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• PUBLIC NEARING TESTIMONY
Wednesday, January 7, 1981 7:00 PM
City Council Chambers, Municipal Building
Denton, Texas 7620,
ELECTRIC RATE STUDY
PURPA COMPLIANCE MANUAL
Denton Municipal Utilities
5802A City of Denton, Texas
THE DENTON MUNICIPAL UTILITIES OF THE CITY OF DENTON, TEXAS, HELD A
• PUBLIC HEARING WEDNESDAY, JANUARY 79 1981, AT 7:00 PM TO CONSIDER
CERTAIN ELECTRIC RATE MAKING AND REGULATORY STANDARDS AS SET OUT IN
SECTIONS 111, 113, and 114 OF THE PUBLIC UTILITY REGULATORY POLICIES
ACT OF 1978 (PURPA), THE HEARING TO ACCEPT COMMENTS FROM ISTERESTED
PARTIES WAS HELD IN THE CITY COUNCIL CHAMBERS OF THE MUNICIPAL
BUILDING AT ZIS CAST MCKINNEY, CITY OF DEN'I'ON, TEXAS, 76201.
TESTIMONY WAS RECEIVED FROM MANAGEMENT AND RESEARCH CONSULTANTS,
INC., REPRESENTATIVES:
FRED MORIARTY, CPA JOAN C. PICKETT, PH.D.
THE HEARING WAS CONDUCTED BY THE DEN'TON PUBLIC UTILITIES BOARD
MEMBERS:
I
• ED COOMES MARVIN LOVELF,SS
SENNETT KIRK MERV WAAGE
WITH CHAIRMAN, ROLAND LANEY, PRESIDING.
CITY OF DENTON
OFFICIALS IN ATTENDANCE:
CHRIS HARTUNG CITY MANAGER, DENTON, TEXAS
R.E. NELSON DIRECTOR OF UTILITIES, DENTON, TEXAS
BILL MCNARY DIRECTOR OF FINANCE, DENTON, TEXAS
C.J. TAYLOR CITY ATTORNEY, DENTON, T1iXA:i
and the DENTON UTILITY ADMINISTRATION STAFF.
PUBLIC NOTICE
• The Denton Municipal Utility Department lives MO -
N($ that it shall consider certain electric ralemaflini
and nlulalorr standards as set out in Sections III,
113 and 114 of the Public Utility Regulatory Policies
Act of 1978 IPURPAJ. This hearlal shall accept com-
ments submitted by Interested parties on the issue
set out in these sections.
v The he, ring to accept comments from Interested
peru$$ will be held In the Gty Council chambers of
=the City of Denton, Taxis In the municipal building
located at 215 E. McRinney on the 7th of January,
.1980 at 7:00 P.M. Copies of the consultant's report
which contains recommendations that address the Sec.
Uoa 111, 113 and 114 standards of PURPA will be
":available In the City Nall and may be obtained from
the Efectrk Utility 0epartmenl.
IndMduals wishing to present testimony during the
"public hearing are requested to provide one wnttea
copy of their comments at the tlme of the public
recltIdlto Ms, Ann aln{nman the the aElectric UGI h De•
%partment at (8111566.8230.
PUBLIC NOTICE PLACED IN THE DENTON RECORD CHRONICLE ON SUNDAY,
DECEMBER 14, 1980, SUNDAY, DECEMBER 27, 1980, AND SUNDAY; -n,lUARY 4,
1981. SEVERAL ARTICLES PREVIOUSLY APPEARED IN THE DENTON RECORD
CHRONICLE REGARDING THE ELECTRIC RATE STUDY AND PURPA COMPLIANCE
MANUAL. SEE EXHIBITS FOLLOWING.
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meek g~ sort foLlortry w o «Alsa em We agenda u Con itkn m
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Of twvilolha cent per kwh t
for electric
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Sbe rate uhedWa bWr by kttlum4 aN dlmllned bMt bdlt citni • j i i 4 t!
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PUBLIC HEARING TESTIMONY
• ELECTRIC RATE STUDY AND PURPA COMPLIANCE MANUAL
We nesday, January 7, 1981 7• pt"~--
Ci~ of Denton, Texas
Chairman Laney:
I can never remember your full name, I keep calling you MARC,
but Mr. Fred Moriarty will give the first testimony. I will
read the question, he will give us an answer. The:; we'll hear
testimony next from Mr. Pickett in the same manner and,
following that, we can ask for some questions from the
audience to direct to these two people and following that
exercise, we can then receive testimony from any others in
the audience who would like to participate.
Chairman:
Mr. Moriarty, please state your name, occupation and business
address.
Mr. Moriarty:
Mr. Chairman, my name is Fred Moriarty, I am President of
Management and Research Con3ultants, Inc., 225 S, Meramec, in
Clayton, Missouri, and before we testify, what I'd like to do
• if r could is present an official copy of both our written
testimony and the two reports we prepared for the City as an
official document or the copy for the records if I may.
Chairman:
Thank you. How long have you been employed by MARC?
Mr. Moriarty:
I am a principal in MARC and participated in its organization
in January, 1980.
Chairman:
What is your educational background?
Mr. Moriarty:
r obtained a masters degree in business administration from
the University
requi em nts as a Certified Chicago
Public Accountant inoIllinois in
1974.
1
Chairman:
What is your professional background?
Mr. Moriarty:
I developed accounting and financial management systems for
clients of the Burroughs Corporation in 1957 and 1968. I
then spent four years in Corporate Finance with Motorola,
Inc. until 1972. That was followed by two years in financial
management with the State of Illinois, 1972 through '74 and
five years '74 througl, 179 as a financial consultant with
Touche Ross and Co. as a financial consultant.
Chairman:
What is your experience in rate regulations?
Mr. Moriarty:
In the last year I have testified before the Alaska Public
Utilities Commission on the PURPA regulatory standards, I
have assisted with Federal Energy Regulatory Commission Staff
Counsel with the preparation of trial briefs regarding rates
for the Trans Alaska Pipeline System, performed several cost
studies for municipalities regarding local cable television
operations and given utility cost of service presentations to
State and local government agencies. Prior to joining MARC,
• I was the manager of the St. Louie office of Touche Ross and
Company. I spent most of my five years with Touche Ross as a
member of its National Public Utility Resource Group. I
testified and/or directed tho development of electric, gas,
telephone, oil pipeline and cable television revenue and governmenttsagencies. ates'vforalFsoede d attachedtaae pro essional
resume as Exhibit A. al
Chairman:
What is the purpose of your testimony in this proceeding?
Mr. Moriarty:
r am sponsoring the revenue requirements and cost of service
analysis presented in MARC's December 12, 1980 report to the
City of Denton on the Electric Utility Rate Study.
Chairman:
Would you summarize your findings regarding the electric
utility's revenue requirements?
2
Mr. Moriarty:
• Yes. Total revenue requirements will almost double by fiscal
19F5 due to customer growth, construction of new power plants
with TMPA and increases in the cost of fuel, labor, and other
operating expenses. The average cost
not expected to change materially, howevper ilowar is
er,kuntiltt1983u when
the new TMPA generation plants begin to produce substantial
amounts of energy. Customer growth is expected to provide
adequate revenues to offset cost increases until
approximately 1983. Total operating expenses are expected to
increase in 1983 and 1984 with the increased purchases from
TMPA and to begin leveling by 1985 when the Commanche Peak
and Gibbons Creek generating units are fully operational.
Chairman:
Would you summarize your findings regarding the electric
utility's class cost of service study?
Mr. Moriarty:
The total system revenue requirements were allocated to four
separate components during the cost of service study;
customer, distribution, energy and capacity. Two major
factors considered during the study accounted for cost
differences between service classes. The first factor, type
of service, reflected three basic service types: single
phase, three phase, and primary service. This factor
directly affected the allocation of customer costs and
indirectly affected the distribution, energy, and capacity
costs. Secondary customers were allocated a larger portion
of distribution costs and a higher line loss percentage for
energy and capacity costs. The second major factor in the
cost study, seasonal energy consumption, resulted Li a larger
proportion of peak capacity costs allocated to those
customers with the highest summer usage. As a result of the
above customer characteristics, the following cost
differences were noted in the basic seasonal cost study.
First of all, Monthly Customer Costs for Single Phase= $4.50,
for three phase service= $8.00, and for primary service=
$46.00.
The energy costs expressed in cost per kilowatt hour for
secondary service is 3.850 primary service was 3.801. The
distribution cost is expressed in kilowatt hours for
residential, which are not demand metered and is 5 mills.
For commercial customers which are demand metered, we've
expressed it in kilowatt hou-- cost per kilowatt for
secondary service $2.10, for primary service $1.80.
3
The capacity costs expressed in kilowatt hours in cost per
kilowatt hour is 3 mills.
• Chairman:
Does this complete your testimony?
Mr. Moriarty:
Yes, except I have two changes I would like to read into the
record. In Exhibit C of the Electric Rate Study. Both
changes are on page C-4 which is the very last page of the
Study, and in the first full paragraph on that page there is
an effective date for the elimination of master metering of
February 28, 1980, and I suggest that that be changed to
March 31, 1981. On the very next line the word "energy"
appears, "energy consumption" and that ef:ould read "electric
consumption",
There is one other clarification I would like to make on page
C-3, in paragraph (f) you'll see the word in all capital
letters, "AND ELECTRIC METER "F AND ONE ELECTRIC METER", Both
of those terms should be in brackets and the purpose for
being in brackets was we're recommending that those words be
dropped from the present billing procedures. That is why
they're in all capital letters and that concludes my direct
testimony.
• Chairman:
Thank you Mr. Moriarty, Next we will hear 1-4r. John C.
Pickett.
Chairman:
Please state your name, occupation and business address.
Dr. Pickett:
Mr, Chairman and members of the Board, my name is John C.
Pickett and I am a Director of Systems and Research for
Management and Research Consultants, Inc., 225 S. Meramec,
Clayton, Missouri.
Chairman:
itow long have you been employed by MARC?
Dr, Pickett:
I am a principal in ~MARC and have participated in its
organization in 01anuary IQ80.
• 4
Chairman:
What is your educational background?
Dr. Pickett:
I obtained a PH.D. in economics from the University of
Missouri, Columbia In 1970.
Chairman:
What is your professional career?
Dr. Pickett:
Assistant Professor, Department of Business Economics and
Quantitative Methods at the University of Hawaii in Honolulu
in 1968 and '71; Research Fellow in the early research unit
of Australian National University in Canberra iii 1971 and
173; Associate Professor, Department of Economics and
Business at Hendrix College in Conway, Arkansas, 173 to 175.
Chairman:
What is your experience in regulated utilities?
Dr. Pickett:
• I was appointed to the Arkansas Public, Service Commission in
May of 1975. In June of 1977 I was appointed Chairman and
remained Chairman until January of 1979. I remained a member
of the Commission until February of 1980, when I joined !'ARC.
Chairman:
Have you authored any professional publications?
Dr. Pickett:
Yes. I have presented numerous papers at many professional
meetings and seminars.
Chairman:
What is the nature of your testimony In this proceeding?
Dr. Pickett:
I am sponsoring the Public Utility Regulatory Policies Act
issues concerning the regulatory and ratemaking standards and
the rate design issues In MARC's December 12, 1980 report to
the City of Denton on the Electric Utility Rate Study.
• 5
Chairman:
• Would you summarize your recommendations regarding PURPA
standards? the
Dr. Pickett:
Yes, I recommend that the City adopt all of the regulatory
and ratemaking standards now with the exception of the
standard related to the Automatic Adjustment Clause. We
recommend that the City defer a decision on the Automatic
Adjustment Clause standard until the transition to TMPA is
substantially completed. At that time by 1983 or 1984,
another restructuring of rates should be considered with a
complete re-evaluation of the proposed Energy Cost Adjustment,
Rational producers and consumers will respond to the price
charged for electricity. The PURPA objectives of
conservation, efficiency and economic equity will be achieved
only if the price of electricity reflects the true resource
cost incurred to produce the electricity. The consumer must
also receive the proper information and price signals and be
able to control at least a portion of his load if he is going
to respond to the appropriate price signals and realize the
available benefits. We, therefore, used the following rule
as a guideline in formulating our recommendation regarding
the PURPA regulatory and ratemaking standards:
The rule is "Does the standard result in the
price
electricity being set equal to its true resource cost or
provide the consumer an opportunity to respond to the
appropriate price signals?"
Chairman:
Would you summarize your recommendations regarding the
proposed rate design?
Dr, Pickett:
I have recommended, with a few exceptions, electric rates
that reflect the estimated cost of providing electricity to
different service types and voltage levels. The
rates are presented as two or three components depending pupon
whether demand meters are installed for particular
customers. The three components are a customer's facilities
charge, an energy charge and a demand charge. All the
customer facilities charges in the proposed rates reflect the
average customer costs identified in the cost of service
study except for the Residential A-1 customers that have
monthly consumption less than 700 Kwh during the summer
• 6
i
months. We have proposed a $2.00 reduction in the monthly
customer charge for these customers to continue the
conservation incentives during the summer months.
. The proposed kilowatt hour energy charge for all customers is
based on the average kilowatt energy and capacity costs for
secondary and primary service. The basic energy costs for
secondary customers is 3.850 per kilowatt hour which is
proposed for all consumption during the year. The
corresponding energy costs for primary customers is 3.810 per
kilowatt hour.
We have proposed a higher 3 mill kilowatt hour charge in the
summer for all customers except street lighting and dawn--and
dusk-to-dawn lights to recognize the higher capacity costs
incurred to meet summer peak loads. We have also proposed a
two mill reduction for winter kilowatt hours for residential
electric heating customers. This lower rate meets the
objective of a City Sneering Committee to continue some
winter discount for residential customers who provide the
system with beneficial off-peak heating energy demand.
The proposed kilowatt demand charge for commercial customers
is designed to recover the distribution related costs
incurred by the system. These costs are generally incurred
as a function of a customer's peak demand regardless of when
that peak is achieved. The charges to recover those costs
are, therefore, based on the monthly billing demand of
customers that are demand metered.
® Since residential customers are not demand metered, we are
propose--we have proposed collecting the distribution costs
as an addition to the kilowatt hour charge rather than on a
kilowatt billing demand basis as proposed for the commercial
customers. Thus the kilowatt hour charge for residential
customers is 5 mills higher than commercial customers
receiving secondary service.
The City Steering Committee has indicated a desire to
continue offering reduced rates to local government agencies
to recognize the cost savings the City electric utility
realizes by not paying local taxes. We have proposed
elimination of any demand charges and continuation of an
energy charge comparable to commercial customers to ensure
that these agencies receive the same conservation incentives.
Our Electric Utility Rate Study also includes proposed rates
for the following servicesi
Dusk to Dawn Lighting
Time-of-Use Rates for Secondary Service
Time-of Uve Rates for Primary Service
and Interruptible Service Rate
• 7
I have attached to this testimony three modified tariffs and
• one additional tariff for street lighting that was not
included in our December 12, 1980, filing. The modified
tariffs include the following:
The Commercial and Industrial Lighting and Power Service is
modified to include a different Customer Facility Charge of
$4.50 for Secondary Service, Single Phase.
The Time-of-Use Rates for Secondary as shown on Schedule S-1
and Primary, Schedule P-1 Service are modified to change the
definition of Billing Demand from the current "mont.h's peak
billing period from 12 Noon through 9 PM" to read "monthly
billing period". Mr. Chairman I would like to call your
attention to an additional distribution that has been made to
members of the committee. We have added a page to the
tarriff's A-17 to apply service 'for street lighting and
traffic signals where the owner of such facilities ingtalls
his own devices. To make this tarriff compatible with our
previously filed tarriff on page A-16 I would like to make
the following changes in Item #2-AvailaW lity:
Chairman:
Which page was that? Is that in the PURPA report?
Dr. Pickett:
. Page A-16 attached to my direct testimony. On Item #2 "Availability should read as follows: page A-16,
"Available to the City for street lights." All other
remaining information reading, "and signal systems and sales
to the
5
Inters ate highway" should gibe rdeleted. That ghcompletes the
changes Mr. Chairman.
Chairman:
Thank you Mr. Pickett. We will now entertain questions from
the audience directed to either Mr. Moriarty or Mr. Pickett.
If you have a question, if you would please come forward and
use the microphone here so that it can be recorded since this
is an official public hearing we have to be very careful
about what is taking place. Are there any questions?
Chairman:
State your name.
• 8
George Krieger:
• I'm George Krieger.
questions i I would like to ask Mr. Pickett several
a n regards to his testimony tons
general question. Could you Please ght. First
Autom
th is
atic Adjustment Clause is that explain whatlsthe
of your testimony? Y
Dr. Pick ou referenced in
Page 2
Pickett:
Yes, Mr. Krieger, the
component of the tariff Automatic Adjustment
increase in fuel that is desi
gne Clause is a
between the time that ethesra est arevset ccurr ae9to recover an or r
known 30 fuel cost that we have historical record smErom cthe
electric department. Those costs mar which are based on a
and the utility has no control over Increase in the future
will flow through directly
approximately to the As such, they
one month's lag, customer with an
Mr. Krieger:
You said in your testimony that the steering committee has
local government a continue offering reduced rates to
City electric utilitncies to recognize the cost savings the
This is not y realizes by not paying local taxes.
• comment, It's rsort eally 80 much of a question to
obtains from the utilita catch 22 here, The CitYs a Of personal
and the reason written behindrthateisubecause we Dentan,
non-taxable real estate to 6% Y City Charter
through the uttlit in our juridiction have so much
that the y► get some funding for then cite want to,
y obtain, And then we turn around and we offer services
a lower rate for the
were trying to utility which sort of
ge were do in the first counteracts what
get our thinking straight, exactly whate. I think we have to
and how we want to handle that. And this
to the rate that we're goi really want ga do
rds
local ng to offer if thisaisoacce regards for
general aEundnient agencies, and the utilit P row l instead you ttr in it out and etranser xpess to the
public exactly what are
Y g to do. the
Mr. Waage:
Well, loll respond to that in
that when you think of just a second. I think commonl
first are the costs of a reduced rate what comes to
the thin mind
governmental rate is included and g' but I believe the
Of Denton and probably more Importantois like for the school district
ns
which the Denton Independen,- School DiAtrict is a large user
• 9
of utilities and now I'm not gonna' speak, I--I understand
what you're sat'in' about (pause) with the college. With the
• school district the fact that Denton owns their own utilities
is not on their tax rolls, it is a burden the school district
and they'd lose tax dollars so I would say as it applies to
the school district anyway. I concur with the reduced rate
because of having had a little experience on the school
board, the increase that consumers have experienced with
utility rates it is really a burden when you're operating
from a school budget.
Mr.Kreiger:
I am in agreement that it is a burden on the school district
and It's a burden on everyone. There are two or three sides
to that thing. School taxes are deductible from income, fuel
bills aren't. We also have within the City a lot more than
the Denton Independent School District that would benefit by
a reduced rate and I dare say that was probably one of the
smaller users of electricity inside of the total rate
classification.
Dr. Pickett:
Mr. Krieger may I make one response to your observation?
Mr. Krieger:
• Certainly.
Dr. Pickett:
Remember that if Texas Power and Light were doing business in
your city, they would be providing taxes to the community
from two different sources. One you would probably levy a
franchise tax on their operations based probably on their
gross revenues. And secondly you would levy a property tax
on their taxable investment Inside your incorporated area.
Now I think that the 6% transfer to general funds corresponds
to the franchise tax which TP&L would pay if they were doing
business here as opposed to the City owned department. This
discount for the school districts basically is designed to
replace the local property tax that would be paid if It was
TP&L so that there are two kinds of taxes that would flow
into and benefit the community, a franchise tax and a
property tax. The 66 transfer of funds focuses on the
substitute for the franchise, this is providing and
recognizing that the City does not pay local property tax.
There are two different things and we have &ddressed both of
them.
. 10
Mr.Krieger:
• Ir you divide between that classification of
many wind up falling into the school category sande1how pmany
wind up falling into the government category on an energy
basis?
Dr. Pickett:
We have that information. Yes, we have that information
just--a total of 46 customers at the present time that fall
into the category of public authorities. A total of
customers at this time that fall into the 4
Public agency category, public authority,
,
Mr Krieger:
Now if you divide those into schools and non-schools, what is
the relation?
Mr. Moriarty:
At the present time there are 14 schools in that group, 21
which are cateLjor--- classified as ci1y accounts and 11 which
are county,
Mr. Krieger:
. Those 14 schools, approximately what prc
demand would It equate out of the total 46customers? the total
Mr, Moriarty:
Demand or energy?
Mr. Krieger:
Energy.
Mr. Moriarty:
Energy----approximately 678.
Mr. Krieger:
Would it be viable to break that category into two
categories, one for schools and one for non-schools? Would
that be allowable within the framework of PURPA?
• 11
Mr. Moriarty:
• I would see no objections in PURPA that would-
prohibit that. that would
Mr. Krieger:
In your testimony that you gave here tonight you really did
not come down and say exactly what the cost would be in
layman's terms to the various average customers in different
classifications. Could you please present that to us if
possible, viewgraph or something, so everyone could see it?
Me. Moriarty:
(Reference Attachment A Mr.
transparencies here of some bill Chairman comparisons that were
prepared by the City Staff for this purpose and I think
basically what you can see from this exhibit is that even
though the overall rates for the City on the average will
remain approximately where the are at the present
there will be some shifts within customer clas estiand
generally what you're seeing is a decrease--slight decrease
for the smaller consumption customers and as the consumption
gets larger, you'll see larger increases. This is primarily
attributed to the elimination of the declining block within
the rates. I think, other than that, I think the exhibit
• pretty much speaks for itself.
Mr. Krieger:
May I ask a question in regards to that chart there? Since I
personally fall into A-2, I would like to ask some questions
about A-2. Is there a base charge for service in A-2? If I
use zero kilowatt hours, do I have a charge?
Mr. Moriarty:
In the A-2 tariff as shown on
Rate Study, the base charge in thee A 2 3cust meri sin lean the
is $4.50 per month, that includes no consumption whatsoehere
That's just the base charge, that's the cost of hooking a
customer up, the Depreciation of the equipment, the reading
of the meter and related expenses.
Mr. Krieger:
Now for the energy concern.
e 12
Mr. Moriarty:
• For each kilowatt hour of energy of electricity
customer in this class you pay 4.350, I'm sorry consumed by a
hour, billing months of October through A per kilowatt
reclassified as winter months and 4.650 May which is
billing months of June through Septemberewhichoistconsidered
the summer.
In addition to that, if a customer has a home electrically
heated they get an additional 2 mill discount during the
winter billing months. Added to that would be any increases
in fuel and purchase power related costs beyond those
considered in developing these basic rates.
Mr. Krieger:
What was the base charge that you assumed for our fuel?
Mr. Moriarty:
Three cents.
Mr. Krieger:
And presently our fuel adjustment charge is?
• Mr. Moriarty:
Approximately two cents.
Mr. Krieger:
Now I read it differently?
Mr. Moriarty:
The base rate is one cent.
Mr. Krieger:
You're putting a two cent fuel adjustment now for a total of
three.
Mr. Moriarty:
What we've done is we've rolled that additional two cents
into the base rate.
Mr. Krieger:
What would happen now if your fuel cost should be decreased?
• 13
Mr. Moriarty:
• You would get a refund in your bill.
Mr. Krieger:
With the fixed rate in the proposed rate, what would happen
If the fuel cost should decrease?
Mr. Moriarty:
It would go down proportionately.
The fuel cost reads plus or minus, it does not read just on
net increases.
Mr. Krieger:
You said you had three cents wrote into the rate for fuel.
Mr. Moriarty:
That's right. If it goes to four cents,
Mr. Krieger:
If it goes to two cents...
• Mr. Moriarty:
If it goes to four cents you pay another
adjustment charge. If it goes penny in the fuel
refund from the fuel adjustment which would beudeduet a
ctedpfrom
your bill.
Mr. Krieger:
And with the fixed rate, you will still have a reduction
possible?
Mr. Moriarty:
Instead of an addition you will have a deduction.
Chairman:
Are there further questions? All right.
• 14
Mr. Glick:
S Gentlemen, my name is David Glick and I'm a resident here in
Denton. The first question I would like to have you---
address to the gentleman from St. I•ouis, where did you get
these figures for your winter and summer times? Is that
based on temperatures, or is that based on the average
winters throughout the United States, or from what source?
Dr. Pickett:
That is based on 1979 load data for the City of Denton
Electric Department. Those are the four months in which this
systom is likely to peak.
Mr. Glick:
Am I to understand that these figures are based on--on a one
year report?
Dr. Pickett:
Yes, but 1979 summer period is approximately a normal weather
period, but 1980 was not.
Mr. Glick:
• Okay, how about '78? Would that have been considered normal?
Dr. Pickett:
I--We didn't go back and look at that, cooling degree days.
Mr. Glick:
Okay, I would like to suggest to you gentlemen and to
authority up here that the '79 might have been considered
average in some respects, but it was decidedly cooler in both
1978 and 1980 and it means that two out of the last three
years were far in excess of what we're using for a base for
winter and summer rates which means that if we go by that,
our consumption for months of April and as a fill in for the
early part of the winter is going to be excessive for what
we're projecting here.
Okay. My next question is, I--I--i would like to have an
explanation of why we're rewarding gluttony, that is why are
we penalizing people for using less energy, more energy
conservation conscious, and being more considerate to others
and to our limited and dwindling supplies?
15
i
I
Dr. Pickett:
In what areas do you think that we're rewarding gluttony?
Mr. Glick:
Well I-- I first got upset about this whole thing when I saw
the thing in the paper Sunday which gave the rates. If you
use x amount you pay one rate. If you ule x amount plus you
pay a reduced rate.
(Reference ?Attachment B)
Dr. Pickett:
That's the way it was presented in the paper, but that's not
correct.
Mr. Glick:
Okay. Would you be kind enough to bring me up-to-date and
correct that?
Dr. Pickett:
(Reference Attachment C)
Yes. As you'll see on the residential electric rate A-2
• during the months June to September a minimum charge single
phase of $4.50. As (pause) see that all kwh charge of 4.650
that's not a reward, but what we're doing is that we're
taking the total customer's bill which includes $4.50 plus
the number of kwh multiplied by 4.650 per kwh and as you take
l
the arger and larger amounts of kwh, you are going to distribute
pp
$4,50 over more kwh ding chart had that slight and
dethat's clining the
but that's the
total bill effect, but it's not level on the sense of a
proportional charge it's flat. But we're not rewarding a
person or a customer for taking more
Air. Glick:
How about commercial accounts? Does it fit In the exact rate
of the residential accounts?
Dr. Pickett:
No. There is a difference for commercial accounts. The kwh
charge is the same but it's lower because we have a separate
billing, the second time of billing runs Jane through
9eptember and minimum charges is 36 bucks it would be all
kwh's at 4.160 per kwh. It's flat. Now the reason it's not
4.650 is we're taking a customer, a commercial customer and
charging him a separate rate of $8.00 per kw and that's a
• L6
different measure than on your electric meter. They have a
different kind of meter than we allow on our residential
• houses.
Mr. Glick:
(At this point, Mr. Glick turned from the mike and the tape
recording of this comment was not understandable.)
Dr. Pickett:
All customers in your city are paying the same rate for fuel
and energy per kwh adjusted for losses, and losses are when
you and I take service of 110 or 240 volts there's a larger
losses because of laws of physics for a customer taking
service at 13.5--- 13,5000 but absolutely, you're paying the
same rate here.
Mr. Glick:
I am gratified to hear that.
Dr. Pickettt
Denton does not suffer from not--not collecting their
electric rates.
Mr. Glickt
That's gratifying (the tape recording of this statement was
not understandable) some people
Dr. Pickett:
No, other cities may have the tax, Denton has none.
Mr. Glick:
Okay. Some of the facts that I had I would like to have your
comments on and you gentlemen up here feel free to enter into
this. I was going to say in the City of Denton not only
includes those of us who are out and about and able to keep
for our share, have you all considered giving reductions
people on fixed incomes such as the elderly and people
who have, what are considered limited income?
Dr. Pickett:
"Residential Electric "Residential
Rate Electric
2" ic theRate- re's a adifference
monthly charge. The A-1 customers have $2.50 a month, all
• 17
other customers have $4.50 a month for single phase service.
The ringer here is that the small customer cannot use greater
• than 700 whs. If he practices consumption he gets a break
on his customer charge, if he doesn't practice consumption,
excuse me, conservation, he does not get the break.
Mr. Glick:
That is more of these things I hear----- could you
some Information as to what constitutes setting thelkwhs?
What's the average, 900 or so?
Mr. Nelson:
800 kwh's to 850 over a month.
Mr. Glick:
So that would be considered within reach of people In that
income group?
Mr. Nelson:
Yes. A customer with a 1200 square foot house in the spring,
fall and winter if he did not have all electric heatin will
use approximately 800 kwh's per month. g'
Mr. Glick:
• That's good. Gee I might be glad I'm here before this is
over. Okay. How about, is there any provision for the
non-heavy hours use. I don't know if its a common thing
around here. I moved here from California and In those areas
where electricity is generally cheaper anyway and hydro
electric, there is an off hours rate that is a rate that can
be given businesses that not in operation and therefore a
lesser drain.
Dr. Pickettr
Yes there is voluntary time of day tariff available for all
customers in the city , which you have to elect to take
service only by tariff. It's not mandatory, these tarriffs
are mandatory, but there is an alternative time of day tariff
at your discretion.
Mr. Glickt
What happens if you are or. the off-time tariff or on the 700
hour limitation thing or both, and overrun them? What's the
adjustment that's made?
• 18
Dr.Pickett:
• The adjustment is that you would get the $2.50 minimum charge
immediately bumped up to $4.50. On the time-of-day tariff,
you just pay more if you don't prar;tice conservation
(meaningful?) to the offpeak periods.
Mr. Glick:
On the particular months in question?
Dr. Pickett:
Yes. There is a peak period on the time of day rates and
there is an off peak seasonal period also.
Mr. Glick:
Okay there was another portion of your newspaper report, and
again i-- without discussing this, I have no way of knowing
how accurate it is or is not, how much money does our utility
department or the City lose when they don't hammer the
deadbeats, the people who don't pay their bills, and either
abandon their residence or just refuse to pay?
Mr. Moriarty:
I don't think we have any figures on that information.
• Mr. Glick:
Would any of you folks have that information?
Bill McNary:
Somewhere in the neighborhood of two hundred or three hundred
thousand dollars.
Mr. Glicks
Two to three hundred thousand dollars a week. What's the
overall income approximately?
Mr. Nelsons
Approximately $270,000 at about one percent.
Mr. Glicks
About 3%--?
Mr. Nelsons
About 11.
19
■
Mr. Glick:
• 187 A good deal. Thank you. Okay, I think that's rob
better than a lot of businesses suffer losses. Is t here la
way so we can reduce that area because while it's only one
percent, $300000 is of course $300,000?
Dr. Pickett:
Mr. Glick, the problem to get these people who won't pay
their bills, Is not a problem of the rates. It is a
problem----it is a problem that is in administration of the
tariffs and clearly the City can't staff to run everybody
down. They'd have to staff up, and I would view where
operations indicates that these cost expenses were not
unusual. They may have been higher than you and I would have
liked, but that is a normal event that uccurs.
Mr. Glick:
You misunderstand me. I think one percent is pretty
admirable.
Dr. Pickett:
Not one, it's one tenth.
• Mr. Glick:
Okay, one tenth. Okay, but what I'm wondering is, is there a
way to improve upon that?
Dr. Pickett:
Ou., study does not address that administration of tariffs.
Mr. Glick:
I see
Mr. Moriarty:
Let me add to that. There's always ways to improve on that.
The question is how much money do you have to spend to
improve on it. You may end up spending core in the cost than
you save in tightening up those controls. You must raise
your deposits and things like that, but tightening up those
controls you may end up spending more money charging all the
good customers the higher deposit or what have you, in order
to cut down on the few that do cause the problems. A crazy
solution.
• 20
Mr. Glick:
e I understand that. I would like to be worth $200,000 in
salary to collect $300,000 in bad debts.
Mr. McNary:
Not $100,000 in bad debts and that's the problem we run into.
Mr. Glick:
I understand that.
Okay For me I'd just like to make one or two comments to you
gentlemen because I've given you the runthough I feel may in
your hands. I want to thank you gentlemen for responding to
my questions. I feel a good deal more at ease than I did
before. I would suggest that both for the school district and
for the municipal buildings which yolu may have some say in
the matter in lightening up our energy use, and therefore our
cost factors, if you were a little bit more careful with the
utilities that you use in those structures. For instance,
while it may not be the most comfortable thing perhaps in the
winter time in cool weather indoors we could turn the heat
down just a little, maybe we'll all have to wear sweaters or
something, and in the summer time, we may have to get
adjusted to a little less air conditioning, its probably
. healthier anyway. And in buildings such as this and rooms
such as this, instead of the standard lighting that we now
have, we could probably save an immense amount of electricity
dispensed as well as the heat loss in the summer which we
would have to replace with air conditioning, by installing
florescent fixtures as opposed to the current incandescent.
Which may not seem like much but I have spoken with a couple
of physicists at North Texas State and they all agree that
its an appreciable difference. Even for a residence but for a
larger building it's just a phenomenal difference because it
uses less energy which would help us. There's another thing
that I might suggest, in the summertime where they're already
utilizing x amount of air conditioning and needed to maintain
that temperature, if we could reduce the amount of smoke in
the buildings, because one, that clogs the filters and, two,
it puts out x amount of heat, one doesn't put out very much,
but cummulatively, it really does add up. I don't have the
exact figures with me, but the gentlemen who showed it to me
at North Texas State checked that out, and its just a basic
law of physics each little heat element adds a little bit to
it. In addition it probably makes the area a little bit
nicer. I would like to thank you all for allowing the
opportunity for those of us who are not smart in the power
structure to get the opportunity to participate In the
setting of the new rates.
• 21
Chairman:
. Thank you Mr. Glick. Chris.
Chris Hartung:
Members of Public Utility Board, I am Chris Hartung, City
Manager, and I want to see if we can't make Mr. Glick
completely happy before he leaves this room tonight. I wanted
to comment on some of the things that he just said in closing
to let you know and let him know and the other members of the
audience that the City of Denton has a very aggressive energy
conservation program. We're very proud of it and we've
received a significant amount of publicity across the state
and across the Nation for the things that we have been
doing. We are controlling, in terms of the thermostats in
this building, in fact one of the biggest complaints that I
generally get in the wintertime is that the building is too
cold. We are reducing the level of lighting, the lights in
this room have been changed and the bulbs that are now being
used are lower wattage than we had in here previously. We
shut the air conditioning air handles off every evening in
the summertime when the building is closed and there's not
going to be a meeting at night. We have done many other
things. We are continuing to review the building to see if
there are additional things that we can do in terms of
sealing the building, insulation, things of that sort, that
are minimum cost that will gain for us additional energy
conservation. The result of all the things we have done has
been to reduce energy conservation in this building
significantly and we are saving some $18,000 a year in the
cost of electricity for the municipal building itself, we
are continuing to look at all of our buildings and even in
the design of new fire stations and things of that sort to
ensure that municipal facilities will set the standard for
energy conservation in the City of Denton.
Chairman:
Thank you, Chris. Are there any further questions?
Mr. Moriartyo
Mr. Chairman, if there are no more questions, I have onp
other additional comment I would like to make. It was
brought to our attention today that, we have noticed in the
tariffs we recommended that we no longer propose the B-1 and
the B-2 commercial tariff, but we consolidated them into one
commercial tariff. It was brought to our attention today
that there are still some commercial customers that do not
a 22
NMI"
have demand meters installed yet, but the City has a program
in effect to install demand meters. And my recommendation is
• that if these rates are implemented, or rates similar to
these are implemented, prior to all those customers getting
demand meters, that the City Electric Department do one of
two things, either to have the engineers estimate what the
load factor would be for those customers without demand
meters and bill them accordingly, or an alternative would be
to put them on the Residential A-1 tariff until such time as
a demand meter could be installed. I think it is important
that we make that plain in the record.
E. Tullos:
A-2 or A-1?
Mr. Moriarty:
A-2. As an alternative, if you don't estimate the load
factor I would put it on the Residential A-1. I'm sorry A-2.
Chairman:
Bob.
Mr. Nelson:
Mr. Chairman and members of the Board, I would like to
O clarify one item that Mr. Krieger brought up and that was in
relation to the governmental service rate in the proposed
rates?
Chairman:
Excuse me, Bob, for the record, would you identify yourself
please.
Mr. Nelson:
Yes, 1 am Bob Nelson, Director of Utilities, City of Denton.
The only basic difference between the governmental lighting
and power service rate and the regular commercial/industrial
lighting power service rate is the fact that the governmental
does not pay demand charge. The energy charge on the
governmental is exactly the same as it is on the commercial.
The only difference is that they don't pay the demand
charge. There is some logic and reason that follows en that
also, and that is the fact that, for example, the school,
many of the school systems operate during the wintertime,
their demand exists in the winter time and of course that i-:
not on our primary demand time, so therefore the demand
charge, there is some logic and continuity to that. One of
• 23
the main reasons of the governmental as far as the City goes
and we might point out that governmentall lighting In the
power service rate does apply to the City of Denton, the
independent school district, and the county offices. But in
the city realm much of the service there is in the water and
the sewer department. The sewer department, for example has
almost a constant demand load the year around. Therefore, it
does not adversely affect from one month, to another. I did
want to point those out.
Chairman:
Thank you, Bob.
Are there any statements anyone would like to make?
All right, in that case, I thank all of you for being here
and the interest you've shown. We certainly want to' take
your questions and your statements under consideration when
making our recommendation to the Council. The Public Hearing
is therefore adjourned. Thank you.
• 24
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•
DEC 1 2
:,oa
PUBLIC NOTICE The Denton Municipal Utility Department gives notice that it shall
consider certain electric ratemaking and regulatory standards as set out in
- - Sections 111, 113 and 114 of--the Public Utility Regulatory Policies Act of -
1978 (PURPA). This hearing shall accept comments submitted by interested
partieson the issues set out in these sections.
The hearing to accept comments from interested parties will be held in
the City Council chambers of the City of Denton, Texas in the municipal - `
building located at 215 E. McKinney on the 7th of January, 1980 at 7:00
P.M. Copies of the consultant's report which contains recommendations that
address the. Section 111, 113 and 114 standards of PURPA will be available
in the City Hall and may be obtained from the
Electric Utility Department.
Individuals wishing to present testimony during the public hearing are
requested to provide one written copy of their comments at the time of the
public hearing.
All inquiries concerning the hearing are to be directed to Ms. Ann
Bingman in the Electric Utility Department at (817) 566-8230.
- PURPA OBJECTIVES
CONSERVATION OF ELECTRICITY BY CUSTOMERS
EFFICIENT USE OF FACILITIES AND RESOURCES BY UTILITIES
PROVISION OF EQUITABLE RATES TO CUSTOMERS -
O'
r
4
1
i
1 ,
OPERATIONAL CRITERIA - CONCLUSIONS
PURPA OBJECTIVES ARE INDEPENDENT OF EACH OTHER
OBJECTIVES ARE ACHIEVED ONLY WHEN ELECTRICITY REFLECTS
TRUE RESOURCE COST
CUSTOMER MUST CONTROL AT LEAST A PORTION OF HIS LOAD
AND RECEIVE A PROPER PRICE SIGNAL TO ENCOURAGE
CONSERVATION
RATEMAKING STANDARDS
ADOPT THE COST OF SERVICE STANDARD WITH THE CURRENT
ELECTRIC RATE STUDY
ELIMINATE DECLINING BLOCK RATES
5
INTRODUCE SEASONAL RATE;.DIFFERENTIALS
1 .
1
DEVELOP TIME OF DAY RATES
OFFER INTERRUPTIBLE RATES TO COMMERCIAL AND INDUSTRIAL
CUSTOMERS
1
INVESTIGATE COST AND BENEFITS OF LOAD MANAGEMENT
o AIR CONDITIONING
1
o IRRIGATION
o WATER PUMPING
COMPARE RESULTS OF ELECTRIC RATE STUDY TO A-1 RESIDENTIAL
RATE TO DETERMINE IF LIFELINE RATE IS REQUIRED
MANAG EII SUMMARY
ELECTRIC SALES (MEGAWATT HOURS) WILL INCREASE 502 BY 1985
FUEL & PURCHASED POWER WILL INCREASE 170% FROM
$13,2 MILLION IN 1980 TO $35,7 MILLION BY 1985
OTHER OJERATING EXPENSES WILL INCREASE 52% BY 1985
NEW DEBT ISSUES - E1,5 MILLION IN 1981, 1983, AND 1985
DEBT RATIO WILL INCREASE FROM PRESENT 47% TO 50%
DEBT COVERAGE RATIO WILL INCREASE FROM 2,0 TO 2.3 TIMES
DEBT SERVICE
CASH WORKING CAPITAL WILL DECREASE FROM 180 DAYS TO 40 DAYS
AVERAGE COST PER KWH WILL INCREASE FROM 4,25,E TO 5,4L
AVERAGE ANNUAL COST INCREASE= 8,5%
NO GENERAL RATE INCREASE REQUIRED BEFORE 1983 UNDER
CURRENT RATE STRUCTURE
CITY SHOULD RESTRUCTURE RATES NOW.
f
ASSUMPTIONS
CASH REQUIREMENTS REVENUE,BASIS
DISCRETIONARY TRANSFER - G% OF NET EQUITY
MINIMUM INTERNALLY GENERATED CAPITAL
8% OF GROSS REVENUES - FUEL 8 PURCHASED POWER
OTHER FINANCIAL ASSUMPTIONS
MAXIMUM DEBT RATIO = 50%
POSITIVE.NET INCOME
MINIMUM DEBT COVERAGE A 1,4 TIMES DEBT SERVICE
DEBT AUTHORIZED BUT UNISSUED - $3 MILLION
Ez AVERAGE LINE LOSSES
CONTINUE CONSERVATION RATE
INTRODUCE SMALL SEASONAL RATE DIFFERENTIAL
LIMIT SUMMER'SEASON TO MONTHS OF POTENTIAL SYSTEM PEAK
REDUCE WINTER SPACE HEATING DISCOUNTS
LIMIT WINTER SPACE HEATING DISCONNECTS TO HIGHEST
HEATING MONTHS '
REVENUE REQUIREMENTS SUMMARY
198___ 0_g l 1984=85
TOTAL l PER KWH TOTAL a PER KWH
0 0) x_512,000 MWk) S2QQZ 1f 0_000 MWH)
DISCRETIONARY TRANSFER $1,325 ,26 $1368 119
PRINCIPAL PAYMENTS 81S ,16 , 761 ,11
INTEREST EXPENSE .13096. ,21 1,3Oi 418
FUEL 8 PURCHASED POWER 15,963 3,12 35,102 5,06
_ OTHER OPERATi,NG EXPENSE 3,522 ,69 5372 ,76
MINIMUM INT,, CAPITAL '588. ,11 . 759 ,11
ADDITIONAL I NT, CAPITAL ---333 vO7 443
• GROSS REVENUES $23,643 4,62 $45,717 6,47
LESS: OTHER INCOME ` 510 -di - 504 07
REVENUE FROM RATES 523473 431 $45,213 6,40
CAPITAL STRUCTURE
X994 BALL4 0 RAM
EQUITY BALANCE $22,086 54% $22,914 50%
DEBT BALANCE 18 JIM j
TOTAL $410003 100% $46,186 100x
i
i
3
1 i
• DEBT COVERAGE
198- 1984-85
GROSS REVENUES $23,643 $45317
FUEL, PURCHASED POWER
& OHER O&M IM 74
$4,158 $4,643
DEBT SERVICE
1,931 2,062
COVERAGE RATIO 2,1 23
ti
M
WORKING CAPITAL
M w
t '
ANNUAL 08M EXPENSE $lGs509,000 $41sO74mOOO
AVERAGE DAILY 08M 45;000 112,000
OTHER CURRENT ASSETS 1,819,000 4,621,000
DAYS OF WORKING CAPITAL 114
41•
I I
,
DISTRIBUTION OF TOTAL, SYSTEM COSTS
GENERATION
TRANSMISSION
DISTRIBUTION
FGENERAL
ENERGY-
RELATED
DEMAND-
' RELATED
CUSTOMER-
RELATED
CUSTOMER GROUPS
fr r
yy LLR' A {ya~ ..X r .~,7 77,. il" 'f .YM t i. h „f.i7 •M !t Y' 1. .t .5
Y P. v. fir" i•^4 • f t• • 7f 7
. CUSTOMER COSTS.
CUSTOMER NUMBER OF MONTHLY
~USTS
RESIDENTIAL & SMALL -COMM-ERC1'AL $815,000 15,639
COMMERCIAL - THREE PHASE $4,34
COMMERCIAL - 205,000 2,143 *7,97
.Ll
PRIMARY'SFRVICE 110000
Pl1HLIC; AUTHORITIES 20 45183
• 4 # 000 4b 7,25.
.
• y I I r j •R. " .I',}S v rp . t 4 J' r Y, H. xfG , '}rr^.y 'a Iy "^sR°ry„s~'"~ i,l"yp," ,15
DISTRIBUTION COSTS
DISTRIBUTION ANNUAL COST
_ COSTS MWN SALES PER KW
RESIDENTIAL 8 SMALL COMMERCIAL $894,000 199,349 *451-
ANNUAL'
BILLING f
LARGE COMMERCIAL - SECONDARY $8800000 457,000 $lm93
LARGE COMMERCIAL - PRIMARY 326,000 202,000 $1,61,
. ' I
f a,y ~'y~~? ` .'k~..F+d54.i!:p `9r 1n~,,,~S,fi~ K , .yK',~.r „ dr .T'rf%' r Y($ Y; . . , i w•~ryCAin, ;r, af. hd.' 'Y i
.E ,r7~ i •67.• ~:E , + F.; 1. .,x;, ,.e
40
SEASONAL ENERGY COSTS-
. .
SECONDARY PRIMARY
SERVICE SERVICE
CU~B~ CUST----O•
BASIC ENERGY. COSTS
. $15 '575,000
;',(INCLUDES 85% OF CAPACITY COSTS) 53,432,000
ANNUAL MWH SALE. 414,750 92,241
COST PER KWH ,
3,791 -3.721 r.
SEASONAL ENERGY COSTS t . 4a5,a
05z OF CAPACITY COSTS} a0 3 93; 'GOO
SEASONAL MWH SALES 174,155 40COST PER KWH `400
.23L 231
.a i• i •'"41'}p M 'a~'' lf''I,~hi~ 'iH " °1 `Qi x 1 a 1A X ,{'btP r} k• -k M .;3
11 TIME-OF-DAY ENERGY COSTS
SECONDARY PRIM RY
SERVICE SERVICE
CUSTOMERS CUSTOMERS
BASIC ENERGY COSTS $13,380,000 $2,930,000
ANNUAL M`d SALES 4i.47S0 92,241 -
COST PER KWN 3,231 3018t
TIME-OF-DAY ENERGY COSTS $ 2,704,000 $ 618tOOO
(1002 OF CAPACITY COSTS)
PEAK PERIOD MWN .SALES 78,310 18,182
COST PER KWN 3,45,E 3.40E
~ 1
.t In i r'~ p~~,1ry r -Yt-, ~ r K 4 •Pgd'n fIY 'r"~. ° ' ~ 14
i
DIRECT TESTIMONY OF
FRED MORIARTY
CITY OF DENTON, TEXAS
ELECTRIC UTILITY COST OF SERVICE
•
JANUARY 71 1981
~4°Y a.F"~ ~ vi it~ ~X ~4 ' 'A°~~ 1 i~_ N~y~ ~1., a'Y'➢(f' ~ i~,J,
DIRECT TESTIMONY OF FRED MORIARTY
• Q. Please state your name, o.;uupation and business address.
A. My name is Fred Moriarty and I am President of Management
And Research Consultants, Inc. (MARC), 225 S. Meramee,
Clayton, Missouri, 63105.
Q, How long have you been employed by MARC?
A. I am a principal in MARC and participated in its
organization in January, 1980.
Q. What is your educational background?
A, I obtained a masters degree in business administration from
the University of Chicago in 1971 and completed my
requirements as a Certified Public Accountant in Illinois in
1974.
Q. What is your professional background?
• A. I developed accounting and financial management systems for
clients of the Burroughs Corporation in 1967 and 1968. I
then spent four years in Corporate Finance with Motorola,
Inc. until 1972. That was followed by two years in
financial management with the State of Illinois (1972-74)
and five years (1974-79) as a financial consultant with
Touche Ross and Co. before forming MARC in January, 1980.
Q. What is your experience in rate regulation?
In the last year I have testified before the Alaska Public
Utilities Commission on the PURPA regulatory standA.rds,
assisted the Federal Energy Reglatory Commission Staff
Counsel with the preparation of trial briefs regarding rates
1
hli 5
^v L air" t 'r. s M .k T Y. ,ER
715
f ~
for the Trans Alaska Pipeline System, performed several cost
• studies for municipalities regarding local cable television
operations and given utility cost of service presentations
to state and local government agencies.
Prior to joining MARC, I was a Manager of the St. Louis
office of Touche Ross s Co. I spent most of my five years
with Touche Ross as a member of its national public utility
resource group. I testified and/or directed the development
of electric, gas, telephone, oil pipeline and cable
television revenue requirements and rates for Federal, state
and local government agencies. A professional resume is
attached as Exhibit A.
Q. What is the purpose of your testimony in this proceeding?
As I am sponsoring the revenue requirements and cost of service
analysis presented in MARC'S December 12, 1980 report to the
City of Denton on the Electric Utility Rate Study.
Q. Would you summarize your findings regarding the electric
utility's revenue requirements?
A. Yes. Total revenue requirements will almost double by
fiscal 1985 due to customer growth, construction of new
power plants with TMPAand increases in the cost of fuel,
labor and other operating expenses. The average cost per
kilowatt hour is not expected to change materially, however,
until 1933 when the new TMPA generation plants begin to
produce substantial amounts of energy. Customer growth is
expected to provide adequate revenues to offset cost
2
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ti rt,
increases until 1983. Total operating expenses are expected
• to increase in 1983 and 1984 with the increased purchases
from TMPA and to begin leveling by 1985 when the Con manche
Peak and Gibbons Creek generating units are fully
operational.
Q. would you summarize your findings regarding the electric
utility's class cost of service study?
A. The total system revenue requirements were allocated to four
separate components during the cost of service studyr
customer, distribution, energy and capaoity. Two major
factors considered during the study accounted for 'cost
differences between service classes. The first factor, type
of service, reflected three basic service types: single
phase, three phase and primary service. This factor
• directly affected the allocation of customer costs and
indirectly affected the distribution, energy and ,apacity
costs. Secondary customers were allocated a larger portion
of distribution costs and a higher line loss percentage for
energy and capacity costs. The second major factor in the
cost study, seasonal (summer and winter) energy consumption,
resulted in a larger proportion of peak capacity costs
allocated to those customers with a higher summer usage. As
a result of the above customer characteristics, the
following cost differences were noted in the basic seasonal
cost study.
Monthly Customer Costs - Single Phase - $4.50
3
` i ri+r i.y6~~t n + t V;' r." rh W Mt y "~1'a 62 t`.., + f i Y: M6 +J," a f
Three Phase - $8.00
Primary Service - $46.00
Energy Costs (Kwh) - Secondary Service - 3.85¢
Primary Service - 3.80¢
Distribution Costs - Residential (Kwh) - 0.50
Distribution Costs - Commercial (Kw)
Secondary Service - $2.10
Primary Service - $1.80
Capacity Costs (Kwh) - 0.3j
Q. Does this conclude your testimony-?
A.' Yes.
4
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7 77
.p 1 .ter i' z.L M ?r.
EXHtB'YT :A
RESUME
FRED MORIARTY
CONSULTING ?inancial Management and Data Processing
EXPERIENCES
o Directed economic, technical and regulatory
evaluation of local cable television operation for
the Columbia, Missouri, Cable Television Commis-
sion.
o Testified and directed field activities related to
cable television companies be"o e rates s Alof two cable aska Public television
Commission.
o Directed financial evaluation and long term rate
projections of cable television proposals for the
North Central Area Cable Television Cooperative
Advisory Committee, a consortium of nine cities in
St. Louis County.
o Directed a cost-of service study and the
development of electric rates for the Columbia,
Missouri, electric utility.
o Testified and directed the development of
testimony for electric, gas and telephone rate
i cases before the Arkansas, Ohio and Pennsylvania
Public Service Commissions.
o Testified on the financing of the Trans Alr.ska
Pipeline System (TAPS) and directed the analysis
of oil pipeline regulatory methodology and the
appropriate return on investment for the Commission.
before the Fedecal Energy Regulatory o
o Developed sewer rates and supportive cost systems
for the sewer utilities inAnchorage, laska;
Garland, Texas; Sheboygan
Washington County, Oregon.
o Performed an evaluation of the medicaid reimburse-
ment rate policy in conjunction with cost audits
of approximately 200 nursing homes for the
Arkansas Division of Social Services. ehen o Performed an evalentigYstemaformCity 8ankv in 3t.
audit freight paym
Louis and directed the development of the Bank's
internal control and reconciliation procedures.
,II
'r~ 7
t
73 7- T7
a,
O Assisted the Director of Management Information
Systems for J, Weingarten, Inc., a large Texas
food retailer, in a management review and reorgan-
ization of data processing. Reviewed long ran
plans, defined needs for a Data Control Section,
developed accounting system interface requirements
and performed quarterly progress reviews for a
period of eighteen months.
o Directed the development of a long range
management systems software evaluation for the
City of Columbia, Missouri,
o Implemented accounting and public, housing
management systems for Municipal Information
Systems, Inc, in St. Louis.
o Reviewed the budget evaluation process used by the
Missouri Mental Health Commission; and the
integration of Mental Health operating budgets and
comprehensive planning activities.
o Performed a comprehensive review of administrati"ie
systems within the St. Louis Community Development
Agency including the contract processing, project
monitoring program evaluation.
r o Management of EDP audit function for local audit
clients of a Big 8 accounting firm located in St,
Louis,
PREVIOUS _eneral Management and g Fir.,
EXPERIENCE: _ ,nce
o Managed the development and implementation of the
State of Illinois comprehensive statewide
accl.~unting system,
o Managed a 180 employee bureau for Illinois
Department of Personnel including data processing,
statewide ccounting, general services and administration of
a
personnel examinations,
o Directed major modification of an Illinois state
personnel/position information system.
o Directed implementation of a program budgeting and
accounting system for Illinois Department of
Personnel,
o Managed sections of Corporate Financial Evaluation
. and Operational Audits for Motorola, Inc.
o Designed and implemented management systems for
1W "'"1'n"~, it w^' j..si y ^R7j+'.:w .
qt .r. ~y ''4,tyFI'~`i ,ti 4 .x 1 ` 4
1
DIRECT TESTIMONY OF
JOHN C. PICKETT
CITY OF DENTON, TEXAS
ELECTRIC UTILITY RATES
•
JANUARY 71 1981
DIRECT TESTIMONY OF JOHN C. PICKETT
4. Please state your name, occupation and business
address.
A. My name is John C. Pickett and I am the Director of
Systems and Research for Management and Research
Consultants, Inc. (MARC), 225 S. Meramec, Clayton,
Missouri 63105.
Q• Crow, long have you been employed by MARC?
A. I am a principal in MARC and participated in its
organization in January, 1980.
Q• What is your educational background?
A• I oLtained a Ph,D, in economics from the University of
Missouri, Columbia in 1970,
Q. What is your professional career?
A, Assistant Professor, Dept. of Business Economics and
Quantitative Methods, University of Hawaii, Honolulu,
Hawaii, 1968-711 Research Fellow, Urban Research Unit,
Australian National University, Canberra, Australia,
1971-73; Associate Professor, Dept. of Economics and
Business, Hendrix College, Conway, Arkansas, 1973-75.
Q. What is your experience in regulated utilities?
A. I was appointed to the Arkansas Public Service
Commission in may, 1975• In June, 1977 I was appointed
Chairman and remained Chairman, until January, 1979. 1
remained a member of the Commission until February,
19801 when I joined MARC. A professional resume is attached
1
as Exhibit A.
S Q. Have you authored any professional publications?
A. Yes. I have presented numerous papers at many
professional meetings and seminars.
0. What is the nat,lre of your testimony in this
proceeding?
A. I am sponsoring the Public Utility Regulatory Policies
Act (PURPA) issues concerning the rea+tlatory and ratemaking
standards and the rate design issues in MARC's December 12,
1980 report to the Ci;;y of Denton on the Electric Utility
Rate Study.
Q. Would you summarize your recommendations regarding the PURPA
standards?
A. Yes. I recommend that the City adopt all of the regulatory
® and ratemaking standards now with the exception of the
standard related to the Automatic Adjustment Clause. We
recommend that the City defer a decision on the Automatic
Adjustment Clause standard until the transition to TMPA is
substantially complete. At that time (1983 or 1984),
another restructuring of rates should be considered with a
complete reevaluation of the proposed Energy Cost
Adjustment.
Rational producers and consumers will respond to the
price charged for electricity. The PURPA objectives of
conservation, efficiency and economic equity will be
achieved only if the price of electricity reflects the true
2
resource cost incurrred to produce the electricity. The
• consumer must also receive the proper information and price
signals and be able to control at least a portion of his
load if hu is going to respond to the appropriate price
signals and relize the available benefits. We, therefore,
used the following rule as a guideline in formulating our
recommendations regarding the PURPA regulatory and
ratemaking standards:
"Does the standard result in the price of electricity
being set equal to its true resourcce cost or provide
the consumer an opportunity to respond to the
appropriate price signals?"
Q. Would you summarize your recommendations regarding the
proposed rate design?
• A. E have recommended, with a few exceptions, electric rates
that reflect the estimated cost of providing electricity to
different service types and voltage levels. The proposed
rates are presented as two or three components depending on
whether demand meters are installed for particular
customers. The three components are a customer facilities
charge, an energy charge and a demand charge. All of the
customer facilities charges in the proposed rates reflect
the average customer costs identified in the cost of service
study except for the Residential A-1 customers that have
monthly consumption less than 700 Kwh during the summer
months. We have proposed a $2.00 reduction in t)e monthly
3
customer charge for these customers to continue the current
conservation incentives offered these customers during the
summer months.
The proposed kilowatt hour energy charge for all customers
is based on the average kilowatt energy and capacity costs
for secondary and primary service. The basic energy costs
for secondary customers is 3.85 cents per kilowatt hour
which is proposed for all consumption during the year. The
corresponding energy costs for primary customers is 3.80
cents per kilowatt hour to recognize lower line losses for
primary service.
We have proposed a higher (three mills) kilowatt. hour
charge in the summer for all customers (except street
lighting and dusk to dawn lights) to recognize the higher
O capacity costs incurred to meet summer peak loads. We have
also proposed a two mill reduction for winter kilowatt hours
for residential electric heating customers. This lower
winter rate meets the objective of the City Steering
Committee to continue some winter discount for residential
customers who provide the system with beneficial oft-peak
heating energy demand.
The proposed kilowatt demand charge for commercial
customers is designed to recover the distribution related
costs incurrec' b., the system. These costs are generally
incurred as function of a customer's peak demand regardless
of when that, peak is achieved. The charges to recover those
4
costs are, therefore, based on the estimated monthly billing
demand of customers that are demand metered.
Since residential customers are not demand metered, we
have proposed collecting the distribution costs as an
addition to the kilowatt hour charge rather than on a
kilowatt billing demand basis as proposed for commercial
customers. Thus the basic kilowatt hour charge for
residential customers is five mills higher than commercial
customers receiving secondary service.
The City Steering Committee has indicated a desire to
continue offering reduced rates to local government agencies
to recognize the cost savings the City electric utility
realizes by not paying local taxes. We have proposed
elimination of any demand charges and continuation of an
• energy charge comparable to commercial customers to ensure
that these agencies receive the same conservation
incentives.
Our Electric Utility Rate Study also includes proposed
rates for the following services.
Dusk t.; Dawn Lighting
Time-Of-Use Rates► Secondary Service
Time-Of-Use Rates, Primary Service
Interruptible Service Rate
I have attached to this testimony three modified tariffs
and one additional tariff for street lighting that was not
included in our December 120 1980. T,.,? modified tariffs
5
ni.
include the following:
The Commercial and Industrial Lighting and Power
Service is modified to include a different Customer
Facility Charge of $4.50 for Secondary Service, Single
Phase.
The Time-of-Use Rates for Secondary (Schedule S-1) and
Primary (Sch(,--dule P-1) Service are modified to change
the definition of Billing Demand from the current
"month's peak billing periods from 12 Noon through 9
P.M." to read "monthly billing period".
4. Does this conclude your testimony?
A. Yes.
6
EXHIBIT A
RESUME
05,
JOHN C. PICKETT
EMPLOYMENT: Chairman - June 1977 - January 1979
Commissioner - May 1975 - June 1577,
January, 1979 - February, 1980
Arkansas Public Service Commission
Associate Professor of Economics, 1973-1975
Hendrix Collects
Conway, Arkansas
Assistant Professor of Business Economics,
1968-1971, 1973
University of Hawaii
Honolulu, Hawaii
Research Fellow, 1971-1973
Urban Research Unit
Australian National University
Canberra, A.C.T.
EDUCATION: Ph. D., Economics, University of Missouri,
Columbia, 1970
M.A., Economics, University of Missouri,
Columbia, 1965
B.A., Hendrix College, Conway, 1963
PROFESSIONAL
ASSOCIATIONS: National Association of Regulatory Utility
Commissioners (Executive Ccmmittee,
Committee on National Energy Act)
Midwest Association of Regulatory Commissions
(Executive Committee)
American Economic Association
American Agriculture Economic Association
I
PUBLICATIONS:
BOOKS: Public Authorities and Development in Melbourne,
Australian National University Press, 1973
ARTICLES: "3ystem Analysis and Long Run Marginal Cost
Electric Rates", 1980, Rate Symposium On
Problems of F:egulrAted IrdustrFes. Forthcoming.
"Forecasting Arkansas General Revenues:, Business
and Economic Review, University of Arkansas,
Spring, 1990.
"APB Opinion No. 2, AddendumProceedings, Edison
Electric Institute Financial Conference, 1979.
"Measuring Corporate Performance", Proceedin s,
Third Annual Conference of the Accounting and
Finance Division of the Southeastern Electric
Exchange, 1979.
"The Structure of the Interdependence of Federal
and State Ratemaking", Third Annual Public
Utilities Conference, University of Texas at
Dallas, 1978.
"A Regulator's View on Rate Structures", Rural
• Electrification Administration Retail Rates
Seminar, 1978.
"Identifying the Seasonal Period of Electric
Energy Consumption", with Leigh Riddick,
Proceedings, First Annual Regulatory
Information Conference, National Regulatory
Research Institute, 1978.
"Energy Policy Formation Using Classical and Box-
Jenkins Models", to be included in a text to be
published in 1980.
"Minimizing the Cost of Electric Power Using the
Tools of InLirconnection, Wheeling and
Pooling", Economic Regulatory Administration,
U.S. Department of Energy, November, 1978.
"Identification of the Seasonal Pattern of
Electric Energy Consumption", Proceedings,
First Biinnual Conference, National Regulatory
Research Institute, 1978.
"National Electric Rate Design Policies", U.S.
• Senate on Energy, Conservation and Regulation
of the Committee on Energy and National
Resources► September, 1977.
"Cogeneration", Inside Arka__ nsas, Sept/Oct 1977.
• "The Economics of Emergency Rate Hearings",
Proceedings of Worksho on Electric Utility
F nano a Pro Tems an PotentiTSolutions, The
M try Corporat on, Wash ii9ton Apra , 1976.
Public Authorities and Develo ment in Melbourne,
Australian -National Un vers ty press, 1973.
"The Public Authorities", Finance for Investment
in Urban Development, Urban Research Unit, ANU
Canberra, 1972.
"A PPB Analysis of the Department of Regulatory
Agencies", Program Evaluation Branch, Dept. of
Budget and Finance, State of Hawaii, 1969.
Numerous seminar papers presented at technical
conferences and University seminars.
CONGRESSIONAL TESTIMONY:
National Electric Rate Design Policies. Testimony
on Part E of S. 1469 before the Subcommittee on
Energy Conservation and Regulation of the
• Committee on Energy and Natural Resources, 95th
Congress, First Session, 1977.
National Electric Rate Design Policies. Testimony
on Part E of HR6831 before the Subcommittee on
Energy and Power of the House Committee on
Interstate and Foreign Commerce, 95th Congress,
First Session, 1977.
Testimony on HR 9482 before the Subcommittee on
Livestock and Grains of the Committee on
Agriculture, 95th Congress, Second Session,
1978.
• Commercial and Industrial Lightinq and Power Servioe Rate
:schedule B
(1) Net Monte Rate:
Demand Charge:
Primary Service: $1.80 per month per kW for all kW of billing
demand.
Secondary Service: $2.10 per oonth per kW for all kW of billing
demand.
Energy Cho e:
Billing months of June through September:
Primary Service: All kWh @ 4.100 per kWh
Secondary Service: All kWh @ 4.V per kWh
Billing months of October through May:
Primary Service: All kWh @ 3.800 per kWh
Secondary Service: All Mi @ 3.850 per kWh
(2) Customer Faciliri Charge.,
Primary Service: @ $46.00 per month
secondary Service: flee Phase @ $8.00 per month
Single Phase @ $4.50 per month
(3) Mailability:
Available to commercial and industrial users except that service
hereunder is not available for resale, breakdown or standby
power.
(2) Billing Demand:
Equal to the kW load metered during the 15-minute period of
maximum use during the current monthly billing period.
(5) Payment:
Billing for services hereunder will be at the net monthly rate,
payment cf which is due when bills are issued. Bills which are
not paid within ten (10) calendar days from the date of issuance
thereof will be considered overdue.
(61, Energy Cost A ustment:
is All charges of the net monthly rate will be increased or
decreased according to tie current energy adjustment clause.
A-4
Time-of-Use Rates - General Service, Secondary
Schedule S-1
(1) Net Monthly Rate:
Demand Charger
$2.10 per month per kW for all kW of Billing Demand
Energy Charge:
Billing months of June through September:
12 Noon through 9 P.M. @ 7.20¢ per kWh
9 P.M. through 12 Noon @ 3.20V per IUh
Billing months of October through May:
All kWh @ 3.202 per kWh
(2) Customer Facility Charge:
Single Phase @ $7.50 per month
Three Phase @ $12.00 per month
(3) Auailability:
Rate Schedule S-2 is applicable to approved electric service
required for secondary distribution service at voltage levels not
to oceed 480 volts.
(4) Billing Demand:
Dgual to the kW load metered during the 15-minute period of
maximum use during the current monthly billing period.
(5) Service:
At the utility's available secondary voltage and phase.
(6) Payment i
Billing for service hereunder will be at the net monthly rate,
payment of which is due when the bills are received. Bills which
are not paid within ten (10) calendar days from the date of
issuance thereof will be considered overdue.
(7) Energy Coot Adjustment:
All charges of the net monthly rate will be increased or
decreased aocccding to the current energy adjustment clause.
(8) Aiecisl Facilities:
i
A-9
• All service which requires special facilities in order to meet
the custcmer% service requirements shall be provided subject to
special facilities rider,
I
•
A-.10
. Time-of-Use Rates - General Service, Primary
Schedule P-1
(1) Net bbnthly late:
Demand Charge:
$1.80 per month per kW for all kW of billing demand
Energy Charge:
Billing months of June through September:
12 Noon through 9 P.M. @ 7.050 per kwh
9 P.M. through 12 Noon a 3.15 per kWh
Billing months of October through May:
All kWh @ 3. IV per kWh
(2) Customer Facilities Charge:. 5,60.00 per month
(3) Mailability:
Rate Schedule P-1 is applicable to approved electric service
• required for primary distribution service at voltage levels not
60 exceed 69,000 volt3 and billing demand equal to or greater
than 20 kW.
(4) Billing Demand:
Equal to the kW load m,stered during the 15-minute period of
maximum use during the current monthly billing period.
(5) Service:
At the utility's available secondary voltage and phase.
(6) Payment:
Billing for service hereunder will be at the net monthly rate,
payment of which is due when the bills are received. Bills which
are not paid within ten (10) calendar days from the date of
issuance thereof will be considered overdue.
(7) Eergy Cost Adjustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
• (8) Special Facilities:
All. service which regjires special facilities in order to meet
the, customer's service requirements shall be provided subject to
special facilities rider.
A-11
® Street Lighting
(1) Net twD1y Fate:
All kWh @ 5.49. per Wh
(2) Vailabilit s
Available to the City for street lights
i~aw slat: %4 -J
(3) Service
At the utility's available secondary voltage and Ehase.
(4) payment.
Billing for service heroonder will be at the net monthly rate,
payment of which is due wikn bills are issued. Bills which are
not paid within ten (16) days from the date of issL Ace thereof
will be considered overdue.
(5) fhecZ Cost pdjustrent:
All. char.les of the net monthly rate will be Increased or
decreased according to the current energy adjustment clause.
Street Lighting 6 Traffic Signals
(1) Net Monthly Rate:
All WE @ 3.650 per k;IH
(2) Availabili~y:
Available to State and local government agencies that install
and maintain their own street lights and traffic signals.
(3) Service:
At the utility's available secondary voltage and phase.
(4) Payment=
Billing for service hereunder will be at the net monthly
rate, payment of which is due ti `.en bills are issued. Sills
which are not paid within ten (10) days from the date of
issuance thereof will be considered overdue.
• (5) Energy Cost Adjustment:
All changes of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
(6) Maintenance Charge:
Maintenance expenses billed at cost.
CITY OF DENTON, TEXAS
ELECTRIC UTILITY RATE STUDY
BY
MANAGEMENT AND RESEARCH CONSULTANTS, INC,
DECEMBER 12, 1980
MARC
A Professional Conjulfing Group
•
MARC A Professional Consulting Group
• MANAGEMENT AND RESEARCH CONSULTANTS, INC. 225 S. Meramec, Suite 105
John C. Pickett. PK0. Clayton, Missouri 63105
(314) 725-6763
F(141 Moriarty. C.P.A.
F;khsrd P. Anthony
December 12, 1980
City of Denton
C/0 Mr. R. E. Nelson
Director of Utilities
Municipal Guilding
Denton, Texas 76201
The City of Denton engaged Management And Research Consultants, Inc.
(MARC) in May, 1980 to develop a PURPA Compliance Manual and to perform an
Electric Rate Study. The enclosed revenue analysis, cost of service study
and prnposed electric rates presents our findings and recommendations
concerning electric rates in Denton.
A summary of our approach to the cost of service analysis and our
proposed electric rate structure is provided in the Management Summary
section of the report.
We appreciate the opportunity to assist the City of Denton in this
important engagement .ghich will have a direct effect on the cost of energy
and conservation in Denton. We also thank the Steering Committee and
Electric Department for their patience and cooperation during the study.
+er truly yours,
n
Fred Moriarty
President
FJM:sh
CITY OF DENTON, TEXAS
ELECTRIC UTILITY RATE STUDY
~I
i
BY
MANAGEMENT AND RESEARCH CONSULTANTS, INC,
DECEMBER 129 1980
TABLE OF CONTENTS
MANAGEMr-NT SUMMARY 1
REVENUE REQUIREMENTS 4
Fuel and Purchased Power 7
Debt Ratio 8
Cash Working Capital 9
Plant Additions and Depreciation 10
COST OF SERVICE 17
Select a Test Period 18
Assign Costs to Functions 18
Classify Costs Within Functions 14
• TARiFFS 46
Residential Service 48
Commercial Service 49
Local Government Service 51
Lighting Ser0 ce 52
Time-of-Use Rates 52
Time-of-Use Methodology 54
Cogeneration Tariffs 56
i
Interruptible Tariffs 57
Energy Cost Adjustment 57
APPENDIX A - Proposed Electric Tariffs
APPENDIX 8 - Comparative Electric Rates
• APPENDIX C - Billing and Col;artion Policies
• MANAGEMENT SUMMARY
The City of Denton, Texas engaged Management And Research Consultants,
Inc. (MARC) in May, 1980 to develop a PUR"A Compliance Manual and to
perform an Electric Rate Study covering a future period from fiscal year
1980-81 through fiscal year 1984-85. The City of Denton Charter requires
that the rates and charges of the Utility Department be reviewed by the
hol is Utility Board at least each five years.
This report will complete the electric rate study and provide the
basis of our recommended electric rates. During the cost of service
analysis, we allocated the total revenue requirements to each customer
class for the first year of the five year projection period according to
cost causation characteristics of each class. These class characteristics
• include the number of customers, peak period consumption and total
consumption. While total revenue requirements will increase during the
study period, relative class consumption characteristics are not expected
to change significantly during the study period.
The class revenue requirements obtained from the class cost of service
analysis have been compared to current revenues and customer class rates to
determine the increase in rates anticipated over the five year period to
meet total system revenue requirements.
The completion of the class cost of service analysis and review of
currently available class load data has provided the basis for our proposed
electric rates and recommendations regarding the PURPA standards. Although
PURPA language designates cost of service as a ratemaking standard along
with declining block, time-of-day, seasonal and interruptible rate,; cost-
1
based rates, not cost-of-service studies, are the means by ohich PURPA's
• objectives of conservation, efficiency and equity ran be achieved. The
cost-of-service analysis, therefore, is required to design cost-based rates
and to evaluate the cost of service standard and the cost effects of the
alternative rate types.
Our analysis of available sales and expenditure data indicates that
increases in electric utility costs will average about 7.0% per year over
the next five years as the City undergoes a transition from self generation
to purchasing under a contract agreement from the Texas Municipal Power
Agency (TMPA). It appears no increase in average base rates will be
required until substantial energy is obtained from TMPA if the current
revenue level is maintained and the sales forecasts defined in the recent
power supply study are achieved. Any cost increases will likely be
• recovered through the fuel adjustment clause because they will likely be
the result of increases in fuel and purchased power costs. Total operating
expenses are expected to increase in 1983 and 1984 with the increased
purchases from TMPA and to begin leveling by 1985 when the Com manche Peak
and Gibbons Creek generating units are fully operational.
These increased revenue requirements do not mean that the revenue
required from all customer classes will increase at the same rate. 'rhe
effect of customer and load growth have been included in the estimate of
the additional revenues required from each customer class necessary to meet
the total revenue requirement. The customer class cost of service study
has recognized the increase in the number of customers, Kwh consumption and
class loads. The low increase in total costs projected during the next two
fears indicates that this may be an opportune time for the City to
2
implement our recommended restructuring of electric rates.
i The effect of the rate restructuring will be offset in part by
customer load growth and increases in KIAH consumption. The combined effect
of all factors will result in rates ..hich more accurately track the costs a
customer causes the Electric Oepartment to incur in order to meet the
customer load.
i
• REVENUE REQUIREMENTS
Two bases of determining revenue requirements are common and each has
its own preferred application. They are referred to as the "utility basis"
and the "cash basis". The utility basis is applicable to investor-owned
utilities which are entitled to earn a profit or return on their
investment. The cash basis is commonly used for publicly owned utilities,
since the consumers or rate payers are also the owners of the system.
The cash basis requires that revenues must be adequate tc meet the
cash requirements as determined by the system cash outflows. It is based
on estimates supported by operating experience and knowledge of future
needs. Tho items included in the determination of the cash requirements
normally include operation and maintenance expense; debt requirement
• expenditures; and the cost of minor extensions, replacements and general
improvements typically financed with current revenues. Optional items such
as appropriations for major improvements and contingency reserves may also
be included. Gross revenues must be provided by operating revenues derived
through the rats schedules and additional nonoperating income collected
from various sources.
Use of the cash requirements method for the City of Denton requires
estimates of three major components to determine the total revenue
requirements. They are:
o Operation and Maintenance Expenses (Excludes Oepreciatio..)
o Debt Service Requirements (Includes Principal and Interest)
o Retained Earnings for Internal Capital Needs and General
Fund Payments
These cash requirements include all the cash expenditures the utility
4
• is now required to produce from its operating funds to m^et its cost of
operations.
Since we anticipated transfers to the General Fund and Improvement
fund in projecting the Revenue Requirements, we assumed that adequate
revenue would be generated to meet the minimum debt coverage ratio of 1.4
times debt service. We, therefore, did not make any additional adjustments
to revenue requirements for the debt service requirements.
Table I-A summarizes the projected revenue requirements for the Denton
electric utility through fiscal year 1985. The following individual cost
items are included on Table I-A in the determination of the revenue
requirement.
1. The Oiscretionary_Transfer is 6% of the prior year-end
iiet equity balance computed on Table I-B.
2. The U.S. Government Obligations purchases are required
during the first six years of the Electric System Revenue
Refunding Bonds, Series 1978 as ih 3wn in the City's debt
service schedule.
3. The Interest Expense - Old Debt represents the first six
years of interest expense on the Electric System Revenue
Refunding Bonds, Series 1978 as shown in the City's debt
service schedule.
4. The Principal Payments nents - New Debt was obtained from the
draft of the 1980 Power Supply Study, Exhibit IV-3 and
...ents the estimated principal payments on new debt
lssijes anticipated from fiscal year 1981 through fiscal
year 1985. The new debt issues projected in fiscal years
5
1981 and 1983 were reduced by one half in accordance with
discussions with the City's Rate Study Steering
Committee. The subsequent years debt service was also
changed accordingly.
5. The Interest Expense - New Debt was obtained from the
draft of the 1980 Power Supply Study, Exhibit IVA and
represents the estimated interest payments on new debt
issues. We adjusted the projected interest expense to
correspond to the adjustments to Principal Payments - New
Oebt discussed above.
b. Fuel ano Purchased Power costs were obtained from the
City Electric Utility. The Electric Utility obtained
preliminary estimates from the TMPA Preliminary Official
• Statement but adjusted the fuel and purchased power cost
in fiscal years 1?81 and 1982.
7. Other Operating Expenses were obtained from the TMPA
Preliminary Official Statement by the City Electric
Utility.
8. The Revenue Requirement Before Adjustment represents the
total system revenue requirements excluding the amounts
required for the Improvement Fund to finance
replacements.
9. Minimum Internally Generated Capital is equal to 8% of
gross revenues lets fuel and purchased power expenses and
represents the minimum internally generated capital
required for transfer to the Improvement Fund.
6
IS . 2f~
• 10. Additional Internal Capital is included to assure a
positive net income to the electric utility and is equal
to an additional 4% of gross revenues less fuel and
purchased power. This item has been increased by
$765,000 in 1980-91 to achieve the Public Utility Board's
desire to obtain rates that prcJuce adequate revenues to
meet the current year budget.
11. Gross Revenues represents the total system revenue
requirements.
12. Other Income includes interest income, rentals from
warehouse aid service center and miscellaneous operating
revenues. No allowance is provided for revenues from
penalties.
13. Revenue Requirement From Rates represents the amount of
revenue requirements that will have to be recovered
through rates charged to electric customers.
Depreciation expense is not included in the determination of total
revenue requirements because it is an expense that does not require an
outflow of funds. We have instead included Principal Payments on debt
service and the purchase of U.S. Government Obligations which represents
the outflow of funds that are required to eventually retire the debt used
to finance most of the utility's construction.
FUFL AND PURCHASED POWER
The largest cost items included in the revenue requirement
• calculations are fuel and purchased power expenses. As shown below, the
7
costs of fuel and purchased power are expected to continue to increase
until the new TMPA power plants are completed in 1984. The cost of
purchased power and fuel is expected to begin lfvoling off. in fiscal year
1984-85 which is the last year included in this Electric Rate Study. A
substantial portion of the future purchased power costs from TMPA is
expected to be charged to the member cities in the form of a demand charge.
This will have a significant effect on the proper allocation of purchased
power costs in future cost of service analyses.
PURCHASED POWEk PERCENTAGE
FISCAL YEAR PLUS FUEL INCREASE
1979-80 $12,2001000
1980-81 159963,000 21%
1981-82 19,499,000
1982-83 24,6410000 26%
1983-84 329575,000 32%
. 1984-85 359102,000 10%
DEBT RATIO
Table I-B is provided to show the calculations required to compute the
year end balances for debt and equity (retained earnings) during the period
covered by the revenue requirement projections. This table serves two
purposes. First, it provides an indication of the expected trend in the
electric, utility's debt ratio over the neAt several years if it realizes
the revenue and expense projections used in the report. As can be seen at
the bottom of Table I-8, the debt r is expected to increase from its
current 47% to appso4imately 46% by ,
The second purpose served by this table is the development of year-end
equity (retained earnings) balances necessary to calculate the estimated
8
~F1
annual discretionary transfer to the General Fund. The annual
® discretionary transfer shown is 6% of the prior fear's ending equity
(retained earnings) balance. As .an be seen on Table 1-8, the year-end
equity balance and consequently the annual discretionary transfer increases
only slightly from 1981 through 1985.
CASH WORKING CAPITAL
Table I-C provides an analysis of the expected annual change in
current assets and liabilities. Accounts receivable are expected to remain
about 22% of gross operating revenues through the study perio.i. Fuel
inventories are expected to remain at about 14% of annual fuel costs until
fiscal year 1983 when the City will be obtaining substantially all of its
power from TMPA. The net change in the balance of these accounts in each
year of the study represents our estimate of the annual change in cash
work4ng capital.
Other current assets which is prioarily cash working capital of
approximately $8 million dollars represents almost six months of cash
working caf,Ital. Daily cash working capital requirements are about $45,000
($16.5 million annual operating expenses divided by 365 days). S8 million
dollars divided by $45,000, therefore, is equal to nearly 180 days or six
months of working capital.
Daily cash working capital needs are expected to increase to
approximm~ately $110,000 per day by 1985 ($41 million annual operating
expenses divided by 365 days). Our cash working projections shown on Table
I-C reflect an estimatec cash working capital or balance in other current
• assets at.the end of fiscal year 1985 of $5.4 million. This will represent
9
approximately fifty days of cash working capital, a substantial reduction
from the current level.
PLAiJ ADDITIONS AND DEPRECIATION
Table I-0 provides the estimated annual plant additions, depreciation
expense and year-end net plant balances. Current plant balances end annual
depreciation rates were obtained from the City's Accounting Department.
Annual plant additions were provided by the electric utility in their
current capital improvement program.
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• COST OF SERVICE
Although PURPA language designates cost of service as a ratemaking
standard along with declining block, time-of-day, seasonal and
interruptible rates; cost of service rates and not cost of service studies
are the means by which PURPA's objectives o° conservation, eIficiency and
equity can be achieved. However, cost of service studies are required to
design cost-based rates. Therefore, it is not possible to evaluate either
the cost of service standard or any rate type independently.
A cost of service study allocates the utility's total costs to
customer groups according to the actual costs of providing electricity to
that group. Rates based oii cost of service study results will represent a
significant step toward meeting PURPA's objectives of conservation,
efficiency and equity.
o Consumers will be motivated to conserve electricity
because cost-based rates reflect, to the greatest extent
possible, the true costs of providing utility services
and, is such, will increase as service costs increase.
o Efficient electricity production will be indirectly
encouraged because a major goal of utility regulation is
to ensure least cost construction, investment and fuel
purchase by utilities.
o Equitable rates will be promoted because customer groups
will be charged on the basis of cost of service,
reflecting their relative demand on the system,
electricity consumption and need for related services.
17
For this study, we have utilized a traditional cost of service
methodology which includes the following four steps,
1. Select a test period.
2. Assign costs to functions (generation, transmission,
distribution and general).
3. Classify costs within functions (energy-related, demand-
related and customer related).
4. Allocate costs to customer groups.
The sequence and relationship of these steps is shown on Table II-A-1.
SELECT A TEST PERIOD
The time period selected for evaluating relative customer class costs
is the same used to determine revenue requirements. Although the analyses
S for a future test year(s) is based on more uncertain data such as expense
forecasts, failure to assess the potential future impact of rate decisions
may adversely affect a utility's earnings and general financial conditions.
Since the relative customer class load characteristics are not expetted to
change significantly during the study period, however, we have not
presented a complete customer class cost of service analysis 'oeyond 1981.
The tables in Sections II-9 and II-C show the results of our cost study for
1981.
ASSIGN COSTS TO FUNCTIONS
The first major step in calculating cost or service to each customer
group is to assign a utility's costs to either the generation,
transmission, distribution or general function. Depending on the techfical
18
configuration of the utility's system, further disaggregation of costs into
subfunctions may be desirable for a more precise allocation to customer
groups. For example, distribution costs could be further allocated between
primary and secondary distribution costs according to voltage service
level. This concept is discussed further in the Rate Design section
relating to the large commercial customer class.
Some costs, such as the cost of speciel facilities as street fighting,
are not classified by function; instead they are assigned directly to a
customer group. Costs that are identified as not being directly related to
these three functions should be assigned to the general cost function.
Tables II-6-1 and II-C-1 show the assignment of general cost
categories to each major function. The costs are taken directly from the
Revenue Requirements section of this report or from supporting workpapers
provided by the Electric Utility.
CLASSIFY COSTS WITHIN FUNCTIONS
As illustrated in Table I1-A-1, the costs assigned to each function
must be further classified as being one or more of the following,
o Demand-Related - The costs are fixed costs of meeting
customer demands. These costs are the function of the
kilowatts (KW) of demand imposed on the generation,
transmission and distribution segments of the utility's
system. The City of Denton does not currently have
adequate load data to accurately estimate the relative
peak KW loads of each customer class. We have,
therefore, allocated demand costs rs a function of
19
+MM"
kilowatt hour sales that will, at a minimum, reflect the
• relative contribution of customer loads on peak capacity
requirements.
Distribution plant peak requirements are generally
determined by individul customer peak demand requirements
whether or not that peak is coincident with the system
peak. Consequently, we have allocated distri')ution costs
based on the relative annual consumption of each customer
class since an increase in an individual customer class
demand could cause additional distribution costs
regardless of the time period in which the increased J
I
demand is required.
Total generation and transmission plant costs
® typically reflect the maximum system generation demand
requirement. An increase ir. customer demend during the
winter or off-peak (seasonal) period will generally not
require the utility to add additional plant although fuel
or other variable expenses will be incurred. A permanent
increase in customer demand during the summer peak period
will most likely require the utility to add or contract
for additionai generation and transmission plant. The
concept of peak load cost allocation recognizes the
greater cost consequences of increased peak period
demands and consequently, allocates a greater proportion
of coincident capacity costs (generation and
transmission) to the seasonal periods in which the system
20
has a high probability to reach its peak demand.
Potential problems exist, however, if summer or peak
period rates are designed to absorb all the system
capacity costs. The utility's summer rates may be
dramatically higher than neighboring communities. The
utility may also be selling energy during the winter or
off-peak period at the variable cost of veneration which
means that revenues from off-peak consumption would
contribute nothing to the fixed generation and
transmission costs of the system. A practical solution
to this situation is to add a demand cost component to
the winter or off-peak period rate to assure recovery of
at least a portion or fixed capacity costs, This is an
important consideration for the Denton Electric
Department during the transition to cost based rates,
while participating in a major construction project and
during the period when more accurate customer load data
is assembled.
For purposes of the Rate Study, two cost of service
I studies hive been performed. For the basic seasonal
rates (Table 1I-8)0 the City Steering Committee has
indicated a desire to have costs assigned based on the
~cirtionship of the summer and winter peak demands. The
winter peak has been approximately 85% of the summer
peak, For optional time-of-day rates (Table II-C),
coincident peak costs are allocated based on summer peak
21
KWH sales. Such an allocation scheme provides a
practical estimate of the coincident peak summer KWH
costs upon which a time-of-day rate differential may be
based.
o Energy-Related - The costs are related to the operation
of facilities to meet customer energy requirements such
as fuel and purchased power. They are a function of the
kilowatt-hours (KWH) produced to serve customer groups
and are, therefore, allocated on an annual KWH basis.
Future purchased power costs from TMPA may include a
fixed demand component as high as 40% of the total
charges necessary to assure that the high fixed costs of
new plants are recovered. The expected increases in
• capacity-related costs associated with TMPA generation
will require extensive analysis of load data and time-of-
use costing in future years to disc:rurage all classes of
customers from adding electric load during the system
peak periods.
o Customer-Related - The costs are related to
providing customer services. These costs are a function
of the number of customers serve) by a utility,
Customer-related costs include portions of the
distribution investment as well as meter equipment, meter
reading and billing expenses. Different customer classes
or services have been weighted for cost items that vary
by service type.
22
The classification of genera" :an, transmission and general costs is
• relatively straightforward. However, the classification of distribution
costs is more complex. One of the major methodological issues related to a
cost of service study is the classification of distribution system costs
into demand and customer-related.
Distribution costs can be divided between the demand and customer-
related categories or weighted to recognize the type of service provirtd.
For lxampli, the need for line transformers is a function of bot,,. the
number of customers served and their peak demand. The costs of the
distribution system incurred in order to meet maximum customer group
demands are generally classified as demand-related while the costs of
distribution facilities incurred to connect customers to the utility system
are generally classified as customer-related. We have allocated all
. distribution costs to the demand-related category but assigned a greater
weight to secondary service customers to recognize costs associated with
the additional distribution lines requirtA to serve these customers.
Customer-related costs such as services and meters have been assigned
to M; weighted customer-related category to allow for differences in meter
and service drop costs between small and large customers. We have used a
weighting factor of ? for small commercial and 10 for large ommercial as
shown on Table II-A-2. The larger weighting factor for large commercial is
based on relative meter installation cost estimates provided by the
Electric Utility.
23
L
TABLE fE -A
COST OF SERVICE METHODOLOGY
AND ALLOCATION FACTORS
i
24
TABLE II-A-1
DISTRIBUTION OF TOTAL SYSTEM COSTS
GENERATION
TRANSMISSION
DISTRIBUTION
GENERAL
•
ENERGY-
RELATED
DEMAND-
RELATED
CUSTOMER-
RELATED
CUSTOMER GROUPS
1 25
• TABLE II-A•2
CUSTOMER ALLOCATION FACTORS
UNWEIGHTED WEIGHTED (1)
ADJUST O
NUMBER OF WEIGHTING CUSTOMER
CUSTOMERS PERCENTAGE FACTOR M FACTOR PERCENTAGE
OM
Residen'~ial
A-1 (2) 41388 24.6% 1 49388 21.7%
A-2 (3) 10,744 60.2% 1 10,744 53.1%
Commercial
B-1 (4)
Single Phase 507 2.8% 1 507 2.5%
Three Phase 1,522 8.5% 2 31044 15.1%
8-2 (5)
Primary
Service 20 0.1% 10 200 1.0%
Secondary
Service 621 3.5% 2 1,242 6.1%
Public Authorities 46 0.3% 2 92 0.5%
T7o848 I0.3% -2'U 1 11 TOO%
(1) Weighting Factor to recognize large meter and service cost: of commercial
accounts
(2) 15,132 x 29%
3 15,132 x 71%
(15,132 total residential customers provided by Electric Utility)
(4) 2,670 x 76% J 2,029
(2,670 total commercial customers provided by Electric Utility)
Single Phase, 2,029 x 25%
Three Phase, 2,029 x 75%
• (5) 2,670 x 24% = 641
Secondary, 641 - 20 • 621
26
TABLE II-A-3
O CUSTOMFR CLASS ALLOCATION
ENERGY ALLOCATION FACTORS
ANNUAL MWH
ANNUAL MWH LINE GENERATION
CONSUMPTION LOSSES REQUIREO PERCENTAGE
Residential
A-1 (1) 229657 6.3% 249180 4.4%
A-2 (2) 1519625 6.3% 1611'20 29.7%
Commercial
B-1 (3) 25,067 6.3% 269752 4.9%
8-2 (4)
Primary Service 920247 4.6% 96,695 17.8%
Secondary Service 196,024 6.3% 2091204 38.5%
Public Authorities 19,377 6.3% 209679 3.8%
Street Lighting 4,844 6.3% 5,170 0.9%
• 511,841 5443500 100.0%
(1) 174,282 x 13%
(174,282 total residential consumption provided by Electric Utility)
(2) 174,282 x 87%
(3) 313$38 x 8%
(313,338 total commercial consumption provided by Electric Utility)
(4) 313,338 x 92% • 288,271
Primary, 288,271 x 32%
Secondary, 288,271 x 68%
2 1
".T
TABLE II-A-4
• CUSTOMER CLASS ALLOCATION
DISTRIBUTION ALLOCATION FACTORS
ANNUAL MWH DISTRIBUTION WEIGHTED
GENERATION 1 FACTOR DISTRIBUTION. PERCENTAGE
(A) _"l '2 ~ Ax B
Residential
A-1 24,180 1.0 24,180 4.7%
A-2 1619820 1.0 1619820 31.1%
Commercial
8-1 (3) 26,752 1.0 269152 5.1%
B-2 (4)
Primary Service 96,695 0.8 77,356 14.9%
Secondary Service 209,204 1.0 2099204 40.2%
Public Authorities 4 O%
b Others 209679 1.0 20,67
5399330 5199991 100.0%
(1) Table II-A-3, Column 3.
(2) Primary distribution lines are estimated by Electric Utility to be 80% of
total distribution s stem; therefore, primary distribution customers receive
a weighting factor 8) that is 80% of the secondary distribution customers
(1.0).
28
• 1
O
ul
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urW Mfh M OD M O
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t\ Ln d
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r y N w-1 In N ~0 01 d 1-4 V 41 O v 1n N 4+ A
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Q Q V 00 Ofi 0. Vhf 1O w-/ N M tt 0 10 f~ 00
wvv.~ vvv
OTC
TABLE ll-B
SEASONAL COST STUDY
30
TABLE iI-8-1
FUNCTIONAL ALLOCATION - 1981
(000)
DISTRI- STREET
TOTAL CAPACITY BUTION CUSTOMER COSTS LIGHTING
COST COSTS COSTS WEIGHTED UNWEIGHTEU ENERGY DIRECT
PLANT (1)
Production $14,796 $29219 $129577
Transmission 29138 321 11817
Distribution 1,961 $7,961
Customer 11156 $1,156
Street Lighting 493 $493
$26,544 TFvW 37-IT3T 31;M $149394 TM
100% 9.6% 30.0% 4.3% 54.2% 1.9%
EXPENSES (2)
Plant Related $ 42313 $ 414 $19294 3 185 S 21338 3 82
Purchased Power 61092 60092
Fuel 99871 91871
Other Production 933 140 793
• Transmission &
Distribution 19046 1,046
Customer Accounts
& Sales 849 849
2156%4 $ 554 ' 51031% 018% 3.7% 51826% 00.4%
Administration &
General 694 17 70 5 26 513 3
5 18 71 IT, 0 90 T-78-9 199661 85
(1) Table 1-0, Page 1, Column 13
(2) Table I-A, Page 1, Column 1
31
TABLE II-B-2
CUSTOMER CLASS ALLOCATION
1981 CUSTOMER COSTS
TOTAL
UNWEIGHTED WEIGHTED CUSTOMER
E}CNT T 1 T COSTS
- (A) _ (B) A+B
I
Residential A-1 24.69 S47,O00 21.7% 5190,000 S2370000
Residential A-2 60.2% 1149000 53.1% 465,000 5799000
Commercial B-1
Single Phase 2.8% 5,000 2.5% 22,000 279000
Three Phase 8.5% 16,000 15.1% 132,000 1489000
Commercial B-2
Primary Service 0.1% 29000 1.0% 91000 119000
Secondary Service 3.5% 61000 6.1% 539000 59,000
• Public Authorities 0.3% -0.5% 49000 49000
100.0% $190,000 (3) 100.0% 58751000(4) $1,065.000
(1) Table II-A-2, C-11umn 2
M (2) Table II-A-2, Column 5
3 Table II-8-1, Total of Column 4
(4) Table II-8-1, Total of Column 5
32
TABLE 1I-8-3
1981 CUSTOMER COSTS
MONTHLY
CUSTOMER NUMBER COST BASED
RELATED OF CUSTOMER
COSTS(l) CUSTOMERS(2) CHARGE
Residential A-1 $2379000 41388 54.50
Residential A-2 579,000 10,744 4.49
Commercial 8-1
Single Phase 27,000 507 4.44
Three Phase 1481000 1,522 8.10
Commercial B-2
Primary Service 111000 20 45.83
Secondary Service 591000 621 7.92
Public Authorities 49000 46 7.25
511065,000 17,848
(1) Table 11-8-2, Column 5
(2) Table II-A-2, Column 1
0
33
TABLE II-B-4
• CUSTOMER CLASS ALLOCATION
1981-DEMAND AND ENERGY COSTS
ENERGY OISiRIBUTION
COSTS COSTS CAPACITY COSTS
RrkCL`NTKG7 AMOUNT RC NTAGE 0 PERCENTAGE AM UN
Residential A-1 4.4% $865,000 4.7% $1139000 3.5% 5 20,000
Residential A-2 29.7% 51841,000 31.1% 750,000 35.3% 202,000
Commercial B-1 4.9% 9640000 5.1% 123,000 4.2% 24,000
Commercial B-2
Primary Service 17.8% 31501,000 14.9% 359,000 18.6% 106,000
Secondary Service 38.5% 71572,000 40.2% 969,000 34.9% 199,000
Public Authorities
a Others 3.8% 7479000 4.0% 96,000 3.5% 209000
Street Lighting 0.9% 177,000
100.0% $19,664},000 100.0% $2,650,000 100% S 57,00
(1) Table II-A-3, Column 4
(2) Table II-A-4. Column 4
(3) Table 'i-A-S, Column 7
(4) Table Total of Column 6
5 fable 11-8-19 Total of W umn 3
(6) Table II-8.1, Total of Column 2
1 4
TABLE II-B-5
• 1981 - ENERGY COSTS
ANNUAL COST
ENERGY MWH PER
COSTS 1 SALES 2
B f
Residential A-1 $865,000 22,657 3.821
Residential A-2 598419000 1510625 3.851
Commercial B-1 964,000 25,067 3.851
Commercial B-2
Primary 3,5011000 09,247 3.801
Secondary 795729000 196,024 3.861
Public Authorities
& Others 741,000 19,377 3.861
Street Lighting 177,000 4,844 3,651
® $19,667,000 $511,841
{1) fable II-B-4, Column 2
{2 Ti,ble II-A-3, Column 1.
,5
,a
TABLE II-B-6
• 1981 - CAPACITY COSTS (1)
SUMMER :OST
CAPACITY MWH PER
COSTS (2) SALES KWH
Residential A-1 5 209000 11545 0.27
Residential A ? 202,000 759588 0.214
Commercial 8-1 24,000 81889 0.270
Commercial B-2
Primary Service 1069000 40;404 0.26
Secondary
Service 1999000 74,685 0.27e
Public Authorities 201000 79448 (4) 0.270
E571,O00 210 9559
(1) Consumption for June through September - Excluding Street Lighting
2) Table II-8-4, Column 6
3) Table II-A-5, Column 3
4) 7,848 - 400 (Estimated Ousk To Oawn Summer Consumption)
s
36
TABLE Ii-B-7
• 1981 DISTRIBUTION COSTS
ANNUAL COST
DISTRIBUTION MWH PER
COSTS 1 SALES 2 KWH
{AM
Residential A-1 S 1139000 22,657 0.504
1509000 1519625 0.494
Residential A-2
Commercial B-1 123,000 25,067 0.494
85,000 (3) 4,844 1.754
Street Lighting
ANNUAL
BILLING
DEMAND KW1
Commercial B-2
Primary 359,000 4572029000 J4~ $1.78
S2.12
Secondary 969,000
Public Authorities
• b Others 96200Q 55,000 (6) 51.75
$2,410,000
1 Tab 1e II-B-4, Column 4
2 Table 11-4-3, Column 1 able II-8-1 Column 1
3 Represents 51'1,000 of Directly Asst nable Costs from
4 19110m KW 12 Morths Ended 4/30/80 x 1.06 SGrowth Factor
4319000 KW (12 Months Ended 4/30180 x 1.06 iGrowh~
5
6 X2,000 KW (12 Months Ended 4/JO/80) x 1.06 (Growth Factor)
37
•
TABLE II -C
TIME-OF-DAY COST STUDY
38
TABLE II-C-1
• FUNCTIONAL ALLOCATION - 1981
(000)
DISTRI- STREET
TOTAL CARACITY BUTION CUSTOMER COSTS LIGHTING
COST COSTS COSTS WEIGHTED UNw I H D ENERGY DIRECT
PLANT (1)
Production 5149796 $14,796
Transmission 2,138 2,:s8
Distribution 71961 $7,961
Customer 11156 319156
Street Lighting 493 3493
$269944 37-999 31 3 5'3
100% 63.8% 30.0% 4.3% 1.91
EXPENSES (2)
Plant Related $ 4,313 S 2,752 $1,294 $ 185 S 82
Purchased Power 69092 $6,092
Fuel 99871 9,871
. Other Production 933 933
Transmission &
Distribution 1,046 19046
Customer Accounts
& Sales 84S 849
$23 104 F3968+5 3-M x-189 S -849 515j95'3 3V
160% 15.9% 10.1% 0.8% 3.7% 69.1% 0.4%
Administration &
General 694 110 70 5 26 480 3
219798 3-'39755 Tro M T-M T__W 316, M 3-"r5
(1) Table I-D, Page 1, Column 13
2 Table I-A, Pige 1, Column 1
39
TALE II-C-2
CUSTOMER CLASS ALLOCATION
1981 CUSTOMER COSTS
TOTAL
UNWEIGHTED WEIGHTED CUSTOMER
NT PERCENTAGE COSTS
n-gt N-TAG E 1 A_O~U~
Residential A-1 24.6% $419000 21.7% 31909000 $2379000
Residential A-2 60.2% 1140000 53.1% 465,000 5799000
Commercial 8-1
Single Phase 2.8% 51000 2.5% 22,000 279000
Three Phase 8.5% 16,000 15.1% 132,000 148,000
Commercial 3-2
Primary Service 0.1% 2000 1.0% 91000 119000
Secondary Service 3.5% 60000 6.1% 53,000 59,000
Public Authorities 0.3% 0.5% 4,000 49000
100.0% $190,000 (3) 100.0% $875,000(4) S1,065,000
i
1) Table II-A-2, Column 2
2) Table I1-A-2, Column 5
3 Table 11-C-1, Total of :olumn 4
14) Table II-C-1, Total of Column 5
40
-Ir _7
TABLE iI-C-3
1981 CUSTOMER COSTS
MONTHLY
CUSTOMER NUMBER COST BASED
OF CUSTOMER
RELATED CUSTOMERS 2 CHARGE
COSTS 1 --F BT-
4,388 $4.50
Residential A-1 $237,000
10,744 4.49
Residv tial A-2 5799000
Commercial B-1
507 4.44
Single Phase 270000 10522 8.10
Three Phase 1480000
Commercial 9-2
20 45.83
Primary Service 11,000 621 7.92
Secondary Service 59,000
• 46 7.25
Public Authorities 4,OU0
$1,065,000 17,848
(1) T(,ble II-C-20 Column 5
(2) Table II-A-29 Column 1
41,
7,..___
0 TABLE II-C-4
CUSTOMER CLASS ALLOCATION
19814VEMAND AND ENERGY COSTS
ENERGY DISTRIBUTION
COSTS COSTS CAPACITY COSTS
PERCENTAGE AMOUNT PERCENTAGE AMOUNT ERCEN AGE AMOUNT
Rasidentlal A-1 4.4% $723,000 4.7% $113,000 3.5% $1339000
Resldontial A-2 29.7% 418849000 31.1% 7500000 35.3% 1$40,000
Commercial B-1 4.9% 8069000 5.1% 1239000 4.2% 160,000
Commercial B-2
Primary Service 17.8% 209269000 14.9% 359,000 18.6% 705,000
SQcondary Service 38.5% 6,331,000 40.2% 969,000 34.9% 1,324,000
Public Authorities
b Others 3.8% 6259000 4.0% 96,000 3.5% 133,000
Streit Lighting 0.9% 148,000
100.0% $16,443,000(4) 100.0% 52,410,000(5) 100% $3,795,000(6)
1 Table II-A-3, Column 4
2 Table II-A-4, Column 4
3 Table II-A-51 Column 7
4 Table II-C-11 Total of Column 6
5 Table II-C-11 Total of Columns
(6 Table II-C-1, Total of Column 2
42
TABLE II-C-5
1981 - ENERGY COSTS
ENERGY ANNUAL COST
COSTS SALES {pJ PER
W "J ( Bj--" XWH
Residential A-1 $723,o00 -M 9-
?2,657 3.I9~
Residential A-2 49884,000
151,625 3.22Q
Commercial 8-1 806,000
25,067 3.224
Commercial 8-2
Primary
Secondary 5.331,000 92+247 3.174
Public Authorities 196,024 3.23e
6 Others 6259000
Street Lighting 14,371 3.234
• 148,000
4,844 3.064
$16,443,000 $511,841
(1) Table 11-C-49 Column 2
(1) Table 11-A-39 Column 1.
43
TABLE II-C-6
1981 - CAPACITY COSTS (1)
SUMMER COST
CAPACITY PEAK MWH PER
COSTS 2 SALES(3) KWH
' A) (W+ B
Residential A-1 31339000 31395 3.920
Residential A-2 11340,000 34,015 3.940
Commercial B-1 160,000 49000 4.000
Commercial B-2
Prim.s.ey Service 7051000 18,182 3.880
Secondary
Service 1,324,000 339608 3.940
Public Authorities 133,000 31352 3.970
$3,795,000 961552
(1) Consumption for June through September - Excluding Street Lighting
(2) Table II-C-4, Column 6
(3 Table II-A-5, Column 4
44
TABLE !'I-C-7
e 1981 DISTRIBUTION COSTS
ANNUAL COST
DISTRIBUTION MWH PER
COSTS 1 SALES 2 KWH
(K+-87
Residential A-1 $ 1139000 22;657 0.504
Residential A-2 7509000 151,625 0.500
Commercial B-1 1239000 250067 0.490
Street Lighting 85,000 (3) 41844 1.750
ANNUAL
BILLING
DEMAND KW
Commercial 8-2
Primary 359,GOO 202,000 (4) $1.78
Secondary 9699000 457,000 5 52.12
Public Authorities
b Others 961 OOU 550000 (6) $1.75
$2,495,000
(1) Table II-C-41 Column 4
2) Table II-A-3, Column 1
3) Represents $709000 of Directly Assi nable Costs from Table I[ -C-1, Column 7
4 191,000 KW (12 Months Ended 4/30/80 A 1.06 (Growth Factor)
5 431,000 KW (12 Months Ended 4/30/80 x 1.06 (Growth Factor)
6~ 52,000 KW (12 Months Ended 4/30/80) x 1.06 (Growth Factor)
I
45
• TARIFFS
The analysis of the rate design and regulatory standards promulgated
by the Public Utilities Regulatory Policy Act of 1978 is provided in a
separate report. The methodology used to develop the proposed City of
Denton electric tariffs generally follows the guidelines and rationale
described in this PURPA compliance study. The proposed rate schedules
applicable to residential, commercial, industrial, governmental and dusk-
to-dawn lights are included in Appendix A.
The proposed rates have been designed to collect the overall revenue
requirement of the utility, to r~Wect one cost of service, to reflect the
PURPA objectives of conservation, efficiency and equity and to ensure that
the rate structure aand rate levels in Denton are not drastically different
• than rates offered in the surrounding areas.
In sJdition, the proposed tariffs incorporate our judgments regarding
the ability of the community to respond to the inflation driven increase in
fuel and capacity costs as quickly and efficiently as possible. A
community cannot respond to a sudden massive shift in electric utility
rates, but it can respond to moderate changes in electricity rates. We
observe that the Electric Department is affirmatively responding to the
PURPA requirements coincicent with the need to finance the increase in the
fuel and capacity cos:s• As such, it is quite likely that the City Council
will be requested to approve additional rate adjustments in the next few
I years. we are not able to accurately estimate the sire of these
adJustments. It is highly likely that the increase in the economic
• activity within the Denton r~.m munity will temper the magnitude of the
46
77 777,77
• increases. The need for an annual review of electricity tariffs is an
excellent opportunity for the City Council to consider rate incentives to
promote efficiency, conservation and equity.
An additional consid.:ration is the effect on Denton O ectricity
tariffs resulting from the tariff under which electricity is purchased from
TMPA. This tariff has not been determined to date. Therefore it is not
appropriate to engage in a major restructuring of current tariffs if it is
highly likely that these may require significant change to reflect Denton's
purchases from TMPA. We believe that our proposed tariffs will both
recover the required revenues and provide adequate incentives to promote
conservation, efficiency and equity as required by PURPA.
PURPA requires that seasonal differences in cost be recognized in an
electric utility's rates charged during the different seasons. The Denton
Electric Utility is clearly a summer peaking system and, as such, incurs
additioiial capacity costs only if it adds demand daring the summer peak
period.
Th'r cost of service study indicates that the summer peak energy and
capacity costs are approximately double the off-peak energy costs. Time-
of-day rates reflecting this cost variance should encourage conservation
during the peak period.
Current rates for residential service offer approximately a 0.U lower
rate for winter consumption over 700 KWH for electric hearing. The City
Steering Committee directing the electric rate study believes that the
current discount for electric heating during the winter can be reduced with
the introduction of seasonal rates. We recommend that the period in which
e the winter electric heating discount applies be restricted to only the
47
• winter heating peak period of December through February. We, therefore,
recommend the adoption of a summer/winter rate differential of 0.3e and an
additional 0.24 discount for residential electric heating customers for
consumption over 1000 KWH during December, January and February. This will
enable the Electric Utility to collect a portion of the fixed capacity
costs during the off-peak months, introduce seasonal price signals to all
customers and to con;~inue to offer the electric heating customers a
substantial winter price break.
The sum mer/winter rate differential of 0.3e in our proposed electric
tariffs means that the proposed rates have a combined summer energy and
capacity charge approximately 0.34 higher than the winter energy and
capacity charge. We have also prop id that this summer/winter
differential be extended to all electric customers except for str.:r.t
lighting and dusk to dawn customers that are clearly off-peaK users of
electricity.
Residential Service
The existing rate schedules for Residential A-1 and Residential A-2
Service cannot be supported on any cost basis for the difference in rates.
While the larger residential customers In the Residential A-2 class
typically place n greater load on the utility system, particularly during
the peak summer months, the difference in the cost of service is generally
accounted for in a larger percentage of the Residential A-2 consumption
being billed during the summer peak months. A uniform summer/winter
differential or surcharge applied to summer consumption will generally
provide a better distribution of total costs between the small and large
48
• residential customers. We have, therefore, proposed comparable KW1i charges
for the Residential A-1 and A-2 customer classes.
The PURPA regulations specifically state that a utility is not
prevented from instituting lifeline rates. The decision to implement
lifeline rates is, therefore, strictly subjective and not cost based. The
City should recognize that instituting such rates may cause other customers
to subsidize lifeline customers in order to meet the total revenue
requirement and that the City would have to decide where the subsidies are
to be collected.
The City Steering Committee directing the electric rate study has
indicated a desire to continue a conservation rate similar to the present
A-1 tariff that provides for a lower rate for small residential users that
do not exceed 700 KWH in any summer month. We suggest that a $2.00
reduction in the monthly customer facilities charge will provide a
conservation incentive comparable to the present 'A tariff. The reduction
will have a moderate- effect on total revenues so that no direct subsidy
from other customer classes will be required. It will also result in
smaller residential customers receiving a KWH charge comparable to other
classes of customers which will provide the incentive for conservation.
Commercial Service
Under existing rates, service to commercial and industrial customers
is provided under two rates: Schedule 8-1, applicable to commercial
customers whose monthly demand is less than 20 kilowatts; and Schedule B-2,
applicable to larger customers whose monthly demand exceeds 20 kilowatts.
0 The electric utility management estimates that approximately 75% of
i
49
the small commercial customers receive three phase service while virtually
all residential customers receive single phase service. Three phase
service requires a larger investment in customer meters and meter related
expenses that should be assigned to the three Phase customers. This
variation in the customer related costs can be readily accounted for in a
higher customer facilities charge for three phase customers.
Since most, if not all, commercial accounts are now demand metered, we
suggest that consideration be given to eliminating the 8-1 tariff. The
customers presently on this tariff could be transferred to the B-2
commercial tariff and be charged a direct KW demand charge in the tariff.
An alternative would be to consolidate the small commercial customers with
large residential on a small general service tariff. We prefer the former
recommendation because the rates wold be closer to what these customers are
now paying and because they are all demand metered.
Large commercial customers (B-2) generally have billing demands in
excess of 20 kilowatts and receive three phase service, Approximately
twenty of these customers receive service directly from the primary
distribution system and thus do not cause the utility to incur any
secondary distribution costs. We have, therefore, separated this class
into primary and secondary service in performing the cost study with e
larger portion of the distribution system costs being allocated to
customers receiving secondary service. Since all :he customers in the
I
commercial class are demand metered, we have proposed a lower kilowatt hour
charge with the class distribution costs being collected through a demand
charge applied to a customer's monthly billing demand. The higher
distribution costs associated with secondary service is reflected in a
50
higher demand charge.
Local Government Serflce
The current local government rate is restricted to city, county and
local school districts. The end use of electricity does not determine the
level of costs incurred by the utility. It costs the same amount to
prod~ice electricity for any use depending on the time the electricity is
usec and the voltage level at which the service is provided. We have not
been able to identify any differences in the costs necessary to serve City
i departments, county government and local school districts.
I The City Steering Committee directing the electric rare study has
indicated a desire for a special local government tariff to recognize the
lower operating costs that result from the City Elect,lic Utility's
exemption from local property and school district taxes. The present local
government rate does not include a monthly demand charge.
We suggest that the present local government agency exemption from the
monthly demand charges is the preferred method of developing a special
local government agency rate. The effect of the special rate on total
revenue requirements will not necessarily require any direct subsidies from
other customer classes. All local government agencies would still receive
the same incentive to conserve as other customer classes because of
comparable KWH charges,
Customers such as local school districts which have smaller summer
consumption will still receive the appropriate price incentives through the
application 0 the proposed sum mer/winter differentials. Lower summer
S consumption under rates which include a sum mer/winter differential will
51
Tom;:
result in lower total electric bills than if the same rate were applied
throughout the year.
lighting Service
Service ;provided under this classification consists of sales to the
city for street lights and signal systems, sales to the State Highway
Department for lighting the interstate highway, and rental of dusk-to-dawn
lights. The proposed rates for the various services have been based on
estimated seasonal kilowatt hours priced at a rate comparable to the
residential and small commercial classes. No customer costs have been
assigned to this class to recognize the relatively small costs associated
with meter reading and billing expenses for this service. Approximately
$85,000 of directly assignable plant related costs have been included in
developing the proposed rates for street lighting. A separate energy cost
adjustment is recommended and reflects the average KWH consumption for each
bulb wattage.
Time-of-Use Rates
The PURPA time-of-use (TOU) ratemaking standard requires that the
standard be considered and adopted if the cost benefit test indicates that
it is cost justified. The consideration must address the differences in
fuel related costs incurred to deliver energy at different load levels.
Utilities which meet loads fror, different generating plants (with different
efficiencies and different fuels purchased at a different price per STU)
incur increasing costs as the customers load increases, This assumes that
the plants are economically dispatched so that those plants with the lowest
52
fuel costs are brought on line first. Summer peaking systems similar to
the Denton system generally incur higher fuel related costs in order to
meet the summer peak loads than is incurred during the other times of the
year. Also, during the summer peak the noontime to early evening peak
loads generally cause higher fuel costs to be incurred than during the
nighttime and early morning period. Time-of-use rates are designed to
reflect the significant difference in the cost of delivering electricity at
the different loads which are incurred at different times during the 24
hour period.
Time-of-use rates also reflect the capacity expansion plan which the
I
system incurred in order to deliver electricity during the peak period.
The presence of a system peak requires that the costs be incurred to meet
the peak loads. Since costs were incurred as a result of the peak load
requirements, the customers who are on the system during the peak cause the
costs to be incurred and are, therefore, properly assigned their
proportionate costs. To do otherwise would require other customers to be
charged a higher price in order to cover the difference between the price
charged and cost incurred during the peak period.
PURPA requires that a regulatory agency's consideration of the time-
of-use standard include an analysis of the associated benefits and costs.
The benefits of TOU rates are that customers have a price incentive (the
difference in the peak and off-peak prices) to adjust their energy
consumption pattern which will cause the utility's cost to ho reduced. A
shift from on-peak to off-peak consumption will lower total fuel costs.
Such a shift will lower the peak period capacity requirements which reduces
the future need for funds to be invested in generation, transmission and
53
• distribution facilities. The total costs the utility incurs to meet
customer loads will decrease because customers have adjusted their loads in
response to the price incentives. When total costs are lowered, the
customers' total bills will be reduced,
The short run costs associated with TOU rates are the additional
metering casts. TOU meters are currently available and priced from S65 to
$300 per meter. We have used an estimate of $250 to cover the cost of the
meter and related expenses in developing the proposed TOU rate. The Denton
Electric Department wishes to offer TOU rates to a small number of
voluntary customers prior to considering a mandatory program. As such, the
appropriate point to prepare a cost benefit analysis is after the
customers' load characteristics are obtained in response to TOU rates.
The City of Denton has received an important Innovative Rates Grant
i• from the U.S. Department of Energy to develop a load management program
which is carried by the City's CATV system. Meters installed in
conjunction with this program will permit TOU recordins. It is likely that
the incremental metering cost assigned to TOU rates will be less than $250.
Nevertheless, the $250 cost was used to estimate the customer facility
charge included in the TOU rates.
Time-of-Use Rate Methodology
The methodology used to estimate TOU rates requires access to load and
fuel related production cost data by hours and load level for the 8,160
hours of the year. Also, the marginal cost of generation, transmission and
distribution capacity is required. This load data and the marginal costs
of the generation and transmission system are not now available for the
54
• Denton electric utility.
We have reviewed available data sources and identified that the annual
peak will occur during the months June through September. The data reveals
that the system wil l peak during the weekday hours 12 noon through 9 p.m.
All other hours are defined to be off-peak.
The development of the time-of-use rates assigns the fuel related
costs incurred to deliver electricity to each time period. Distribution
costs are assigned to each KWH taken during the year. All capacity related
costs are assigned to KWH taken during the summer peak hours. We have
increased the monthly minimum customer facility charge to reflect the
increase In meter related costs incurred to serve time-of-use customers.
We further discuss the application of time-of-use in the next section on
cogeneration tariffs.
The revenue requirement collected under time-of-use rates is equal to
the total embedded i:ost of service determined in the cost of servlc3 study.
The proposed TOU rates, if applied to the entire system, would collect the
same total revenues as the traditional tariff structure.
For the KW demand metered customers, an additional non-coincident KW
charge is included in the TOU tariffs. This charge is to collect
separacsly the related non-coincident capacity costs where the billing
determinants are known. Coincident KW loads are not available separately
for each of the traditional rate groups, but then customer groups within a
TOU rate system defines customer classes by time-of-use and losses and not
by the ultimate use of electricity by a customer.
55
r
• Cogeneration Tariffs
We recommend that cogeneration of electricity be defined as broadly as
possible to promote the innovative use of alternative energy sources. As
such, the cogeneration tariff should set out that the City is prepared to
purchase electricity from all sources at any time and in any amount as the
supplier wishes to deliver into the system,
The tariff applicable to cogenerated electricity should be the TOU
tariff wherein the cogenerator must both purchase and sell to the City
under the same schedule. The same tariff schedule avoids the
discrimination issue which may be raised if separate sale and purchase
schedules were offered to the cogenerator.
A relevaiit issue to be addressed in the cogeneration tariff is the
• technical characteristics of the electricity to by delivered to the City's
system and the cost of ensuring that the technical characteristics are met,
Clearly, electricity cannot be fed into the City's system without damage
unless certain conditions are met. We recommend that the cogeneration
tariff set out the technical characteristics which electric service must
meet such as voltage, phase, amperage, etc. It shall be the responsibility
of the cogenerator to meet these conditions. That is, the cogenerator, not
the City, should properly bear the cost of ensuring that the minimum
technical standards are met.
An item associated with meeting the technical characteristics of the
City's system is the necessity for meeting minimum sr.Ifety standards. The
cogenerator shou?G be assigned the responsibility for ensuring that the
interconnection meets the American National Standard Institute National
Electrical Safety Code, 1977, as periodically revised. The cost of meeting
56
. the Code should be the responsibility of the cogenerator.
Interruptible Tariffs
Interruptible tariffs are designed to provide service to large
customers whose consumption patterns permit the supplying utility to
provide service to all or a portion of the customers' load and to interrupt
service on a portion of the load if certain conditions arise. The
advantages to the customer are that his ability to interrupt his load will
reduce the capacity costs or firm purchase power contracts which Denton
would otherwise have to incur. The customer can obtain the power above his
firm power contract on the condition that he pay the full cost incurred by
the Denton Electric Department, The customer controls his load and bears
. the cost consequences.
We recommend that customers taking service under the interruptible
l tariff be charged under the commercial tariff for all firm power
commitments, Purchases in excess of the minimum will be provided under
this same tariff as long as the emergency conditions du not exist and the
customer chooses not to interrupt his service. If interruption is
requested but th3 customer elects not to interrupt, then the applicable
rate should be the commercial tariff for the firm power commitments plus
the cost of emergency power purchased by the Denton Electric Department in
order to meet the customer's load,
jam Cost Ad ustment
The present fuel adjustment clause has an inherent two month tag
between the time fuel costs are incurred until the excess costs are
57
• collected due to the current billing system and the structure of the
adjustment clause. Actual fuel costs for a billing month are usually not
known until the end of the following month. This does not permit the
utility to add the excess fuel costs to a customer's bill until the second
month following the actual consumption which caused the increase in fuel
costs.
We have recommended a modified energy cost adjustment that eliminates
the billing lag for fuel costs and better matches the timing of fuel and
purchased power expenses with the billing of excess energy costs to the
utility's customers.
The basic modification incorporates a charge in the current month's
billing for the estimated excess energy costs. When the actual excess
. energy costs are known, an adjustment to correct any error in the estimate
will be computed and applied to the second billing month following the
estimated adjustment, This will improve the cash flow of the utility by
more closely matching revenues and expenses without increasing or
decreasing the customer's total electric costs.
We have also modified the energy cost adjustment to compute the excess
costs based on energy consumption rather than energy produced or purchased.
Under this method, line losses are not considered in calculating the excess
energy costs. This eliminates the complicated process of converting the
excess energy costs based on energy produced or purchased to an energy
adjustment based on consumption. We believe this later modification will
make the energy cost adjustment easier for customers to understand.
i
58
i
•
APPENDIX A
PROPOSED ELECTRIC TARIFFS
• PROPOSED
ELECTRIC RATE SCHEDULES
Residential Service Rate
Schedule A-1
(1) Net Monthly Rate:
Billing months of June through September:
All kWh @ 44650 per kWh
Billing months of October through May:
All kWh @ 4.350 per kWh
Energy billed during each of the months of December through
February which is in excess of 1000 KWh will be supplied at
4.154 per KWh if the entire home is electrically heated - heat
pump or resistance.
(2) Customer Facility Charge: $2.50 per month
(3) Availability.
Rate Schedule A-1 is applicable to all electric service required
for single family residential purposes where usage is not in
excess of 700 kWh per month during the bi l ling months of June,
July, August, or September. In any such month IF usage exceeds
700 kWh, billing will be rendered that month under Rate Schedule
A-2 and thereafter for a period extending through the 12 billing
months of the next fiscal year ending September 30.
In instances where multiple dwelling units (family or
housekeeping units) are being served through the same meter as of
the effective date of this rate schedule and the kWh in the
billing months of June, July, Aiigust or September exceeds 700 kWh
times the number of dwelling units, the billing for that month
and thereafter will be rendered under Rate Schedule A-2.
(4) Service:
At the utility's available secondary voltage and phase.
(5) Payment:
Billing for service hereunder will be at the net monthly rate,
• payment of which is due when bills are issued. Bills which are
not paid within ten (10) calendar days from the date of issuance
thereof will be considered overdue.
• (b) Energy Cost Ad.iustment:
All charges of the net monthly rate will be increased or
decreased according to the current ener:y adjustment clause.
(7) Special Facilities:
All services which require special facilities in order to meet
the customer's service requirements shall be provided subject to
special facilities rider.
A.2
Residential Service Rate
• Schedule A-2
(1) Net Monthly Rate:
Billing months of June through September:
All kWh @ 4.654 per kWh
Billing months of October through May:
All kWh @ MU per kWh
Energy billed during each of the months of December through
February which is in excess of 1000 KWh will be supplied at 4.154
per KWh if the entire home is electrically heated - heat pump or
resistance.
(2) Customer Facility Charge:
Single Phase @ $4.50 per month
Three Phase @ $8.00 per month
(3) Availability:
• Applicable for single family residential use.
(4) Service,
At the utility's available secondary voltage and phase.
(5) Payment:
Billing for service hereunder will be at the net monthly rate,
payment of which is due when bills are issued. Bills which are
not paid within ten (10) days from the date of issuance thereof
will be considered overdue.
(6) Ener Cost Adlustment_,
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
(7) S e,~ cial- Facilities:
All services which require special facilities in order to meet
the customer's service requirements shall be provided subject to
special facilities rider.
A.3
• Commercial and Industrial Lighting and Power Service Rate
Schedule B
(1) Net Monthly Rate:
Demand Charm
Primary Service: $1.80 per month per kW for all kW of bil ling
demand.
Secondary Service: $2.10 per month per kW for all kW of billing
demand.
Enemy Charge:
Billing months of June through September:
Primary Service: All kWh @ 4.104 per kWh
Secondary Service: All kWh @ 4.154 per kWh
Billing months of October through May:
Primary Service: All kWh @ 3.80¢ per kWh
Secondary Service: All kWh @ 3.854 per kWh
(2) Customer Facility Charge:
Primary Service: @ $46.00 per month
Secondary Service: @ $ 8.00 per month
(3) Avail4bili L'
Available to commercial and indust~ial users except that service
hereunder is not available for resale, breakdown or standby
power.
(2) Billing Oemand:
Equal to the kW load metered during the 15-minute period of
maximum use during the current monthly billing period.
(5) Payment:
Billing for services hereunder will be at the net monthly rate,
payment of which is due when bills are issued. Bills which are
not paid within ten (10) calendar days from the date of issuance
thereof will be considered overdue.
(6) Energy Cost Adjustment:
O All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
A.A
• (7) Power Factor Requirements and Adjustments;_
The utility reserves the right to make tests to determine the
power factor of the user's installation served hereunder during
perinds of maximum demand or by measurement of the average power
factor for the monthly billing period, Should the power factor
so determined be below ninety (90%) percent, the demand for
billing purposes will be determined by multiplying the
uncorrected kW Billing Demand by ninety (90%) percent and
dividing by the determined power factor.
(8) Alternate Primary Service and Discount (Transformation Equipment
wne k the ser :
Primary service will, upon request, be made available to users
with a twelve (12) month average monthly demand of 750 kW or
greater. Primary service will be rendered at one point on the
user's premises at a nominal voltage of 13,200 volts or 69,000
volts three-phase, at the option of the utility.
When the alternate primary service is supplied, the user shall
own, operate and maintain all facilities necessary to receive
primary service and all transformation facilities required for
conversion to utilization voltage. The utility shall own,
operate and maintain all metering facilities (either primary or
• secondary metering at the utility's option).
Where the user owns, operates and maintains the transformation
equipment and where the utility elects to apply its metering
facilities on the high voltage side of such transformation
equipment, the user will be allowed a fifteen (15%) percent
reduction from the monthly Demand Charge.
Where the user owns, operates and maintains the transformation
equipment and where the utility elects to apply its metering
facilities on the low voltage side of such transformation
equipment, the user will be slowed a thirteen (13%) percent
reduction from the monthly Demand Charge; the difference between
fifteen (15%) percent and thirteen (13%) percent being the
allowance for losses in the user's facilities.
(9) 5 ep ciai Facilities:
All servicas which require special facili .ies in order to meet
the customer's service requirements shall bi provided subject to
special facilities rider.
A-5
• Governmental Lighting and Power Service Rate
Schedule G-1
(1) Net Monthly Rate:
Energy Charge:
Billing months of June through September:
All kWh @ 4.150 per kWh
Billing months of October through May:
All kWh @ 3.850 per kWhr
(2) Customer Facility Charge: $7.25 per month
(3) Availability:
Applicable for local government use
(4) Service:
At the utility's, available secondary and primary voltage and
phase
(5) Payment:
Billing for service hereunder will be at the net monthly rate,
payment of which is due when bills are issued. Bills which are
not paid within ten (10) calendar days from the date of issuance
thereof will be considered over6ue.
(6) Energy Cost Adjustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
(7) Special Facilities:
All service which requires special facilities in order to meet
the customer's service requirements shall be provided subject to
special facilities rider.
•
A-6
Dusk-to-Dawn Lighting
(1) Net Monti Rate:
100 watt Sodium Vapor Lamp @ $6.75
175 watt Mercury Vapor Lamp @ $5.00
250 watt Mercury Vapor Lamp* @ $7.00
400 watt Mercury Vapor Lamp @ $10.00
* No new or additional 250 watt lamps will be installed after the
effective date of this schedule.
Where necessary for proper illumination or where existing poles
are inadequate the city will install or cause to be installed one
(1) poll for each installed light, at a distance not to exceed
eighty (801) feet from said existing lines, at no charge to the
customer. Each additional pole span shall not exceed a span
spacing of one hundred (1001) feet. Additional poles required to
install a light in a customer's specifically desired location,
and not having a light installed on same, shall bear the cost.
(2) Availability:
To any customer within the area served by the city's electric
distribution system for outdoor area lighting when such lighting
. facilities are operated as an extension of the city's
distribution system.
(3) Service:
The city shall furnish, install, maintain and deliver electric
service to automatically controlled, mercury vapor lighting
fixtures conforming to the utility's standards and subject to its
published rules and regulations.
(4) Payment:
Billing for service hereunder will be at the monthly rate,
payment of which is due when bills are issued. Bills which are
not paid within ten (10) calendar days from the date of issuance
thereof will be considered overdue.
(5) Enerav Cost Adjustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
(6) Term of Contract:
A two (2) year contract shall be agreed to and signed by each
• customer desiring Dusk-to-Dawn Lighting Service autorizing fixed
monthly charges to be applied to the monthly municipal utilities
bill, In the event that a customer desires the removal of the
unit or discontinuance of the service prior to completion of two
years, service shall continue on a month to month basis and may
• be cancelled by either party upon thirty (30) days notice.
(7) Special Facilities:
All service which requires special faci 1 ities in order to meet
the customer's service requirements shall be provided subject to
special facilities rider.
r
Time-of-Use Rates - General Service, Secondary
Schedule S-1
(1) Net Monthly Rate:
Demand Charge:
$2.10 per month per kW for all kW of Billing Demand
Energy Charge:
Billing months of June through September:
12 Noon through 9 P.M. @ 7.204 per kWh
9 P.M. through 12 Noon @ 3.204 per kWh
Billing months of October through May:
All kWh @ 3.20Q per kWh
(2) Customer Facilit Charge:
Single Phase @ $7.50 per month
Three Phase @ $12.00 per month
• (3) Availability:
Rate Schedule S-2 is applicable to approved electric service
required for secondary distribution service at voltage levels not
to exceed 480 volts.
(4) Billing Demand:
The kW load metered during the 15-minute period of maximum use
during the current month's peak billing periods from 12 Noon
through 9 P.M.
(5) Service:
At the utllity't available secondary voltage and phase.
(6) Payment:
Billing for service hereunder will be at the net monthly rate,
payment r,' which 1s due when the bills are received. Bills which
arp r;,t paid within ten (10) calendar days from the date of
issuance thereof will be considered overdue.
(7) Ener Cost Adjustment:
. All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
(8) Special Facilities:
A-
• the customer's service requirements shall be provided subject to
special facilities rider.
A-10
Time-of-Use Rates - General Service, Primary
Schedule P-1
(1) Net Monthly Rate:
Demand Charge:
$1.80 per month per kW for all kW of billing demand
Energy Charge:
Billing months of June through September:
12 Noon through 9 P.M. @ 7.050 per kWh
9 P.M. through 12 Noon @ 3.150 per kWh
Billing months of October through May:
All kWh @ 3.150 per kWh
(2) Customer Facilities Charge: $60.00 per month
(3) Availabilit :
• Rate Schedule P-1 is applicable to approved electric service
required for primary distribution service at voltage levels not
to exceed 69,000 volts and billing demand equel to or greater
than 20 kW.
(4) Billing Demand:
The kW load metered during the 15-minute period of maximum use
during the current month's peak billing periods from 12 Noon
through 9 P.M.
(5) Service:
At the utility's available secondary voltage and phase.
(6) Payment:
i
Billing for service hereunder will be at the net monthly rate,
payment of which is due when the bills are received. Bills which
are not paid within ten (10) calendar days from the date of
issuance thereof will be considered overdue.
(7) Energy Cost AdJustment:
All charges of the net monthly rate will be increased or
. decreased according to the current energy adjustment cleuse.
(8) Special Facilities:
All service which requires special facilities in order to meet
the customer's service requirements shall be provided subject to
a_ti
Interruptible Service Rate (primary service for a firm power load
exceeding 5,000 KYA in June, June, July or August)
(1) Net Monthly Rate for Firm Power:
Demand Charge:
$1.80 per month per kW for all kW of billing demand
Energy Charge:
Billing months of June through September:
All kWh @ 4.10 per kWh
Billing months of October through May:
All kWh @ 3.80 per kWh
(2) Net Monthly Rate for Interruptible Load:
When the Electric Department requests a customer to interrupt
load and the customer elects not to Interrupt his load then the
following rates shall apply for all kW and kWh the Electric
Department requests to be interrupted:
Demand Charge:
The actual cost of al l kW purchased by the Electric Department
necessary to service the customer's load adjusted for losses.
Energy Charger
The actual cost of all kWh purchased by the Electric Department
necessary to serve the customer's load adjusted for losses.
(3) Customer Facility Charge:
$46.00 per month
(4) Availability
Available for all customers taking primary servic.;, at a firm
power load exceeding 5,000 KYA during the months of June, June,
July and August.
(5) Billing Demand:
The kW load metered during the 15-minute period of maximum use
e during the current monthly billing period.
(6) Conditions of Interruption:
The Electric Department shall notify the customer by telephone at
least thirty (30) minutes prior to the time at which the load Is
• required to be curtailed. The request shall b-) for all or part
of the customer load exceeding 5,000 KVA. The maximum period of
interruption shall be for six hours. The interruption shall be
at the request of the Electric Department during periods when a
potential forced outage could deny power to other customers or
when available spinning reserves are threatened. The customer
shall respond by stating he will or will not comply with the
Electric Department's request within fifteen (15) minutes after
notification.
(7) Payment:
Billing for service hereunder will be at the net monthly rate,
payment of which is due when the bills are received. Bills which
are not paid within ten (10) calendar days from the date of
issuance thereof will be considered overdue.
(B) Energy Cost Ad ustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
S ecial Facilities:
All service which requires special facilities in order to meet
i the customer's service requirements shall be provided subject to
special facilities rider.
• Energy Cost Adjustment
All monthly kWh charges shall be increased or decreased by an
amount equal to "x" cents per kWh.
The energy cost adjustment applicable to the monthly dusk-to-dawn
lighting charge shall be the amount equal to "x" cents multiplied
by following factor corresponding to the bulb wattage.
Bulb Wattage Factor
100 45
175 74
250 104
400 162
a d + e
9-- _0.03
..x.4 c c --r- ' .f
a - Estimated next month's cost of fuel used in the utility's electric
generating plants
b - Estimated next month's cost of purchased energy
c - Estimated next month's kWh sales
• d - Estimated cost of fuel two months previous used in the utility's
electric generating plants
e - Estimated cost of purchased power two months previous
f - Estimated kWh sales two months previous
g - Actual cost of fuel two months previous used in the utility's
electric generating plants
h - Actual cost of purchased energy two months previous
,j - Actual kWh sales two months previous
Notes:
1. Elements a, b, d, e, g and h exclude costs associated with sales
to non-Oenton Electric Oepartment jurisdictional customers.
2. Elements c, f and exclude kW sales to non-Denton Electric
Oepartment jurisdictional custome s.
• 3. Elements b, a and h exclude demand charges included in purchased
power costs and rental charges for facilities.
A,JA
. Special Facilities Rider
(1) Applicability:
All service shall be offered from available facilities. If a
customer service characteristic requires facilities and devices
which are not normally and readily available at the location at
which the customer requests service, then the Electric Department
shall provide the service subject to paragraph 2 of this
schedule.
(2) The total cost of all facilities required to meet the customer's
load characteristics which are incurred by the Electric
Department shall be subject to a special contract entered into
between the Electric Department and the customer. This contract
shall be signed by both parties prior to the Electric Department
providing service to the >:ustomer.
A-it
APPENDIX B
COMPARATIVE ELECTRIC COSTS
RESIDENTIAL - SUMMER
•
"160
Texas Power and Light
City of Denton
Community Public Service Co
$120 Denton County Electric Coop
80
$40
s20
,10
500 KWtt 1000 KWh 2000 KWh 3000 KWh
B•1
0 RESIDENTIAL - WINTER
SPACE HEATING
$160
$120
Denton County Electric Coop
' Community Public Service Co
0 City of Denton
Texas Power and Light
$ 80
$ 40
$ 20
~0
500 KWh 1000 KWh 2000 KWh 3000 KWh
9-2
GENERAL SERVICE - SUMMER
401 LOAD FACTOR
1, 600
Texas Power and Light
City of Denton--
$1,200 Community Public Service Co
Denton County Electric Coop
0
800
$ 400
200
L 4000
50000 KWh 15,000 KWh 25,000 KWh 35 000
B.3 ~Kwh
i
I
GENERAL SERVICE - WINTER
• 40% LOAD FACTOR
1,600
Texas Power and Light
Denton County Coop
$1,200 Community Public Service Co
City of Denton
0
800
$ 400
$ 200
$ 40 0
50000 KWh 15,000 KWn 25,000 KWh 350000
8.4 KWh
e
APPENDIX C
BILLING AND COLLECTION POLICIES
0
•
PROPOSED
BILLING & COLLECTION FOR SERVICES
SECTION I.
(1) That Chapter 25 "Utilities% Article I, Section 25-4 is hereby
amended to read as follows:
"Section 25-4. Service Deposits
(a) No service deposit will be required if the customer
requesting water and/or electric service can provide or meet
one of the following conditions:
(1) A record of prompt payment for the past twelve months
with the City of Denton Utility System or another
electric utility system.
(2) A co-signer who has a good credit rating with the City
of Denton Utility System or another electric utility
system and will guarantee payment of the utility
statement.
(b) If one of the conditions in (a) cannot be met, then he
customer requesting water and/or electric service will be
required to deposit an amount equal to 1/6 of the last 12
months billing at the location where service 1s requested.
If no previous history is available for the location, a
representative similar type facility will be used to
establish the amount of the deposits. In the case of
commercial or industrial service, if the credit of a
customer for service has not been established satisfactorily
to the utility, the applicant may be required to make a
deposit or, in the case of new corporate &cco!jnt, a personal
guarantee may be accepted in lieu of a dep.5it. Deposits
will be refunded after a prompt payment record has been
established over the past 12 months.
Interest on deposits shall be paid at an annual rate at
least equal to six percent (6%). If refund of deposit is
made within thirty (30) days of receipt of deposit, no
interest will be paid. If the deposit is retained more than
thirty (30) days, payment of interest shall be retroactive
to the date of deposit. The deposit shall cease to draw
interest on the date it is returned or credited to the
customer's account. Payment of the interest to the customer
shall be annually, or at the time the deposit is returned or
credited to the customer's account.
(c) After making application for service, the customer service
department may have to pursue a credit reference check. The
customer will be given service promptly after application,
C-1
but if the credit check proves negative, the customer will
be required to produce a co-signer or place a deposit.
Failure to do so will result n the discontinuance of
service with no less than two days of notification to the
prospective customer by the customer service department,
(d) A connection fee of $10.00 will be charged to new customers
requesting water and/or electric service and a transfer fee
of $10.00 will be charged existing customers for
transferring from one location to another.
(e) If water and/or electric utility service is disconnected for
non-payment, then the customer will be required to pay a
$20.00 reconnect fee and maintain a deposit sum equal to 1/6
of the last 12 months billing at the location where service
is requested."
(2) That Chapter 25 "Utilities", Article 1, Section 25-6 is hereby
amended to read as follows:
(a) Payment of Statements. The due date for the payment of the
utility statement will be no less than fifteen (15) days
from the date of the utility statement. Payment must be
received in the City of Oenton's Cashier Office by close of
business on the due date regardless of the postmarked date
in order to avoid assessment of a penalty. Payments placed
in the mail and showing a postmark on due date will not be
considered as being received on the due date.
(b) Oiscontinuance of Service for Non-Payment of Statement.
Each customer of the City's utility system will be rated "A"
or "B" at the time their current utility statement is
prepared. A customer with no outstanding past due balance
will be rated "A", and a customer with an outstanding past
due balance will be rated "B".
(1) A customer with an "A" rating will not be disconnected
if his account is not paid in full by the clue date.
(2) A customer with a "B" rating may be disconnected if his
account is not paid in full by the due date.
(c) Notice of Termination for Customers With a "B" Rating. A
customer with a 118" rating will be notified on his current
utility statement that his service will be disconnected the
day after the present due date if payment for the past and
present, statements is not received by the due date. A
residential customer will be errmitted to designate a
co~nsen-~t Dj individual which shall also receive a cow ofa1T
notices of d scontTnun"`5`vee-n T~ xR{_1__i_ty to` e
• customer. -"T~~ce will in a~ rm tt-ie rustomeer-t~iat'~'e s e
should contact the customer service department of the City
of Oenton within the fifteen (15) day period and prior to
disconnection of utility service to present any evidence or
argument concerning the statement or amount of utility
C•2
. service provided by the City,
ustoms If full payment has not been
made approwxi mllatelagya Ifni vbee ( 5) days prior to the due date the
c
notified by mail of possible
termination and his alternatives.
(d) Alternatives to termination of Utility Service. A customer
with a "811 rating may avoid termination of utility service
by doing one of the following:
(1) Paying the total amount due.
(2) Arranging with the Customer Service Department for a
deferred payment agreement that would require payment
of at least fifty (50X) percent of the remaining amount
in not more than six (6) equal monthly payments.
(3) If the customer is unable to meet these conditions or
if he/she has defaulted on a deferred agreement, he/she
will bereferred to a "Utility Account Review
Committee" for further action. This Committee will be
composed of the City Manager, City Attorney, Finance
Director and Utility Director or their designated
representative if they are unable to attend a meeting,
The Utility Account Review Committee is authorized to
develop a deferred payment agreement beyond the six (b
month period but could not extend beyond twelve (12)
months. Neither the Customer Service Department nor
the Utility Account Review Committee will have the
authority to waive all or any portion of the utility
statement owing to the City except when an error in
billing has occurred.
Any account that is delinquent will be referred to the
City Attorney for collection, and appropriate reports
regarding the account's credit rating w111 be
processed.
(a) Certain Adjustments Prohibited. No adjustment will be made
in any monthly bill because of any water or electric leak or
loss.
No allowance shall be made on utility bills by reason of use
of less service than the quantity set as the basis for the
minimum charge.
(f) Separate Meters Required. Each customer maintaining a
separate residence, eit er house or apartment shall have a
separate water meter (NAND ELECTRIC METER) and a separate
service connection to the city sewer lfnes; rovdedo
however, that multiple dwellings con aining less p hanifive
• (5) units may be served by one water (AND ONE ELECTRIC METER)
and one sewer service connection and will be billed under
the residential multiple block rate. Multiple dwellings
containing five (5) or more units which do not have separate
metering 4nd service facilities shall be classified as
C•3 - '
.~S
I
~er 1; a~
commercial buildin s for utility purposes and shall be
billed under the applicable commercial rates for water and
sewer service.
Each residential and commercial unit in a _m_u__t~i lie occupancy
KlTd ng an eac mobile home union a mobile Time- par , n
A~C~ 3111ci8~ which construnon of the building or a, was be un ter
i _ will ave an ~lnddivTdua meTer to measure
~iQGfriC. e consumaf{on an3eman commerciaTand~industr a
customers attributab•Te to ch unit, except o r tie
following;
ja For transient multi le occu anc buildin s and
trans en m om
o a e ar s nc u n ' u ro mfled p. i
to hots s motels dorm for es rooming houses
Dios ita s nur~s~n~ homes, an mo 1e home arks or
trave tra Ters.
L21 For commercial unit sface_ which is subject to
&Iterat~fio-with change n eriants as ev ence
emorar asefist ni uisTied~ro`p~m~an'ent _ pe o gad
bearing wall an floor construct n separating the
commerciaTunlt s aces.
Where electricity is utilized in connection with
central heating, ventfTat~n'g anTair con t onlna
s s ems.
In common buildin areas such as hallwa s elevators.
r`ece ETon areas an wa er um in at' s_~---
(g) Notice on Moving Required. Any customer or prospective
customer of the City of Denton Utility System moving into or
out of a building where electric, water or sewer service is
or will be provided shall give a minimum of twenty-four (24)
hours notice to the Customer Service Department prior to the
proposed date of connection or disconnection of said
utility,
C-4
CITY OF DENTON, TEXAS
PURPA COMPLIANCE MANUAL
BY
MANAGEMENT AND RESEARCH CONSULTANTS, INC,
DECEMBER 12,* 1980
M
Group
MARC A Professional Consulting Group
• MANAGEMENT AND RESEARCH CONSULTANTS, INC, 225 S Meromec, Suite 1U5
John C Pickett. Ph D ClaytOn, Missouri 83103
Fred MOriarty, C P.A (314) 725-8783
Rkhard P, Anthony
December 12, 1980
City of Denton
C/0 Mr. R. E. Nelson
Director of Utilities
Municipal Building
Denton, Texas 76201
The City of Denton engaged Management And Research Consultants, Inc.
(MARL) in May, 1980 to develop a PURPA Compliance Manual and to perform an
Electric Rate Study. The enclosed PURPA Compliance Manual completes our
review of the Public Utilities Regulatory Policy Act of 1978 and presents
our conclusions and recommendations concerning the current status and
compliance of electric rates and policies in Denton to the guidelines
presented in PURPA.
A sumnary of all the PURPA issues and our recommendations on each
issue is provided in.the Management Summary section of the report. We also
present a brief implementation plan in this section which addresses the
need for a public hearing and the expansion of the City's current electric
utility informational requirements.
We commend the City of Denton and the management of its electric
utility on its initiative to address the requirements of PURPA even before
the City becomes covered by the Act. We also }hank the Steering Committee
and the Flectric Department for, their patience and cooperation during the
study.
Very truly yours,
Fred Moriarty
President
FJMtsh
•
CITY OF DENTON, TEXAS
PURPA COMPLIANCE MANUAL
BY
MANAGEMENT AND RESEh CH CONSULTANTS, INC$
DECEMBER 12, 1980
0
CITY OF DENTON
• PURPA COMPLIANCE MANUAL
INDEX
Page
I. INTRODUCTION 3
II. MANAGEMENT SUMMARY 5
III, CRITERIA FOR EVALUATING PURPA STANDARDS 11
A. Background 11
B. The Criteria 12
C. Conclusion 15
IV. APPLICATION OF EVALUATION CRITERIA TO CURRENT 16
TARIFFS AND POLICY
A. General Discussion 16
B. Cost of Service 17
C. Declining Block Rates 19
D. Time of Day Rates 21
E. Seasonal Rates 23
F. Interruptible Rates 26
G. Load Management Techniques 26
H. Master Metering 29
I. Automatic Adjustment Clause 32
3. Information to Electric Consumers 34
K. Uniform Service Disconnection Rules 36
L. Advertising 38
1
M. Lifeline Rates 39
A N. Informational Requirements 40
•
2
• I. INTRODUCTION
The Public Utilities Regulatory Policies Act of 1978 (PURPA)
requires that state regulatory authorities and nonregulated
utilities, within two years after the enactment of the
leg[slatiin, provide public notice, conduct a hearing and decide
whether to adopt the regulatory policies standards established in
Title I Sections 1110), li3(b) and 114 of the Act. Section 111
establishes the ratemaking standards regarding cost of service,
declining block rates, time-of-day rates, seasonal rates,
interruptible rates and load management techniques. Master
metering, automatic adjustment clauses, information to consumers,
procedures for termination of electric service and advertising
are the regulatory standards established for electric utilities
in Section 113. Section 114 addresses lifeline rates. The Act
applies to each electric utility with total sales of electric
energy by such utility for purposes other than resale exceeded
500 million kilowatt-hours during any calendar ear
after December 31, 1975, and before the immediately beginning
calendar year. Although the City of Denton will not likely ecome
ender the mandatory requirements of PURPA until 1982, the City
his appropriately taken the initiative to comply with the spirit
of the PURPA and national energy policy.
The PURPA requires that each nonregulated utility must
consider each standard and make a determination concerning
whether or not it is appropriate to implement the standard to
carry out the purposes of this title. Nothing in the Act
prohibits any nonregulated utility from making any determination
that it is not appropriate to implement any such standard.
The City's consideration of the regulatory standards must be
made after public notice and hearing. The findings and
determination of the appropriateness of each standard must be
based upon evidence presented at the hearing,
written document and made available to the b provided in a
li Except for
these requirements and other PURPA rules regardin
gc.inte vention,
the consideration and determination shall be those established by
the City. The City may, to the extent consistent with applicable
City law, implement or decline to implement any standard. If it
declines to implement any standard, it must state its reasons in
writing.
The purpose of this report is to provide a description of
the regulatory evaluation criteria developed by Management And
Research Consultants, Inc. (MARC) to analyze the PURPA ratemaking
and regulatory standards, our conclusions regarding the
appropriateness of each standard and recommendations regarding
the form of the standards.
• standards have been designed T to study ssureap compliance withothe
standards set forth in PURPA.
3
i
• The report consists of three major sections. The next
section summarizes our conclusions regarding each of the PURPA
ratemaking and regulatory standards and the major recommendations
regarding the preferred scope and content of each standard.
Section III provides a discussion of the evaluation criteria
utilized to determine if the proposed regulatory standards will
achieve the stated objectives of. PURPA.
Section IV presents a detailed analysis of the standards
proposed for the City of Denton including our application of the
evaluation criteria and a specific recommendation on each
standard.
4
rl. MAyAGFMENT SUMMARY
• Title I of the PURPA defines "just and reasonable" as a
result which achieves the PURPA objectives of conservation,
efficiency and equity. it has a direct effect on the traditional
concepts of regulation and will consequently change the focus of
future regulatory and rate policies. More emphasis should be
placed on utility rates and regulatory policies that are
necessary to provide timely price signals to consumers and
encourage reduced energy consumption and the purchase of energy-
saving devices such as insulation, storm doors and storm windows.
Other probc'')lP changes will occur in utility operations and City
policies to encourage conservation of scarce resources and
maximum utilization of the more efficient utility generating
equipment.
The relationship of the standards to each other and to the
purposes of PURPA is consistent and mutually reinforcing. For
example, end-use conservaticn of energy supplied by a typical
olectric utility ought to result when the electric rates reflect,
to the maximum extent practical, the cost consequences imposed on
the utility by a consumer's decision to use or, alternatively,
conserve electricity. Rates which reflect these consequences,
expressed in terms of costs, provide consumers with the
Information they need to determine whether they wish to conserve
or consume. Similarly, two of the regulatory standards should
encourage end-use conservation. The information to Electric
Consumers Standard should heighten consumer understand!ng of
rates and the extent to which end-use conservation measures
reduce electricity hills. The Master Metering Standard would
confront the consumer who actually makes usage decisions with the
cost consequences of those decisions.
The second purpose, efficient use by utilities of their
facilities and resources, relates to minimizing the total costs
of meeting "efficient" demand patterns. Here again, attainment
of the purpose would generally imply electric rates that reflect
the utility cost consequences of consumer decisions. Such rate
structures should influence the demand patterns of the utility
customers in ways which encourage the utility to he as efficient
as possible in supplying electricity. The Automatic Adjustment
Clause Standard should directly encourage util'.ty efficiency in
the production of power by requiring that any procedure
permitting automatic pass-through of costs provida incentives to
the utility to reduce its cost of production.
The third purpose, equitable rates to consumers, also
implies a policy of charging each individual or class of
consumers a rate which reflects the cost consequences of their
decisions to use or consume electricity. Equitable rates would
• treat each consumer according to a single criterion: aach user,
5
large or small, should only pay for the costs incurred by the
utility as a consequence of that user's decision to consume or
conserve electricity. We believe, therefore, that the overall
structure of the standards and purposes is cohesive. We concur
with the City of Denton's attempt to implement the standards
prior to the time when the City will achieve the minimum PURPA
consumption requirements and believe them to be supportive of
national energy policy.
Cost of Service Standard: The PURPA goals of efficiency,
conservation, and equity clearly imply a measure of marginal cost
to use in the determination of the rate design standards. Data
limitations exist for Denton that require estimation, rather than
calculation, of marginal costs. We recommend that Denton adopt
this standard, estimate marginal costs, and begin collecting the
necessary data to actually calculate marginal costs in future
years.
The Cost of Service section of the Rate Study report will
provide a reasonable estimate of the current embedded cost of
providing electric service to present customer classes. While
the wording of PURPA implies marginal costs as the appropriate
measure of.costs, it doen allow accounting costs as a practical
alternative. While we recommend marginal costs as the ultimate
e measure for the City of Denton, we believe the embedded
accounting cost study included in the Rate Study report will
comply with tho PURPA cost of service standard.
Declining Block Rates: The PURPA specifically requires that
declining block recovery of energy related costs must be shown to
fol)ow declining cost patterns to be acceptable. However, it is
virtually impossible for systems that economically dispatch to
experience declining energy costs although individual customers
may fit the pattern. Data is not available to prove that this
pattern does exist for any specific group of customers. In
addition, the potential need for such rates is eliminated if
time-of-use rates are instituted. We recommend that the City, at
a minimum, adopt a flat energy charge in its rates and eliminate
all declining block energy charges.
The rates proposed in the Rates Section of this report
incorporate flat demand charges as well as flat energy charges.
Energy charges are proposed to be collected on a flat kilowatt
hour basis adjusted through the fuel adjustment clauses for
changes in fuel costs. Demand charges are proposed for large
commercial customers based on a flat kilowatt charge. Demand
charges for all other customer classes which generally do not
have demand meters are proposed to be recovered as part of the
flat KWH charge.
• Time of Day TODD Rates: TOD rates are clearly the best
alternative-for and meeting the objectives of
b
PURPA. As soon as estimates of marginal costs are available, the
City can design and implement actual TOD rates. This will allow
the collection of the information necessary to analyze custom<ir
impact and to do a cost/benefit analysis. This will also provide
more accurate data for periodically assessing the rates if they
are adopted. In addition, a cost/benefit analysis of the most
effective method and timetable for TOD rate implementation can be
identified.
The major constraint to incorporating time-of-day rates on a
broad scale is the cost of mitering customer loads throughout the
day. The most reliable technology available for time-of-day
metering is through the use of broadband cable ;cable TV). While
it may be difficult to cost justify a broadband cable system
dedicated to automated meter reading, the cost of one or two
channels of an existing cable system will be much more cost
effective. We recommend that the TOD rates be incorporated over
the next two to three years in conjunction with the development
of broadband cable energy systems in the City of Denton.
Seasonal Rates: PURPA requires' that rates charged by an
electric utif3ty for providing electric service to each class of
electric consumers be on a seasonal basis which reflects the
costs of providing service to such class of consumers at
• different seasons of the year to the extent that such costs vary
seasonally.
The current City tariffs reflect seasonal differentials but
only for residential customers with electric heat. Since the
time during which electricity is used and the voltage level at
which it is received determines the cost to generate the
electricity, we recommend that cost based seasonal rates be
extended to all customer classes. We also recommend that the
summer period be shortened to four months (June through
September) from the present six months to reflect the shorter
period of time in which seasonal patterns are apparent.
Interruptible Rates: PURPA requires electric utilities to
provide interruptibble rates to commercial and industrial
customers. We recommend that the City of Denton provide these
interruptible rates and that the credits for such rates be based
on the savings the system experiences due to its increased
reliability. While the initial credits will have to be based on
estimates, the City should continually monitor the effect of
interruptible customers on system reliability and adjust
interruptible rates accordingly.
Load Management Techniques: PURPA requires that load
control be adopted i cost elective. Each potential load for
control must be evaluated separately since costs and benefits
vary. We recommend that air conditioi:ing and pumping loads be
examined as potential controlled loads.
7
• The two-way communication capabilities of broadband cable
make it a relatively efficient method of incorporating load
management with or without automated meter reading. The
downstream channels installed for cable television generally
contain adequate amplifiers necessary for electric load
management. inexpensive switches can be installed on
transformers or on individual customer premises to allow the
utility to directly control selected electric loads. The City
should study the cost and benefits of incorporating load
management techniques for air conditioning customers through the
use of broadband cable.
Master Metering. Adoption of the Master Metering standard
is recommended because consumers in the individual units of
master metered buildings do not directly pay the electric bill
and thus receive little incentive via a direct price signal to
conserve electricity. The criteria of economic equity requires j
that costs caused by one consumer not be assigned to another
consumer which is exactly what does occur with master metering.
Over the long run, the increased energy consumption resulting
from master metering will result in an inefficient allocation of
capital resources.
A review of some studies of individual metering of multiple
• unit residential buildings in other parts of the country showed
reductions in electric consumption in excess of 309 with
individual metering. Considering the current average energy
costs of approximately 3.00 and the current customer cost of
approximately $4.30 for small customers, a 30% reduction in
consumption (140 kilowatt hours) with individual electric
metering would be cost justified for consumers in multiple unit
buildings with a monthly average electric consumption of 500 KWH
or above. If a `nigher percentage reduction is realized or a
higher energy charge is incurred in the future, the KWH breakeven
point to cost justify individual metering would be lower.
Automatic Adjustment Clause. We recommend the City defer a
decision on the Automatic Adjustment Clause standard and continue
with its present clause or a smiliar version until the transition
to TMPA is substantially complete. At that time, another
restructuring of rates should be considered and a public hearing
held for the purpose of reviewing the current clause to be sure
that incentives for utility efficiency are provided in the
structure of the clause. Electric rates and the fuel clause
should also be analyzed at that time to assure consistency with
and appropriateness of the rate design for purchases from TMPA.
For now, we recommend that the City adjust base rates to
reflect the current cost of fuel and that the base fuel cost in
the fuel adjustment clause be adjusted accordingly. This is also
a good opportunity to modify the specifics of the clause to
8
• remove the effects of billing lag.
Information to Electric Consumers. The ability of electric
consumers to make rational decisions regarding the use of
electric energy depends on the information available. A general
information form the electric utility has used in the past cost
only $59 per 10000 forms printed. The cost per customer,
therefore, to provide the information required by the proposed
standard will be insignificant. Any customer which becomes aware
of the relationship between energy consumption and cost can
easily reduce his consumption to offset his portion of the
incremental cost of providirig the required information. We, ~
therefore, recommend that the proposed standard be adopted and
the electric utility provide all customers with a summary of
rates at least once a year. A copy of the summary should also be
given to all new customers who apply for electric service. An
updated summary of proposed new rates should also be mailed to
all customers at least thirty days prior to a public hearing on
such rates.
Uniform Service Disconnection' Rules. This standard has been
specifically exemptedrom the RA-objectives of conservation,
efficiency and equity. The critical social criteria that this
standard appears to fulfill is that it provides a uniform policy
for customers, recognizes electric service as a basic necessity
(S to health and life, and provides special consideration4 for
certain disadvantaged groups. We have, therefore, not attempted
to evaluate the costs of implementation for this standard and
recommend adoption of the proposed standard. We believe that our
recommendations provide a proper balance between the
responsibilities of the utility and the consumer.
Pdvertising. The Conference Report stressed that the
standard on advertising prohibits recovery of expenditures for
promotional or political advertising from anyone "other than the
shareholders (or other owners)" of the utility. The earlier
House bill had prohibited recovery from the electric c^nsumers
through electricity rates. We recommend the proposed House
version of the standard be adopted to prohibit promotional. or
political advertising in the rates of the electric utility.
Lifeline Rates: The PURPA exempts lifeline rates standard
from e hterrTa discussed for the other standards and basically
leaves the decision to implement them to the City. We recommend
that the City examine the coat impacts on its current A-1
customers that are to be created by our recommended rates and
then determine whether lifeline rates are needed.
Informational Requirements: The PURPA informational
requirements will have a dramatic effect on the reporting and
record keeping procedures of electric utilities. While many
utilities may be required to expand the amount of accounting
9
• information, particularly as it relates to time-of-use and
marginal cost factors, the area of greatest change will occur in
the quantity and quality of plant operating data and customer
load characteristics.
Title I, Section 133 of PURPA requires each covered electric
utility to file biennial information with the Federal Energy
Regulatory Commission (FERC) and to make such information
available to the public in a form and manner prescribed by the
available to the public whenever the utility requests a rthe ate
increase.
In response to the PU RPA regul onstthe ioFERC has issued
n and reporting
regulations and procedures governing the
service. These associated regulations with the electric
of information review.
Implementation Plan: We propose the following activities to
the CTUy `of' Denton in order to complete its PURPA evaluation and
to incorporate electric rates and policies consistent with its
finding's relative to the PURPA.
Schedule it public nsultants'
1. hearing co
recommendations and proposed revenues rate design
and regulatory policies.
2. Provide a summary to pthe roposed rates to all electric
customers 30 days prior
3. hInvi,te earing and provide access ato consultants report to intervene in the public
intervenors.
4. Conduct a public hearing and prepare a public record of
all evidence submitted during the hearings.
5. on Review
the PURPA standards randrappropriate a elfinal ectric rates
and tariffs.
b. Incorporate the FERC informational requirements into the
electric utility's accounting and customer information
system requirements to ensure future compliance with the
FERC.
7. Begin customer load sampling, marginal costing and time-
the cable
of-day
and Innovative utilizing Rates
electric system rate
television grant obtained
. from the Department of Energy.
10
• III. CRITERIA FOR EVALUATING PURPA STANDARDS
A~ Background
In 1978, Congress passed the Public Utility Regulatory
Policies Act (PURPA), Title I which establishes federal
ratemaking and regulatory standards, lifeline rate guidelines,
and cost-of-service data requirements. The federal ratemaking
standards address cost of service, load management techniques
(including interruptible rates), and declining block time-of-day
(T
provisions OD), and seasonal rates. These standards, as well as the other
conservation of established to
cobjecti es: of
customers# the
efficient use of facilities and resources by electric utilities,
and the provision of equitable rates to customers.
Under the provisions of Title I, state regulatory
authorities and nonregulated utilities are required to complete a
formal consideration of these ratemaking standards by 1981 and
determine if they (1) promote conservation, efficiency, and
equity, and (2) are consistent with state law. As part of this
formal consideration, the regulatory authorities are required to
hold hearings on these standards,
• The Conference Report sets out three objectives to be
achieved by the adoption of PURPA. The first objective relates
to conservation of energy supplied by electric utilities. It is
the purpose of Title I to foster conservation by the ultimate end
user of electricity. The second objective relates to
optimization of the efficiency of the use of facilities and
resources by electric utilities. This objective is directed at
the utility in its use of energy and of its facilities. The
Conference Report indicates that capital resources are included
within the meaning of resources. The concept of optimization is
intended to include the notion that the most efficient use is
made of electric generation and related facilities. The phrase
"efficiency of use resources" is intended to include the
concept of conserving scarce energy resources by techniques of
rate reform which substitute the use of more plentiful resources
produced in the United States in lieu of less plentiful
resources, especially those imported to this country. The third
purpose relates to encouraging equitable rates for consumers.
The Conference Report is not specific on this purpose, and
appears to leave the determination of what is equitable to the
State or unregulated utility.
The objectives of PURPA are independent of one another and
not listed in any order of priority. The Conference Report
indicates that it is not necessary that all of these three
• objectives be achieved for any action to be adopted in carrying
11
. Out the purposes of PURPA. Rather, if any of these objectives
is achieved and the others are not negatively impacted, a finding
can be made that the purposes of the Title are carried out.
Regulatory laws applicable to electric utilities typically
require that the regulatory body make a finding on any particular
issue that is "just and reasonable". Just and reasonable are not
operational concepts, but a value position which is
representative of regulators' opinions of the evidence brought to
bear on any issue. Such statutory language does not set out the
specific objectives that regulatory decisions should achieve.
The statutory objectives usually require that a decision must be
"in the public interest". In fact such language is almost a
tautology. What is "just and reasonable" is answered by
decisions which hold that a decision is "in the public interest".
What is "in the public interest" is supported by language which
asserts that the final rates are "just and reasonable".
The criteria a regulator uses to determine whether any .
particular outcome is just and reasonable is a personally held
concept which cannot be transferred to another individual.
Another regulator may have another criteria which he uses to
determine whether a particular outcome is just and reasonable.
Title I of the PURPA makes just and reasonable a much more
precise term by stating very explicitly that an issue is just and
e reasonable only if it achieves the purposes of conservation,
efficiency and equity.
B. The Criteria
In order to determine a methodology for choosing among
alternative solutions intended to promote conservation,
efficiency and equity, it is necessary to convert each objective
into an operational criteria. For any particular rate-making or
regulatory ::tandard, a regulator should evaluate each fact
brought to bear on ar,y particular Issue according to whether its
adoption will promote conservation, efficiency or equity. We
have atcempted, therefore, to develop an operational criteria
that w!11, except where overpricing of electricity may exist,
encourage consumers and producers to respond to regulatory
standards that will positively impact all three objectives of
PURPA.
Conservation may be accomplished by responses or actions
taken by both the supplying utility and by the customers. From
the customer's perspective, his electricity consumption will
increase and potentially be used in a wasteful manner if that
electricity is underpriced. A customer will be more likely to
conserve higher priced electricity. Underpricing elecricity
removes the proper cost signals on the customer's bill. Hence,
12
For
17
he has less incentive to use electricity efficiently.
Expanding upon this point, a higher electricity price will
cause the customer to have less funds available to purchase all
other goods and services. Since the customer prefers more of ail
goods, more or the same amount of higher priced electricity
causes a reduction in other purchases. The customer is then
stimulated to change the quantity of KWH he purchases when the
price is increased or decreased.
Conservation also means promoting the substitution of one
form of our nation's resources for resources in another form such
as electricity. The customer is more likely to be stimulated to
substitute energy-saving equipment and devices such as
insulation, storm doors, and storm windows for the consumption of
expensive electricity than if the electricity is underpriced.
The customer is equally warm if he buys insulation to retain
heat or if he buys more electricity to provide more heat. He is
better off economically, however, if he biiys insulation to
reduce his electric consumption and receives an electric bill
reflecting cost savings greater than his investmen': in
insulation. A customer is nct encouraged to seek alternatives to
the use of scarce and expensive energy resources if the
alternative is not economical when compared to the continued use
of energy. For example, if an expenditure for insulation will
not at least pay for itself by a reduction in energy costs, the
customer will not purchase the insulation. If electricity is
underpriced and insulation is not, then the regulatory policy
which allows the price of electricity to be below its true
resource cost is less likely to promote conservation.
From the producer's perspective, conservation is achieved
when it delivers any given amount of energy at minimum cost. For
instance, conservation of our nation's scarce resources is not
achieved if an electric utility meets existing load requirements
through excessive use of its less efficient generating equipment
and underutilization of its more efficient generating equipment.
Maximum conservation would not be achieved because the utility
would be using more fuel to weet the load than would be necessary
if the utilization of the more efficient generators were
increased.
The producer has an incentive to not operate his facilities
in an efficient manner if the cost of such action is not assigned
to him. General rate proceedings are undertaken to review
management practices and to establish the total revenue
+quirement, i.e., the total cost of service. If inefficient
oparations cause an increase in costs, then the producer's margin
is reduced. Hence, adopting policies which assign cost increases
to the producer, provide an incentive for efficient operation of
facilities.
13
• Efficiency also may be viewed from both the producers' and
the consumers' perspectives. Efficiency in production means that
for any given level of consumer demand the utility minimizes the
cost of production. In the short run this means that the utility
adopts a program for the economic dispatch of its generating
units. Economic dispatch of existing generating units means that
the firm always meets demand at minimum available fuel cost. In
the long run efficiency means that given the expected level of
future customer demand, the utility adds generating capacity
which minimizes the present value of the future stream of total
costs.
From the customer's perspective efficiency means that he is
stimulated to use alternative forr..s of energy in the most
efficient manner. In particular, efficiency in the use of energy
resources means that electricity is not underpriced relative to
other forms of energy. if electricity is underpriced, the
rational consumer is likely to respond in two ways. First, he
will use more electricity than he would otherwise by not
substituting insulation, sweaters and storm doors for electricity
or by not substituting more efficient electric devices for the
less efficient. Second, the customer will be stimulated to
substitute electricity for other forms of energy such as wood,
natural gas, etc.
• Equity has two dimensions. There is an economic equity
argument and a social equity argument. Economic equity means
that a particular customer is being charged a price that reflects
the actual costs incurred by a utility to meet his level of
demand. In particular, economic equity means all customers who
place similar loads upon a utility will be charged the same price
because similar load characteristics cause the utility to incur
similar costs. It is not equitable to charge the same price to
two different customers whioh have different load patterns and
corresponding cost differences.
Social equity is addressed by relating the price of
electricity and its total cost to a customer's income. Clearly,
a low incnm,e person spends a larger percentage of his income for
,-he purchase of electricity than a higher income person given
equal levela of consumption. As a result, the low income
individual has less income available to purchase all other goods
and services. Data is not available which would permit MARC to
recommend regulatory policies which would consider customer
incomes and, correspondingly, the customer's ability to pay his
energy bills any assure that the objectives of conservation and
efficiency are not negatively impacted.
14
i
w
• C4 Conclusion
Rational producers and consumers will respond to the price
charged for electricity. Conservation, efficiency and economic
equity will be achieved only if the price of electricity reflects
the true resource cost incurred to produce the electricity. The
Conference Report indicates that the purpose of Title 1 is
carried out if aM of these three objectives is achieved and the
others are not negatively impacted. Pricing at true resource
cost will always promote the objectives of PURPA. The consuner
must also receive the proper information and price signals and be
able to control at least a portion of his load if he is going to
respond to the appropriate price signals and realize the
available benefits. The objectives of conservation, efficiency
and economic equity will be achieved by adopting the following
rule as the operating criteria which is to be used to choose
among alternative'solutions:
"Does the solution result in the price of electricity
being set equal to its true resource cost or provide
the consumer an opportunity to resp,)nd to the
appropriate price signals?"
If the answer to this question is yes, then adopt the
• solution. If the answer to this question is no, then reject the
solution.
15
IV. APPLICATION OF EVALUATION CRITERIA TO CURRENT
• TARIFFS AND POLICY
A. General Discussion
The application of the criteria is easiest when the issue
goes directly to the price itself. For instance, the issue of
whether to adopt seasonal rates requires that the decision maker
has available to him an empirical analysis to determine if
significant cost differences exist in different seasonal periods.
If the answer to the question is yes, then the decision maker
must determine the cost of seasonal metering. If seasonal
metering costa are excessive relative to the expected benefits,
then the imposition of additional metering requirements in order
to implement seasonal rates that reflect the seasonal production
cost differences may result in an inefficient use of capital
resources.
On other issues, particularly those associated with
individual electric meters and information to consumers, the
solutions may only indirectly affect the true resource corst. As
a result, the decision maker must examine the second round effect
before its effect on true resource cost may be identified. The
• second round effects can be viewed from two perspectives. If the
adoption of the regulatory standards has only an indirect effect
and is dependent on cost base) electric rates to achieve its
objectives, the regulatory and ratemaking standards become
ins4parable and mutually dependent. Secondly, since proper
education of the consumer and the development of properly
designed electric rates can take months or even year;, the total
effects of the regulatory standards can be viewed as a long teem
investment in customer related plant necessary to reduce long
term investment in gegerating plant.
We have taken the following approach in evaluating each
standard for the City of Denton. First, marginal costs must be
calculated and the most accurate TOU rates possible be designed
for the electric system. only then can the necessary
cost/benefit and billing impact analyses be done to determine the
appropriateness of each standard.
We also recommend that the cost/benefit analyses for the
various standards be considered simultaneously as well as
individually since certain fixed costs need only be incurred
once, but will be necessary for all standards.
16
• B. Cost of Service Standard
Operational Criteria: The cost of service standard is
defined in sections 111 and 115 of Subtitle B - Standaris for
Electric Utilities. Specifically, rates charged by any electric
utility for providing electric service to each class of electric
consumers are to be designated, to the maximum extent possible,
to reflect the cost of providing service to each class. In t e
case of unregulated utilities, the choice of which cost of
service method to use is left to the utility. However, the
method is required, to the maximum event possible, to permit the
identification of cost incurrence attributable to:
1) Daily time of use,
2) Seasonal time of use,
3) Customer cost components,
4) Demand cost components and
5) Energy cost components.
In addition, the method should account for the extent to
which the total costs of an electric utility are likely to change
if additional capacity is added to meet peak demand relative to
base demand or if additional KWH are delivered to customers at
any time. Marginal cost studies are designed to fulfill these
. requirements. To comply with PURPr a utility must have some
meaningful measure of marginal cost.
The determination of the appropriate cost of service (COS)
method is clearly one of the most important standards, since it
is the basis for. determining the true resource cost upon which
al), other judgements are made. For this reason it is critical
that the most accurate cost study possible be done prior to
developing specific criteria for other standards.
The PURPA does specifically state that COS results are the
starting point for tariff and other policy decisions, but that
such decisions are not expected to follow the COS study precisely
in every instance. The two main reasons for this qualification
are essentially potential customer impact caused by sudden shifts
in bills and the potential for the implementation of new policies
to cost the utility and/or the customer more than they will save
in resources. However, the actual cost of service must be
determined before any such judgements can be made.
There are numerous approaches to quantifying the utility's
costs of providing its services: PURPA clearly requires that the
total costs of operation be divided among classes, resulting in
what is commonly called a class COS study. There are two main
types of class COS studies known as fully distributed or marginal
• studies. The f,,ret type allocates current annual fixed and
variable accounting costs of service among classes and the second
17
• typo allocates future changes in fixed costs and future variable
costs among classes of service.
Section 115 of Title I clearly requires that the COS
methodology chosen by a non-regulated utility must consider
marginal costs to the maximum extent practicable because it
rftgwires the consideration of future costs. Generally, only a
lack of data makes considering marginal costs by class
impractical. Few utilities have every bit of information
necessary to calculate marginal costs at their fingertips, but it
is often available in less than perfect form.
If the data is not available, and the utility is not
currently budgeted to acquire it in time to r.eet the PURPA
requirements, it may not be physically or financially possible to
acquire the data. In such cases the utility should try to
estimate unavailable data to allow the calculation of marginal
costs. However, the estimation technique(s) used should be
clearly documented. In addition, sensitivity analyses should be
done to determine the effects on cost allocations to customer
classes'of changing the estimated data. If meaningful data
estimation is not possible, it is better to delay the computation
of marginal costs until meaningful data is available. if any of
the required data is unavailable and estimates are used, or
delayed, the utility should examine the feasibility of
instituting procedures for data collection for future use. Fully
distributed cost studies should only be used as an interim last
resort until marginal cost studies are feasible.
Current Policyi The City of Denton has never done a
marginal cost st=udy or a complete class cost of service study of
any type for its electric system. Its most recent COS study was
done in 1973 by Black and Veatch and focused on det=ermining total
embedditd revenue requirements for the period 1975-80. Some
detailed work was done at the class levels to forecast customer
growth, sales, and similar items.
Without considering current data limitations, our
reccmmendation would be that the City do a thorough marginal cost
study by voltage level to quantify its true resource cos!.
However, severe data limitations at both the Company and class
Sevels exist, making it impossible to du such a study
immediately. Our review of the electric utility's records
indicates that almost no class hourly demand data is available,
and very little hourly dispatching data for the current
generation facilities is available. In addition, the City's
electric operations will be in a state of transition as the Texas
Municipal Power Agency (TMPA) becomes operational because,
effectively, a major portion of Denton's marginal costs will be
determined by the rate policy they face in buying power from
TMPA, In one sense the demand/energy rate the City will face
from TMPA will be its marginal cost. However, TMPA's rate must
18
accurately reflect its marginal cost for the rate to be a measure
of true resource cost to Denton. A thorough marginal cost
analysis of TMPA's system must be done before the quality of its
rates as a measure of true resource cost can be settled.
The TMPA has done no marginal cost analysis, and is only now
beginning to finalize embedded cost studies for use in designing
its rates for the four member cities. The system operation data
necessary to do a thorough marginal analysis is not yet available
because the cities do not have detailed records of their
operations and the TMPA has not yet begun operations so that the
information can be acquired at the total system level. Estimates
of the system characteristics are available.
Recommendations We recommend that the City adopt the Cost
of Service standard as the basis of all the ratemaking standards.
It is absolutely necessary that the City of Denton have a
meaningful measure of the true resource cost of providing
electricity to carry out the requirements of the PURPA regarding
other standards. We recommend that three things be done to
accomplish this.
First, an estimate should be made of the future costs the
utility will face from TMPA and its other operations. These
estimates will serve as proxies for system marginal costs for use
in decision making until better data is available. Class
• allocations of these measures will have to be made on the basis
of estimates of current class and voltage level characteristics.
Customers will probably need to be regrouped in new classes to
more accurately reflect cost responsibility. All estimates and
data sources should be carefully documented.
Second, the utility should institute data collection
procedures for future use. This is a critical step in improving
the estimate
of true resource cost necessary for evaluating
policies and standards, which should in turn improve the
utility's ability to effectively manage its operations. The
required data will be discussed below in more detail.
Third, a marginal cost analysis should be done for TMPA if
the City wants to determine the quality of the TMPA rate as a
measure of true resource cost.
C, Declining Block 9 Ck Rates
0 erational Criteria: The declining block rate standard is
explicitly defined -in Section 111 of Subtitle B. It requires
proof that the energy costs for a class decline as consumption
incrRases before the energy component of a rate, or the amount
• attributable to the energy component in a rate, can decline as
19
consumption increases. The demand part of a rate is explicitly
• exluded from this standard.
It should be noted that recovering energy costs with a
declining block KWH rate implies a certain relationship between
quantity and timing of use. Specifically, it implies that load
factor the ratio of average to peak use increases as
consumption increases. A further implication is that as average
use increases relative to peak use, average fuel costs decline.
The only situation that can exist where such costs decline
is one in which more efficient use is made of the fuel source in
a currently running plant as consumption increases. This is true
because plants are typically brought on line in the order of
least incremental running costs, the majority of which is fuel.
Thus, any time increases in consumption require bringing the next
plant on line, average and marginal fuel costs will ~X design go
up.
It is almost impossible for this to be the case for all
customers since most utilities experience increases in total KWH
sales and system peak demand simultaneously. It is possible that
a group of customers may exist that fit this case, but detailed
load information for each customer within the group must be
available to prove that marginal energy costs for that group
decline as usage increases for any time period in which declining
block rates are desired.
Current Policy: All residential and commercial/industrial
customers gave some form of declining block KWH charges. No
records exist which explicitly identify the energy and demand
cost components in these rates.
The governmental agency rate is a flat rate for all KWH and
has no minimum charge. The dusk-to-dawn lighting rate is a flat
charge for each lamp size with no relation to measured VWH usage.
No minimum charge is applied since the rate is unrelated to
consumption.
Recommendation: The daCa required to determine whether or
not cost based support for declining block energy charges, either
by daily time period or seaeonal period, s not exist or is
unavailable. However, as pointed out above, it is highly
unlikely that such rates can be supported. Further, if TOU rates
are implemented, much of the potential need for declining block
rates is eliminated.
For these reasons we recommend that the City adopt the
seasonal Rates standard and in future tariffs the City recover
energy costs on a flat per KWH charge by time of day, eliminating
declining block energy charges.
20
• DL Time of Day Rates
Operational Criteria: The PURPA is explicit in Subtitle 8,
Svc. 115.b in requiring the use of long-run cost/benefit analyses
in determining the appropriateness of time-of,-day or time-of-use
(TOU) rates.
Once marginal costs have been identified by time period, it
is a relatively straightforward process to design rates by time
period to recover those costs. It is implementing rather than
designing the rates that has the potential to cause problems.
Three main hurdles exist for most utilities to implement time-of-
use (TOU) rates: 1) Metering and administrative costs, 2)
customer impact, and 3) data limitations. These hurdles are not
usually sufficient to cause abandonment of TOU pricing but do
play an important role in deciding how to TOU price.
Initially, there is a required investment in metering
equipment and in reorganizing billing procedures to fit TOU
requirements. Customers must also be educated so that they
understand TOU billing. The extent of any impact on the utility
and its customers of these requirements depends mainly on the
state of current procedures. One of the main criteria in
determining if and how far a utility should move in TOU pricinq
is whether the costs of the required procedures will be exceeded
by the benefits. If it can be demonstrated that responses to TOU
pricing will result in long run benefits that exceed
implementation costs, some sort of TOU pricing scheme is in
order. When a utility institutes TOU pricing it is essentially
trading investments in more expensive metering and billing
systems for the fuel and capacity costs it would have been
required to pay to meet the additional demand for electricity it
would have experienced without TOU pricing.
Once a utility decides to use TOU pricing, it faces the
practical problem of how quickly it can proceed. Again, the
current tariff policy of the utility affects the decision.
General rate-making principles as well as the PURPA clearly state
that billing impacts caused by change in tariffs must be
considered in instituting any new policy. The decision is
basically subjective and best made after careful examination of
bill impacts that will be caused by regrouping customers and
redesigning rates.
Data limitations also create problems because good price
elasticity of demand estimates must be available to do the
initial cost/benefit analysis and to predict future revenue
streams as customers alter consumption in response to price
changes.
21
1
• Short run revenue instability can also be a problem if
future revenue streams are incorrectly forecasted. However
marginal cost based rates eventually improve revenue stability
since the rates will provtde revenues as costs are incurred.
It should also be noted that while implementing TOU rates
can create short run problems, it also eliminates many long run
problems. The criteria to correctly group customers is clear
cut: costs vary by TOU by voltage level, hence customers served
at the same voltage level should be charged the same TOU rate.
All of the many problems of trying to identify the myriad of the
patterns of the timing and amount of electricity consumption of
individual customers to group them disappear. It is no longer
necessary to identify such patterns on the front end. TOU meters
record the information for you. Perhaps an even greater
advantage is that subsidy among classes is almost entirely
eliminated.
All of these factors must be considered in evaluating the
TOD and other PURPA standards.
Current Policy: The City of Denton currently has no time-
of-day rates.
Recommendation: Denton must first obtain an accurate
estimate of Tts marginal cost before implementing TOD rates. Our
recommendation to accomplish that is explained in the Cost of
Service section above. Once the first estimates are available,
actual TOD rates will have to be designed to enable the City to
do a cost/benefit analysis and to evaluahe customer impact.
Costs estimates for a metering and billing system must be
obtained and compared with these potential savings.
Estimating potential savings will require some estimate of
price elasticities of demand. Technically accurate estimates are
scarce, and calculating one that is system specific for Denton is
virtually impossible because identifying consumers' responses
requires already having had the rates in effect. Euphemistically
speaking, it is a "chicken and egg" problem. However, estimates
for some customer groups can be obtained.
Data is available on industrial and residential customer
response elsewhere in the U.S. It is commercial customers for
whom data is lacking. We recommend that these estimates be used
initially in deciding whether to institute TOD pricing on a small
enough scale to obtain system specific data. Other systems'
experinces have yielded positive recommendations for gathering
data. We expect the same will be true of Denton, particularly
sine the procedure to institute TOD metering will be required to
collect load data necessary to do an accurate marginal cost study
as recommended in the Cost of Service section above.
22
There are a number of ways to meter electricity by time of
• upe. Certain types of metering systems have other capabilities
an well that the City might find useful. Possible systems
include:
1) Converting existing standard meters through attachments
2) Buying new multiple dial meters
3) Installing an automatic digital meter reading system
with transmission along electric, telephone, or cable TV
lines.
4) Installing a digital recording system that still
requires personnel to physically retrieve data from each
meter.
The ultimate decision concerning the best system for the
City to use will be affected not only by coi,sideration of TOD
rates, but other factors as well. For that reason, it will be
necessary for the City to first estimate the costs of all types
of metering systems and their potential for altering personnel
needs (with a potential for reducing costs), use in load
management, use in automatic meter reading, and use in
connect/disconnect for interruptible service or other reasons.
This information can be obtained from various manufacturers of
such systems.
These joint costs must be compared with the joint benefits
of the various rate standards, once the required data is
available. If the long-run benefits exceed costs, TOD rates
should be adopted.
E. Seasonal Rates
The issue of seasonal rates is closely associated with time-
of-day rates. The issue for the City to address is do the
utility's costs vary by season cf the year. The costs to be
examined are fuel, coincident capacity and non-coincident
capacity costs. We may eliminate customer costs from any further
discussion of seasonal rates.
Fuel related costs are a function of loads, relative fuel
prices, fuel sources of the generating units and the technical
characteristics of a power station's ability to convert energy
from one form into another form. The loads are usually not f ixed
between seasons. Therefore, it becomes an empirical question to
determine if fuel related costs vary by season. If so, then the
tariff applicable to each KWH should reflect the difference
• between the costs incurred in each season. The City's current
23
fuel adjustment clause combined with a base rate that reflects
average base fuel costs should adequately reflect seasonal
differences in fuel costs.
Non-coincident capacity costs are a function of individual
customer's peak loads and may or may not be seasonally related.
As such these capacity costs are not generally thought to vary
seasonally although there may be exceptions, i.e., irrigation
loads.
If a utility exhibits a distinct seasonal peak, the
coincident capacity costs are seasonally related. Some utilities
may exhibit a dual peak of equal heights. If so, there are two
seasons, one including the two peaks and the other which includes
all other loads. The seasonal nature of coincident capacity
costs is most appropriately determined by an inspection of an
annual load curve. It is appropriate to adopt seasonal
differentials in the coincident capacity costs if the load curve
exhibits a characteristic seasonal shape.
The coincident peak season is defined as the period when the
system has a high probability of experiencing an annual peak.
The Denton electric system appears to have the highest
probability of peaking in the months of June through September.
It is not appropriate to define the peak season by examining only
one annual load curve. Rather, it is necessary to examine the
• load curves for a five to ten year period. The seasonal period
should be defined the same for both fuel relate? costs and
coincident capacity costs.
The practicpl importance of identifying the presence of a
seasonal period For establishing tariffs is that the associate
costs are most appropriately collected during this period. It is
not appropriate to collect seasonally incurred coincident
capacity costs outside the defined seasonal period. All
coincident capacity costs are best collected either through a
coincident KW charge (if appropriate metering is available) or
over KWH billed during the period. All seasonal fuel related
expenses are to be collected by a KWH charge applicable during
the seasonal period. Non-coincident capacity costs may be
collected over all billing KWH or KW without regard to a season.
To adopt tariffs which do not reflect the presence of the
seasonal component of costs will violate the criteria of adopting
policies (in this case tariffs) which set price equal to the true
resource cost.
An associated, issue is the relationship of seasonal tariffs
and non-TOU metered customers. If TOU tariffs cannot be cost
justified for customers who take small amounts of energy, the
issue becomes W:.iat is the appropriate rate structure to post for
these customers?" We recommend that all non-TOU customers face a
• seasonal flat rate in addition to a flat monthly facilities
24
charge. All coincident capacity costs should be collected during
the peak period and all non-coincident capacity costs are to be
collected throughout the year. The fuel component will reflect
neasonal cost differences in fuel related expenses that are
different between the seasons.
The adoption of seasonal rates requires that an examination
be ;nade of both a utility's load curve and its fuel related costs
associated with the production of KWH. An examination of the
load curve will reveal whether it has a distinct seasonal peak
over a number of years. If so then the system planner will incur
capacity costa in order to meet the seasonal peak. The customers
who impose the loads during the seasonal period cause the costs
to be incurred and should be charged for the capacity costs on
bills rendered during the peak season.
If fuel related coats vary by season then the customers who
impose loads when costs are high should be charged for these
costs. Similarly, customers imposing loads when fuel costs are
lower should be charged the lower costs.
Current Polio : The current City tariffs reflect seasonal
differentials only in its residential rates. These current
winter discounts apply only to residential customers if the
entire home is electrically heated - heat pump or resistence.
The end use of electricity does not determine the cost to produce
that electricity. Consequently, if seasonal differences in
the production of electricity do exist, those cost differences
should be reflected in the rates of all customers that contribute
to those cost differences.
The present summer period for residential service is defined
as May through October. Uiscussions with management of the
Electric Utility and a review of recent monthly consumption
statistics indicates that the probability of the utility reaching
its peak during May and October are very low. Thus, the
currently defined summer period does not appear to reflect the
true summer period.
The current residential rates reflect a seasonal
differential of 7 mills for electric heating customers for
consumption over 7GO KWH. This means that electricity sold in
the trailing blocks of the tariff to specified customers in the
summer is sold at a base rate of 2.560 as compared to the base
rate of 1.85¢ at which electricity is sold to the same customers
in the winter.
Recommendations We recommend that the city continue to
offer rates `that reT1ect differences in seasonal costs to the
utility but suggest that these rate incentives be extended to all
electrin customers regardless of the end use of the electricity.
Since the Denton Electric Utility is a definite summer peaking
25
• system, it only incurs Additional capacity costs if it adds
electric demand during the summer peaking period. The generation
and transmission costs incurred to provide additional capacity
during the seasonal peak period provides an objective and
practical basis upon which to develop an appropriate seasonal
rate differential.
F. Interruptible Rates
Operational Criteria: The PURPA, in Subtitle 61 Sec.
111.d.5, explicitly requires all utilities to offer cost
reflective interruptible rates to all commercial and industrial
customers. No exceptions are included.
Current Polic : The City of Denton currently offers no
interrupEfbYe tarTf s.
Recommendation% We recommend that the City offer
interruptible rates with a lower demand charge based on the
increase in reliability the s7s`_em will have as a result of the
existence of the option of cutting off loads. This will require
recalculating system reliability by hou►• and redispatching the
system as if the loads were cut off. The total change in
reliability can then be determined and applied to marginal cost
• estimates to calculate appropriate credits. Unique credits will
be rsauired for each voltage level served.
G. Load Management Techniqued
Operational Criteria: Sec. l1l.d.6 and sec. 115.c require
an electric utility Eo offer its customers those load management
techniques that are practical, reliable, and likely to reduce
maximum kilowatt demand for the system and thus lower long run
costs resulting in savings greater than the long run costs of the
load mmanagement program.
Again, the City must conduct a coat/benefit analysis to
determine whether to accept this standard or not. The expected
savings per KW of controlled load can be estimated from the
system marginal cost study. The cost of control and the
potential amount to be shifted in KWH must be estimated
separately for each controlled device.
In general, any large load required for a service that can
be deferred witho,t adversely affecting the quality of the
service is a potential candidate for control. Likely loads for
control include, but may not be limited to, air conditioning,
water heating, space heating, water pumping and irrigation
26
services.
There is potential for the utility, and ultimately its
ctintomers, to benefit from shifting loads to off peak hours
because costly future capacity additions can be delayed if growth
In peak demand is slowed. Likely loads for such shifting are air
conditioning, space heating, irrigation and water
services. Such loads tend to coincide with system pumping
It is unlikely that water heating is a andidatekfodeds.
rmsuch
shifting because the natural d..,:.lrsity in water heating use tends
to ameliorate its effect on pe,~k demand in a summer peaking
system. However, water heating service is definitely a candidate
for control that lowers total KWH usage because water heaters use
energy to keep water hot during extended periods of non-use.
Simple timing devices could prevent unnecessary heating and save
the associated energy costs. Control of the other loads is less
likely to result in substantial energy savings because use is
merely shifted to another period. While shifting use may result
in using KWH in times with slightly lower energy costs, the
services may also require more KWH to "make up" for the slight
slippage in the service during the control period. For example,
an air conditioner that is shut off for 15 minutes during a peak
hour may have to work a little harder when it comes back on to
recover the degree or fraction of degree of cool that was lost
during control.
® These factors will need to be weighed in analyzing the costs
and benefits of each potential controlled load, Credits for any
control should be based on the net savings of controlling the
load.
Load management can be voluntary or mandatory. Many
utilities have had success with voluntary load control for these
services, both in terms of customer acceptance and resulting coat
savings.
Some utilities and regulatory commissions have instituted or
are considering phasing in mandatory controls, which differ
slightly in the credit procedure. Voluntary control credit
policies tend to give a credit to the customer who is willing to
have his load controlled. The reasoning is that if he is willing
to give up control of his load, he should recoup the benefits.
The same argument can apply to mandatory control credit
policy: if a customer is going to be required as a condition of
service to let the utility control his load, he should recoup the
benefits. The potential problem with such a policy with
mandatory controls is that if almost all customers have
controlled loads, they all receive credits. Essentially, the
source of funds for these credits are the general rates, so all
customers end up paying a fraction of everyone else's control
credit. They would be at least equally well off if no credits
27
-7-7777
S ware given at all. Credits in such a situation are merely
t: ansfers that raise the total revenue requirement of the City.
Even without credits, the fact that the total utility costs are
Inns means that savings occur to individual customers. In
addition, the administrative burden of keeping up with credit
records is alleviated.
Another potential problem with mandatory control is that
customer acceptance may be impaired. For this reason phasing in
mandatory control is being considered by many utilities. Such
plans often include the provision that new customers are subject
to mandatory control with a credit and existing customers are
urged to accept control. A more common procedure is to require
all customers tc accept control with a credit and then gradually
phase out the credit. Any control plan must be cost effective to
fulfill "URPA requirements.
Current Policy: No loads in the City of Denton are being
controlled by the utility at this time.
Recommendation: Evidence from other summer peaking
utilitlesr exile: Ienees indicates that control of air
conditioning and pumping loads will probably be beneficial to the
City and its customers. A comprehensive load control program
should be designed to minimize the cost of the control system.
The City will need to investigate various management systems.
There are four basic types currently available whose
distinguishing characteristics are mainly a function of the
transmission mechanism for the control signal. They are systems
that use 1) electric wires, 2) telephone wires, 3) cable
television linas, or 4) radio signals to activate the control
devices. Each has various technical difficulties.
Reliability is the chief problem with using electric lines.
damage electric the ability to control rload generation
Any line time
problems in transmission of the signal can occur. Using
telephone linen requires some assurance that the inesw ill
continue to be available to the City for use on a cost effecte
basis. This requires the continued cooperation of the telephone
utility in question and limits the managerial control of the City
over its control system. Using radio controlled devices is
limited by the available frequencies and physical transmission
range of the broadcast. Cable television lines have two
potential problems in that not all houses choose to be served and
cable television lines, like electricity lines, are subject to
physical damage. However, most utilities consider cable control
the most reliable alternative, but they are often prevented from
using it if no cable system is in existence. This is not the
case in Denton, so a likely candidate for a low cost control
• mechanism is the City's new cable television system.
28
• An administrative decision must be made concerning the use
o!' voluntary or mandatory controls. We recommend that the City
boijin with voluntary controls with individual credits to insure
customer acceptance since the concept of direct load management
will be new to its customers. Once the City decides which
control system to use, the costs and benefits for each type of
control must be used in designing the credit.
11. Master Metering
Operational Criteria. Consumers cannot generally make
rational decisions regarding their use of electric energy and
power unless they have control over at least a portion of their
electric consumption and receive a clearly identified price
signal that reflects the dollar impact of reduced consumption.
The owners of master metered facilities recover electric costs in
a number of ways. A landlord may simply include in each tenant's
rent an allocated estimate of the cost of electricity. A common
estimating technique is to allocate the monthly electricity costs
to each tenant based upon floor space.
Regardless of the method used to recover the electricity
costs from the tenants, the property owner of a master metered
building is the individual that receives the price signals
charged by the utility. The user of electricity, the tenant, may
not control his usage because he is not paying the electric bill
directly. He responds differently because he does not receive a
clear price signal. Thus, a tenant who does conserve energy will
cause the total master metered bill to decline. The decline,
however, is then distributed to all other tenants in exactly the
same fashion as the total costs are normally distributed. Hence,
this customer may receive only a small portion of the savings
caused by him., In contrast, a customer who wastes electricity
under a master metered arrangement will be subsidized by other
tenants for a large portion of the associated coats. As a
result, where master metering of electricity exists, the true
resource costs are generally not assigned to the individual users
in proportion to their consumption or conservation habits.
The conservation criteria can best be realized if cost
saving: resulting from energy conservation are assigned to the
individual user who causes the resources to be either used or
saved. The criteria of economic equity requires that cost
burdens caused by one individual not boa assigned to another
individual. Thus if the City does not adopt the prohibition of
master metering, the allocation of cost increases or decreases
resulting from changed energy habits of individual tenants will
likely not be distributed to the tenants in the most equitable
method. Thia improper cost allocation will result in individual
29
w
• tisriants not receiving the proper price signals or incentives to
conserve energy. Over the long run, the increased energy
e,t)nsumption resulting from master metering will result in an
inefficient allocation of capital resources to otherwise
linnecesary generating plant.
Costs and Benefits. Our analysis of the available data and
Eif)tential benefits regarding the prohibition of master metering
involved two areas. First, we reviewed the minimum charges
applicable to the City's current tariffs to obtain an estimate of
customer related costa that would be incurred by the electric
utility if individual metering of electric service is adopted.
4!Ev compared these minimum charges to the current energy costs.
Secondly, we obtained copies of some recent industry studies on
the effects of individual and master metering on individual unit
energy consumption.
The City electric utility will incur additional metering
costs and higher operating expenses including meter expenses,
meter reading and customer records and collections expenses with
the installation of, individual meters. The customer expenses
will likely represent the rniost significant cost increase to the
utility as a result of a future ban on master metering. A common
method of estimating customer costs is to look at the utility's
monthly customer costs or minimum charge although this charge is
not always based on actual costs. The present residential
customer cost is approximately $4.30 for residential and small
commercial service.
The electric utility industry has completed some studies to
identify the benefits of the elimination of master metering.
Recent studies of the effect of individual metering have been
conducted in Los Angeles, New York and Seattle. All three of
these studies reflect savings in excess of 308 with individual
metering. We submit these not as estimates of the effect in
Denton but as representative of the types of responses one may
expect from the elimination of master metering.
The study of the effects of master metering in Seattle,
Washington. found that there is a 318 higher electric consumption
in master metered apartments when .,ompared with idertical
individually metered apartments. The study also found 728 'iigher
electrical use for domestic hot wator heating in apartments
receiving their hot watkar from a central system when compared
with apartments with individual systems. The report indicated
that these findings were "consistent with national findings."
A report on the installation of submetering of electricity
in a cooperative housing company in the State of New York has
indicated a 35% reduction of electricity by the cooperators in
the first month. The cooperative housing company, Penn South
Houses, was the first in New York State to conform to the
30
• requirements of the New York Public Service Commission in
converting to sub-metering.
A third report summarizes a survey conducted by the Los
Angeles Department of Water and Power to determine the effect on
electrical consumption when metering is changed from group
metering to individual metering. The two areas surveyed showed a
reduction of 378 and 458 in their electrical consumption. The
hLgher figure is "attributed to high air-conditioning saturations
in the latter". A comparison of these documented experiences
with current rates and customer costs in Denton demonstrates the
potential benefits that individual metering presents to
residential and commercial customers,
A Denton master metered residential or small commercial
account presently pays an energy charge of about 3.0Se per KWH.
Considering the current average ever-v cs and the current
customer facilities cost of $4.30, an ndividual unit would have
to decrease its consumption by 140 KWH to cover the additional
customer costs associated with Individual metering.
If under individual metering, a residential or commercial
customer in the Denton service area using 500 KWH a month can
realize the thirty (30) percent reduction in consumption realized
in other parts of the country, the total
monthly
cost of energy
for the individual customer would decrease. The potential
savings increases as t
he minimum charge decreases or the monthly
consumption or energy costs increase. 't'hus the benefits to the
customer of individual metering in the Denton service area appear
to exceed the additional customer costs of implementing the
prohibition on master metering,
Current Polic. Our review of prior ordinances and
regulatioais of the City reveals that multiple dwellings
containing less than five (5) units may be served by one electric
meter. There apparently has been some reluctance on the part of
financial lending institutions in the area to finance master
metered buildings because of the inability of many property
owners to cope with the rapidly increasing cost of energy. 'Where
is also a state law prohibiting the installation of master
msters.
Recommendation. It appears from our analysis of the coat
and benefits-of1inaividual metering and our review of the Denton
electric rates that the potential energy cost savings to an
individual residential or commercial unit will exceed the
additional customer costs associated with individual metering,
Thu decrease in energy consumption resulting from individual
metering will reduce their long term capital resource needs. We,
therefore, recommend that the standard on Master Metering be
adopted for the Denton electric utility for all multiple unit,
buildings and that the five unit limitation be removed.
31
• The major problem anticipated with the Master metering
strindard concerns the definition of permanent type wall
coontruction for commercial buildings. We have, therefore,
stlopJlested individual meters for multiple units on each floor,
whIcrh are merely horizontal walls, and in each bearing cwalls. ommercihlh space
on the same floor separated by a
iaiil.ti-story commercial building could have only one tenant or
ocrnupant, a future change in the ownership or tenants may result
in multiple occupancy in which individual metering may not be
prnctical if the building was not originally wired by the builder
for individual meters. Common building areas where individual
unit contribution to electricity
the
practical to meter should still be consumption om?tered minor
i provisions of this standard.
I 1. Automatic Adjustment Clause
OEerational Criteria. A proper evaluation and application
of the operational cr teriz to the Automatic Adjustment Clause
standard requires a review of the background and purpos,ns of
interim adjustment clauses including fuel adjustment clauses.
When the electri.c utility deoires to change its prices it must
propose a sel: o! rate schedules setting out the new prices that
it proposes tc.charge. These rate schedules are simply price
lists showing the rates and charges for electric service and also
conditions under which electricity
explaining ary other tertheanutility.
service is furnished by Before approving a utility's request for a rate increase,
the City Council generally institutes a hearing into the need for
higher rates. This process of investigation and hearing involves
a presentation of evidence by the utility showing its need for
the higt,er rates. After all the evidence has been reviewed, the
City Council examines the evidence and renders its decision.
Each general rate increase is a major undertaking for the
City Council and it generally extends over a period of many weeks
and in some cases for months. The effort and time required for a
examined satisfy the
procedural requirement sthat rall the evidence part
There are two principal issues to be decided in a general
rate application: the rate level and the rate structure. The
rate level is the amount of money that the utility needs to
collect from its customers to cover the total cost of furnishing
electricity including the necessary internally generated capital.
total structure
This ssum is the revenue how much of the rate
issue involves the determination o revenue
requirement shall be collected from each of the customer classes
32
• stich as residential and industrial and involves the question of
how the specific rate schedules for each class are designed.
As a result of the length of time necessary to complete a
rnte investigation, many months may pass between the date of the
evidence that is the basis of the City Council's decision and the
final order. In times of rapidly changing electric utility
coats, the delays necessitated by a complete general rate
investigation are a major aspect of the problem of regulatory
1,19.
In an effort to reduce the regulatory lag occasioned by a
complete rate investigation, utilities have turned to the use of
interim adjustment procedures for changing electric utility rates
between the complete genn,ral rate increases. The purpose of
these interim adjustment procedures is to permit timely changes
in electric utility rate levels in accord with changes Ir. some of
the larger and more volatile cost elements without the necessity
of a complete and costly rate investigation, particularly where
these cost increases are beyond the control of utility
management.
Costs and Benefits. The costs to the City of not having a
fuel ad3ustment clause would be borne by both the customer a.,%d
the utility. Incentives to the customers would be eliminated
that encourage them to take steps to conserve electricity. If
incentives are not also provided to the utility, however, tnen
production costs may become higher than necessary.
if an automatic adjustment clause is not available, then any
increase in fuel costs can only be recovered through a separate
rate increase. Administration costs to the City will increase
because the utility would have to increase the size of its rate
staff to handle the additional workload imposed on it by the need
for frequent rate increases. While we cannot specifically
quantify the additional costs of frequent rate hearings or
potentially serious regulatory lag, we believe significant cost
savings can be realized through the application of the automatic
adjustment clause if the City follows a practice of balancing the
interests of consumers and the utilities in the design of ~.he
clause.
Current Policy. The present fuel adjustment in effect in
Denton is an automatic clause as defined in PURPA. The electric
utility is required to calculate a monthly fuel adjustment but
City Council approval is not specifically required prior to the 1
surcharge becoming effective.
The fuel price changes include the effect of generation mix
and are properly discussed as fuel cost chancles. Since most
0 electric service rendered in the Cit,- is provided with alas
generating plants, the problem of generation mix generally does
33
s~~
l+ut arise. The role of purchased power, however, is significant
au(l Increasing with the Texas Municipal Power Agency assuming an
aver increasing role and becoming an important source of power
r•)r the City.
Changes in the price of electricity signal to the customer
Tat more expensive resources are being used in the production of
electricity. If the customer is aware of the change in cost, he
piny respond accordingly. If the elecric price change did not
rlr,cur, then there would be no signal to the customer that
renource costs had changed. It is doubtful that a consumer will
i espond unless he is signaled that a change has occurred which is
one benefit provided by the present fuel adjustment clause.
Recommendations. We recommend that the City defer any
decision on the automatic adjustment clause standard until the
transition to TMPA is substantially complete and the entire rate
structure can be adjusted. At that time we recommend the
standard be adopted and a public hearing be held to review the
current automatic adjustment clause to determine if it provide3
proper incentives to utility management to mininize fuel •ind
purchased power costs. Such a hearing should be held at least
every four years to assure the form of the clause continues to
meet the stated purpose. If the startup of TMPA operations is
delayed and City achieves the minimum consumption requirements to
place it within the PURPA mandates, the review of the automatic
adjustment clause may have to be completed earlier than
recommended.
J. Information To Electric Consumers
0 er~atioonnaal Criteria. The ability of the electric consumer
to make rational dec iTons regarding the use of electric energy
depends on the information available. The success of a rate
structure policy designed to encourage consumers to conserve
electricity depends upon consumers voluntarily reducing total
consumption or moving consumption from on-peak to off-peak use
where they have a choice as to when to use electricity.
Voluntary actions of the consumer depend on the customer's
knowledge regarding the costs and benefits of the alternatives
available.
Although the number of customers who may respond to this
standard cannot be estimated with any reasonable degree of
accuracy, information is a precondition for consumer response.
More consumers will be aware of the relationship between energy
consumption and price if information regarding rates and
kilowatts and kilowatt hours is widely disseminated. This
increased awareness on the part of electric consumers will
encourage more consumeCs to change their consumption
34
chnracteristics in response to the price signals provided by the
aInutric rates. Thus, improved infori,iation to consumers and
properly designed rates will promote the objectives of PURPA.
IE the city does not adopt the Information to Consumers
at,indard, the typical
relationship between energy consumption and price and less likely
to respond to changes in electric rates structures or levels. If
tho consumer is not periodically reminded that his energy bill is
(lnpondent on classification of service and energy usage, he is
lung likely to change his consumption habits or attempt to reduce
tonal consumption. Consequently, a rather inexpensive method of
roir.forcing the consumption and price relationship will have been
bypassed and h the potential
will t not be realized. consumption
standard reduction
regulting f
The critical criteria the City will deal with in its
evaluation of the ratemaking standards will be the proper
relationship of electric rates and the cost of service. The City
will have to determine if the prices charged for electricity in
Denton provide the proper price signals to the consumers. If the
Information to Consumers standard is not adopted by the City, the
benefits of pricing policiiys developed in conjunction with the
rate making standards could be reduced significantly.
. Costs and Benefits. The cost of implementing this standard
will depend on the creativity of utility management. This
standard should not be interpreted as requiring Denton electric
utility to provide copies of elaborate electric tariffs to all
its customers or to develop expensive data processing systems to
record consumer energy consumption. The City electric utility
has already developed an iner-?ensive pamphlet that describes all
its current or proposed major class electric ratef. The latest
cost to print this form was only $59 per 1,000 forms.
We estimate that an annual mailing to all customers which
summarizes current rate schedules would cost less than $5,000.
We estimate that the annual cost of providing each new customer a
copy of the applicable rate schedule would be even less. Since
Denton has close to 20,000 customers, the average cost per
customer to provide the rate information required by the proposed
standard would be less than 50 cents per customer per year. Any
reduction in an individual customer's consumption resulting from
the dissemination of rate information should more than offset the
additional costs incurred to provide the information to that
customer. The additional cost to a customer that failed to
respond to the information would be insignificant.
The cost to the electric utility to respond to inquiries
from its customers regarding prior period energy consumption will
be minimal utility
inquiries basic
e since
system necessary to properly lalready developed
35
• Adoption of this standard should not require the utility to adopt
any new or elaborate filing systems or computer systems.
Current Policy. Our review of prior ordinances and
rlrguletlons did not reveal any direct prior action in Denton
regarding the issue of information to consumers. The City has
developed an effective rate summary pamililet that they give to
now customers and anyone else who requests rate information. The
City also maintains a comprehensive customer usage data base
which enables it to respond in a timely manner to customer
inquiries regarding prior months' consumption.
Recommendation. We recommend that the proposed Information
to Consumers standard be adopted by the City despite the lack of
any empirical data on the potential energy savings resulting from
the adoption of the standard. The benefitr, of providing
consumers with proper price signals have been demonstrated in
numerous studies of consumer consumption in various parts of the
country. The communication to customers of the relationship
between rates or prices and kilowatt hours has played an
important role in achieving these benefits. We specifically
recommend that the City provide every customer a copy of the
current rate summary form at least annually and that a similar
form be developed to notify customers of proposed rate changes at
least 30 days before they bscome effective.
K. Uniform Service Disconnection Rules
Operational Criteria. This standard has been specifically
excluded r~ om the PURPA'objectives of conservation, efficiency
and equity because it is regarded as a social policy. This
standard provides that no electric utility may terminate service
to any consumer except pursuant to a standard set of procedures
described in a special rule. The critical social criteria,
therefore, is that the rule be applied consistently. This rule
provides that no electric service to a consumer may be terminated
unless reasonable prior notice (including notice of rights and
remedies) is given to a consumer and the consumer has had a
reasonable opportunity to dispute the reasons for termination.
This special rule also provides that no electric service
provided to a residential consumer who establishes his inability
to pay for such service within a reasonable period of time may be
terminated for nonpayment if termination would be espec.ally
dangerous to health. This social criteria recognizes electric
service as a basic necessity to health and life. PURPA Lequires
that these procedures for termination also include special
criteria for certain disadvantaged groups and include reasonable
• provisions for elderly and handicapped consumers.
36
• Costs and Benefits. Since this standard has been
eiieciEically excludedrErom the PURPA objectives of conservation,
efficiency, and equity a cost benefit analysis has not been
performed. The ultimate costs will depend primarily on the
Ltility's management ability and creativity but should not be
cost prohibitive if the burden of proof for inability to pay and
medical emergencies is not placed on the utility.
Current Policy- The City's current ordinance regarding the
discontZnuance oTelectric utility service requires that each
cilstomer be rated "A" or "B" at the time their monthly utility
statement is prepared. A customer with an outstanding balance
due is rated "B". A customer with a "B" rating may be
disconnected if his account is not paid in full by the due date.
':he customer is notified on his utility statement that his
service will be disconnected the day after the present due date
if payment for the past and present statements is not received by
the due date. The notice informs the customer that he (she)
should contact the customer service department of the City within
the fifteen (15) day period an prior to disconnection of utility
service to present any evidence or arguin-int concerning the
statement or amount of utility service provided by the City. If
full payment has nog been made approximately five (1) days prior
to the due date the customer is again notified by mail of
possible termination and his alternatives.
• A customer with a "B" rating may avoid termination of
electric service by doing one of the followings
1) Pay the total amount due.
2) Arrange for a deferred payment agreement that would
require payment within six months.
3) Receive authorization from the Utility Account Review
Committee for a deferred payment agreement beyond the
six month period but not more than twelve months.
The occurence of delinquency can increase above normal
lel!els during the heating and air conditioning seasons because
many of the delinquent customers are faced with a personal
financial crisis. Termination during these seasons could place
the health and life of these consumers in jeopardy.
The PURPA has expressed its concern that although many
electric utilities have informaly adopted certain policies
regarding the discontinuance of customer services during severe
winter weather and in other situations invol%-ing hardship or
medical problems, a number of the utilites have not provided
these policies in their filed tariffs.
• Recommendation. We believe the City electric utility's
37
• rrent service disconnection rules incorporates the specific
1:11RPA requirements that attempts to balance the responsibilities
If both the utility and the consumer. While we agree that it is
th" utility's responsibility to inform customers of their rights,
wU believe the consumer or a designated third party should have
ili4 opportunity to defer disconnection for a reasonable period.
'N" current policy appears lenient enough to allow consumers to
make special arrangements when disconnection would be detrimental
to health or life. Placing this burden of proof on the utility
would make the process of disconnecting slow paying customers
ml)re costly and would require a subsidy from the remaining
oonsumers. We believe such action would be unequitable.
The rules should address special provisions for the aged or
handicapped as required by PURPA. A reasonable solution to this
special problem would be to allow any electric consumer to
doeignate any third party, such as a relative, friend, clergyman
or social service worker to receive the notice of termination.
Ouch notice would provide sufficient advance notice for the third
party to take whatever action is deemed appropriate to prevent
interruption of service. This procedure should provide ample
opportunity to further protect the aged, the infirm and those who
may not understand the consequences of having service
discontinued.
b. Advertising
OQerational Criteria. This standard pcovides that no
electric utility may recover from any person other than the
shareholders or other owners of the utility any direct or
indirect expenditure by the utility for promotional or political
advertising. Political and promotional advertising do not
include advertising which informs consumers of techniques which
will enable them to conserve energy or reduce peak demand for
energy; is required by law; explains service interruptions,
safety measures, or emergency conditions; concerns employment
opportunities; promotes the use of energy efficient anpliances,
effuipment or services; or explains or justif!es existing or
proposed rate schedules or notifications of related hearings.
The PURPA proposal to prohibit promotional advertising is clearly
directed at eliminating a practice that could Interfere with
actions designed to achieve the PURPA objective of conservation.
The Conference Report stressed that the standard on
advertising prohibits recovery of expenditures for promotional or
political advertising from anyone "other than the shareholders
(or other owners)" of the utility. The House bill had prohibited
recovery from the electric consumers of the utility which could
• effectively prohibit municipal utilities from engaging in this
kind of advertising because the owners are also the electric
38
• uunsumers.
We suggest that the prohibition on political advertising may
Ira more of a soufal objective than an operational objective. The
uncial criteria appears to center on the issue of whether
consumers should have to reimburse utilities for the utilities
rest of influencing public opinion concerning to legislative,
administrative, electoral, or other controversial public issues.
Costs and Benefits. The cost to implement and enforce this
policy should be nfnimal since the current utility system of
accounts provides for separate identification and accounting of
these costs. In addition, the electric utility apparently keeps
copies of ads in its files. The availability of this data should
facilitate an audit to determine utility compliance with the
advertising standard,
Current Policy, A review of prior City ordinances and
regulatfons dIVR5t reveal any direct prior action in Denton
regarding the issue of promotional or political advertising. A
review of the City's accounting report indicates that the utility
has virtually no advertising expenditures.
Recommendation. We recommend that the proposed PURPA rule
be adopted ~w t~h one modification. We believe the attempt by the
S House to prohibit recovery of promotional or political
advertising fom the electric consumers through 'rates was
appropriate and, therefore, should be specified in the rule. We
do not hold that this will completely prevent the electric
utility from engaging in this kind of advertising. It will,
however, prohibit it from recovering such costs in electric rates
and thereby discourage the use of such advertising.
M. Lifeline Rates
Operational Criteria: Sec. 114 in Subtitle B specifically
states that the remainder of the PURPA requirements are not
intended to prevent a utility from Instituting lifeline rates.
Further, utilities are required to hold hearings on the
appropriateness of having lifeline rates. Th- criteria for this
decision are not defined.
The decision to implement lifeline rates is strictly
subjective, but the City should recognize that instituting such
rates causes other customers to subsidize lifeline customers,
The PURPA does not disallow this, but neither does it encourage
it,
• Current Policy The City of Denton currently has no overt
lifeline rate . -Ri;~ever, its A-1 residential rate, a low use rate
39
with lower charges than other rates, essentially serves the same
purpose.
Recommendation: We recommend that the City base its
,locisionon evidence presented in a hearing in which the bill
impacts on moving its A-1 customers to our proposed rates is
in esented.
N, Informational Requirements
Section 133 of PURPA requires that each electric utility
periodically gather information as the Federal Energy Regulatory
Commission (FERC) determines necessary to allow determination of
the costs associated with providing electric service. These
costs should be separated, to the maximum extent practicable,
into the following components: customer cost component, demand
cost component, and energy cost component. This information
which is defined in Subchapter K of the Regulations under the
Public Utility Regulatory Policies Act of 1978 .should include:
1) The costs of serving each electric consumer class, based
on voltage level, time-of-use and other appropriate
factors;
S 2) Daily kilowatt demand load curves for all ele,-.tric
consumer classes combined representative of daily and
seasonal differences in demand, and daily kilowatt
demand load curves for each electric consumer class for
which there is a separate rates representative of daily
and seasonal differences in demand;
3) Annual capital, operating and maintenance costs
a. For transatissior and distribution services, and
b. For each type of generating unit? and
4) Costs of purchased power, including representative daily
and seasonal differences in the amount of such costs.
The FERC has interpreted the legislation to require the
gathering and reporting of both marginal and accounting cost
Information. FERC also requires that all of the accounting costs
marginal cost and load information be provided separately from
and in addition to cost calculations. The requirement for
calculations will provide a common point from which all partlas
can commence an analysis of rate design issues. Requiring that
the supporting raw information also be provided will assist chose
who wish to challenge the assumptions un3erlying the chosen cast
methodology or to propose a different methodology. Th:use
calculations should include the calculation of marginal energy
40
coats and annual carrying chorge rates.
Coverage. A utility will be required to report the
neo;nssary rn7ormation beginning in the first even-numbered
cnlondar year not less than two years following the first year in
which its total sales of electric energy by such utility for
purposes other than resale exceeded 500 million kilowatt-hours.
EAch utility will also be required to report biennially for all
fait+tre years even if its volume of sales in those year3 `alls
below the statutory threshold.
FERC has established May 31 as the biennial filing date for
the calendar year immediately preceeding the filing year. If
information is based on a reporting period reasonably near the
most recent, calendar year, FERC will permit the alternative
submission of the equivalent information. A separate filing of
the specified data will not be required at the time of a proposed
rate increase. The FERC will, in the future, provide standard
forms for certain items of data required by PURPA and will
prescribe the general forms of presentations for the remainder.
Accounting Cost Information. The FERC requires the
submission of the Eolfowing information in order to develop fully
allocated cost of service studies:
o Rate base information including plant, depreciation,
prepayments, materials and supplies, electric plant
held for future use, nuclear fuel material and
construction work in progress
o Operating expense information including operation
and maintenance expense and rate of return
information
This accounting cost information coupled with the load
information is intended to permit the development of fully
allocated accounting cost of service studies under a variety of
methods currently in use. The FERC requires that publicly owned
systems follow the FERC Uniform System of Accounta only to the
extent practicable. The City of Denton presently has a cross
reference available between the City's account coda structur.. and
the FERC chart of accounts for electric plant accounts.
Operating expense information according to the FERC chart of
FERC. 'out this should
accounts
resent a not readil available In
major obscle to compliance o with now
not p
Rate Base Information. Rate bane balances are required to
be repotti&-foi Egie'lieg-rr~KAng and end of the reporting period
together with the average of the thirteen monthly balances during
the period, if available. The Finance Department of. the City of
Denton has recently begun to issue nionyhly rate balance a shoot information
should provide the necessary
41
although it is not now <i FERC requirement.
Sub-account data and functional breakdown of distribution
r,lnnt into demand and customer related components is not
not:uasary in the raw data although the utility will be required
to develop support for the costs assigned to various
classifications, furictionalizations and voltage level,i. The
current cost of service study for example is based on estimates
or the relative costs of primary and secondary distrTbutfon
far;ilities and single and three phase customer service. The City
Electric Utility and Finance Department should assure that any
future modifications to the utility billing system include
identification of voltage levels and circuit phase for all
cuntomers.
Other rate base information required by FERC includes
depreciation and construction work for progress data to be shown
by primary function as currently required for depreciation under
the FERC Uniform System of Accounts. Since the City of Denton
currently identifies all plant accounts by FERC plant account
codes, this requirement should not be a problem for the City.
Operating Expense Information. Functional and classiflca--
tion break3owns of raw operating^and maintenance expenses are not
required by PURPA although the utility will be required to
develop support for their assumptions for the costs assigned to
various classifications in their own calculations.
Under the FERC requirements, the utility will be required to
report estimated hourly average energy costs (including both
generation and purchased power) per kilowatt-hour for a typical
weekday, a typical weekend day and the system peak day for each
month of the reporting period. This is intended to permit a
reconciliation to average monthly or annual energy costs
necessary for the development of time-of-day rates. Since
estimated data are all that are required, substantial changes in
accounting for fuel expenses are not anticipated.
Marginal Cost Information. The FERC requirements relative
to rnarglnaf-costlreportfng provide for the reporting of future
costs in either base year or current year dollars( however, it
will be necessary to indicate the inflation factors used in
producing the cost estimates.
The regulations require the reporting of certain cost data
and operating characteristics. The regulations do not require
that the unito comprising a group be located at the same site.
The data for existing generating units will be required only for
the reporting period. The data for planned generating units
expected to come on--.line during the next ten years will be
t required only for the first full year of commercial operation.
Information required for each group of existing plants and
47
.s~uara~~►vt~f ~
planned additions is included in ouhpact C, Marginal Cost
Information, of the regulations.
The data requirements for a conprehensivra marginal cost
study are not now available for the Denton electric utility. For
example, the regulations require estimates oe hourly marginal
energy costs for certain typical days for the reporting period
and for the five following years. This will require the utility
to maintain more detailed records than f.t currently has available
for existing plants and will require considerably more
Information on planned additions.
In addition to estioates of specific utility marginal energy
costs, the FERC regulations require utilities to provide marginal.
energy costs from centrally dispatched power pools in that they
could become the relevant basis for determining company marginal
costs. The City of Denton should begin now to collect the
required pool information from TMPA to assure itself that it will
be able to meet the FERC data requirement:3.
Transmission Distribution and Custoner Cost Information.
This sec`trion o~ie`~regu~acfons`shoul~ not~presen't~~any major
difficulties for the Denton Electric Utility. The Information
required ur_der this section includes proje=;ted five year totals
for transmission operating and maintenance expenses, projected
three year totals for distribution operating and maintenance
expenses, and detailed information regarding estimates of the
current cost of connecting new customers to the distribution
system. The utility may have to keep more detailed records in
order to provide additions to the transmission systzm by pole
miles added to each principal transmission voltaqe levol.
Toad Data. The FERC regulations require that utilities
report est~3eated load data for residential, commercial and
industrial use classes and for any rate class to which 10 percent
or more of the system's retail kilowatt-hour sales are snade for
any month during the reporting period. The rules exclude the
loads in master metered mixed use buildings from the estimates
for major customer class loads.
FERC has specified certain end uses for required load data
although the requirement will not take effect until the
Commission makes a determination to implement the list or to
modify it. FERC anticipates that the end use data will be
required on a sample metered basis beginning in 1982. Utilities
that do not have a separate rate applicable to the specified end
uses would be required to report load data for each of the
specified end uses on a best estimate basis in 1982 and on a
n,ample metered basis beginning in 1.984.
The FERC has interpreted the le4lislation to moan that coat
information must he collected for subgroups of customers within a
43
Aces if these subgroups have different consumption patterns,
tsuuh as electric space heating within the broad residential
In order to determine the costs of serving various
Ooftt;umption patterns, the utility must collect load data
t "'1^rding subgroups. New technology will reduce the costs of
I'll Iing under time-of-day rates and make them more cost
"rfontive. Thus, it is important to begin to collect load data
ti+'w ns a guide to designing time-of-day rates for the near
t'1st I) (op.
PERC has established some standards for conducting load
""itch programs and the filing of sampling plans with the
r (llriq of estimated load data. if the sanpled load data do not
'nn4,h the target level of accuracy, utilities will be required to j
10+01ville an explanation for the defiency.
The original proposed regulations specified that load data
I"' rel'Orted as total sixty minute integrated demands for each
h41,,r of, a twenty-four hour period. The final rule allows the
ttt.ility to report load data on whatever basis it chooses, so long
4h the pool, system and class loads are reported using the same
lntagrAtion interval. Each utility that is a member of a power
VOOI will be required to report the load data for its pool. This
approach was based on the FERC's intent to make each utility's
report self-contained so that partiem using the data would not be
reg14ired to go elsewhere for the information. The specific
reportinq requirements for load data are provided in Subpart D,
Load Data, of the regulations.
Caloillated Costs. Electric utilities will be required to
calcu7141'~o B;T accounting costs and marginal costs by costing
(?oriod, oilstomer class, and voltage level. The reporting utility
will be required to describe the method used for the calculations
and prov1dr a copy of any cost study upon which the calculations
are ha"611, The utility may provide a recent cost of service
study (Fiflly allocated and marginal) provided that the study
included All the information specified in Subpart 8 and C of the
regulatiottn.
's'hin section of the PURPA imposes a responsibility upon
covered tlktli:ies to perform on-going reviews of the utility's
cost ref service in order to meet the periodic reporting
rhquiremettts, The City's current charter requi.res the utility to
review Ira cost of service every five years. This may not be
ade'gttattt with the new requirements mandi,ted by PURPA and its
interpro)(ntlon by the FERC. We recommend that the City review
the curtt,nL charter requirements for utility cost of service for
pOssihlU Modifications.
44
,r
P~
P'JI'1gA. As soon a.3 estimates of marginal costs are available, the
? '.an design and .implement actual TOD rates. This will allow
tl'o ''Ollection of the information necessary to analyze customer
imi'n'1, and to do a cost/benefit analysis. This will also provide
111010 necurate data for periodically assessing the rates if they
`lr'd 11110pted. In addition, a cost/benefit analysis of the most
001'taCt ive method and timetable for TOD rate implementation can be
1~1~~~r l~iod.
No major constraint to incorporating time-of-day rates on a
"o.Ile is the cost of metering customer loads throughout the
day. The r,,ost reliable technology available for time-of-day
melrifinq is through the use of broadband cable (cable TV). While
it mny bti difficult to cost justify a broadband cable system
defilr,Atid to automated meter reading, the cost of one or two
channela of an existing cable system will be much more cost
<"Ffh`;tive,, We recommend that the TOD rates be incorporated over
Clio next- two to three years in conjunction with the development
O e 1)(040h4nd cable enorgy systems in the City of Denton.
80110tinal Rates: PURPA requires' that rates charged by an
eier;trlc 1r-,{lity7for providing electric service to each class of
eleotrio consumers be on a seasonal basis which reflects the
roots of providing :service to such class of consumers at
different reasons of the year to the extent that sut-h costs vary
seannnally,
The current City tariffs reflect seasonal differentials but
only for residential customers with electric heat. Since the
time during which electricity is used and the voltage level at
which It, is received determines the cost to generate the
elsatrioit, are recommend that cost based seasonal rates be
extended Co ta),1 customer classes. We also recommend that the
summer period be shortened to four months (June through
SePtumbe:) from the present six months to reflect the shorter
pertoo or time in which seasonal patterns are apparent.
Tntgfru tp ible Rates: PURPA requires electric utilities to
provide viiterruptible rates to comMercial and industrial
Customers, We recommend that the City of Denton provide these
intrarruiillhle rates and that the credits for such rater, be based
on this o1niings the system experiences due to its increased
rellabilliy, While the initial credits will have to be based on
estimati,a, the City should continually monitor the effect of
interruipjibie customers on system reliability and adjust
interriipi llfip rates accordingly,
G2~11 Management rechni ues: PURPA requires that load
control lie adopted -f` cost efMective. Each potential load for
control must be evaluated separately since costs and benefits
vary. Wa recommend that air conditioning and pumping loads be
examined na potential controlled loads.
7 M~