fixed charge of $22/month.70
14. Texas
Austin Energy began offering a Value of Solar (“VOS”) tariff in October 2012. The tariff is similar in concept to the buy-sell arrangement offered by other utilities, although the payment to DG owners
66 “OGE Energy: Utilities eye tariffs for solar, wind users.”, 4-traders , Published June 17, 2015,
70 “South Carolina Public Service Authority Residential Demand Service Rider RD-13” tariff sheet, Accessed July 22, 2015 < https://www.santeecooper.com/pdfs/rates/2013/residential-demand-service-rider-rd-13.pdf>
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includes a number of components, such as environmental value and avoided fuel hedging costs, which tend to lead to a higher price paid to DG owners. The tariff also includes a floor price that ensures a minimum payment level to DG owners over a future time period.71
MP2 Energy began offering net metering in March 2015 for the first time in Texas72 to the Dallas-Fort
Worth area. It offers a retail credit (including transmission and distribution service charges) to its solar customers who produce more energy than they consume, set at the long-term fixed retail supply rate.73
MP2 offers 12 or 24 or 60-month fixed rates.
15. Utah
After several years of unsuccessful attempts to introduce a fixed customer charge above $5/month,
PacifiCorp (through subsidiary Rocky Mountain Power) proposed a surcharge of $4.65/month for DG customers, indicating that the charge would “produce the same average monthly revenue per customer for distribution and customer costs that is recovered in energy charges from all residential customers based on the cost of service study.”74 In its rate case testimony, the utility advised the Utah
Commission that the surcharge was an interim measure and that in its next rate case it would be proposing a three-part rate designed specifically for partial requirements DG customers. The Public
Service Commission of Utah did not approve the proposal, citing a need for further assessment of the
71 Austin Energy – Value of Solar Residential Rate, DSIRE website. < http://programs.dsireusa.org/system/program/detail/5669 >, Accessed December 14, 2014. 72 “SolarCity, MP2 Energy Offer Solar to Texas Homeowners for Less than Utility Power without Local Incentives.” Pr Newswire. Published March 10, 2015. < http://www.prnewswire.com/news-releases/solarcity-mp2- energy-offer-solar-to-texas-homeowners-for-less-than-utility-power-without-local-incentives-300048028.html>, Accessed July 20, 2015 73 MP Energy. “MP2 Residential Solar Net Metering Program.”
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costs and benefits of net metering.75 The commission set up a public hearing for October 2015 to discuss this matter further.76 However, the decision by the Commission approved an increase in the customer charge from $5.00/month to $6.00/month as well as an increase in the minimum bill from
$7.00/month to $8.00/month for residential customers.77
16. Washington
In May 2014 PacifiCorp proposed to increase its fixed charge from $7.75/month to $14/month, which was rejected by the Washington Utilities and Transportation Commission in March 2015. 78 The proposal was packaged with a request for an overall rate increase with no increase to the fixed charge.
The commission accepted a smaller rate increase for PacifiCorp than was requested, citing that these were the “reasonable” rates. The utility advised the Washington Utilities and Transportation
Commission that in its next rate case it would be proposing a three-part rate designed specifically for partial requirements DG customers.79
75 PacifiCorp dba Rocky Mountain Power 2014 General Rate Case, Public Service Commission of Utah, pages 66 and 67, August 29, 2014,
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Avista filed a request with the Washington Utilities and Transportation Commission in February 2015 to increase its electric and natural gas rates. The filing includes a request to increase the monthly basic charge from $8.50/month to $14.00/month, and a decision is expected by January 2016.80
17. Wisconsin
As approved by the Commission in December 2014, WE Energies will offer a three-part rate to DG customers with less than 300 kW of installed capacity as of January 2016. The rate consists of a fixed charge of about $17.86/month81, a demand charge that depends on the class and voltage usage of the customer, and either a flat energy rate or an energy rate that depends on the time of year, time of day and voltage.82 The company credits net energy supplied by the customer using the Buy-Back Energy
Rate which differs with the customer’s rate schedule. Standard Residential Customers are offered a two part rate that includes a daily fixed charge (lower than the one in the new DG rate) and an energy charge which can be either flat83 or dependent on the time of use.84
80 Washington Filing FAQ, Avista Utilities, Accessed on July 24, 2015,
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