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AHMAD FARUQUI - Microsoft · Ahmad Faruqui . I. INTRODUCTION OF WITNESS . 1. Q. AND PARTY FOR WHOM...
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Transcript of AHMAD FARUQUI - Microsoft · Ahmad Faruqui . I. INTRODUCTION OF WITNESS . 1. Q. AND PARTY FOR WHOM...
AHMAD FARUQUI
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BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
Nevada Power Company d/b/a NV Energy
Docket No. 15_____ Net Metering and Distributed Generation Cost of Service and Tariff Design
Prepared Direct Testimony of
Ahmad Faruqui
I. INTRODUCTION OF WITNESS
1. Q. PLEASE STATE YOUR NAME, JOB TITLE, BUSINESS ADDRESS
AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
A. My name is Ahmad Faruqui. I am a Principal with the Brattle Group. My
business address is 201 Mission Street, Suite 2800, San Francisco, California
94105. I am filing testimony on behalf of Nevada Power Company d/b/a NV
Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV
Energy (“Sierra” and, together with Nevada Power, “NV Energy” or the
“Companies”).
2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
EXPERIENCE.
A. I have 35 years of consulting and research experience. During my career, I
have advised several dozen utilities, private energy companies, technology
providers, transmission system operators, regulatory commissions and
government agencies in the United States and in Australia, Canada, Egypt,
Hong Kong, Jamaica, Philippines, Saudi Arabia, South Africa and Vietnam
on a wide range of customer-side issues including sales and peak demand
forecasting, demand response, energy efficiency, rate design, integrated
resource planning, and the use of demand-side resources to facilitate the
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integration of retail and wholesale markets. I have testified or appeared
before a dozen state and provincial regulatory commissions and legislative
bodies. I have authored or co-authored more than one hundred papers on rate
designs and related issues and co-edited three books on pricing and customer
choice.
More details regarding my professional background and experience are set
forth in my Statement of Qualifications, included as Exhibit Faruqui-
Direct-1.
3. Q. WHAT ARE YOUR RESPONSIBILITIES AS PRINCIPAL WITH
THE BRATTLE GROUP?
A. In my current position, I lead the firm’s practice in understanding and
managing the changing needs of energy consumers. This work encompasses
rate design, distributed generation, energy efficiency, demand response,
demand forecasting and cost-benefit analysis of emerging technologies such
as advanced metering, energy storage, rooftop solar, smart thermostats and
electric vehicles.
4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
A. No, I have not.
II. OVERVIEW AND TESTIMONY ORGANIZATION
5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT
TESTIMONY IN THIS CASE?
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A. The purpose of my testimony is to review the new rate designs that Nevada
Power and Sierra are submitting to the Commission for net energy metering
(“NEM”) customers in Nevada.
6. Q. PLEASE SUMMARIZE YOUR TESTIMONY.
A. I have reviewed the three-part rate designs for new NEM customers that are
being proposed by Nevada Power and Sierra Pacific. The rates are based on
marginal cost of service studies. The three-part rates include a monthly
service charge, a demand charge and an energy charge. Two choices are
being offered to NEM customers, one of which does not have time variation
in the demand and energy charges, and one of which does have time
variation in these charges. I have calibrated NV Energy’s rates against the
Bonbright principles of rate design, which can be distilled into five
principles: economic efficiency, equity, bill stability, revenue stability and
customer satisfaction. I have found the NV Energy rates to be consistent with
those principles. Finally, I have calibrated their numerical values against the
three-part rate designs that are being offered by other utilities in the US and
found them to be broadly in line with those of the sampled utilities.
7. Q. HOW IS YOUR TESTIMONY ORGANIZED?
A. It is organized into several sections. Section III reviews the principles of rate
design. Section IV presents NV Energy’s rate design proposal, and compares
it to similar rates or rate proposals of other U.S. utilities. Section V
concludes the testimony.
8. Q. ARE YOU SPONSORING ANY EXHIBITS?
A. Yes, I sponsor the following exhibits to my testimony:
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Exhibit Faruqui Direct-1: Statement of Qualifications
Exhibit Faruqui Direct-2: Summary of Residential Three-Part Tariffs
Exhibit Faruqui Direct-3: Summary of Utility Distributed Generation
(“DG”) Rate Reform
III. PRINCIPLES OF RATE DESIGN
9. Q. PLEASE PROVIDE A HISTORICAL PERSPECTIVE ON THE
THEORY OF ELECTRIC RATE DESIGN.
A. The principles that guide electric rate design have evolved over time. Many
authorities have contributed to their development, beginning with the
legendary rate engineer John Hopkinson in the late 1800’s.1 His thinking on
the subject led him to propose a three-part tariff, consisting of a fixed service
charge a demand charge and an energy charge. The demand charge was
based on the maximum level of demand which occurred during the billing
period. In some versions of the Hopkinson tariff, as the demand, fixed
service fee and energy charge tariff came to be called, also feature seasonal
or time-of-use (“TOU”) variation corresponding to the variations in the costs
of energy supply.2
British, French and American economists have made further enhancements
to the original three-part rate design. These include: Maurice Allais, Marcel
Boiteux, Douglas J. Bolton, Ronald Coase, Jules Dupuit, Harold Hotelling,
Henrik Houthakker, W. Arthur Lewis, I. M. D. Little, James Meade, Peter
Steiner and Ralph Turvey. In 1961, Professor James C. Bonbright coalesced
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. 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).
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economists’ thinking in his canon, Principles of Public Utility Rates,
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was reissued in its second edition in 1988. Some of these ideas were further
expanded upon by Professor Alfred Kahn in his widely cited treatise, The
Economics of Regulation.4
10. Q. WHAT ARE THE GENERALLY ACCEPTED RATE DESIGN
PRINCIPLES?
A. Professor Bonbright developed 10 Principles of Rate Design that are widely
used as a foundation in designing rates. We have distilled these 10 principles
into five Core Principles of Rate Design.
1. Economic efficiency: this principle ensures that price acts as a signal
ensuring resources are not wasted. If a price is set to the incremental cost
of providing a kWh, customers who value the kWh more than the cost
will use it and customers who value it less will not.
2. Equity: no customer should unintentionally subsidize another customer.
For example, under flat rate pricing, different load profiles mean that
“peaky” customers are using electricity when it is most expensive and
they are subsidized by less “peaky” customers who overpay for cheap
off-peak electricity. Note that equity is not the same as social justice.
3. Revenue adequacy and stability: theoretically, all pricing schemes can be
implemented to be revenue neutral within a class, but this would require
perfect foresight of the future. Changing technologies and customer
behaviors make load forecasting more difficult and increase the risk of
the utility either under-recovering or over-recovering costs when rates are
not cost reflective.
3 James C. Bonbright, Albet L. Danielsen, and David R. Kamerschen, Principles of Public Utility Rates, 2d ed.
(Arlington, VA: Public Utility Reports, 1988). 4 Alfred Kahn, The Economics of Regulation: Principles and Institutions, rev. ed. (MIT Press, June 1988).
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4. Bill stability: rates should be stable and predictable. Rates that are not
cost reflective are less stable over time, since both costs and loads are
changing over time. For example if you spread a fixed charge over a
certain number of kWh’s and the next year the number of kWh’s halves,
then the price per kWh will double even though there is no change in the
underlying fixed cost.
5. Customer satisfaction: for a rate to work as planned, customers need
“buy in” for the rate. Because residential customers consider electricity to
be a relatively low priority, rates need to be relatively simple to
understand and simple to respond to. Providing choices to customers can
also help, because it allows customers to better answer varying needs and
risk tolerances.
Figure 1 shows the mapping between Bonbright’s original 10 principles and the
Five Core Principles defined above.
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Figure 1: Deriving the Five Core Principles of Rate Design
11. Q. HOW DO THESE PRINCIPLES ACCORD WITH THE WIDELY
ACCEPTED NOTION OF COST CAUSATION IN RATE DESIGN?
A. Economic efficiency and equity relate directly to the notion of cost
causation. Economic efficiency is achieved by having cost-reflective prices.
This ensures that products are only consumed by those customers who value
them at more than they cost to produce. Pricing below cost is wasteful
because customers will purchase and consume products that they would not
choose to consume if faced with paying full cost. Similarly, pricing above
cost is wasteful because customers, who would get a net benefit from
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consuming the product over its cost of production, lose out on that
enjoyment. Respecting the equity principle requires that the tariff’s design
not result in one customer unintentionally subsidizing another customer. This
differs from social justice, which would be an intentional subsidization
among customers through the tariff. Prices that are cost reflective minimize
unintentional subsidies. Cost causation may need to be balanced against the
other Core Principles such as customer satisfaction or bill stability.
12. Q. PLEASE SUMMARIZE THE STRUCTURE OF UTILITY COSTS?
A. In order to provide electricity to a customer, a utility must bear – directly or
indirectly – costs related to energy, generation, transmission, distribution,
metering and customer service (billing, customer inquiry, etc.). Generation
energy costs vary directly with electricity consumption, while distribution
and transmission costs vary with demand. Generation capacity costs vary
with demand. Metering and customer services are a fixed cost per each
customer. Some of these costs vary across time. Generation costs will vary
from hour to hour depending on the marginal generation source. Distribution
and transmission networks, while used year round, are sized to meet peak
demand. This system peak will be split across a limited number of hours
throughout the year.
13. Q. HOW DO THESE COSTS TRANSLATE INTO RATES?
A. According to the notion of cost causation, rates structure should match the
nature of the costs and have a fixed service charge, a demand charge and an
energy charge. The demand charge and the energy charge might vary with
the time of use of electricity and have different seasonal and/or peak/off-peak
charges.
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14. Q. HAVE THESE COST CAUSATION PRINCIPLES BEEN APPLIED IN
PRACTICE?
A. Yes, most commercial and industrial customers across the U.S. are served
under cost-reflective three-part rate structures.
15. Q. HAVE THESE COST CAUSATION PRINCIPLES BEEN APPLIED
TO RESIDENTIAL CUSTOMERS?
A. Historically they have not, however this is changing rapidly due to several
technological advances that have emerged in the last several years. As
described in the Summary of Residential Three-Part Tariffs that is attached
as Exhibit Faruqui Direct-2, at least 19 utilities in 14 states are currently
offering three-part rates to residential customers. Exhibit Faruqui Direct-3
discusses rate reforms which for the most part aim at modifying rates to
make them more cost-reflective. For instance, as shown in Table 1 of
Exhibit Faruqui Direct-3, most of the rate changes discussed in other US
jurisdictions include an increase in fixed the charge or minimum bill,
proposed to better reflect the utilities’ costs in the rates.
16. Q. WHAT TECHNOLOGICAL ADVANCES HAVE LEAD TO
INCREASED USE OF THREE-PART RATE STRUCTURES FOR
RESIDENTIAL CUSTOMERS?
A. Smart meters are capable of recording advanced billing functions such as
incremental consumption and demand, thereby removing a large barrier/cost
to the dissemination of cost-reflective rates (since additional specialized
meters are no longer required). In addition, smart meters can provide
feedback to customers on their electricity usage in real or near-real time and
also communicate with devices in the home. This allows a customer to
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clearly understand their electricity usage and manage their bills in a way that
was not widely available before.
The introduction of renewable DG, coupled with the two-part rate structure,
has resulted in the shifting of costs and revenue requirement. Utilities receive
less revenue from customers who pay two-part rates after the customer
installs renewable DG; yet, fixed and demand costs incurred to serve the
customer are largely not reduced. Responsibility for these costs is then
shifted to other customers, thereby shifting costs from customers who install
renewable DG to other customers. In short, customers who install renewable
DG are subsidized by customers who do not when a simple two-part rate
design that relies primarily on volumetric rates to recover demand and fixed
costs continues to be used. In these circumstances, the benefits of cost-
reflective rates (due to decreases in equity and efficiency) are larger than
before.
17. Q. WHY IS THERE A COST SHIFT?
A. The cost shift occurs because the current flat/volumetric rate includes several
fixed cost and demand-based elements. Customers who self-generate can
reduce the amount of energy that they receive from the utility and thereby
avoid paying for these fixed and demand elements.
IV. THE RATE DESIGN PROPOSAL
18. Q. WHAT ARE THE CURRENT RATE DESIGNS FOR NV ENERGY’S
NEM CUSTOMERS?
A. Residential NEM customers at Nevada Power and Sierra currently pay the
same rate as their otherwise applicable tariff schedule. This includes a
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monthly service charge (called the Basic Service Charge or “BSC”) and a
volumetric rate. Customers have a choice of a flat volumetric rate or a TOU
volumetric rate. Both are described for Nevada Power and Sierra in Table 1.
It is important to note that 99% of residential customers have chosen the flat
rate and 1% have chosen the TOU rate.
Table 1: Current Residential Rate Design
Any excess production from the customer’s self-generation facility is subject
to the NEM arrangement. Under this arrangement, the customer is credited
for the excess kWh production on the otherwise applicable tariff schedule.
This credit goes into a “bank” account which will be used to pay for kWh
consumption either in the current or future billing period.
19. Q. WHY IS IT NECESSARY TO CHANGE THE CURRENT RATE
STRUCTURE FOR NEM CUSTOMERS?
A. The current two-part NEM rate structure has two shortcomings – it shifts
revenue requirements (and therefore electricity costs) from NEM to non-
NEM customers, thereby raising the bills for non-NEM customers, and it
Summer OnSummer
MidSummer Off
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Sierra Flat rate 15.25 0.09842
Sierra TOU rate 15.25 0.41175 0.20562 0.06735 0.08465 0.06735
Nevada Flat rate 12.75 0.11642
Nevada TOU rate 12.75 0.36709 0.06314 0.04857 0.04857
Source: NVE Net metering proposal July 16, 2015 presentation
Notes: Chart excludes Generation Meter Charge that is waived for Solar Generations customers
Variable Charge ($/kWh)
Flat rateTOU rate
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does not account for any incremental costs that NEM customers may place
upon the system, which again means that bills for non-NEM customers are
raised.
20. Q. PLEASE DESCRIBE THE COST SHIFT CAUSED BY THE
CURRENT RATE STRUCTURE FOR NEM CUSTOMERS.
A. The standard two-part residential rate consists largely of a volumetric rate
which covers several cost elements, some of which are volumetric and some
of which are not. Energy costs are volumetric, while distribution,
transmission and the capacity component of generation costs are not. NEM
customers will upload power to the grid in some periods and offload power
in others, sometimes even within a single hour. Even though their net energy
consumed may be zero, they have still been using the grid extensively in
aggregate. Under the current NEM rate structure, any electricity exported
onto the grid will earn a credit at the full retail rate which includes the cost of
the grid as well as the cost of energy.
These credits reduce the contribution that NEM customers make toward the
costs of transmission and distribution assets, but do not proportionately
reduce the costs that they impose on the grid. For example, if the volumetric
rate is 10 cents, and the cost of energy (scaled to recover revenue) is four
cents, then the remaining six cents will be used to cover the costs of the grid
and customer services. On a particular day, if a NEM customer exports five
kWh of energy onto the grid, the NEM customer will receive a credit for
each kWh, totaling 50 cents. However, the NEM customer would not have
reduced the costs the utility incurs by 50 cents, but only by 20 cents (five
kWh times four cents). This creates a revenue shortfall of 30 cents which
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then must be recovered from the non-NEM customers, thereby creating a
cost shift from non-NEM customers to NEM customers.
21. Q. WHO PAYS FOR THIS COST SHIFT?
A. Currently, all non-NEM customers pay for the NEM cost shift.
22. Q. PLEASE DESCRIBE THE POTENTIAL INCREMENTAL COSTS
THAT NEM CUSTOMERS IMPOSE ON THE UTILITY?
A. Serving and signing up NEM customers requires additional support staff to
activate the new NEM accounts, answer customer inquiries and handle the
advanced billing required due to the NEM credits. Other costs such as
integrating renewables into the grid may also be applicable, but are not
included in the current rates calculations.
23. Q. WHAT NEW RATE DESIGNS FOR NEM CUSTOMERS ARE THE
COMPANIES PROPOSING?
A. Two new rate designs are being proposed. The first one is a three-part rate
where the demand and energy charges do not have a time-of-use component.
The second one is also a three-part rate, but its demand and energy charges
have a TOU component. These rates are shown in Table 2.
Table 2: Proposed Residential NEM rate Designs
Summer OnSummer
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Off
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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
Nevada Flat rate 18.15 14.33 0.0547
Nevada TOU rate 18.15 4.04 22.15 0.09147 0.05016 0.04727
Source: Rate Summary_SPPC and NPC.xlsx
Notes: Chart excludes Generation Meter Charge that is waived for Solar Generations customers
Fixed
Charged
($/kW)
Max
Demand
Charge
($/kW)
Coincident Demand
($/kW)Variable Charge ($/kWh)
Summer On
Peak
Winter On
Peak Flat rate
TOU rate
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24. Q. WILL THE NEM RATES BE MODIFIED OVER TIME?
A. All rates are subject to change as the underlying cost drivers and load
changes. The numerical parameters of the rates, such as the basic service
charge, the demand charge and the energy charge, should be updated
periodically in a general rate case to reflect changes in the marginal costs and
loads that determine the rates. Structurally, the rates should remain
unchanged unless it is shown that the three-part rate no longer adequately
reflects the underlying cost elements.
25. Q. HAVE YOU SEEN THE RESULTS OF THE MARGINAL COST OF
SERVICE STUDIES FOR NEM CUSTOMERS FILED BY THE
COMPANIES?
A. Yes, I have seen the results of the studies.
26. Q. ARE THE RATES DEVELOPED BY NV ENERGY CONSISTENT
WITH THE RESULTS OF THE COST OF SERVICE STUDIES?
A. Yes, the three-part rates developed directly reflect the different cost elements
from the cost of service studies, scaled so as to recover the revenue
requirement.
27. Q. HAVE YOU SEEN THE RESULTS OF THE JULY 2014 COST-
BENEFIT ANALYSIS (CALLED “NEVADA NET ENERGY
METERING IMPACTS EVALUATION”) PREPARED BY E3?
A. Yes, I have seen the results of that analysis.
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28. Q. WHAT IS THE PURPOSE OF A MARGINAL COST OF SERVICE
STUDY WHEN SUCH A COST-BENEFIT ANALYSIS IS
AVAILABLE?
A. Prices send signals to customers about what actions to take and to the utility
about what investments to make. If these price signals are cost reflective,
then optimal decisions will be made that raise economic efficiency and
enhance customer well-being, making society better off. Marginal cost of
service studies establish a measure of long-run marginal costs for various
aspects of utility costs. If these costs are then passed on to customers with
minimal distortions (distortions are needed for revenue recovery), then
customers will pay cost-reflective prices that enable them to make optimal
decisions. A cost-benefit study does not estimate marginal costs or prices of
any kind. Rather, it focuses on whether a specific investment, policy or
program is desirable or not. For these reasons, cost-benefit studies are not
suitable for determining rates.
29. Q. ARE THE NEWLY DESIGNED RATES CONSISTENT WITH THE
COMPANIES’ COST OF SERVICE STUDIES?
A. Yes, the rates are based on their cost of service studies.
30. Q. HAVE YOU REVIEWED SENATE BILL 374 FROM THE 2015
SESSION OF THE NEVADA LEGISLATURE (“SB 374”)?
A. Yes, I have.
31. Q. WHAT ARE THE RELEVANT ASPECTS OF SB 374 WITH
RESPECT TO NEM RATE DESIGN?
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A. SB 374 directs the Commission to develop new NEM rules and rates that
ensure that costs are not shifted from NEM customers to non-NEM
customers. Section 2.3.e of SB 274 states that the Commission shall not
authorize
“Any rates or charges for net metering that unreasonably shift costs from
customer-generators to other customers of the utility.”
Section 4.5 of SB 374 states that the proposed NEM rate may include:
“(a) A basic service charge that reflects marginal fixed costs incurred by the
utility to provide service to customer-generators;
(b) A demand charge that reflects the marginal demand costs incurred by the
utility to provide service to customer-generators; and
(c) An energy charge that reflects the marginal energy costs incurred by the
utility to provide service to customer-generators.”
32. Q. IS THE THREE-PART RATE DESIGN PROPOSED BY THE
COMPANIES CONSISTENT WITH THE REQUIREMENTS OF SB
374?
A. Yes, it is. The Companies have conducted marginal cost of service studies
for NEM customers by treating them as their own customer class, both in
terms of costs incurred to serve them and load shapes used to derive marginal
cost revenue. These cost of service studies were then used to derive class-
specific factors for several NEM-only customer classes. The proposed NEM
rates provide NEM customers a choice between a simple three-part rate and a
time varying three-part rate. It is my belief that the proposed rates are
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consistent with the principles of cost-causation and that they largely
eliminate subsidies from non-NEM to NEM customers as required by SB
374 section 2.3e. In accordance with section 4.5, the rates include a basic
service charge that reflects marginal fixed costs incurred by the Companies
to serve NEM customers; a demand charge that reflects the marginal demand
costs incurred by the Companies to serve NEM customers; and an energy
charge that reflects the marginal energy costs incurred by the Companies to
serve NEM customers.
33. Q. HAVE THREE-PART RATES BEEN PROVIDED TO RESIDENTIAL
NEM CUSTOMERS IN OTHER U.S. JURISDICTIONS?
A. Yes, at least three U.S. utilities are currently offering three-part rates to
residential NEM customers in three different states, as described in Exhibit
Faruqui-Direct-2.5 These three-part rates include a fixed charge, a demand
or capacity charge and a variable energy charge. All three rates are (or will
be) applicable to all customers who elect to install a new grid-connected
NEM system. These utilities are Salt River Project in Arizona, South
Carolina Public Service Authority in South Carolina and We Energies in
Wisconsin. Other utilities have proposed a three-part rate specific to NEM
customers, such as UNS Energy in Arizona, but these rates have not been
approved yet.6 Three-part rates have a long history for larger commercial and
industrial customers, including NEM customers.
Furthermore, Exhibit Faruqui Direct-3 gives an overview of the current
DG related reform landscape in the U.S. Several other U.S. jurisdictions and
5 WE Energies has published its new NEM specific rates but will these will only be applicable after January 1,
2016. 6 See Exhibit Faruqui Direct-3.
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utilities are proposing to change their rates. Some utilities only apply fixed
charge increases for all residential customers (including DG customers),
some design a three-part rate structure specific to NEM customers, while
other utilities design a buy-sell arrangement through which the utility pays
the customer-generator a volumetric rate for the electricity generated by the
customer-generator that is different than the rate the customer-generator pays
the utility for bundled electric service. Table 1 in Exhibit Faruqui Direct-3
attempts to give an overview of these proposed changes. All rate proposals
discussed are driven by a similar cost recovery issue and aim at
implementing a rate structure that better reflects cost causation.
34. Q. HAVE TIME-VARYING CHARGES OR CHARGES VARYING BY
SEASON BEEN INCLUDED IN RATES OFFERED BY OTHER
UTILITIES FOR NEM CUSTOMERS?
A. Yes, time-varying demand and energy charges are not uncommon for rates
offered to NEM customers. For instance, the Salt River Project offers a rate
to NEM customers with time-varying demand and time-varying energy
charges that also vary seasonally (Winter, Summer and Summer Peak).
South Carolina Public Service Authority, often known as Santee Cooper,
also offers energy charges that vary with both the season and the time of day.
Exhibit Faruqui Direct-3 also discusses several examples of proposed rates
with time-varying charges for NEM customers.
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35. Q. IS IT POSSIBLE TO COMPARE NV ENERGY’S PROPOSED
THREE-PART RATE TO THOSE OFFERED BY UTILITIES IN
OTHER STATES?
A. Yes, but any such comparison should recognize the fact that different utilities
have different costs to serve7 and thus different overall rate levels.
Figure Figure 2 shows the average volumetric rate in 2014 for all residential
customers (NEM and non-NEM) for utilities offering three-part rates. The
average rate is derived by dividing residential class revenue requirements by
class sales. Figure 2 shows a circumscribed set of these utilities, limited to
the 18 (out of 28) utilities for whom average volumetric rate data was readily
available.8+9
Although both Nevada Power’s and Sierra Pacific’s average
residential rates are generally in line with the U.S. average rate of 12.5
cents/kWh,10
they are at the higher end relative to the comparison group of
utilities that offer three-part rates and have data readily available. This
indicates that Nevada Power and Sierra Pacific are most likely in the higher
range of the spectrum in terms of costs of service compared to the rest of the
comparison group. This context should be recognized in the rate
comparisons.
7 Not only do the utilities have different costs to serve, but they also base their rates on different kinds of cost
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
Average Rates Report Winter 2015 were included. 9 If no separate DG class is defined, these rates will also apply to DG customers.
10 U.S. Energy Information Administration (EIA) 2015: “Electric Power Monthly”, Table 5.3.
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Figure 2: Comparison of Average Residential Rates for 2014 between Utilities
36. Q. HOW DO NV ENERGY’S PROPOSED THREE-PART RATES
COMPARE TO THREE-PART RATES OFFERED BY UTILITIES IN
OTHER STATES?
A. Figures 3 through 7 hereafter compare the fixed charge, the demand charge
and the energy charge offered by Nevada Power and Sierra to three-part rates
offered by other utilities. Both the flat and the three-part TOU rates are
shown in all instances. All figures differentiate rates offered only to NEM
customers (grey) from rates offered to all customers. All Nevada Power and
Sierra rates are shown in as diagonal stripes.
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Figure 3 shows NV Energy’s proposed fixed charges for their residential
three-part NEM rates compared to those from other utilities offering three-
part rates. These charges are at the higher end of the spectrum, but do not
stand out as outliers. They are significantly lower than some of the NEM-
only fixed charges being offered by other utilities.
Figure 3: Comparison of Fixed Charges between Utilities
In Figure 4 and Figure 5, we compare NV Energy’s set of proposed demand charges
to those from other utilities offering three-part rates. In general, none of the
components of NV Energy’s proposed rates are materially out of bounds with the
other utilities’ demand rates. Demand charges vary along a number of dimensions
including the length of the demand charge period and whether the demand charge is
coincident with the utility’s peak demand or based on the customer’s maximum
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demand regardless of time of occurrence. Some of these rates are explored in more
detail in Exhibit Faruqui Direct-2. The basic three-part rate structure proposed by
NV Energy has a non-coincident demand charge, while the TOU rate schedule has
both a non-coincident and coincident demand charge. For ease of comparison, we
have separated coincident and non-coincident (max demand) demand charges in
both Figure 4 and Figure 5. Figure 4 shows the summer demand charge. The
maximum demand charges for the flat three-part rates are on the higher end of the
spectrum, but are not outliers. The maximum demand charges for the TOU rates are
very low, but the rates also include a coincident demand charge. The coincident
demand charge for the TOU rates is again on the higher end of the spectrum, but in
line with other NEM-only coincident demand charges. Figure 5 shows the winter
demand charge. The maximum demand charges for the flat three-part rates are again
on the higher end of the spectrum, but are not outliers, while the winter coincident
peak charge for the TOU rate is by far the lowest (Nevada Power has a zero winter
coincident peak charge).
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Figure 4: Comparison of Summer Demand Charges between Utilities
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Figure 5: Comparison of Winter Demand Charges between Utilities
Figure 6 and Figure 7 show summer and winter energy charges respectively.
Nevada Power’s and Sierra’s energy charges appear to be in the middle of
the spectrum.
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Figure 6: Comparison of Summer Energy Charges between Utilities
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Figure 7: Comparison of Winter Energy Charges between Utilities
V. CONCLUSION
37. Q. WHAT ARE YOUR CONCLUSIONS ABOUT NV ENERGY’S RATE
PROPOSAL FOR NEM CUSTOMERS
A. I find that NV Energy’s proposed NEM rates meet the widely held principles
of rate design and are reasonable in magnitude compared to similar rates in
other jurisdictions. NV Energy’s rates are derived from marginal cost of
service studies and are consistent with the principles of economic efficiency
and equity (no unintentional subsidization). Compared to the existing NEM
rate, which is mostly a volumetric rate, the fixed charge and the demand
charge of the new NEM rate offer month-to-month bill stability for
customers and revenue stability for the utility. Since the rate is only
applicable to new NEM customers, there are no issues with bill shocks or
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need for transition to the new rate. NEM customers are offered a choice of
two rates and a simple and clear rate design meeting the principle of
customer satisfaction.
38. Q. DOES THIS COMPLETE YOUR TESTIMONY?
A. Yes, it does.
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Exhibit Faruqui-Direct-1
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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
Page 259 of 284
Exhibit Faruqui-Direct-1
Page 17 of 21
“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
Page 260 of 284
Exhibit Faruqui-Direct-1
Page 18 of 21
“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
Page 261 of 284
Exhibit Faruqui-Direct-1
Page 19 of 21
“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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Exhibit Faruqui-Direct-1
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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
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“The role of demand-side management in Pakistan’s electric planning,” Energy Policy, August
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Exhibit Faruqui-Direct-1
Page 21 of 21
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“Time-of-Use Rates and the Modification of Electric Utility Load Shapes,” with J. Robert
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Page 264 of 284
Sum
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Ele
ctric
Dep
artm
ent
Mun
icip
alVT
3,2
08
9/1/
2014
26.5
7
6.
77
6.77
Any
time
Unk
now
nN
AN
AN
oAl
l
[28]
UN
S En
ergy
Inve
stor
Ow
ned
AZ
81,
399
Prop
osed
20.0
0 6
.00
up to
7 k
W;
9.95
ove
r 7kW
6
.00
up to
7 k
W;
9.95
ove
r 7kW
An
y tim
e60
min
NA
NA
No
DG o
nly
[29]
We
Ener
gies
Inve
stor
Ow
ned
WI
98
4,86
0 1/
1/20
1617
.86
3.79
3.
79
Any
time
Unk
now
nN
oDG
onl
y[3
0]W
esta
r Ene
rgy
Inve
stor
Ow
ned
KS
323,
581
Prop
osed
15.0
010
.00
3.00
Any
time
15 m
inN
AN
AN
oAl
l[3
1]Xc
el E
nerg
y (P
SCo)
Inve
stor
Ow
ned
CO
1,1
82,0
93
7/1/
2012
12.2
5
8.
57
6.59
An
y tim
e15
min
NA
NA
No
All
Util
ityO
wne
rshi
p
Resid
entia
l Cu
stom
ers
Serv
ed
Dem
and
inte
rval
Com
bine
d w
ith E
nerg
y TO
U?
#St
ate
Util
ityEf
fect
ive
Date
of
Rate
Appl
icab
leRe
siden
tial
Cust
omer
Se
gmen
t
Fixe
d ch
arge
($
/mon
th)
Dem
and
Char
ge($
/kW
-mon
th)
Tim
ing
of
dem
and
mea
sure
men
t
Dem
and
Char
ge P
eak
Hour
s
Exhibit Faruqui Direct-2 Page 1 of 2
Page 265 of 284
Not
es:
[2]:
[4]:
[5]:
[6]:
[3]:
[8]-
[9]:
[15]
:
[18]
:[2
0]:
[21]
-[23
]:
[24]
:
[27]
:[2
8]:
[29]
:
[30]
:W
esta
r Ene
rgy'
s rat
e ha
s bee
n pr
opos
ed b
y th
e ut
ility
in a
n on
goin
g re
gula
tory
pro
ceed
ing
but h
as n
ot y
et b
een
appr
oved
.
Blac
ks H
ills a
lso
offe
rs a
n op
tiona
l tim
e of
use
rate
that
incl
udes
bot
h en
ergy
and
dem
and
char
ges f
or cu
stom
ers o
wni
ng d
eman
d co
ntro
llers
, the
se a
re sm
art h
ome
ener
gy co
ntro
llers
that
lim
it m
axim
um d
eman
d.
Rate
als
o in
clud
es a
thre
e m
onth
shou
lder
per
iod
durin
g w
hich
the
ener
gy ch
arge
is a
lway
s equ
al to
the
5.80
49 ce
nts p
er k
Wh
off-
peak
rate
(mon
ths o
f Oct
ober
, Apr
il, &
May
).M
anda
tory
if cu
stom
er co
nsum
es m
ore
than
5,0
00 k
Wh
per m
onth
for t
hree
cons
ecut
ive
mon
ths o
r has
a re
cord
ed p
eak
dem
and
of 2
0 KW
for t
hree
cons
ecut
ive
mon
ths.
Dem
and
char
ge is
the
sum
of t
he d
istr
ibut
ion
dem
and
char
ge a
nd th
e ge
nera
tion
dem
and
char
ge. E
nerg
y ch
arge
s are
the
sum
of t
he g
ener
atio
n kW
h ch
arge
, tra
nsm
issi
on k
Wh
char
ge, a
nd d
istr
ibut
ion
kWh
char
ge.
The
dist
ribut
ion
dem
and
char
ge is
1.6
12 d
olla
rs p
er k
W a
nd th
e ge
nera
tion
dem
and
char
ge is
4.0
70 d
olla
rs p
er k
W fo
r the
sum
mer
and
2.3
34 d
olla
rs p
er k
W fo
r the
win
ter.
The
tran
smis
sion
char
ge is
.970
cent
s per
kW
h an
d th
e di
strib
utio
n ch
arge
is .8
92 ce
nts p
er k
Wh.
The
ge
nera
tion
char
ge is
2.8
43 ce
nts p
er k
Wh
for p
eak
and
0.91
5 ce
nts p
er k
Wh
for o
ff-p
eak
hour
s.
Dem
and
perio
d is
not
exp
licitl
y id
entif
ied
and
it is
ass
umed
to b
e m
axim
um d
eman
d.Th
e de
man
d ch
arge
is b
ased
on
the
high
er o
f max
imum
dem
and
or 8
0% o
f the
ave
rage
max
imum
dem
and
for t
he la
st th
ree
sum
mer
mon
ths.
De
man
d is
mea
sure
d as
the
max
imum
win
ter d
eman
d fo
r the
mos
t rec
ent 1
2 m
onth
s. N
ew cu
stom
ers h
ave
an a
ssum
ed d
eman
d of
3 k
W fo
r the
ir fir
st y
ear.
Fixe
d ch
arge
for M
N i
s cus
tom
er ch
arge
per
mon
th p
lus f
acili
ties c
harg
e pe
r mon
th.
The
dem
and
char
ge is
tier
ed a
nd a
pplie
s to
dem
and
with
thre
shol
ds o
f the
firs
t 3 k
W, t
he n
ext 7
kW, a
nd a
ll re
mai
ning
kW
. Ene
rgy
and
dem
and
char
ges v
ary
acro
ss th
ree
seas
ons:
Win
ter,
Sum
mer
(May
, Jun
e, S
epte
mbe
r, an
d O
ctob
er),
and
On-
Peak
Sum
mer
(Jul
y an
d Au
gust
). Al
l ene
rgy
and
dem
and
char
ges s
how
n he
re a
pply
for t
he O
n-Pe
ak S
umm
er p
erio
d. T
he u
tility
is e
xper
imen
tally
off
erin
g th
e ra
te p
lan
to a
lim
ited
num
ber o
f non
-DG
cust
omer
s.
This
rate
pla
n is
pro
pose
d an
d pe
ndin
g ap
prov
al. T
he p
ropo
sed
rate
is m
anda
tory
for n
ew D
G cu
stom
ers a
nd o
ptio
nal f
or o
ther
resi
dent
ial c
usto
mer
s. F
or th
e en
ergy
char
ge, t
he o
ptio
n to
hav
e a
time
of u
se fe
atur
e is
als
o pr
opos
ed.
The
rate
is m
anda
tory
for D
G cu
stom
ers w
ith a
n ag
greg
ate
nam
epla
te ra
ting
of le
ss th
an 3
00 k
W. T
he m
onth
ly fi
xed
char
ge is
the
daily
gen
erat
ion
faci
litie
s cha
rge
plus
a D
G rid
er m
ultip
lied
by 3
0.5
days
. If e
xpor
ts to
the
grid
exc
eed
deliv
ered
en
ergy
in a
par
ticul
ar m
onth
then
the
diff
eren
ce is
cred
ited
at 4
.245
cent
s per
kW
h.
Dem
and
will
be
the
grea
ter o
f the
mea
sure
d de
man
d fo
r the
curr
ent m
onth
or 8
5% o
f the
hig
hest
reco
rded
dem
and
esta
blis
hed
durin
g th
e pr
eced
ing
elev
en m
onth
s.
The
mon
thly
fixe
d ch
arge
is a
dai
ly b
asic
serv
ice
char
ge m
ultip
lied
by 3
0.5
days
.
If m
ax d
eman
d oc
curs
dur
ing
the
Coin
cide
nt P
eak
perio
d th
en th
e m
ax d
eman
d ch
arge
(4.4
6 do
llars
per
kW
) and
coin
cide
nt d
eman
d ch
arge
(14.
66 d
olla
rs p
er k
W in
sum
mer
and
1.4
3 do
llars
per
kW
in w
inte
r) a
re a
dded
toge
ther
to m
ake
the
dem
and
char
ge: 1
9.12
dol
lars
per
kW
in su
mm
er a
nd 5
.89
dolla
rs p
er k
W in
win
ter.
Oth
erw
ise
the
dem
and
char
ge is
sim
ply
equa
l to
the
max
dem
and
char
ge. T
he ra
te a
lso
incl
udes
a su
mm
er m
id-p
eak
perio
d fo
r ene
rgy.
Sour
ces:
Util
ity's
tarif
fs a
nd “F
orm
EIA
-861
201
3 da
ta fi
les,
EIA
_861
_Ret
ail_
Sale
s_20
13.x
ls”(
for U
tility
, Sta
te, a
nd R
esid
entia
l Cus
tom
ers S
erve
d co
lum
ns)
Peak
per
iods
are
app
licab
le fr
om M
onda
y th
roug
h Fr
iday
exc
ludi
ng fo
llow
ing
holid
ays :
New
Yea
r's D
ay, M
emor
ial D
ay, I
ndep
ende
nce
Day,
Labo
r Day
, Tha
nksg
ivin
g Da
y, a
nd C
hris
tmas
. For
som
e ut
ilitie
s, th
e m
onth
ly fi
xed
char
ge h
as b
een
calc
ulat
ed b
y m
ultip
lyin
g a
daily
char
ge b
y 30
.5. R
ates
that
are
app
licab
le to
DG
cust
omer
s onl
y ar
e fo
r the
mos
t par
t man
dato
ry a
nd a
pplic
able
onl
y to
new
cust
omer
s aft
er th
e ra
tes c
ome
into
eff
ect.
If m
ax d
eman
d in
sum
mer
occ
urs d
urin
g th
e Co
inci
dent
Pea
k pe
riod
then
the
max
dem
and
char
ge (4
.04
dolla
rs p
er k
W) a
nd co
inci
dent
dem
and
char
ge (2
2.15
dol
lars
per
kW
) are
add
ed to
geth
er to
mak
e th
e de
man
d ch
arge
: 26.
19 d
olla
rs p
er k
W.
Oth
erw
ise
the
dem
and
char
ge is
sim
ply
equa
l to
the
max
dem
and
char
ge.
Exhibit Faruqui Direct-2 Page 2 of 2
Page 266 of 284
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
State Utility
Demand Charge
Seasonal or TOU Demand
Charges
Fixed Monthly Charge
Increase of Fixed Charge or Minimum
Bill
Capacity Charge
Streamlined Tiered Rate Structure
Seasonal or TOU Energy
Charges
Buy-Sell Arrangement
DG-Specific Rate
[1] Arizona Arizona Public Service[2] Arizona Salt River Project[3] Arizona UNS[4] California Investor Owned Utilities[5] California Sacramento Municipal Utility District[6] Colorado Statewide[7] Connecticut Connecticut Light and Power[8] Georgia Georgia Power Co.[9] Hawaii Hawaiian Electric Co.
[10] Idaho Avista[11] Idaho Idaho Power Co.[12] Illinois Statewide[13] Minnesota Xcel Energy[14] Missouri Ameren[15] Missouri Empire District Electric Co.[16] Missouri KCP&L[17] Oklahoma Statewide[18] South Carolina South Carolina Public Service Authority[19] Texas Austin Energy[20] Utah PacifiCorp (Rocky Mountain Power)[21] Washington Avista[22] Washington PacifiCorp (Pacific Power)[23] Wisconsin WE Energies
KeyApprovedProposed (decision pending)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.
[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.
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 House.[7]
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 does not depend on the size of the solar panel installation. [11]
Exhibit Faruqui Direct-3 Page 1 of 17
Page 267 of 284
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,<https://www.aps.com/en/ourcompany/news/latestnews/Pages/aps-asks-to-reset-grid-access-charge-for-future-solar-customers.aspx> 3 “AZ regulatory staff rejects solar net metering changes outside full rate case.”, Utility Dive, accessed on July 20, 2015,<http://www.utilitydive.com/news/az-regulatory-staff-rejects-solar-net-metering-changes-outside-full-rate-ca/400656/> 4 Based on FERC Form-1 Data from 2013 and 2014.
Exhibit Faruqui Direct-3 Page 2 of 17
Page 268 of 284
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, <http://www.srpnet.com/newsroom/releases/022615.aspx> 7 Ahmad Faruqui and Ryan Hledik, “An Evaluation of SRP’s Electric Rate Proposal for Residential Customers with Distributed Generation,” prepared for Salt River Project, January 2015. <http://www.srpnet.com/prices/priceprocess/pdfx/DGRateReview.pdf>8 SRP Standard Electric Price Plans, Prices Effective with the April 2015 Billing Cycle, released in February 26, 2015, pages 11, 28 and 29. <http://www.srpnet.com/prices/priceprocess/pdfx/April2015RatebookPUBLISHED.pdf>9 Ibid., page 30. 10 Ibid., pages 34 - 39.
Exhibit Faruqui Direct-3 Page 3 of 17
Page 269 of 284
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, <https://www.uesaz.com/news/updates/e-rates/ > 12 Unisource Energy News release on May 15, 2015, accessed on July 20, 2015, <https://www.uesaz.com/news/newsroom/release/index.php?idRec=342 > 13 “Rate Application.”, UNS, <https://www.uesaz.com/doc/UNSE_Rate_Application.pdf > 14 “UES seeks new electric rates to reflect higher costs.”, UniSource Energy Services Updates, Accessed on July 10, 2015, <https://www.uesaz.com/news/updates/e-rates/ > 15 “What's solar worth? Inside Arizona utilities' push to reform net metering rates,” Published June 1, 2015, Utility Dive, <http://www.utilitydive.com/news/whats-solar-worth-inside-arizona-utilities-push-to-reform-net-metering-r/399706/,> Accessed July 28, 2015.
Exhibit Faruqui Direct-3 Page 4 of 17
Page 270 of 284
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. <http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201320140AB327> 17 “Rooftop Solar 2.0 – Hawaii and California grapple over net energy metering.”, Published on July 2, 2015, in Fortnightly , accessed on July 2, 2015, <http://www.fortnightly.com/fortnightly/2015/06/rooftop-solar-20>18 Notice of Southern California Edison Company’s Supplemental Filing for Residential Electric Rate Changes (R/12-06-013, Phase 1), p.1, accessed on July 2, 2015.<https://www.sce.com/wps/wcm/connect/a0984d12-3f22-45da-8495-910c0641705b/Phase1ResRateNoticeV4_English.pdf?MOD=AJPERES>19 Decision on Residential Rate Reform, California Public Utilities Commission, p. 218, July 3, 2015, < http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M153/K024/153024891.PDF>20 “Calif. regulators approve major overhaul of residential electric rate design”, published on July, 3 2015 in SNL Financials. 21 California Public Utilities Code Section 2827.1(b)(7). < http://www.leginfo.ca.gov/cgi-bin/displaycode?section=puc&group=02001-03000&file=2821-2829>
Exhibit Faruqui Direct-3 Page 5 of 17
Page 271 of 284
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. <http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M153/K024/153024891.PDF>, accessed on July 20, 2015. 24 Ibid., page 1. 25 Rate Schedule 1-R for SMUD Residential Service, applicable from January 1, 2015, Accessed on July 26, 2015, < https://www.smud.org/en/business/customer-service/rates-requirements-interconnection/documents/1-R.pdf>26 Chief Executive Officer and General Manager’s Report and Recommendation on Rates and Services, Sacramento Municipal Utility District, April 2, 2015, Volume 1, page 14. <https://www.smud.org/en/about-smud/company-information/document-library/documents/2015-GM-Rate-Report-Vol-1.pdf> 27 General Manager’s Report and Recommendation on Rates and Services, Sacramento Municipal Utility District, Volume 1, May 2, 2013, page 19. <https://www.smud.org/en/about-smud/company-information/document-library/documents/2013-GM-Rate-Report-Vol-1.pdf> 28 Ibid. pages 13-17.
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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, <http://foxct.com/2014/12/01/pura-proposal-cuts-clp-customer-increase-by-6mo/>33 “CT 2015 legislative session—victories and unfinished business.”, accessed on July 21, 2015, <https://greencitiesbluewaters.wordpress.com/2015/06/06/ct-2015-legislative-session-victories-and-unfinished-business/>34 “Acadia Center analysis.” Acadia Center, accessed on July 21, 2015, <http://acadiacenter.org/document/ct-fixed-electric-charge-impact-analysis-may-2015/> 35 Brian Dowling, “Legislature Maroons Major Energy Bill; Other Measures Push Solar, Natural Gas,” Hartford Courant, accessed on July 23, 2015.
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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. <http://facts.psc.state.ga.us/Public/GetDocument.aspx?ID=150488,> Accessed July 28, 2015. 37 “Order Adopting Settlement Agreement,” Georgia Public Service Commission, Docket No. 36989, Decided December 17, 2013. 38 Georgia Power Residential Service Schedule: “R-20”, Page1, Accessed July 26, 2015, <http://www.georgiapower.com/pricing/files/rates-and-schedules/residential-rates/2.10_R-20.pdf>39 Georgia Power Time of Use – Residential Demand Schedule: “TOU-RD-2”, Page 1, Accessed July 27, 2015, <http://www.georgiapower.com/docs/rates-schedules/residential-rates/2.40_TOU-RD-2.pdf> 40 Order Approving Tariffs Subject to Refund in Re: Georgia Power Company’s Update of Base Tariffs, Georgia Public Service Commission, Docket No. 36989, December 18, 2014.
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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. <http://files.hawaii.gov/puc/3_Dkt%202011-0206%202014-08-26%20HECO%20PSIP%20Report.pdf>42 Hawaiian Electric Companies’ Distributed Generation Interconnection Plan, Hawaii Public Utilities Commission, Docket No. 2011-0206, issued August 26, 2014. 43 HECO Companies Propose Significant Charges for DG Customers, Green Energy Institute, September 24, 2014. <http://law.lclark.edu/live/news/27986-heco-companies-propose-significant-charges-for-dg> Accessed onDecember 14, 2014. 44 “Rooftop Solar 2.0 – Hawaii and California grapple over net energy metering.”, Published on July 2, 2015, in Fortnightly <http://www.fortnightly.com/fortnightly/2015/06/rooftop-solar-20>, Accessed on July 2, 2015. 45 Final Statement of Position of the Hawaiian Electric Companies, Hawaii Public Utilities Commission, page 76, June 29, 2015. 46 Ibid., page 2.
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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. <http://www.puc.idaho.gov/fileroom/cases/elec/IPC/IPCE1227/ordnotc/20130703FINAL_ORDER_NO_32846.PDF> 48 Ibid. page 13. 49 “Avista requests multi-year electric and natural gas rate increase in Idaho,” News Release. <http://www.puc.idaho.gov/fileroom/cases/elec/AVU/AVUE1505/20150601CUSTOMER%20NOTICE%20AND%20PRESS%20RELEASE.PDF>, Accessed July 22, 2015. 50 HB 3328/SB1879 Offers a Comprehensive Plan for Illinois’ Energy Future, Commonwealth Edison, News Release, March 19, 2015, <https://www.comed.com/newsroom/pages/newsroomreleases_03192015.pdf?FileTracked=true>, Accessed July 27, 2015.
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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, <http://www.ilga.gov/legislation/BillStatus.asp?DocNum=3328&GAID=13&DocTypeID=HB&SessionID=88&GA=99> accessed July 27, 2015. 52 Bill Status of SB1879, Illinois General Assembly, <http://www.ilga.gov/legislation/BillStatus.asp?DocNum=1879&GAID=13&DocTypeID=SB&SessionID=88&GA=99> accessed on July 27, 2015. 53 “Louisiana rules to preserve net metering,” Published July 11, 2013, IREC,<http://www.irecusa.org/2013/07/louisiana-rules-to-preserve-net-metering/>, Accessed July 27, 2015. 54
“Staff Report and Recommendation,” Issued April 2013, Louisiana Public Service Commission Docket R-31417, <archive.shreveporttimes.com/assets/pdf/D9203969416.PDF>55 “Do solar power costs outweigh benefits?”, nolo.com. Published April 3, 2015, <http://www.nola.com/business/index.ssf/2015/04/solar_dismukes_net_metering.html>, Accessed July 22, 2015 56 “Minnesota’s Value of Solar.”, Published April 2014, Institute for Local Self-Reliance,<http://ilsr.org/downloads/Minnesota%27s+Value+of+Solar>, Accessed July 20, 2014.
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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, <https://mn.gov/commerce/energy/businesses/energy-leg-initiatives/value-of-solar-tariff-methodology%20.jsp>58 “If ‘value of solar’ is optional, will Minnesota utilities adopt it?,” Midwest Energy News, Published April 9, 2014, < http://midwestenergynews.com/2014/04/09/if-value-of-solar-is-optional-will-minnesota-utilities-adopt-it/>,Accessed July 27, 2015
60 “Shining Rewards,” Environment America, Published June 2015, <http://www.environmentamerica.org/sites/environment/files/reports/EA_shiningrewards_print.pdf>, Accessed July 27, 2015. 61 “Minnesota will ‘get the ball rolling’ on community solar today,” Midwest Energy News, Published December 12, 2014, http://midwestenergynews.com/2014/12/12/minnesota-will-get-the-ball-rolling-on-community-solar-today>, Accessed July 27, 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,<http://www.midwestenergynews.com/2015/01/06/as-in-wisconsin-missouri-utilities-seek-to-raise-fixed-charges/> 63 “PSC Issues Decision In The Empire District Electric Company Rate Case,” Missouri Public Service Commission, June 25, 2015, <http://psc.mo.gov/Electric/PSC_Issues_Decision_In_The_Empire_District_Electric_Company_Rate_Case> 64
“Noranda gets rate cut, other Ameren consumers see increase,” Wistv.com, <http://www.wistv.com/story/28931560/noranda-gets-rate-cut-other-ameren-consumers-see-increase,> Accessed July 27, 2015. 65 Senate Bill 1456, Oklahoma State Senate, April 15, 2014, <http://www.oklegislature.gov/BillInfo.aspx?Bill=sb1456&Session=1400>
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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, <http://www.4-traders.com/OGE-ENERGY-CORP-13889/news/OGE-Energy--Utilities-eye-tariffs-for-solar-wind-users-20555043/>, Accessed July 20, 2015. 67 “Oklahoma Gas & Electric considers new charge for distributed generation”, Utility DIVE, November 3, 2014, <http://www.utilitydive.com/news/oklahoma-gas-electric-considers-new-charge-for-distributed-generation/328739/>, Accessed July 20, 2015. 68 “OGE Energy: Utilities eye tariffs for solar, wind users.”, 4-traders, Published June 17, 2015, <http://www.4-traders.com/OGE-ENERGY-CORP-13889/news/OGE-Energy--Utilities-eye-tariffs-for-solar-wind-users-20555043/>, Accessed July 20, 2015. 69 “Residential Net Billing Rate.”, South Carolina Public Service Authority, page 2, <https://www.santeecooper.com/pdfs/rates/2014/rb-14.pdf >, Accessed July 20, 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.” <http://www.mp2energy.com/solarhomes>,Accessed July 20, 2015. 74 PacifiCorp dba Rocky Mountain Power 2014 General Rate Case, Docket No. 13-035-184, p.20
<http://psc.utah.gov/utilities/electric/elecindx/2013/documents/26006513035184rao.pdf>.
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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, <http://www.psc.utah.gov/utilities/electric/elecindx/2013/documents/26006513035184rao.pdf> 76 “Net Metering and Valuing Rooftop Solar.” Utah Clean Energy. <http://utahcleanenergy.org/policy-central/item/94-net-metering>, Accessed July 22, 2015. 77 PacifiCorp dba Rocky Mountain Power 2014 General Rate Case, Public Service Commission of Utah, page ii, August 29, 2014, <http://www.psc.utah.gov/utilities/electric/elecindx/2013/documents/26006513035184rao.pdf> 78 Docket UE-140762 et al. Order 8 Final Order, March 25, 2015, Page 96. <http://www.utc.wa.gov/_layouts/CasesPublicWebsite/GetDocument.ashx?docID=1677&year=2014&docketNumber=140762.>79 “Testimony of Jeremy B. Twitchell,” October 10, 2014. Docket UE-131384 and Docket UE-140094.<http://www.utc.wa.gov/_layouts/CasesPublicWebsite/GetDocument.ashx?docID=503&year=2014&docketNumber=140762.>
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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, <https://www.avistautilities.com/services/energypricing/Pages/wafaq.aspx> 81 The monthly fixed charge is the daily generation facilities charge plus a DG rider multiplied by 30.5 days. This calculation is (0.05951*30.5)+(0.52602*30.5).82 Wisconsin Electric Power Company. Customer Generating Systems – Net Metered (CGS NM) Less than 300 KW. <https://www.we-energies.com/pdfs/etariffs/wisconsin/ewi_sheet2016-2018.pdf>, Accessed July 20, 2015.83 Wisconsin Electric Power Company, Electric Rates, Residential Service, Volume 19. <https://www.we-energies.com/pdfs/etariffs/wisconsin/ewi_sheet21.pdf>, Accessed July 20, 2015. 84 Wisconsin Electric Power Company, Electric Rates, Residential Service — Time-of-Use, Volume 19. <https://www.we-energies.com/pdfs/etariffs/wisconsin/ewi_sheet23-24.pdf>, Accessed July 20, 2015.
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