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CITY OF DENTON, TEXAS
ELECTRIC UTILITY RATE STUDY
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BY
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MANAGEMENT AND RESEARCH CONSULTANTS, INC,
DECEMBER 12, 1980
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MARL
4 Pro/ Cona+lr6,! (croup
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MMC A Professional Consulting Group
1 225 S. MO MMO, SURS 105
MANAGEMENT AND RESEARCH CONgUtYANTB, iNC.
CI OI% i"Wri OW05
' John 0. mck4 PhD.
Fred µodwty, O.PA.
FtWWd P. Am""
December 12, 1980
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City of Denton
CIO Mr. R. E. Nelson
' Director of Utilities
Municipal Building
Denton, Texas 76201
The City of Denton e 89 ~ a PURPAeCompl Compliance Manual and sto tpeants* rform nan
(MARC) in May, 1980 to d
Electric Rate Study. The enclosed revenue analysis, cost of service study
and proposed 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
sectiun of the report.
We appreciate the chpwill shave a° assisteffthe ect cony the D ost of a ergy
important engagement whi Dento
We also th the and conservationist for their patience andacooperat oneduring otheistudy an
Electric Deparlme
Very truly yours,
Fred Moriarty"
1 President
1 FJMssh
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1 CITY OF DENTON, TEXAS
` ELECTRIC UTILITY RATE STUDY
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BY
MANAGEMENT AND RESEARCH CONSULTANTS, INC,
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DECEMBER 12, 1984
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TABLE OF CONTENTS
t MANAGEMENT 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
r Select a Test Period 18
Assign Costs to Functions 18
Classify Costs Within Functions 19
TARIFFS 46
' Residential Service 48
Commercial Service 49
Local Government Service 51
Lighting Service 52
Time-of-Use Rates 52
' Time-of-Use Methodology 54
Cogeneration Tariffs 56
' Interruptible.Tariffs 57
Energy Cost Adjustment 57
APPENDIX A - Proposed Electric Tariffs
' APPENDIX B - Comparative Electric Rates
APPENDIX C Billing and Collection Policies
k tr~'1,rt "•iR~ ~t .r Ll1-$ 1 r .r`~~tk 1+ ~r'
MANAGEMENT SUMMARY
' The City of Denton, Texas engaged Management And Research Consultants,
' Inc. (MARC) in May, 1980 to develop a PURPA 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
Public 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
r analysis have been compared to current revenues and customer class rates to
determine the increase in rates anticipated over the five year period to
t 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 rates; cost-
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' based rates, not cost-of-service studies, are the means by which PURPA's
objectives of conservation, efficiency and equity can 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
t to purchasing under a contract agreement from the Texas Municipal Power
Agency (TMPA). It appears no increase in average base rates will be
1 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. The
A effect of customer and load growth have been included in the estimate of
the addit, tonal 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
' years indicates that this may be an opportune time for the City to
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implement our recommended restructuring of electric rates,
The effoct of the rate restructuring will be offset in part by
customer load growth and increases in KNH consumption. The combined effect
' of all factors will result in rates which more accurately track the costs a
customer causes the Electric Department to incur in order to meet the
customer lord.
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' 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 to 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. The 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 rate 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 Depreciation)
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
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ds to meet its cost of
from its operating fun
is now required to produce
` operations.
Since we anticipated transfers to the General Fund and Improvement
that adequate
Fund in projecting the Revenue Requirements, we as`O~e age ratio of 1.4
revenue would be generated to meet the minimum
make any debt coverage
adjustments
1 times debt service. We, therefore► did not
to revenue requirements for the debt service requirements.
Table I-A summarizes the projected revenuerequirements
individual cast
electric utility through fiscal year 1965. The following
of the revenue
items are included on Table I-A in the deter
1 requirement.
tionary Transfer. is 6% of the prior year-end
1• The Discre
net equity balance computed on Table I•B,
2, The U.S. Gove_____ nment Obl io_ a S purchases are required
during the first six years of the Electric System Revenue
Refunding Bonds, Series 1978 as shown in the City's debt
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' service schedule, se d . The interest gg nn - 0 Debt represents thpmRe Pnue
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years of interest expense on the Electric
theteCity's debt
Refunding Bondi, Series 1978 as shown
service schedule.
4. The tinci al Payments - New Oebt was obtained from the
3 and
1 Study, Exhibi
draft of the 1980 power SupP Y Payments on new debt
l represents the est•!mated principal through fiscal
issues anticipated from fiscal year lin fiscal years
year 1985. The new debt );sues projected
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1981 and 1983 were reduced by one half in accordance with
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discussions with the City's Rate Study Steering
Committee. The subsequent years debt service was also
changed accordingly,
5. The Inter st Ex.-n ' New Debt was obtained from the
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draft of the 1980 Power Supply Study, Exhibit IV
represents the estit,ated interest payments on new debt
issues. We adjusted the projected interest expense to
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' correspond to the adjustments to Principal Payments - New
Debt discussed above.
6. Fuel and Purchased Power costs were obtained from the
City Electric Utility. The Electric Utility obtained
preliminary estimates from the TMPA Preliminary Official
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' Statement but adjusted the fuel and purchased power cost
in fiscal years 1981 and 1982.
1. Other 0 eratln ExenseS were obtained from tMPreliminary Official Statement by the City Electric
Utility.
t 8. The Revenue Requi~ r 9nt Before Ad ustment represents the
total system revenue requirements excluding the amounts
' required for the Improvement Fund to finance
replacements.
9. Minimum Internal) Generated Capital is equal to 6% of
' gross revenues less fuel and purchased power expenses and
represents the minimum internally generated capita
required for transfer to the Improvement Fund.
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Additional internal Capital is included to assure a
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' 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 produce adequate revenues to
` meet the current year budget.
11. Gross Revenues represents the total system revenue
1 requirements.
12. Other Income includes interest income, rentals from
warehouse and service center and miscellaneous operating
revenues. No allowance is provided for revenues from
penaltl?3.
1 , Revenue Requirement From Rates represents the amount of
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revenue requirements that will have to be recovered
through rates charged to electric customers.
Depreciation expense is not included in the determination of total
r ments because it is an expense that does not require an
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revenue require
outflow of funds. We have instead included Principal Payments o 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
t to finance most of the utility's construction.
' FUEL AND PURr,Cr D POWER
The largest cost items included in the revenue requirement
' calculations are fuel and purchased power expenses. As shown below, the
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and purchased power are expected to continue to increase
costs of fuel an
The cost of
until the new TMPA power plants are completed in 1984.
purchased power and fuel is expected to begin leveling 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.
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PURCHASED POWER PERCENTAGE
INCiZEAS£
' FISCAL YEAR PLUS FUEL
1979-80 $1392009000 21%
' 1980-81 150963,000
1981-82 19,499,000 26%
1982-83 2496410000 2%
1983-84 32,5750000 3 3O%
1984-85 35,702,000
' DEBT RATIO
Table I-8 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 next several years if it realizes
the revenue and expense projections used in the report. As can be seen at
' the bottom of Table I-B, the debt ratio is expected to increase from its
' current 47% to approximately 48% by 1985.
The second purpose served by this table is the development of year-end
t equity (retained earnings) balances necessary to calculate the estimated
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annual discretionary transfer to the General Fund. The annual
discretionary transfer shown is 6% of the prior year's ending equity
(retained earnings) balance. As can be seen on Table I-B, 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
r current assets and liabilities. Accounts receivable are expected to remain
about 22% of gross operating revenues through the study period. Fuel
1 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
r year of the study represents our estimate of the annual change in cash
working capital.
Other current assets which is primarily cash working capital of
approximately $8 million dollars represents almost six months of cash
working capital. Daily cash working capital requirements are about $45,000
' (S16.5 million annual operating expenses divided by 365 days). $8 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
approximately $110,000 per day by 1985 (S41 million annual operating
expenses divided by 365 days), Our cash working projections shown on Table
' I-C reflect an estimated cash working capital or balance in other current
assets at the end of fiscal year 1985 of $5.4 million. This will represent
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of cash working Capital, a substantial reduction
approximately fifty days
from the current level
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PLANT ADDITIONS AND DEPRECIA1I4
e annual pl depreciation
Table I-D provides the estimated Current plant lant additions,
and annual
i expense and year-end net plant balance
obtained the City's Accounting Department.
depreciation rates were obtained f utility in their
Annual plant additions were provided by the electric
current capital improvement program.
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I Table [-A
PRUCTEDI R EYEMA REQUIREMENTS
1979-85
2E5CRIPTION 1980-81 1981-82 1982-93 1983-84
19&1-95
Discretionary Transfer (I) S 1,342,000 1111,420 ,000 S 1,149,000
V.S. Government Obligations S 1,476 S 1.502,000
816,000 781.000 717,000 )11,000 000 Interest Expense - Old Debt 1,036,000 1,036,000 1,036,000 OM's
Principal Payments - New Debt (2) 30,000 35,000 1,036,000 1,075,000
65,000 )5,000
Interest Expense - New Debt (2) 60,000 119,000 169,000 218000 265000
Fuel 6 Purchased Power (3) 15,963,000 19,499,000 21,641,000 32,515,000 35,702,000
Other Operating Expenses 3) 31522,000 3,820.000 _4,2993000 4,927.000 _5.372 000
Revenue Requirement Before Adjustment 22,)39,000 26,705,000 32,376,000 40,908,040 44,638,000
Minimum Internally Generated Capital(4) 589,000 627,000 673,000 )25,000
Additional Internal Capital (5) 11100,000 357,000 ?17,000
382,000 411,000 469.000
Gross Revenues 24,428,000 27,688,000 33,431,000
Less: Other Intone (3) 630.000 41,041,000 15,8&4,000
700 000 800,000 _ 750,000 750,000
Revenue Requirement From Rates $23,198,000 526,988,000 $32,631,000 $41,294,000
545,13/,000
Megawatt Hours 5126000 358,000 606,000 655,000 706,000
Cents per KNH 4.65f 4,84E
5.38E 6.301 6.39E
Annual Percentage Increase per KWH 0.1% 411.2% 417.1% 41,4%
Gross Revenues $24,428,000 $27,698,000 $33,431,000 $42,041,000 $45,88/,000
Less Fuel, Purchased Power i Other
0 L M 19,485,000 23.319,000 28,940,000 31,401,000 41,071,000
Debt Service (U.S. obligations, 4,943,000 1,369,000 4,491,000 1,642,000 4,810,000
Principal and Interest) 10912,000 11966,000 1,987,000 1,030,000 2,062,000
Coverage Ratio 2.6 2.2 2.3 2.3
1.3
(I New Equity Balance, Prior Year from Table 8 X 6%
12~ 1980 Power Supply Study, Draft 11981 and 1983 Debt Issues Reduced by One Half)
3) Estimates Provided by City Electric Utility - Includes Revenues from Lease of New Warehouse but Excludes Revenues From Penalties
4; internally Generated Capital • 8% (Gross Revenues - Fuel and Purchased Power)
Gross Revenues • X
X - (I - Fuel and Purchased Power) 08 • Revenue Requirement Before Adjustment
(5) ammount (8%)icalculated Iita (4). Anaadditionalsf765ro000 Is Included above 12% to
to ensure provide that proposed nratescge eratestotalcrevenueslmum
approximately equal to revenues projected from current rates.
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Tabu 1.1
CITY OF DENTON
PRUCTO CNANBE IN EQUITY
1979-85
00CRIPT;4N 1978-79 1979-80 1980-81 198142 1.982-83 1983-84 198445
Revenue (Excl. Aid to F~ist.) (1) 120,919,000 524,428,000 $27,6880000 $330431,000 $42,044,000 $43,884,000
Less, Expenses (1) 16,509,000 19,485,000 23,319,000 28,940,000 37,402,000 41,014,000
Less: Net Depreciation (2) 1,167,000 1,277,000 1,376,000 -IM IM 11565,000 1,667,90Q
Operating Income 3,243,000 3,666,000 2,993,000 3,019,000 3,077,000 3,153,000
Less: Interest Expense Old Debt
New Debt (1) 1,036,000 1,096,000 1.16S,000 1,205,000 1,254,000 1,301,000
Discretionary Transfer (1) 1,268,000 1,342,000 1,420,000 1,449,000 1,476,000 1.501.000
Net Income 939,000 1,218,000 418,000 36S,000 347,000 350,000
Plus: Contributions-In-Aid (1) 300,000 63,000 65,000 128,000 89,000 100,000
Net Change in Equity 1,239,000 1,291,000 483,000 4930000 436,000 450,000
Plus: Prior Year's Equity Balance 21,130,000 22,369,000 23,660,000 24,143,000 24,636.000 25,07?1
006
New Equity Balance $21,130,000 $22,369,000 $13,660,000 $24,143,000 $140636,000 325,072,000 31S,522,000
Prior Year Debt Balance 18,917,000 18,917,000 20,417,000 20,387,000 21,8S2,000 21,787,000
Plus: New Debt Issues (3) - 1,SO0,0D0 1,500,000 1,500,000
Less: Principal Retirement 30.000 35,000 65,000 75,000
New Debt Balance 518,917,000 $18,917,000 $20,417,000 $20,387,000 $21,852,000 $21,187,000 $23,212,000
Debt Ratio (Debt s Total Capital) 47% 46% 46% 46% 47% 47% 48%
N 1) First Year from City's Revised Estimate, Remaining Years from Table A
2) See Table D
3 1980 Power Supply Study, Draft (1981 and 1983 Debt Issues Reduced by One Half)
IRA
640
e it 5 Mal
Tab la I-C
CITY of DENTON
WORKING CAPITAL ANALSIS
1979-80 THRO11611 1984-65
1981-82 1982-83 1983-64 1984-85
1978-79 1979-80 1980-81 (000)
ASSETS aETenc - a ante Annual a ant nus ante n as ante ua ante ua1iT
Accounts Receivable (1) f 40160 S 4,470 S 5,283 S 6,024 S 76210 S 9,202 $10,041
Fuel Inventory (2) 1,005 1,176 1,382 1,040
Restricted Assets - Start of Period S 3,652 S 4,502 S 5,318 S 6,129 S 60911 f 7,687
Plus: Transfers from Operations 850 816 841 817 6'.1 836
Less: Principal Retirements (30) (3S) (65) (75)
Restricted Assets - End of Period 3,652 4,502 5,318 6,129 6,911 7,687 8,448
Other Current Assets - Start of Period 7,993 7,819 7,303 6,277 6,870 5,216
Plus: Net Income 939 1,228 418 36S 341 3S0
De reciation Expense 1,167 11277 1,376 1,472 1,565 1,657
Debt Issue Proceeds 11500 1 500 1,500
Less: Transfers to Restricted Funds (8501 `816) (841) )811) (841) (836)
Capital Expenditures (1,275) (3,221) (2,270) (2,733)) (2,316) (2,310)
Net Change - Cash Working Capital (155) (484) 291 806 (409) (178)
Other Current Assets - End of
Period 1,993 7,819 7,303 6,277 6,870 5,216 5,399
Net Plant - Start of Period 26,284 26,692 28,699 29,658 31,041 31,881
Plus: Capital Expenditures 1,215 3,221 2,270 2,733 2,316 2,310
Contributions less Amortization 300 63 65 128 89 100
Less: Depreciation Expense (11167) (1,277) (1,376) (1,472) (1,565) (1,651)
Net Plant - End of Period 26.284 26,692 28.699 29.658 31LW1 31.881 32.640
Total Assets $43,094 $44,659 547,985 $49,128 $ 52,098 553,992 $56,528
....s.
LIA8lt1T1ES i SYSTEM EQUITY
2,646 $ 2,972 S 3,507 S 4,197 5 5,209 f 6,732 S 7,393
urrent Liabilities (3 S.
Other Liabilities 401 401 401 401 401 401 401
Long Term Debt - Start of Period $18,917 $18,917 20,417 20,387 21,852 21,787
Plus: New Debt Issues 11500 1,500 1,500
Less: Principal Retirements (30) (35) (65) (75)
Long Term Debt - End of Period 18,917 18,911 20,417 20,387 21,852 21,787 23,212
System Equity 211130 22,369 23.660 24,143 24,636 251072 25,522
Total Liabilities 6 Equity $43,094 144,659 $47,985 $49,128 $52,098 $53,992 $56,528
.....s a.....
ill Revenue Excluding Interest Income and Aid to Construction x 22%
2 Current Year Fuel Cost x 14%
3 Current Year Operating Expenses x 18%
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Page 1 of 3
CITY Of DENTOM
DEPRECIA~~)ANALYSIS
OEPR leg' 1~PR-B1DEPR
PLANT NET
9/30/79 9/30179 RADEPR TE EXPPOLO ADDO HTHT S EXP-REI1 PLANT NET EPR VALUE PLANT EXP-OLD PLANT EXP-NN PLANT NET
VALUE PLANT
(1) (1) (L) PLANT (2) (5011) 9130/80 9/30/80 PLANT ADDINS (SO%) 9/30/81 9130181.
310 Land 1 Land Rights S 291 f 291 S 291
311-46 Production Plant $26,384 15,725 .0289 S 747 S 159 $ 2 $26,543 15,135 S 743 f 115 S 2 $26,658 $14,505
350-59 Transmission Plant 2,418 1,654 .031% 74 375 6 2,793 1,949 87 280 4 3,073 2,138
36U-68 Distribution Plant 10,10: 5,827 .04% 407 2,330 47 12,526 7,703 501 775 16 13,301 7,961
369 Services 924 446 .05% 46 45 1 969 444 48 50 1 1,019 445
370-71 Meters 919 502 .04% 37 254 5 1,173 714 47 45 1 1,218 71t
373 Street Lighting 1,151 513 .05% 58 34 1 1,185 488 59 66 2 1,251 493
378-99 General Plant (3) S87 93 .032% 19 6 593 80 19 1_1890 30 2,483 1.921
$42,579 $25,051 $1,348 $3,203 $62 $45,782 $26,804 $1,504 $3,221 556 $49,003 $28,465
Plus: zigzags
Depr. Exp. - New Plant 62 56
Less: Imo' r1w
Amortization of Unrealized
Increment $1,454 283 $1,171 283 5 888
Met Depr. ;xp. $1,167 $1,277
l Provided by City of Denton Accounting Department
2 includes 9130170 CIi1P Balances Obtained from Mork Orders and Orlyinal 1979/80 Budget Estimates
3 Includes $1.7 Million for Morehouse and Service Center in 1980-89
■■s IM
Table 1-D
Page 2 of 3
CITY OF DENTON
DEPRECIATION ANALYSIS
1981-82 (000) 1982-83
KW- EXP-NEW PLANT NET
DEPR EXP-NEW PLANT NET 6LPR
EXP-OLD PLANT PLANT VALUE PLANT EXP-OLD PLANT PLANT YAIIIE PLAN
PLANT ADOTNS (W%) 9/30/82 9/30;82 PLANT ADOTNS (W%) 9/30/B3 9130313
$291
310 Land S Land Rights
31t-46 Production Plant S 745 $ 50 S 1 $26,708 $13,808 $ 148 S 60 S 1 $26,768 $13,119
3,073 2,043 95 900 14 3,973 2,834
350-59 Transnlsslon Plant 95 '
532 1,612 32 14,913 9,009 597 1,260 25 16,173 9,647
360-68 Distribution Plant
51 54 1 1,073 441 S4 72 2 1,145 463
369 Services 1 1,326 711
370-71 Nuter$ 49 48 1 1,266 709 $1 60
63 80 2 1,331 508 67 93 2 1,424 532
373 Street Lighting S 3,197 2,451
378-99 General Plant _ 79 426 7 2.909 2,261 91 Y88
$1,615 $2,270 544 f51,213 529m01b $1,105 52,733 SSO $54,006 $30,054
sees" Aid:
Depr. Exp. - New Plant ^44
1,]55
1,659
Less: $322
Amortitatlon of Unrealized 283 $605 283
$1,376 1,412
Income Net Depr. Exp.
Table E-D
Page 3 of 3
CITY Of DERM
DEPRECIATION ANALYSIS
1983-84 1984-85
EXP-K£k PL VAANT K"
EXP-NEV PLANT NET DEPR
ENP~OtD PLANT PLANT YALIiE PLANT EKP-OLD PLANT PLANT LUE PLANT
PLANT ADOTKS (sox) 9/30/82 9/30/82 PLANT ADOTNS (50%) 9/30/83 (9/32913
$ 291
310 Land 6 Land Rights S + %26,877 $11,725
311-46 Prod-xtion Plant f 750 f 53 $ 1 $26,821 $12,421 f 751 % 56 - 4,053 2,664
350-S9 Transmission Plant 123 80 1 4,053 2,790 126
360-b8 Distribution Plant 547 1,665 33 17,838 10,632 714 1,240 25 19,018 11,133
57 7S 2 1,220 479 61 75 2 1,295 491
369 Services 1,396 733 S6 75 2 1,471 750
370-71 Peters 53 70 71 100 3 1,524 558 76 108 3 1,632 587
373 Street lighting 12 4,226 3.251
202 273 4 3.470 2.618 111 756
37g-99 General Plant
$oasis
51,803 $2,316 $45 $58,322 $30.122 $1,895 $2,310 So $58,632 $30.892
Add: 45
Depr. Exp. - New Plant 45 1,940
1,848
Less: 244
Depreciation Adjustment 0
MMrlittion of Unrealized 283 $39 39
increment S1,b57
Net Deer. Exp. $1,565
A '
r
777,
i l
777777777f~'
1
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 of conservation, efficiency 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
' customs~r groups according to the actual costs of providing electricity to
that group. Rates based on cost of service study results will represent a
significant st.po 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
1 and, as such, will increase as service costs increase.
o Efficient elr:ctricity production will be indirectly
' encouraged because a major goal of utility regulation is
r to ensure least cost construction, investment and fuel
purchase by utilities.
1 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.
i
1
For this study, we have utilized a traditional cost of service
methodology which includes the following four steps,
14 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 11-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
t 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 expected to
t change significantly during the study period, however, we have not
presented a complete customer class cost of service analysis beyond 1981.
' The tables in Sections 11-8 and 11-C show the results of our cost study for
' 1981.
' ASSIGN COSTS TQ FUNCTIONS
' The first major step in calculating cost of service to each customer
group is to assign a utility's costs to either the generation,
transmission, distribution or general function, Depending on the technical
' 18
s i
MIVVIFPTI~
77,
of the utility's systems further disa9gregation of costs into
configuration
subfunctions may be desirable for a mare precise further allocated between
groups. For example. distribution costs could .e furrther a
primary and secondary distribution costs according to voltage service
section
level. This concept is discussed further in the Rate Design se
relating to the large commercial customer class.
kitining,
Some costs, such as the cost of special facilities as street
directly a
instead they are assigne
are not classified by function;
directly related to
customer group. Costs that are identified os the t genbeing eral cost function.
to
1 these three functions should be assigned
Tables II-8-1 and II-C-1 show the assignment of general cost
the
' categories to each major function. The costs are taken directly from Revenue Requirements section of this report or from supporting
workpapers
provided by the Electric Utility.
CLASSIFY COSTS WITHIN 17TIONS
J the costs assigned to each function
As illustrated in Table tt A-1,
must be further classified as being one or more of the following. of meeting
o Demand-Related - The costs are fixed costetion of the
customer demands. These costs are the fun
' kilowatts (KW) of demand imposed on the generation,
transmission and distribution segments of the utility's
r system. The City of Denton does not currently have
adequate load data to accurately estimate the rtiative
'
peak KW loads of ea61 customer class. We have,
therefore, allocated demand costs as a function of
1
19
r "9 r .r. d°3 l a W t
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 distribution 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
' demand is required.
Total generation and transmission plant costs
' typically reflect the maximum system generation demand
requirement. An increase in customer demand 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 contrac':
' for additional 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
-7777-
t
' 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 generation 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 of 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 tie Rate Study, two cost of service
studies have been performed. For the basic seasonal
rates (Table I1-8), the City Steering Committee has
indicated a desire to have costs assigned based on the
1 relationship 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
1
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
' kilowctt-hours (KWH) produced to serve customer groups
' and are, therefore, allocated on an annual KWH basis.
Future purchased power costs from TMPA may include r
' 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 discourage 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 served 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
+ r*..It J
77777777
r
' The classification of generation, transmission and general costs is
relatively straightforward. However, the classification of distribution
r costs is more complex. One of the major methodological issues related to a
cost of service study is the classification of distribution system costs
t into demand and customer-related.
r Distribution costs can be divided between the demand and customer-
related categories or weighted to recognize the type of service provided.
r For example, the need for line transformers is a function of both 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
r are generally classified as customer-related. We have allocated all
distribution costs co the demand-related category but assigned a greater
r weight to secondary service customers to recognize costs associated with
' the additional distribution lines required to serve these customers.
Customer-related costs such as services and meters have been assigned
r to the weighted customer-related category to allow for differences in meter
and service drop costs between small and large customers. We have used a
r weighting factor of 2 for small commercial and 10 for large commercial 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
r Electric Utility.
r
r
r 23
r
77
t TABLE 11-A
1 COST OF SERVILE METHODOLOGY
■ AND ALLOCATION FACTORS
0
' 24
1
TABLE II-A-1
DISTRIBUTION OF TOTAL SYSTEM,COSTS
' GENERATION
' TRANSMISSION
1
DISTRIBUTION
t
' GENERAL
1
' ENERGY-
RELATED
DEMAND-
RELATED
' CUSTOMER-
RELATED
1
' CUSTOMER GROUPS
25
TABLE II-A-2
t CUSTOMER ALLOCATION FACTORS
UNwEIGHTED WEIGHTED 1
AD3UST D
NUKER OF N£IGHTIM CUSTOMER
CUSTOMERS PERCENTAGE FACTOR(j) FR. PERCENTAGE
Residential
49388 24.6% 1 4,388 21.7%
A-1 (2)
10.744 63.1%
1
A-2 (3) 10,744 60.2%
Commercial
1 507 2.5%
Single Phase 507 2.8%
8.5% 2 3,044 15.1%
Three Phase 1,522
' 8-2 (5)
Primary 10 200 1.0%
Service 20 0.1%
' Secondary 2 11242 6.1%
Service 621 3.5%
0.3% 2 92 0.5%
Public Authorities 46
TTw T". n-92V T-60--16%
1
(1) weighting Factor to recognize large meter and service costs of Commercial
' accounts
(2) 15,132 x 29%
3 15,132 x 71%
(15,132 total reesidential customers provided by Electric Utility
t (4) 2,670 x
(2,670 total commercial customers provided by Electric Utility
Single Phase, 2,029 x 25%
Three Phase, 2,029 x 75%
' (5) 20 670 x 24% a 641
641 - 20 • 621
' 26
ling! 'FRORT-77-,
TP.BLE II-A-3
CUSTOMER CLASS ALLOCATION
ENERGY ALLOCATION FACTORS
ANNUAL Midis
ANNUAL MW LINE GENERATION PERCENTAGE
CONSUMPTION LOSSES REED
Residential 4.4%
22,657 6.3% 16124,,180820 29.1%
` A-1 (1) 151,625 6.
A-2 (2)
t Commercial 256067 6.3% 26,752 4.9%
B-1 (3) 96,695 17.8%
1 B-2 (4) 92,247 4'6% 209,204 38.5%
Primary Service 196,024 6.3%
Secondary Service 3.8%
19,311 6.3% 20,619
Public Authorities 6.170 0+
4 841
Street Lighting 544,500 100.0%
511,841
(1) 174,282 x 13% tion provided by Electric Utility)
(1749282 total residential consume
l 2 114,282 x 87% provided by Electric Utility)
~3~ 313 338 x 8%
013,338 total commercial consumption p
1 (4) 313,338 x 92% ■ 288,211
Primary, 288,271 x 321
Secondary, 288,271 x 68%
27
v
TABLE II-A•4
CUSTOMER CLASS ALLOCATION
DISTRIBUTION ALLOCATION FACTORS
ANNUAL MWH DISTRIBUTION WEIGHTED
PERCENTAGE
GENERATION 1 FACTOR 2 DISTRIBUTION
A
' Residential
A-1 24,180 1.0 249180 4.7%
A-2 1619820 1.0 1619820 313%
t Commercial
26,752 1.0 269752 5.1%
8-1 (3}
B-2 4 77,356 14.9%
Primary Service 960635 0.8
' Secondary Service 209,204 110 209,204 40.2%
Public Authorities 201679 1.0 201679 4.0%
L Others
t 539,330 519,991 100.0%
t
' (1) Table II-A-3, Column 3.
(2) Primary distribution lines are estimated by Electric Utility to be 80% of
ao weighting distribution
factor s(0.8)mthateisf80%'ofrthersecondaryudistribution"customers
1
1
' 28
~_r' ■rriii-ir~i~ 1t#Ili~"
TABLE II-A-5
CUSTOMER CLASS ALLOCATION
CAPACITY ALLOCATION FACTORS
ANNUAL MMi SUMMER SUMMER SUMMER SUMMER MWH
CONSUMPTION CONSUMPTION MNH PEAK LINE GENERATION
(1} _ PERCENTAGE CONSUMPrIONMWH - LOSSES RE UIRED PERCENTAGE
Residential
A-1 22,657 33,3% (2) 70545 31395 6.3% 39623 3.5%
A-2 15I 16W26 26 47.7% (3) 75 588 (4) 34,015 6.3% 36,302 35.3%
Commercial
B-1 25,067
B_2 8,889 (5) 41000 6.3% 4,269 4.2%
Primary Service 92,247 43,8% (3) 40,404 18,182 4.6% 19,059 18.6%
Secondary Service 196,024 38.1% 3 74,685 339608 6,3% 35,868 34.9%
Public Authorities
b Others 19,377 40.5% (3) 7,848 30352 (8) 6.3% 7,949 3.5%
Street Lighting 4 1844 32.0% (3) 1 550
Total System 511,841 42.3% (6) 216,509 96,552 1020698 100.0%
1) See Table II-A-3, Column 1
2 Estimate assumes level monthly consumption
3 Customer Analysis provided by Electric Utility
4) Total Residential (83 133) - Residential A-1 (70545)
15) Total System (216,509 - Residential (83,133) - Commercial B-2 (115,089) - Street Lighting (1,350) -
Public Authorities b Others (7,848)
6 1979 Power System Statement - Page 25
7 Summer MwH Consumption x 45X
8 70848 - 400 (Estimated Dusk to Dawn Summer Consumption) x 45%
1
e :m'W~'4^•'
,y i t 7 ~7', n l tY t'•,Y r i
03
7-77 7~777,77
TABLE !1-B
' SEASONAL COST STUDY
1
1
1
1
30
77-i 77 - -7"
777 7777 7,77,
' TABLE 11-8-1
FUNCTIONAL ALLOCATION - 1981
(000)
' DISTRI- STREET
TOTAL CAPACITY BUTION CUSTOMER COSTS ENERGY LIGHTING
' COST COSTS C0_ -
PLANT (1) 5121,517
' Production $14,796 $2,219 19817
Transmission 2,138 321
Distribution 7,961 $1,961 $19156
' Customer 1,156 $493
Street Lighting 493
$26544 3~,3r4a 3'l, I 3T,I b ~T~,3 34
100% 9.6% 30.0X 4.3% 54.2% 1.9%
' EXPENSES (2) S 185 $ 2,338 $ 82
' Plant Related S 4,313 S 414 $1,294 69092
Purchased Power 6,092 9,871
Fuel 91871 793
Other Production 933 140
' Transmission b
Distribution 11046 19046
Customer Accounts 849
' b Sales 849
23,104 S 554 52,340 S 135 S 849 5191094 $ 82
100% 2.4% ' 10.1% 0.8% 3.7% 82.6% 0.4%
' Administration &
General 694 17 70 5 26 573 3
' 23,798 57 2,4 d 90 81 $19,661 1 85
1
(1) Table I-D, Page 1, Column 13
(2 Table I-A, Page 1, Column 1
31
'a ,Y r
i
TABLE 11-8-2
' CUSTOMER CLASS ALLOCATION
1981 CUSTOMER COSTS
' TOTAL
UNWEIGHTEO WEIGHTED CUSTOMER
t p~~ COSTS
~A (8) A+
Residential A-1 24.6% 5479000 ?1.7% $1901,000 $2379000
Residential A-2 60.2% 114,000 53.1% 465,000 519,000
' Commercial B-1
Single Phase 2.8% 59000 2.5% 22,000 27,000
' Three Phase 8.5% 165000 15.1% 132,400 148,000
Commercial B-2
' Primary Service 0.1% 29000 1.0% 9,000 11,000
Secondary Service 3.5% 6,000 6.1% 53,000 599000
Public Authorities 0.3% 0.5% 49000 4,000
' 100.0% $190,000 (3) 100.0% $875,000(4) $100659000
' (1) Table II-A-2, Column 2
(2) Table II-A-2, Column 5
3 Table II-B-1, Total of Column 4
(4) Table II-8-1, Total of Column 5
' 32
777777~7~', 7, 7 17,
TABLE 1I-B-3
1981 CUSTOMER COSTS
MONTHLY
CUSTOMER NUMBER COST BASED
' RELATED OF CUSTOMER
COSTS M CUSTOMERS 2 C Oj-E-
f
$4.50
Residential A-1 $237,000 49388
'
Residential A-2 579+000 109744 4.49
' Commercial B-1
507 4.44
Single Phase 27,000 19522 :.10
' Three Phase 1489000
Commercial 6-2
20 45.83
Primary Service 11,000 621 7.92
Secondary Service 59,000
'
Public Authorities 49000 46 7.25
' $1,065,000 17,848
1
(1) Table II-8-2, Column 5
(2) Table I1-A-2, Column 1
t
' 33
-.,V s s c . n V
TABLE 11-B-4
' CUSTOMER CLASS ALLOCATION
1981-DEMAND AND ENERGY COSTS
' ENERGY DISTRIBUTION
COSTS COSTS CAPACITY COSTS
' PERCENTAGE AMOUNT PERCENTAGE PERCENTAGE W NT
Residential A-1 4.4% $865,000 4.7% 5113,000 3.5% S 20,000
' Residential A-2 29.7% 51841,000 31.1% 750,000 31",.3% 2029000
' Commercial B-1 4.9% 964,000 5.1% 1230000 4.2% 249000
Commercial B-2
' Primary Service 17.8% 3,501,000 14,9% 3599000 18.6% 1069000
Secondary Service 38.5% 7,572,000 40.2% 9699000 34.9% 199,000
Public Authorities
b Others 3.8% 7470000 4.0% 96,000 3.5% 20,000
' Street Lighting 0.9% 177,000
' 100.0% $19,664,,000 100.0% $2, 5,,000 100% S 5711)00
(1) Table II-A-3, Column 4
(2) Table II-A-4, Column 4
3 Table II-A-59 Column 7
4 Table II-8-1, Total of Column 6
5 Table I1-8-19 Total of Column 3
(6) Table II-B-1, Total of Column 2
1 34
~ ash ,a f a C+~4+n aar;,54t i~4 ~np" hrMx
r ,
t TABLE I1-8-5
1981 - ENERGY COSTS
i
ANNUAL COST
r ENERGY MWH PER
COSTS 1 SALES 2 X_ w*B)
r Residential A-1 $8659000 229657 3.824
1510625 3.850
r Residential A-2 59841,000
Commercial 8-1 964,000 259067 3.854
' Commercial B-2
Primary 39501,000 92,247 3.804
Secondary 115721000 196,024 3.864
Public Authorities 199377 3.864
& Others 7479000
177,000 40844 3.650
Street Lighting
r $199667,000 $5119841
r
1
1
(1) Table II-8-4, Column 2
' (2) Table II-A-39 Column 1.
1
r
r
r
' 35
' TABLE 11-8-6
1981 - CAPACITY COSTS (1)
S"ER COST
1 CAPACITY MWH PER
COSTS 2 SALES M (K
Residential A-1 S 209000 79545 0.271
t Residential A-2 202,000 75,588 0.271
Commercial B-1 24,000 8,889 0.271
' Commercial B-2
Primary Service 1069000 405404 0.261
Secondary 1999000 74,685 0.271
Service
Public Authorities 20,000 7,448 (4) 0.211
$571,000 214,559
e
(1) Consumption for June through September - Excluding Street Lighting
(2) Table 11-B-4, Column 6
13) Table II-A-S, Column 3
t ~4) 7,848 - 400 (Estimated Dusk To Dawn Summer Consumption)
1
' 36
1 K v aJ: i~v7 5 M1` ~ ~ 'v ~'~ry71
' TABLE I1-8-7
' 1981 DISTRIBUTION COSTS
ANNUAL COST
DISTRIBUTION MWH PER
,
WH
COSTS 1 SALES 2 (KWH
Residential A-1 S 1139000 22,657 0.501
Residential A-2 7509000 1516625 0.490
Commercial B-1 123,000 259067 0.494
' Street Lighting 859W3 (3) 41844 1.751
ANNUAL
' BILLING
DEMAND KW
Commercial B-2
Primary 359,000 202,000 {4) $1.78
Secondary 9699000 451,000 5 $2.12
' Public Authorities
& Others 96,{100 55,000 (6) $1.75
' $2,410,000
' (1) Table I1-8-4, Column 4
(2) Table II-A-3, Column 1
(3 Represents $709000 of Directly Assi nable Costs from Table 1I-8-1, Column 7
(4 191,000 KW (12 Months Ended 4/30/80 x 1.06 {Growth Factor)
(5 4310000 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)
37
1 .
1
1 TABLE II-C
1 TIME-OF-DAY COST STUDY
1
1
1
1
1
1
1
1
38
' TABLE 1I-C-1
' FUNCTIONAL ALLOCATION - 1981
(000)
' DISTRI- STREET
TOTAL CAPACITY BUTION CUSTOMER COSTS LIGHTING
COST COSTS COSTS G T U H ENERGY DIRECT
PLANT (1)
' Production $14,796 $14,796
Transmission 20138 20138 $70961
Distribution 7+961 S1,156
' Customer 1,156 $493
Street Lighting 493
f3
'96 944 3` ~T, ~f 3T;1
100% 63.8% 30.0X 4.3% 1.9X
S 82
EXPENSES (2)
Plant Related S 4,313 $ 2,752 $1,294 S 185 $6,092
Purchased Power 61092 91871
Fuel 9,871
Other Production 933 933
Transmission b 1,046
Distribution 19046
Customer Accounts 849 849
b Sales
'3-55 3~3da ~~S '~4 3I€ 82
100X 15.9X 10.1X O.SX 3.7X 69.1X 0.4%
' Administration & 26 480 3
General 694 110 70 5
1 3-23-D7 F8 TT, _M5 16,4 3 85
1
' {1} Table I-D, Page 1, Column 13
2 Table I-A, Page 1, Column 1
1
' 39
il '177
-..c. -
w TABLE II-C-2
CUSTOMER CLASS ALLOCATION
1 1981 CUSTOMER COSTS
' TOTAL
UNWEIGNTED NEIGHTEO CUSTOMER
_
P RCENTAGE 2 S C0-105)
Residential A-1 24.6% $47,000 21.7% $190,000 $237,000
'
Residential A-2 60.2% 1149000 53.1% 465,000 379,000
' Commercial B-1
Single Phase 2.8% 59000 2.5% 22'000 27,000
Three Phase 8.5% 16,000 15.1% 1329000 148,000
1
Comwrrial B-2
' Primary Service 0.1% 21000 1.0% 90000 11,000
Secondary Service 3.5% 6+000 6.1% 53,000 59,000
t Public Authorities 0.3% - 0.5% 49000 41000
100.0% $1909000 (3) 100.0% $6759000(4) $1,065,000
1
t 11) Table 1I-A-21 Column 2
2) Table I1-A-2, Column 5
' 3 Table 11-C-1, Total of Column 4
4) Table II-C-1, Total of Column 5
1
' 40
.n .c ! b'.,As".` Ma TABLE 11-C-3
' 1981 CUSTOMER COSTS
MONTHLY
' CUSTOMER NUMBER COST BASED
RELATED OF CCOSTSM- CUSTOMERS(2) CHARGE
(A- )
' Residential A-1 5231,000 41388 $4.50
Residential A-2 579,000 109744 4.49
Commercial B-1
Single Phase 279000 507 4.44
' Three Phase 1489000 11522 8.10
Commercial B-2
Primary Service 119000 20 45.83
Secondary Service 59,000 621 7.92
' Public Authorities 40000 46 7.25
' $190659000 119848
(1) Table II-C-2, Column 5
(2) Table I1-A-2, Columii 1
41
SPCA'.%_ 1`~ 5l u?
41
t
TABLE II-C-4
CUSTOMER CLASS ALLOCATION
1981-DEMAND AND ENERGY COSTS
' ENERGY DISTRIBUTION
COSTS COSTS CAPACITY COSTS
PERC NTAGE OUNT DE_ OUNT RC N~
Residential A-1 4.4% 5723,000 4.7% $113,000 3.5% $133,000
Residential A-2 29.7% 49884,000 31.1% 750,000 35.3% 19340,000
Coiwrcial 8-1 4.9% 8069000 5.1% 123,000 4.2% 1609000
Commercial 8-2
Primarce 17.8% 2926 000 14.9% 359OOO 18.6% 705000
econdaryeService 38.5% 6,331,000 40.2% 969,000 34.9% 1,3249$000
t S
' Public Authorities 3,SX 625,000 4.4% 96,000 3.5% 133,400
& Others
Street Lighting 0.9% 148,000
100.0% 51694431000(4) 100.0% $2,410,000(5) 100% $3,795,000(6)
1 TiTable 11-A-3, Column 4
ble Ii0A-4, Column 4
13) Table II-A-S, Column 7
4 Table 1I-C-1, Total of Column 6
5 Table 11-C-10 Total of Column 3
) Table II-C-1, Total of Column 2
' 6
4 '
17 I~ . fN M Y .1L ~ d1 rJ.1 4 1 i'- ,r
' TABLE II-C-5
' 1981 - ENERGY COSTS
ENERGY ANNUAL
PERT
COSTS 1 SALES 2 K,~ Vl_
1 .
hesidential A-1 $723,000 22,657 3.19#
' Residential A-2 408849000 151,625 3,22`
Commercial B-1 8061000 25,061 3,220
Commercial B-2
' Primary 2,926,000 92,247 3.179
Secondary 69331,000 196,024 3.230
Public Authorities
r b Others 6259000 19,377 3.23¢
Street Lighting 1489000 49844 3.061
$1694439000 $5110841
1
1
' (1) Table II-C-4, Column 2
(1) Table II-A-39 Column 1.
1
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My i ti .r. If to
Y p :9 IL r
r
TABLE II-C-6
' 1981 - CAPACITY COSTS (1)
SUMMER
AK MWH COST
' CAPACITY PE
COSTS 2 SALES M PER
' KMiH
Residential A-1 $133,000 39395
3.921
Residential A-2 1,340,000 349015 3.941
Commercial 8-1 160,000 40000
' 4.001
Commercial 8-2
' Primary Service 7059000 18,1b2
Secondary 3.881
Service 1,3249000 33,608 3.941
' Public Authorities 1339000 39352
3.971
' $39795,000 96,552
1
r
I
' (1) Consumption for June through September - Excluding Street Lighting
{2) Table II-C•4, Column 6
3 Table II-A-59 Column 4
1
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1
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44
177,7. F-3 ~f1 +ti
' TABLE 11-C•7
' 1981 DISTRIBUTION COSTS
' ANNUAL COST
DISTRIBUTION MWH PER
COSTS 1 SALES 2 KWH
' (Af9T
Residential A-1 S 113,000 22,657 0.501
' Residential A-2 750,000 1519625 0.501
Commercial B-1 1239000 25,067 0.491
Street Lighting 85,000 (3) 40844 1.751
ANNUAL
BILLING
' DEMAND KW
Commercial B-2
' Primary 359,000 2029000 (4) $1.78
Secondary 969,000 457,000 j5 $2.12
Public Authorities
b Others _ 96,000 559000 (6) $1.75
' $2,495,000
1
1
' (1) Table I1-C-4, Column 4
2) Table II-A-3, Column 1
3 Represents 570,000 of 0lrectly Assi nable Costs from Table I1-C-1, Column 7
1 4 191,000 KW (12 Months Ended 4/30/80 x 1.06 (Growth Factor)
5 431,000 KW 12 Months Ended 4/30/80 x 1.06 (Growth Factor)
6 529000 KW (12 Months Ended 4/30/80) x 1.06 (Growth Factor)
45
1 ii 1. . 'l .'~1 i:T ~ ~i,,: M.. F. R n.Wy♦ 1 '.0 n'e R.kJT i, ~ ~a ~ ~
h
TARIFFS
The analysis of the rate design and regulatory standards promulgated
' by the Public Utilities Regulatory Policy Act of 1918 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 includod in Appendix A.
The proposed rates have been designed to collect the overall revenue
requirement of the utility, to reflect the cost of service, to reflect the
1 PURPA objectives of conservation, efficiency and equity and to ensure that
the rate structure sand rate levels in Denton are not drastically different
than rates offered in the surrounding areas.
t In addition, 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 coincident with the need to finance the increase in the
' fuel and capacity costs. As such, it is quite likely that the City Council
will be requested to approve additional rate adjustments in the next few
years. We are not able to accurately e,timate the size of these
' adjustments. It is highly likely that the increase in the economic
activity within the Denton commurity will temper the magnitude of the
46
1
__J
ti N i ' r r 0' .v ~ v d y i i, WE i
s an
increases, Tho need for an annual review of electricity tariffs
to
excellent opaortunity for the City Council to consider rate Ince fs
conservation and equity-
promote efficiency►
An additional consideration is the effect on Denton electricity from
urc
tariffs resulting from the tariff under which electricity is p
1 it 1s not
TMPA. This tariff has not been determine to ing date. Therefore current tariffs i1f it is
appropriate to engage in a major rest uctur
1 highly likely that these may require significant change to reflect Denton's
tariffs will both
' purchases from TMPA- We believe that our proposed
recover the required revenues and provide adequate incentives to promote
1
conservation, efficiency and equity as required by PURPA.
PURPA requires that seasonal differences in cost be recognized
Denton
1 electric utility's rates charged during the different seasos
Electric Utility is clearly a summer peaking system and, as such, incurs
1 if it adds demand during the summer peak
additionalcapacity costs only
period.
The cost of service study indicates that the summer peak is rgy an
capacity costs are approximately double the off-peak energy cos Time~
of-day rates reflecting this cost variance should encourage conservation
during the peak period. approximately a 0.1Q lower
' Current rates for residential service offer app The City
rate for winter consumption over 100 KWH for electheating,
that the
' Steering Committee directing the electric rate study believes
current discount for electric heating during the winter can be reduced with
1 the introductiin of seasonal rates. We recommend that the period in which
the winter electric heating discount applies be restricted to only the
' 47
r ,
winter heating peak period of December through February., We, therefore,
r recommend the adoption of a summer/winter rate differential of ON and an
additio~ial 0.U discount for residential electric heating customers for
consumption over 1000 KWli 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, introdupl~- seasonal price signals to all
' customers and to continue to offer the electric heating customers a
substantial winter price break.
' The sum mer/winter rate differential of 0.-3'd it our proposed electric
tariffs means that the proposed rates have a combined summer energy and
capacity charge approximately 0.3d higher than the winter energy and
r capacity charge. We have also proposed that this summer/winter
differential be extended to all electric customers except for street
r 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 a 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
I provide a better distribution of total costs between the small and large
48
71-77
h
' residential customers. We have, therefore, proposed comparable KWH charges
t for the Residential A-1 and A-: customer classes.
The PURPA regulations specifically state that a utility is not
t 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
1 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 100 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-1 tariff. The reduction
1 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 8-2,
applicable to larger customers whose monthly demand exceeds 20 kilowatts.
Tte electric utility management estimates that approximately 75% of
d9
1
Y
1.
' 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
t 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 (8-2) 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 st+idy with a
larger portion of the distribution system costs being allocated to
' customers receiving secondary service. Since all the customers in the
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
' s0
777
i higher demand charge.
' Local Government Service
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
produce electricity for any use depending on the time the electricity is
' used 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
departments, county government and local school districts.
t The City Steering Committee directing the electric rate study has
indicated a desire for a special local government tariff to recognize the
' lower operating costs that result from the City Electric Utility's
' exemption from local property and school district taxes. The present local
government rate does not include a monthly demand charge.
t 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
corsumption will still receive the appropriate price incentives through the
application of the proposed summer/winter differentials. Lower summer
t consumption under rates which include a summer/winter differential will
51
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
t adjustment is recommended and reflects the average KWH consumption for each
bulh wattage.
t Time-of-Use Rates
r 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 from different generating plants (with different
' efficiencies and different fuels purchased at a different price per BTU)
incur increasing costs as the customer's load increases. This assumes that
the plants are economically dispatched so that those plants with the lowest
' 52
~..~.ti;-.x 'f-~ ~•--a-i---:h,- ) --F .fir-i=^-~-;nt t ' ~''~",'F"i~~;--------y.~ -i-+,"v.
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
1 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
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 be 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
i
Y 5i rV{{4ylI:.r Y.. a r..~i ~sb;rV tlY
' distribution Racilitie ,
5 The total costs the utility incurs to meat
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 costs. TOU meters are currently available and priced from $65 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
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 pe-mit YOU recording. 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
chargn included in the TOU rat,:s.
Time-of-Use Rate Meth udcloav
The methodology used to estimate TOU rates requires access to load and
fuel related production cost data by hours and load level for the 8,760
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 gene;-ation and transmission system are not now available for the
54
t _ ! Y '4 7 1 i.. 7 M Y'i di j~ 4°, n r~ fa q¢., I ° 1 a t b~ h`t r t~Pw f 1 i'i .'V 1 1~
S ' I 4 ie~ 1 1 I'~ 1 1
Denton electric utilitys
ilable data sources and identified that the annual
We have reviewed ava
The data reveals
peak will occur during the months June through September.
that the system will peak during the weekday hours 12 noon through 9 p•me
All othar hours are defined to be off-peak.
' The development of the time-of-use rates assigns the fuel related
Distribution
costs incurred to deliver electricity to each time period. related
the year. All capacity
costs are assigned to each KWH taken during
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 cost of service determined in the cost of service 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
This charge is to collect
t charge is included in the TOU tariffs.
separately 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 ;,y time-of-use and losses and not
by the ultimate use of electricity by a customer.
t
' 55
e
' Cogeneration Tariffs
We recommend that cogeneration of electricity be defined as broadly as
t possible to promote the innovative use of alternative energy sources. As
such, the cogeneration tariff should set out that the Ci,:y 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
' tarifif wherein the cogenerator must both purchase and sell to the City
under the same schedule. The same tariff schedule avoid;: the
' discrimination issue which may be raised if separate sale and purchase
schedules were offered to the cogenerator.
' A relevant issue to be addressed in the cogeneration tariff is the
' technical characteristics of the electricity to be 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 safety standards. The
cogenerator should 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
M V + Y..rv ''f{{.D
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
t 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 do not exist and the
customer chooses not to interrupt his service. If interruption is
' requested but the 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.
' Ener Cost Ad ustment
' The present fuel adjustment clause has an inherent two month lag
between the time fuel costs are incurred until the excess costs are
' 67
f e t, rm
r
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 whic'n caused the increase in fuel
costs.
r We have recommended a modified energy cost adjustment that eliminates
the billing lag for fuel costs and better matches the timing of fuel and
r 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
r 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 oi
r decreasing the customer's total electric costs.
We have also modified the energy cost adjustment to compute the excess
' costs based on nergy 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 tnis later modification will
' make the energy cost adjustment easier for customers to understand.
r
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77
■ APPENDIX A
PROPOSED ELECTRIC TARIFFS
1
1
1
77
PROPOSED
' ELECTRIC RATE SCHEDULES
' Residential Service Rate
Schedule A-1
' (1) Net Monthly Ra_ te:
Billing months of June through September:
' All kWh @ 4.650 per kWh
' Billing months of October through May:
All kWh @ 4.351 per kWh
Energy billed during each of the months of December through
February which is in excess of 1000 Kkh will be supplied at
4.15$ per KWh if the entire home is electrically heated heat
' pump or resistance,
(2) Customer Facilit Charm m $2.50 per month
(3) Avaitability_
Rate Schedule A-1 is applicable to all electric service required
' for single family residential purposes where usage is not i.i
excess of 700 kWh per month during the bi I Iing months of June,
July, August, or September. In any such month usage exceeds
700 kWh, billing will be rendered that month under kzte Schedule
year d ending extending September through 30the 12 billing
and thereafter
months of the next fiscal
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, August or September r:xceeds 700 kWh
times bbe rendered units, r t Rate billing Schedule A2h at month
and thereafter will
' {Ql .Service.-
At, the utility's available secondary voltage and phase.
(5) pa ant:
' Billing for service hereunder will bo at the net monthly rate,
payment of which is due when bills are iss:ied. Bills which are
not paid within ton (10) calendar days from the date of issuance
' thereof will be considered overdue.
1 A-1
6 Energy. Cost M ustme^ nt:
All 9chirges of the
g to net
current energy adjustment increased clause. or
decreasd
'
(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.
1
r
A-2
j, r 7- ~7T
K,
Residential Service Rate
Schedule A-2
' (1) Net 1kntb-11 Rate:
' Billing months of June through September:
All kWh @ 4.65¢ per kWh
Billing months of October through May:
All kWh @ 4.351 per kWh
' Energy billed during each of the months of December through
February which is in excess of 1000 KWh will be supplied at 4.151
' per KWh if the entire home is electrically heated - heat pump or
resistance.
' (2) Customer Facilit 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) lner Cost AdSustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
' (7) Special Facilities:
' All services which require special facilities in order to meet
the customer's service requirements sl:all be provided subject to
special facilities rider,
A-3
r t
77,
i
t
Commercial and Industrial Lighting and Power Service Rate
Schedule B
(1) Net honthly Rate:
Demand Char e:
Primary Service: $1.80 per month per kW for all kW of billing
demand.
Secondary Service: $2.10 per month per kW for all kW of billing
' demand.
Energy Char e:
Billing months of June through September:
Primary Service: All kWh @ 4.10$ per kWh
Secondary Service: All kWh @ 4.15¢ per kWh
Billing months of October through May:
Primary Service: All kWh @ 3.80Q per kWh
Secondary Service: All kWh @ 3.854 per kWh,
(2) Customer Facility Charge:
Primary Service: @ $46.00 per month
Secondary Service: @ S 8.00 per month
' (3) Availabil
' Available to commercial and industrial users except that service
hereunder is not availabl,: for resale, breakdown or standby
power.
i (2) Billing Demand:
Equal to the~Nnload metered
moduring the 15-minut nthly billing ~eriode period of
' maximum use during the current
(5) Payment;
Billing for servictc hereunder will be at the net monthly rate,
payment of which is due when bills are issued. Bills which are
t not paid within ten (10) calendar days from the date of Issuance
thereof will be considered overdue.
' (6) Ener Cost Adjustment:
All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
1
1 A.4
M irrr''&~y,
ll a~ .a a
777777o",
(T) Power Factor Peaui rements and ad ustments:
The t:tility reserves the right to make tests to determine the
t power factor of the user's installation served hereunder during
periods of maximum demand or by measurement of the average power
' factor for the monthly billing period. Should the power factor
the demand for
so determined be below ninety (90%4 percent.
billing purposes will be determ ned by multiplying the
uncorrected kW Billing Demand by ninety (90%) percent and
' dividing by the determined power factor.
(B) Alternate primar service and Discount Transformation Equipment
1 ne t e_ ser
Primary service will, upon request, be made available to users
with a twelve (12) month average monthly demand of '150 kW or
' greater. Primary service will be rendered at one point on the
the i option voltage of the utili2ty0 volts or 69,000
user's at nominal
volts
When the alternate primary service is supplied, the user shall
own, operate and maintain all facilities necessary to receive
primary service and all transformation acilutiies equir door
conversion to utilization voltage. The lity shall wn,
metering iatathemutility'sf option). (either primary or
seeondary and
' Where the user owns, operates and maintains the trans iformation
equipment and where the utility elects to apply
facilities on the high voltage side of such transformation
Charge3 fifteen (15X) percent
from the user will be
monthly Demand allowe
reduction equipment,
Where the user owns, operates and maintains the -itss forma ion
equipment and where the utility elects to arp y
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
in the user's thirteen facilitzes~erce>>t being the
fifteen fo~) losses ercent
allowance
(9) S ep 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.
1
A-S
t 7-7
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Governmental Lighting and Power Service kaN
e Schedule G-1
(1) Net Monti Rate:
Ener9 Charge;
Billing months of June through September:
All kWh @ 4.154 per kWh
Billing months of October through May:
All kWh @ 3.85$ per kWh,
(2) Customer Facilit 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) PaLment:
Billing for service hereunder will be at the net monthly rate,
p,yment 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) EneEU Cost Adtivstment:
All charges of the net monthly rate wi',1 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 !,e provide: subject. to
' special facilities rider.
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Dusk-to-Dawn Lighting
' (1) Net Monthly gate:
100 watt Sodium Vapor Lamp @ $6.15
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 sill install or cause to be installed one
(1) poll for each installed light, at a distance not to exceed
' eighty (601) 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.
t (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 fvrnish, 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
t not paid within ten (10) calendar days from the date of issuance
thereof will be considered overdue.
(5) Energy Cost A 1211ment:
All charges of the net monthly rate will bL 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 bas's and may
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i be cancelled by either party upon thirty (34) days notice.
(7) Special Facils's
All service which requires Pel-ts shalillbeiprovided d subject meet
the customers service requiremen
special facilities rider.
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Time-of-Use Rates - General Seritice, 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. @ 7.200 per kWh
9 P.M. through 12 Noon @ 3.204 per kWh
t Billing months of October through May:
All kWh @ 3.204 per kWh
(2) Customer Facility Charge:-
Single Phase @ $7.50 per month
Three Phase @ $12.00 per month
' (3) Availability:
Rate Schedul: 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 utility's available secondary voltage and phase.
t (6) Pa nt:
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 (:0) 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) 5_pecial, Facilities:
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the customer's service requirements shall be provided subject to
1 special facilities rider.
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F771 77"777777 1 77~ s
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Time-of-Use Rates - General Service, Primary
Schedule P-1
(1) Net ___th._I Rate:
Demand Char e:
$1.80 per month per kW for all kW of billing demand
Ener Char e:
Billing months of June through September:
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12 Noon through 9 P.M. @ 7.050 per kWh
3.15 per kWh
9 P.M. through 12 Noon
' 811ying months of October through May:
All kWh 3.15¢ per kWh
'
(2) CustomE`r Facilities Char e: $60.00 per month
1 (3) AwaiIabI111
Rate Schedule P-1 is applicable to approved electric service
levels not
and b billing voltage
required 69 primary 00 volts distribution
to exceed greater
t to
than 20 kW-
(4) Billing Demand
from maximum use
d Noon
The k'ri tload metered durin he current month's tpeak5billing periods of
during the
1 through 9 P.M.
(5) Service:
At the utility's available secondary voltage and phase.
(6) P enter under
at the net ateo
Billy r
which
Billing f o which iseduher e when thew billseare received.monthl
payment of
overdue.days from the date o
are not paid i i m 1 be 11ron sideredcalendar
issuance thereof will
' (7) Ener Cost Adius_, t._me_
All charges
according to the current energy adjustmentncla0s6 or
decreased d
(8) S e_Q„c1a1 Faci_ _ 1 S_
All service which requires special
shall mbeiprovideddsubje t to
the customer's service requirements
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' Interruptible Service Rate (primary service for a firm power load
exceeding 6*000 KYA in June, June, July or August)
(1) Net Mont hl Rate for Firm Power:
e pemand Char e:
$1.80 per month per kW for all kW of billing demand
' Energy Chafe
Billing months of June through September:
All kWh @ 4.1¢ per kWh
t Billing months of October through May:
All kWh @ 3,8¢ per k'wii
' !2} Net MontillZ Rate for Interruptible Load:
When the E' ectric Department requests a customer to interrupt
load and the customer elects fnot or to all kW interrupt andhkWh is the Electric
following, rates shall app y
Departme+it requests to be interrupted:
' Demand Char e:
The actual cost of al l kW purchased by the Electric Department
' necessary to ser-;ice the customer's load adjusted for losses.
Ener Charge:
i'he actual cost of all kWh purchased by the Electric Department
necessary to serve the customer's load adjusted for losses.
(3) Customer Facllit Charge:
' $46.00 per month
(4) Availability
taki
ers
Avai abl
ice power loadfexceeding 5,000 KYA during theamonthsvof June,~June,
power to
July and August.
' (5) Billing Demand:
The kW load metered during the 15-minute period of maximum ise
t 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
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required to be curtailed. The request shall be 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
1 notification.
(7) Pa nt,.
' 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 f ron the date of
issuance thereof will be considered overdue.
(8) Ener Cost diustment=_
' All charges of the net monthly rate will be increased or
decreased according to the current energy adjustment clause.
' (9) 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.
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Energy Cost Adjustment
All monthly kWh charges shall be increased or decreased by an
amount equal to "0 cents per kWh.
The energy cost adjustment applicable to the monthly dusk-to-dawn
multiplied
lighting charge by following factor shall corrsponding amount to equal bulb wattage.
'
bY
' Bulb Wattage Factor
115 145
4
' 250 104
400 162
' a+b+ d fe,-~ -0.03
"x" = c
' a - Estimated next month's cost of fuel u,ed 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 wo 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
1 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. non-Denton £ ectre, and h ic Department exclude jurisdlctionl associated customers. sales
to
2. ec~urlsdictionalccustomerssales to non-Denton Electric
Department
faccharges illties.included in purchased power
t 3. Euwerncosts andarentalxchargesdemand
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Special Facilities Ride::r
' (1) Apclicabili,~X
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
1 providing service to the customer.
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' APPENDIX B
t COMPARATIVE ELECTRIC COSTS
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RESIDENTIAL - SUMMER
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~60
Texas Power and Light
r city of Denton
Community Public Service Co
Denton County Electric Coop
120
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ISO
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140
120
~IO
S00 KWh 1004 XWh 2000 KWh 3000 KWh
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RESIDENTIAL - WINTER
SPACE HEATING
$160
l
$120
Denton County Electric Coop
Community Public Service Co /
1
City of Denton
Texas Power and Light
80
44
1$ 20
10
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2000 KWh 3000 KWh
500 KWh 1000 KWh
8-2
- MAWAM
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' tmzRAL SERVICE - SUMMER
401 LOAD FACTOR
,600
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Texas Power and Light
City of Denton
Community Public Service Co
11 200
Denton County Electric Coop
800
$ 400
200
100
15,000 Kwh 25,000 KWh 35,000
5,000 KWh Kwh
r GENERAL SERVICE - WINTER
40% LOAD FACTOR
~ 1600
' Texas Power and Light
' Denton County COOP
$1,200 Community Public Service Co
City of Denton
800
1
400
200
100
' 25,000 KWh 35,000
50000 KWh 15,000 KWh KWh
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1 APPENDIX C
1 BILLING AND COLLECTION POLICIES
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PROPOSED
t BILLING b COLLECTION FUR 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:
the of of Denton tUtfor the past ility System or eanomonths
ther
(1) with record
1 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 ;eater 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 is 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 account, a personal
guarantee may be accepted in lieu of a deposit. 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, nc
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) Aftsr making application for service, the customer service
department may have to pursue a credit reference check. The
customer will bi given service promptly after application,
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but if the credit check proves negative, the customer will
be required to produce a co-signer or place a deposit.
Failure to do in of the
notification to the
1 service with no less than two d
prospective customer by the customer service department.
(d) requesting o water $10.00 w I be service a to a transfermfee
from one location to anothe9 customers for
transferng will
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(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 I, 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 Denton's Cashier Office by close of
business on the due date regardless of the postents e date
in order to avoid assessment of a penalty. pym placed
on m the due d date. will not be
in the mail a,nd receivedpostmark
considered as being
' (b) Discontinuance 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
r will be rated "A". and a customer with an outstanding past
due balance will be rated "B".
' (1) customer a'paid rating in full by the eduesdatected
if his account is not
due disconnected if his
(2) customer Bnfull rating by may be
in
account is of paid
(c) Notice of Termination for Customers With a "B" Rating. A
t customer with a "B" 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 permitted to des_ig_nate a
consenTn _Ty-Ma l which shall also receive a copy o al l
notices of discon-Ce 7ion~mnRe ~o,te t_ at7ie s e Co t- Fe
' cus omer. T rye no ce w n
shouted ntact the customer service department of the City
of Denton 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
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service provided by the City. If full payment has not been
made customer approximately tagain five be (6) days of e podate the
ssible
' termination and his alternatives.
' (d) Alternatives to Termination of Utility Service. A customer
with a "B" 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 aggreement that would require payment
of at least fifty (50%) 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 be referred 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 desiyiated
representative if they are unable to attend a meeting.
The Utility Account Review Committee is authorized to
develop a deferred payment agreerent beyond the six (6
' 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 will be
' processed.
(e) Certain Adjustments thly bill because of ' any water adjustment
or m electric 1 leak a
in any mon 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, either house or apartment shall have a
separate water meter AND ELECTRIC METER and a separate
service connection to the city sewer lines; provided,
' hiwever, that multiple dwellings containing less than five
(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 unis ervice facilities shall be tclhave assified separate
metering and s as
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t commercial buildings for utility purposes and shall be
billed under the applicable commercial rates for water and
' sewer service.
Each residential and commercial unit in a multi le occupancy
B-Md n an eac mob a ome union a mobile home ark, in
' w ich construction of tine b_ i Unn or ~ark_ was ee un after
e ruars+ 1980 wM T'ave an idivfdual me3er o measure
We evera conSu~rp on and deman commerEJ-&r ndIndustrial
customers attributab e to each un- I IL #r tie
following:
' For transient mul le occu anc buildings and
transient n g u no wimfie3
mo a -home Aarks nc u
to hotels motels, dormitories roomin houses
1FOS itals nursin homes, and mobile home parks for
i travel tra ers.
2) For commercial unit _sDace which is subject to
alteration with cFian a in tenants as ev eence D
u s ed-#rom permanent yFe_ o oad
l:em orar as-dish fn -
bearing wall and floor construction se aratfg the
' commercial unit sMaces'
u Where electricity is utilized in connection with
central heating, vents ating and air conditioning
t sus t?ms_ .
in common building areas such as hallways-1- elevators)
reception areas and water um in acs t es.
(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.
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