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Before the Minnesota Public Utilities Commission
State of Minnesota
In the Matter of the Application of Otter Tail Power Company
For Authority to Increase Rates for Electric Utility
Service in Minnesota
Docket No. E017/GR-15-1033
Exhibit___
FIXED CHARGES AND RATE DESIGN POLICY
Direct Testimony and Schedules of
AMPARO NIETO
February 16, 2016
TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS................................................................... 1
II. THE ROLE OF FIXED CHARGES IN RATE DESIGN ................................................... 3
III. ALTERNATIVE APPROACHES TO FIXED CHARGES ............................................... 7
IV. FUTURE OF FIXED CHARGES IN ELECTRIC RATE DESIGN ................................ 10
V. CONCLUSION ................................................................................................................. 13
ATTACHED SCHEDULES
Schedule 1 – Curriculum Vitae
Schedule 2 – National Survey of Fixed Charge Proposals
1 Docket No. E017/GR-15-1033
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I. INTRODUCTION AND QUALIFICATIONS 1
2
Q. PLEASE STATE YOUR NAME AND BUSINESS ADDRESS. 3
A. My name is Amparo Nieto. My business address is 777 South Figueroa Street, Suite 4
1950, Los Angeles, California 90017. 5
6
Q. BY WHOM ARE YOU EMPLOYED AND WHAT IS YOUR POSITION? 7
A. I am a Vice President at NERA Economic Consulting (NERA). 8
9
Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 10
A. I have an M.A. degree in Public Finance and Economics from the Madrid Institute for 11
Fiscal Studies in Spain, and a B.A. in Economics from the University of Carlos III of 12
Madrid, Spain. At NERA, I specialize in energy regulatory policy. Since 1996, I have 13
extensively advised utilities and regulatory commissions in the U.S. and overseas on a 14
wide range of regulatory and electricity ratemaking issues, including the use of marginal 15
cost data in retail rate and contract design, evaluation of demand response programs and 16
interruptible rates, reform of distributed generation (DG) rates, incentive regulation in 17
distribution service, and cost allocation techniques. I have also advised Independent 18
System Operators in the U.S., Spain and Australia on methods to improve transmission 19
planning, design of financial transmission rights, and reforms to wholesale capacity 20
markets mechanisms. 21
For more than a decade, I have taught seminars on electricity marginal costing 22
and rate design for rate managers and regulatory commission staff. I direct NERA’s 23
Marginal Cost Working Group, a utility group dedicated to improving methods for 24
estimating and using marginal cost information in a variety of utility applications. I have 25
testified and presented papers on energy regulatory issues in industry and academic 26
forums in the U.S. I have also been an instructor in the University of Florida/World Bank 27
International Training Program on Utility Regulation and Strategy. My Curriculum Vitae 28
is set forth in Exhibit __ (AN-1), Schedule 1. 29
30
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Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE ANY REGULATORY 1
AUTHORITIES? 2
A. Yes. I have testified before the New York Public Service Commission with regard to the 3
quantification of marginal costs for electricity and natural gas and the importance of 4
using marginal costs to set rate structures. I have also provided my expert opinion before 5
the Board of Directors of Salt River Project (SRP) regarding the cost basis and structure 6
of a new rate for net metering customers in SRP’s service territory. I testified before the 7
North Carolina Utilities Commission in the context of reviewing the pricing terms of a 8
long-term power purchase agreement with two qualifying facilities. 9
10
Q. FOR WHOM ARE YOU TESTIFYING? 11
A. I am testifying on behalf of Otter Tail Power Company (OTP) in support of OTP’s 12
proposed fixed charges. 13
14
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 15
A. The purpose of my testimony is to: 1) define fixed electricity charges and explain why 16
they are important component in utility rate design; 2) discuss alternative approaches to 17
setting fixed charges and explain why OTP’s use of marginal cost information to design 18
electricity rates is superior to those alternatives; and 3) explain why appropriately 19
designed fixed charges will be increasingly important as distributed renewable generation 20
continues to grow in OTP’s service territory. 21
22
Q. WERE THE SCHEDULES YOU SPONSOR PREPARED BY YOU OR UNDER 23
YOUR DIRECTION? 24
A. Yes, they were. 25
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II. THE ROLE OF FIXED CHARGES IN RATE DESIGN 1
2
Q. WHAT ARE FIXED CHARGES AND WHAT COSTS DO THEY RECOVER? 3
A. Fixed charges are per-customer charges that do not change month by month. They are 4
intended to recover costs of service that do not vary with electricity consumption after the 5
customer connects to the grid. Costs recovered through fixed charges include marginal 6
customer-related expenses, such as installing, operating and maintaining the meter and 7
service drop, conducting meter reading and billing activities, and providing marketing or 8
other informational services. 9
10
Q. ARE THERE OTHER COSTS THAT CAN BE RECOVERED THROUGH FIXED 11
CHARGES? 12
A. Yes. In addition to customer-related costs, fixed charges may be also used to recover the 13
cost of connecting to the local distribution system, involving the required transformers, 14
secondary lines or local primary lines that may need to be added or expanded to 15
accommodate the expected customer’s maximum demand over the life of the facilities. 16
The local marginal distribution cost per kW of design demand may be different 17
depending on the service area (rural vs. urban) and expected maximum demand of each 18
customer. The type of distribution connection policy in place will determine the local 19
facilities costs that are to be recovered in rates as opposed to up-front. If customers 20
within the class are relatively homogeneous, the local facilities costs may be recovered in 21
a per-customer monthly fixed charge, calculated on the basis of the class average kW of 22
design demand, as opposed to the individual customer’s design demand. This way of 23
collecting distribution facilities costs as a monthly fixed charge is illustrated in NERA’s 24
marginal cost report: “Otter Tail Power Company, Marginal Cost of Electric Service 25
Study”, December 2015, which is included as a schedule to the Direct Testimony of OTP 26
witness Mr. David G. Prazak. 27
28
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Q. WHY IS IMPORTANT TO HAVE CORRECTLY DESIGNED FIXED CHARGES IN 1
ELECTRICITY RATES? 2
A. Appropriately designed fixed charges help promote key ratemaking objectives, such as 3
efficiency in usage and investment decisions, inter and intra-class equity and assurance of 4
cost recovery. Mr. Prazak identifies all the critical ratemaking objectives in his Direct 5
Testimony. 6
7
Q. ARE THERE REVENUE NEUTRALITY CONSIDERATIONS THAT MAY AFFECT 8
THE LEVEL OF FIXED CHARGES? 9
A. Yes. The starting point of the level of a fixed charge is the sum of the marginal customer 10
related and marginal local facilities unit costs. However, adjustments may be needed to 11
ensure that total class revenues match the revenue target that is determined for the class 12
in the cost of service study. While energy charges and any demand charges should be 13
kept as close as possible to the underlying marginal unit cost to preserve efficiency in 14
customer usage decisions, customers are generally less prompt to modify usage when the 15
fixed charge changes. Thus, when there is a gap between marginal cost-based revenues, 16
i.e., the revenue that would be achieved when prices are equal to marginal costs, and the 17
class revenue target, the fixed charge may need to be adjusted to recover that gap and 18
ensure a revenue neutral rate design. This principle is particularly important as utilities 19
accommodate increased levels of DG in their service territories. 20
Finally, costs associated with social programs such as those required to fund 21
subsidies to low income customers may be best recovered in fixed charges if that is 22
required to ensure that the volumetric components of the rate are set to recover no more 23
than the underlying marginal costs. 24
25
Q. WHAT HAPPENS WHEN FIXED CHARGES ARE SET TOO LOW? 26
A. When fixed charges are set too low, costs that are unrelated to usage are more likely to be 27
shifted to volumetric charges. This has two effects: first, it creates intra-class subsidies. 28
Customers that use more than the class average usage pay more than their fair share of 29
the fixed cost of service, while customers with usage below the class average receive a 30
5 Docket No. E017/GR-15-1033
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subsidy. The size of intra-class cross subsidy can be reduced if the amount of fixed costs 1
recovered through variable charges is kept to reasonably minimal levels. 2
The second effect of low fixed charges is inefficient consumption and use of the 3
system. High volumetric prices, all else being equal, would incentivize customers to 4
reduce usage below optimal levels or self-generate. Such reductions result in an 5
inefficient use of the capacity that is available. If customers self-generate due to 6
excessive usage charges, that decision represents uneconomic bypass of the system 7
because the total cost of service for all customers (those with self-generation and those 8
without self-generation) will increase. Keeping volumetric prices at marginal costs is 9
justified by economic theory. 10
11
Q. IS AN UNREASONABLY LOW FIXED CHARGE JUSTIFIED TO ENSURE 12
AFFORDABILITY FOR RESIDENTIAL CUSTOMERS? 13
A. No. First of all, low usage is not always correlated with low income. Some low income 14
customers are in fact, high electricity users. Keeping fixed charges unreasonably below 15
cost helps residential customers with usage below the class average usage, but a good 16
share of these customers are not low income. A typical example is vacation homes or 17
users with natural gas for heating. This is done at the expense of residential customers 18
with above average usage, some of whom are low income. This is a very inefficient 19
means of helping low income customers, as the benefits flow to both low income and 20
higher income customers. 21
22
Q. ARE THERE OTHER OPTIONS TO ADDRESS AFFORDABILITY FOR LOW 23
INCOME CUSTOMERS? 24
A. Yes. Assisting low income customers is better achieved through direct assistance such as 25
the Low Income Energy Assistance Program (LIHEAP). 26
27
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Q. DOES A LOW FIXED CHARGE ALWAYS PROMOTE COST-EFFECTIVE ENERGY 1
CONSERVATION? 2
A. No. Very low fixed charges normally mean that an unreasonable amount of cost 3
recovery is shifted to energy charges, leading those energy charges to exceed the 4
underlying marginal usage-related costs. As a result, rates may provide an overstated 5
incentive to shift to another choice of fuel or to self-generate. This is inconsistent with 6
Minnesota policy as expressed in Minn. Stat.§ 216B.2401, which focuses on “cost-7
effective energy savings.” Having appropriate price signals allows customers to address 8
whether they can achieve cost-effective energy savings and the means to achieve those 9
savings. In any case, when rates are not time-differentiated, a seasonal average 10
volumetric rate has a very limited potential to promote conservation goals, even if rates 11
are set in excess of marginal costs. 12
13
Q. WHAT OTHER PROBLEMS MAY EXIST WITH TOO LOW FIXED CHARGES? 14
A. Low fixed charges, when not justified by marginal cost principles, are not only 15
inefficient, but also inequitable. As I discussed earlier, a high energy charge means that 16
low usage customers are subsidized by high usage customers. There are also more 17
incentives for customers to install on-site generation to meet a share or all of their energy 18
needs. Customers installing on-site generation are still using portions of the transmission 19
and distribution system, but the customer’s bill will decrease by more than the costs 20
avoided by the utility because the fixed charge is set inappropriately low. The customer 21
will avoid paying the costs that the utility incurs to standby when the customer generator 22
system goes out of service, or to supplement their energy needs. This represents an intra-23
class cross subsidy, since non-participating customers are left to make up the difference. 24
If the customer generation is billed under net metering, cross subsidies associated with 25
export energy will only worsen the equity problem. 26
27
Q. WHAT IS THE APPROPRIATE WAY TO PROMOTE CONSERVATION ? 28
A. The ideal way to promote conservation is to provide signals of the higher cost of service 29
in the hours in the day when electricity costs are the highest or when capacity is strained 30
7 Docket No. E017/GR-15-1033
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so that load reductions provide the highest value to the utility and the system overall. 1
Dynamic rates (such as Critical Peak Pricing, or Peak Time Rebate) can provide the 2
strongest conservation signals. Less dynamic but still useful for conservation purposes 3
are marginal-cost based time of use (TOU) rates, which may include either a super peak 4
kWh charge or an on-peak demand charge to reflect peak marginal energy and capacity 5
costs, including marginal generation capacity, transmission and high-voltage distribution 6
costs. When adopting these time-varying rates is not possible, due to lack of smart 7
meters or other reasons, direct-load control rates like OTP’s Water Heating – Controlled 8
Service Rider are a very effective way to achieve energy conservation goals and promote 9
more optimal patterns of usage. A well designed direct load control program keeps 10
marginal cost principles in mind so that customers’ benefits (in the form of bill 11
reductions) are aligned with avoided cost to the utility over time. 12
13
Q. ARE THERE ANY SITUATIONS WHERE FIXED CHARGES MAY NEED TO BE 14
SET BELOW ITS EFFICIENT LEVEL? 15
A. In some cases, increasing the fixed charge to meet the class revenue target may not be 16
feasible to accommodate the principal of gradualism. In that case, some costs that should 17
be recovered through fixed charges may be recovered in volumetric rates. This measure 18
should be implemented on a temporary basis to avoid the efficiency and equity 19
distortions I explained earlier. 20
21
III. ALTERNATIVE APPROACHES TO FIXED CHARGES 22
23
Q. HAVE YOU REVIEWED THE COST BASIS FOR OTP’S FIXED CHARGES? 24
A. Yes. OTP’s design of the various components of each rate relies on the OTP’s marginal 25
cost estimates that my team and I developed for the period 2016 through 2020. The 26
marginal cost analysis is tailored to the specific characteristics of OTP’s system costs and 27
customer characteristics, and took into account current and expected market 28
arrangements in MISO, based on the best available information. The study provided 29
8 Docket No. E017/GR-15-1033
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time-differentiated marginal cost estimates for OTP’s supply and delivery service. It 1
provides the basis to design fixed and volumetric charges close to marginal costs, thus it 2
was critical to inform OTP’s rate design. 3
4
Q. HOW DOES OTP SET ITS FIXED CHARGES? 5
A. As explained by Mr. Prazak in his Direct Testimony, OTP’s fixed charges are set to 6
recover as much of the marginal customer-related expenses and the marginal cost of local 7
distribution facilities as possible, while recognizing the principle of gradualism. 8
9
Q. DOES OTP’S APPROACH MAXIMIZE THE OPPORTUNITY TO ACHIEVE 10
EFFICIENCY, EQUITY, AND COST RECOVERY GOALS? 11
A. Yes. OTP’s method is the most suitable method for maximizing the opportunity to 12
achieve efficiency, equity, and cost recovery goals. 13
14
Q. ARE THERE OTHER APPROACHES THAT COULD BE USED TO DESIGN FIXED 15
CHARGES? 16
A. Yes, there are alternative approaches employed elsewhere, but they involve sacrificing 17
rate design objectives. For example some utilities set the monthly fixed charge equal to 18
embedded customer-related costs. If the embedded customer-related cost is low and 19
volumetric charges are set above marginal costs in order to meet class revenue targets, 20
there are distortions as discussed above. Setting the customer charge no higher than 21
marginal customer-related costs (i.e., the meter and service drop) is also not an 22
appropriate method unless a local facilities charge is also included in the rate. A rate 23
design where facilities costs are shifted out of the fixed charge and moved into 24
volumetric charges lead to cross-subsidies and efficiency-distortions in price signals. 25
Another option employed by a number of utilities is the minimum bill approach. 26
California is an example. The minimum bill approach ensures a minimum amount of 27
revenue is collected from all ratepayers within a rate class, while collecting the remaining 28
revenue through volumetric charges. Some utilities argue that a minimum bill provides 29
more protection to low income customers than does a fixed charge approach. The main 30
9 Docket No. E017/GR-15-1033
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problem with the minimum bill is that it typically applies to very few customers. Further, 1
the minimum bill approach perpetuates cross subsidies because volumetric charges are 2
kept artificially above cost, giving inappropriate price signals that could lead to economic 3
inefficiencies. 4
In the context of solar customers and net metering, a number of utilities have 5
proposed shifting to the straight fixed-variable (SFV) approach. Under the SFV 6
approach, all fixed costs are recovered through fixed charges, with fixed cost being 7
defined as any cost other than embedded generation cost. It can lead to very large bill 8
impacts for low-use customers. In addition, volumetric charges may be too low, 9
promoting excessive use of energy and harming conservation. 10
The best way to ensure an optimal fixed charge is to make sure that fixed charges 11
recover marginal customer-related costs, marginal local facilities costs – since these 12
facilities are not changing with temporary changes in demand – and any additional 13
amount needed to meet the revenue gap after setting all charges at marginal costs. 14
15
Q. IS REVENUE DECOUPLING A SUBSTITUTE TO AN APPROPRIATELY 16
DESIGNED FIXED CHARGE? 17
A. No. Decoupling may be an appropriate mechanism to remove a utility’s disincentive to 18
promote energy efficiency or conservation, but it perpetuates cross subsidies, as the 19
mechanism does nothing to make sure customers see the right price signals. All 20
customers will see rate surcharges to recover the lost revenue between rate cases, 21
meaning there are still intra-class subsidies and inefficient use of resources. 22
23
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IV. FUTURE OF FIXED CHARGES IN ELECTRIC RATE DESIGN 1
2
Q. DO YOU ANTICIPATE THAT SETTING FIXED CHARGES AT COST-BASED 3
LEVELS WILL BECOME MORE IMPORTANT OVER THE NEXT SEVERAL 4
YEARS? 5
A. Yes. Customers increasingly have choices in their energy sources, the most common 6
being on-site, rooftop solar. Rates that recover marginal costs in volumetric charges and 7
recover local facilities costs and customer costs in a fixed charge will help ensure that 8
consumer decisions to install rooftop solar are based on economically efficient incentives. 9
Minnesota has an opportunity to be a leader in promoting clean distributed resources in a 10
way that serves environmental goals without unduly burdening non-participant 11
customers. Getting the right rate structure in place as the market gets ready to embrace 12
DG will be critical in ensuring that outcome. 13
14
Q. DO CUSTOMERS THAT UTILIZE ON-SITE GENERATION LIKE ROOFTOP 15
SOLAR STILL USE THE UTILITY SYSTEM? 16
A. Yes. Even if a customer uses on-site generation, the utility will still need to have 17
sufficient capacity in its local distribution facilities to handle the customer’s demand 18
when the on-site generator is out of service. Customers also need the system to absorb 19
excess energy produced and unused locally. 20
21
Q. WHAT HAPPENS WHEN THE ON-SITE GENERATING CUSTOMER DOES NOT 22
PAY FOR THE COSTS OF PORTIONS OF THE SYSTEM THEY ACTUALLY USE? 23
A. Allowing customers with on-site generation to forgo contributing to the recovery of the 24
costs of the system they use (i.e. local distribution facilities costs) will put pressure on the 25
electricity bills of other customers on the system that do not have on-site generation. The 26
utility’s lost revenue will not be matched by cost savings, meaning rates will need to be 27
raised at the next general rate case to keep the utility financially whole. These cross 28
subsidies between participants and non-participants may become unsustainable with high 29
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levels of on-site generation, since system costs will have to be recovered over fewer 1
energy sales. 2
3
Q. WILL SETTING FIXED CHARGE LEVELS REQUIRE REGULATORS TO 4
BALANCE SEVERAL FACTORS? 5
A. Yes. Increasing fixed charges reduces the value of on-site generation. But doing so also 6
helps ensure that non-participants, many of whom may be low income users that cannot 7
afford on-site generation, do not subsidize the use of the system by participating 8
customers. 9
10
Q. HAVE SOME UTILITIES ADOPTED NEW KINDS OF FIXED CHARGES TO 11
ADDRESS THE IMPACT OF ON-SITE GENERATION? 12
A. Yes. A number of utilities have proposed a distribution grid access charge as a means of 13
avoiding the subsidization of on-site generation by non-participants. This typically 14
involves setting a charge to recover the excessive bill reduction enabled by net metering 15
for an average residential solar customer. The distribution grid access charge would 16
recover the difference between expected tariff revenue and the actual revenue net of 17
avoided costs. This revenue gap may be recovered from the customer through a charge 18
on the basis of the customer’s solar system nameplate capacity or production (in kWh). 19
20
Q. ARE THERE OTHER FACTORS THAT MAY PLACE UPWARD PRESSURE ON 21
FIXED CHARGES? 22
A. Yes. Higher fixed charges may be needed to take into account gaps between expected 23
marginal cost-based revenues and the class’ revenue target or embedded cost allocation. 24
25
Q. IS THERE A TREND NATIONWIDE TOWARDS HIGHER FIXED CHARGES? 26
A. Yes. A large number of utilities have proposed shifting cost recovery to fixed charges 27
over the last two years, generally applying to standard residential and small commercial 28
rates, and in large part motivated for expected growth of distributed solar generation. 29
Some regulators rejected these proposals, but others either approved them or are 30
12 Docket No. E017/GR-15-1033
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considering doing so. Exhibit __ (AN-1), Schedule 2 identifies 14 utilities in 12 states 1
that have recently received regulatory approval to implement fixed charge increases for 2
residential rates. Schedule 2 also identifies two utilities that implemented higher fixed 3
charges to net metering customers only and six utilities that are awaiting a decision on 4
their proposals. The largest fixed charge increases in standard residential rates were 5
requested in Indiana, Missouri, Kansas, Arizona, and Wisconsin, with increases of $9 per 6
month or more. In some cases, such as Kansas and Missouri, only a portion of the 7
requested increase was approved; decisions in other states are still pending. 8
The Salt River Project (SRP) in Arizona is an example of increases to fixed 9
charges to all residential customers with the goal to move price signals in volumetric 10
rates closer to marginal costs, but with a more noticeable increase in the monthly fixed 11
charges of net metering customers. Effective January 2015, all residential customers saw 12
an 18 percent increase in their monthly fixed charge, from $17 to $20. For SRP’s new 13
net metering customers, the monthly fixed charge increased from $20 to $32.44 (for 14
services at or below 200 amp) and $45.44 for larger residential customers. The new net 15
metering residential rate also included a peak demand charge and mandatory time-of use 16
kWh pricing. Effective January 2016, NV Energy implemented large fixed charge 17
increases for net metering customers only. The charge for new solar customers will 18
increase from $12.75 per month to $17.90 a month in 2016, then will keep increasing by 19
$5.15 each year until it reaches $38.51 a month in 2020. 20
Northern States Power Company in Wisconsin was authorized a fixed charge 21
increase of 75 percent, from $8 to $14. In the same state, Wisconsin Public Service 22
Corporation was authorized a fixed charge increase to $21 a month in November 2015, 23
following an increase in the prior year from to $10.40 to $19 a month. 24
25
Q. WILL RATE STRUCTURES NEED TO CHANGE TO ACCOMMODATE 26
ADDITIONAL SELF-GENERATION? 27
A. Yes. Residential and small commercial rates may need to move to a three- (customer, 28
energy, and demand) or four- (customer, energy, demand, and facilities) part structure to 29
better reflect cost causation, especially when customers in the class have dramatically 30
13 Docket No. E017/GR-15-1033
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different load shape characteristics, e.g., due to the presence of self-generation and the 1
resulting impact on load factor. These more granular rate components may be necessary 2
to preserve both efficiency and equity goals. Finally, net metering customers may need 3
to be moved to a standalone class if residential rates cannot be structured with sufficient 4
granularity, including enforcing appropriate time-differentiation that clearly targets the 5
peak hours of the day and peak months of the year. 6
7
V. CONCLUSION 8
9
Q. PLEASE SUMMARIZE YOUR CONCLUSIONS REGARDING FIXED CHARGES 10
AND RATE DESIGN POLICY. 11
A. In determining the proper level fixed charges, the goal should not be to pick winners and 12
losers, but rather to adopt rate design that gives appropriate and equitable price signals, 13
which ultimately will lead to cost-effective energy savings, including the use of on-site 14
generation. This requires setting rates that rely on marginal cost principles. 15
16
Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 17
A. Yes. 18
Recently Implemented and Pending Residential Fixed Charge Increases in the US
Monthly Residential Fixed Charge
State Utility Prior Proposed Approved
Arizona Salt River
Project
$17.00
(Residential-Basic)
$18.50 (Summer),
$20.00 (Non-
summer)
Approved
Salt River
Project
$17.00 (Net
Metered
Residential)
Service >=200 amp:
$30.94 (Summer).
$32.44 (Non-
Summer)
Service >200 amp:
$43.94 (Summer)
$45.44 (Non-
summer)
Approved
UniSource
Energy
Services
$10.00 $20.00 Pending
Arkansas Entergy
Arkansas
$6.95 $9.00 Approved
California Sacramento
Municipal
District
$16.00 $18 (2016)
$20 (2017)
Approved
City of
Roseville
$18 $22 (2016);
$26 (2017)
Approved
Idaho Avista Utilities $5.25 $8.50 Approved
Indiana Indianapolis
Power and
Light
$6.75 (monthly
usage <=325
kWh);
$11 (monthly
usage >325 kWh)
$11.25 (monthly
usage <=325 kWh);
$17 (monthly usage
>325 kWh)
Pending
NIPSCO $11.00 $20.00 Pending
Docket No. E017/GR-15-1033 Exhibit___(AN-1), Schedule 2
Monthly Residential Fixed Charge
State Utility Prior Proposed Approved
Kansas Kansas City
Power & Light
$10.71 $19.00 $14.00
Westar Energy $12.00 $27.00 $14.50
Missouri Kansas City
Power & Light
$9.00 $25.00 $11.88
Nevada NV Energy
(Southern
Nevada)
$12.75
(Residential - Net
Metered)
$18.15 $17.90 (2016)
$23.05 (2017)
$28.21 (2018)
$33.36 (2019)
$38.51 (2020)
NV Energy
(Northern
Nevada)
$15.25
(Residential-Net
Metered)
$24.50 $21.09 (2016)
$26.92 (2017)
$32.76 (2018)
$38.59 (2019)
$44.43 (2020)
New Mexico Public Service
Company of
New Mexico
$5.00 $13.14 Pending
New York New York State
Electric & Gas
$15.11 $18.89 Pending
Rochester Gas
& Electric
$21.38 $26.73 Pending
Pennsylvania PECO Energy $7.13 $12.00 $8.45
South
Carolina
Santee Cooper $14.00 $17.00 (in 2016);
$19.50 (in 2017);
$21.00 (in 2018)
$17.00 (in 2016)
$19.50 (in 2017)
Approved
Docket No. E017/GR-15-1033 Exhibit___(AN-1), Schedule 2
Monthly Residential Fixed Charge
State Utility Prior Proposed Approved
South
Dakota
NorthWestern
Energy
$5.00 $9.00 Approved
Texas Southwestern
Public Service
Company
$7.60 $9.50 Approved
Wisconsin Wisconsin
Public Service
Corporation
$19.00 $25.00 $21.00
Northern States
Power
Company
$8.00 $18.00 $14.00
Docket No. E017/GR-15-1033 Exhibit___(AN-1), Schedule 2
