HomeMy WebLinkAboutAgenda Packet - September 24, 2007 G i
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AZUSA
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AGENDA ITEM
TO: HONORABLE CHAIRPERSON AND MEMBERS OF THE AZUSA UTILITY BOARD
AND AZUSA CITY COUNCIL
FROM: JOSEPH F. HSU, DIRECTOR OF UTILITIES
DATE: SEPTEMBER 24, 2007
SUBJECT: ELECTRIC RATE ADJUSTMENT COMMENCING OCTOBER 1, 2007
RECOMMENDATION
It is recommended that the Utility Board/City Council adopt the attached resolution approving
a 5% electric rate adjustment effective October 1, 2007.
BACKGROUND
In May 2006 staff provided electric utility financial projections for the next five years. It was
identified that the electric utility will require revenue enhancement of 5% commencing FY 07-
08 to fund ongoing electric utility operations. Staff updated the financial projections recently
and the same conclusion still holds. The findings of the need to adjust electric retail rates
were previously presented to Utility Board/City Council at the July 23th Utility Board meeting.
The increased revenue requirement is primarily driven by: (a) increased cost of complying with
California Independent System Operator's (CAISO) resource adequacy requirements; (b)
increased cost of complying with California's mandate for renewable energy; distributed solar
power; and energy efficiency programs; and (c) increased cost of transmission and generation
of electricity.
In view of the need to adjust rates to ensure revenue adequacy in the coming years, staff
conducted a comprehensive review of the allocation of cost of providing electric services to
the various customer classes.
This review differs from the rate adjustments made in the past in that the review starts with a
bottom-up review of cost causation factors of the electric utility cost of services to the various
customer classes and attempts to allocate costs based on cost causation principles. The rate
adjustments done in the past applied an across-the-board rate increase without regard to
cost causation principles, i.e. the presumption is each customer class contributes equally to
cost incurrence.
Staff's bottom-up review shows that cost incurrence attributable to each customer class a g a,
the resulting cost obligation by each customer class is not uniform across customer cls s./(
0 .1d(6
As detailed in attached staff's report and the presentation, the resulting rate adjustments by
y
customer class to yield a 5% overall revenue increase are as follow:
Residential customer class 4.6% increase
Small commercial G 1 class 5.0% increase
Medium commercial G2 class 5.5% increase
Municipal class 7.0% increase
Large TOLL class 6.0% increase
It should be noted that the contributions to cost of service by each customer class are very
likely to change over time as the customer usage patterns and the relative usages among
customer classes change. Thus, staff will periodically review the cost of service studies to
ensure that appropriate and accurate cost of service allocation among customer classes is
used.
FISCAL IMPACT
The proposed rate adjustments effective October 1, 2007, are expected to add about
$1,000,000 in FY 07/08 and $1,500,000 annually thereafter to the electric utility's revenues to
fund ongoing electric utility operations.
Prepared by:
Bob Tang, Assistant Director of Resource Management
Li Ei!li .
ElecRateAdjust.ppt Retail Rate Cost Electric Rate
Allocation Stud ies.doc Resolution.doc
058
Electric Utility Rate
Adjustment
9/24/07
Outline
• Updated five-year financial projections
• Cost allocation studies
• Rate adjustment
• Rate impacts to various retail customer
classes
� 2
Updated Five-Year Financial
Projections
Minor updates to the previous financial projection
presented to the Board on May 22, 2006. The minor
updates are (a) use the estimated actual costs and
revenues for FY 06-07; and (b) higher depreciation
Retail Rates
Bond Interest
Depreciation 2%
4%
GF Transfer
10%
Customer Service r Purchased Power
5% u 59%
Distribution
16% .'
Transmission
4%
CD
0)
3
Updated Five-Year Financial Projections
Basic conclusion still holds:
ADDITIONAL 5% REVENUES OR ABOUT
$1 ,500,000 PER YEAR IS REQUIRED BY NO
LATER THAN JANUARY 1 , 2008 TO
PROVIDE SUFFICIENT FINANCIAL
RESOURCES TO FUND ONGOING
ELECTRIC UTILITY OPERATIONS AND
COMPLY WITH VARIOUS REGULATIONS
0
N 4
Updated Five-Year Financial Projections
, ,
FINANCIAL PROJECTIONS(ELECTRIC)-BASE CASE
' FY 06-07 FY07-08 = FY 08-09 ` FY 09-10 FY 10-11 I
REVENUEPSOURCE OF FUNDS I
PROJECTED RETAIL REVENUE ' $28,600,000; $27,441,700 $27,716,117' $27,993,278 l $28,273,211 ;
PROJECTED WHOLESALE REVENUE $15 000,000} $12500 pool1
$15,000 poo $15 000 poo!$15 poo.000l
PROJECTED FCA REVENUE $272 000 $1 500 000E $1 500000 $1,250,000 I $750,0001
SCPPA RESERVE FUNDS $0 1 $2,000,000 I I I
TOTAL REVENUES ? $43,872,0001 $43,441,700 i $44,216,117€ $44,243,278 $44,023,211
COST COMPONENT I
POWER RESOURCE E $30554 000 i $33,290,0004_$30,141 000 $31 350,000 $30,498,000'
TRANSMISSION L $2 880,000 $3,352,000 $3,400,000 $3,340,0001 $3,355,000
DISTRIBUTION
;BondPayment(Interest lent CUSTOMER SE
RVICE $6 000 000, $5 947 000, $6137 000 $6 335 000I $6540,000
Only) $542,000 E $542,000 I $542,0001 $542,0001 $542 000!
'GENERAL FUND TRANSFER 8 IN-LIEU-TAX $2,860,0001 $2,744,170; $2,771,612 $2 799 328 $2,8273211
DEPRECIATION(NON CASH ITEM) $1 000 000; $1 000 000 $1,000 000 $1 000 pool
€ $1 000 000 i
'TOTAL COSTS ; $44,136,000; $46,875,170 $43,991,612; $45,366,3281 $44,762,321
E
OPERATING INCOME ($264,000) ($3,433,470) $224505 ($1,123,050) ($739,110)',
? l
BEGINNIIIG CASH BALANCE $24,000,000 i$23,345,400 l$19521,330 i$19,355,235 i$17541 586
Y 1 ; f 'I
OPERATING INCOME ($264 000) ($3 433,470)E $224 505 ($1 123 050)4 ($739,110)'
'ADJUSTMENTS $1,000,000 $1,000,000 I $1,000,000 $1,000 000 i $1,000,000
CAPITAL390500)l
(PRINCIPAL)BOND PAYMENT $
OUTLAYS AND RELATED ITEMS ($1000000) ($1390500), $000 000) ($1390500)1 $000 000)> ($1390500) $000 000)1 ($1390500)1 $000 000)1
i
YEAR END CASH AND INVESTMENTS $23,345,400 $19,521,330 $19,355,235 $17,841,586 $16,711,876
(z) 5
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Updated Five-Year Financial Projections
FINANCIAL PROJECTIONS(ELECTRIC)-SCENARIO 1 -5%RATE INCREASE III FY 07-08 COMMENCING Jan 1,20081
•
j
FY 06-07 FY07-08 FY 08-09 FY 09-10 1 FY 10-11
REVENUE 1
PROJECTED RETAIL REVENUE $28500,000 $28,127,743 $29,101,923 $29,392,942$29,392,94ir$29,686,871 I.
PROJECTED WHOLESALE REVENUE $15,000 pm $12500,000 $15 poo poo $_15,000,000 $15 000,000j
PROJECTED FCA REVENUE $272,000 $1500,000 $1,500,000 $1 250 000 1 $750,000 1
SCPPA RESERVE FUNDS $0 $2,000,000 $0 $0 $0 0
TOTAL REVENUES $43,872,000 $44,127,743 $45,601,923• $45,642,942 $45,436,871
COST COMPONENT 1 !
POWER RESOURCE $30,854,000 $33,290 000 $30,141 000 $31,350 000 $30 498,000
TRANSMISSION $2,880,000 $3,352,000 $3,400,0007 $3,340,000 $3,355,000]
DISTRIBUTION&CUSTOMER SERVICE $6,000,000 $5,947,000 $6,137,000 $6,335 poo I $6 540 poo
Bond Payment(Interest Only) $542,000 $542,000 $542,000 $542,0001 $542,000
GENERAL FUND TRANSFER&IN-LIEU-TAX $2,860,000 $2,744,170 $2,771,612 $2,799,328 $2,827,321
•TOTAL COSTS $44,136,000 $1 00,000 $1,000,0001 $1,000,000 $1,000 000
�... $1,000,000
1 , .._..
DEPRECIATION(NON CASH ITEM) $1 000 0 $46,875,170� $43,991 612; $45,366,328 $44,762,3211
OPERATING INCOME ($264,000) ($2,747,428) $1,610,311 $276,614 $674,550
1
BEGINNING CASH BALANCE $24,000,000 $23,345,400 '$20,207,373 '$21,427,084 1$21,313,098
OPERATING INCOME
.__._ •• ($264,000) ($2,747,428) $1,610,311 $276,614 $674,550
ADJUSTMENTS $1 000,000 $1,000 000 $1 000,000 ` $1,000 000 $1 000,000
BOND PAYMENT(PRINCIPAL)
($390,600) ($390500) ,,. ($390,600)., ($390,600) ($390,600)'
CAPITAL OUTLAYS AND RELATED ITEMS ($1,000,000) ($1.000,000) ($1,000,000)1 ($1,000,000) ($1,000,000)
f
,YEAR END CASH AND INVESTMENTS $23,345,400 $20,207,373 $21,427,084 $21,31.3,098 $21,597,048
Q
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az. 6
Cost Allocation Studies
• Allocate each cost component based on
causation principles to various customer classes
• There are seven cost components:
- Purchased power
- Transmission
- Distribution
- Customer Service
- GF Transfer
- Depreciation
- Interest Payment on Bonds
0
Measurement of Cost Causation
• Capacity Based
— One measurement of cost causation is based on the usage of
electricity at the time of system peak usage, commonly known as
coincidental peak usage
— The rationale of this measurement is that infrastructures must be
built to serve peak usage EVEN IF they are not fully utilized at all
times. Thus, each customer class should be assigned cost
obligation based on their contribution to the system peak usage
• Usage Based
— Another measurement of cost causation is based on the volume
of electricity used
Depending on the nature of the cost component, either of
these two measurements will be used to assign cost
responsibility
0
a) 8
Measurement of Costi
Causat on
(con 'd)
• Purchased Power is 86% capacity based and 16%
usage based
• Transmission is 100% usage based
• Distribution is 100% capacity based
• Customer Service is chosen to be 50% capacity
based and 50% usage based 50%
• GF Transfer is 100% usage based
• Depreciation is 100% capacity based
• Interest payment on bonds is 100% capacity based
0
C)
-4 9
Cost Allocation Based on Cost Causation
The cost responsibilities of each customer class based on capacity
and usage based contribution factors are summarized below:
Cost Of Service
Allocation
Residential 28.27%
G1 8.68%
G2 24.26%
Municipal 5.58%
TOU 33.22%
00
10
Rate Adjustments
The magnitudes of rate adjustment for a
5% revenue increase based on cost of
service principles are:
Residential 4.6% increase
G1 5% increase
G2 5.5% increase
Municipal 7% increase
TOU 6% increase
co
11
Rate Impacts to Various Retail
Customer Classes •
PERCENT
EXISTING PROPOSED SAVINGS
SCE AZUSA AZUSA VS SCE
2,000 kWh $469.18 $258.25 $270.13 73.69%
1,000 kWh $157.53 $127.93 $133.81 17.72%
700 kWh $96.29 $88.83 $92.92 3.63%
RESIDENTIAL 500 kWh $60.72 $62.77 $65.66 -7.52%
400 kWh $48.10 $49.74 $52.03 -7.55%
300 kWh $36.29 $36.70 $38.39 -5.47%
200 kWh $24.49 $23.67 $24.76 -1.09%
5,000 kWh $867.86 $642.53 $674.66 28.64%
G1 2,000 kWh $354.83 $268.85 $282.29 25.70%
CUSTOMERS 1,000 kWh $183.82 $144.28 $151.49 21.34%
500 kWh $98.32 $82.00 $86.10 14.19%
5,000 kWh $867.86 $501.07 $536.14 61.87%
MUNICIPAL 2,000 kWh $354.83 $204.07 $218.35 62.50%
CUSTOMERS 1,00.0 kWh $183.82 $105.07 $112.42 63.50%
500 kWh $98.32 $55.57 $59.46. 65.36%
G2
50,000 kWh 150 kW 9,190.86 5,344.10 5,638.03 63.02%
CUSTOMERS
SUMMER 10,000 kWh 40 kW 2,173.61 1236.78 1,304.80 66.59%
G2
CUSTOMERS 50,000 kWh 150 kW $5,331.36 $5,344.10 $5,638.03 - -5.44%
WINTER 10,000 kWh 40 kW $1220.87 $1,236.78 $1,304.80 -6.43%
TOU
CUSTOMERS 250,000 kWh 350 kW $34,474.08 $24,816.96 $26,305.98 31.05%
SUMMER 100,000 kWh 300 kW $18,322.02 $11,782.21 $12,489.14 46.70%
TOU
CUSTOMERS 250,000 kWh 350 kW $22,873.83 $21,043.79 . $22,306.42 . 2.54%
WINTER 100,000 kWh 300 kW $10,576.99 $9,582.29 $10,157.23 i 4.13%
0 12
RETAIL RATE STUDIES
COST ALLOCATION ANALYSIS
AZUSA LIGHT AND WATER
PREPARED BY POWER RESOURCE DIVISION
JULY 23, 2007
071
• RETAIL RATE STUDIES
COST ALLOCATION ANALYSIS
EXECUTIVE SUMMARY
Based on the cost of service studies, staff concludes the following:
• Based on cost of service principles, the following rate increases will be required to
produce an overall revenue enhancement of 5%in electric retail revenues:
Residential customers 4.6%rate increase
GI customers 5%rate increase
G2 customers 5.5%rate increase
Municipal customers 7% rate increase
TOU customers 6% rate increase
072
Background:
The Azusa electric utility is in the midst of conducting a cost of service study for retail
electric services.
The steps that staff will undertake for this study are as follow:
• Conduct an in-depth analysis of the cost of service parameters by analyzing the usage
patterns of each customer class (coincident peaks and MWh consumption)
• Allocate the revenue requirement based on cost of service principles
• Conduct the retail rate designs
The following will describe each of the steps in more detail.
Step 1—In-Depth Analysis of the Cost of Service Parameters by Analysis the Usage
Patterns of Each Customer Class
Staff used the test year FY 05-06 (July 05 through June 06) as the basis for data analysis. The
following process was used to analyze the customer consumption data:
1. The actual hourly consumption data of TOU customers available from the MV-90
system was compiled
2. The fitted hourly consumption data for residential, G1, G2, and Municipal
customers was compiled by using the aggregated monthly consumption data of each
of these customer classes and Edison's hourly load profile for each of these
customer classes
3. Stress tests were conducted in the hourly data files for check for any errors and
inconsistencies
4. The output of this process is the coincident peak load information for each month
during the test year and the aggregated MWh consumption information by each
customer class for the test year
•
073
The following tables summarize the results of this process:
Table 1: Coincident Peak Load by Customer Class:
SIMULAYED COINCIDENTAL PEAKS FY 05 06
DATE HE MWH System(95%of Actual Peak) Residential :1G1 G2 Other TOU
721/2005 14 58.21, 5530 18.21; 5.16 13.00 3.61 15.32:
8292005 16 58.74: 55 80' 19 72': 505. 1303 350 14.51
9/29/2005 16 5569 52.90' 16.33, 4.72 11.75 310 17.01
1016/2W5 16 48.62; 46.191 11.70' 4.51 11.68 2.95 15.36'
11/12005 14 41.671 39.58 7631 3.56 10.78 225 1536
12/132005 19 36.70' 34.861 1239`'` 266: 7.40' 1.61. 10.79€
1242006 14 35.24 33.48 6.01 2.85 9.15 1.68 13.79
2)92006 15 37.62! 35.73 645': 319 9.68 1.96 14.45'.
3242006 14 36.34! 34.521 5.99 3.031 9.16 1.89 14.451
4/132006 15 36.39 34.57 6.41 3.21 9.53 1.92 13.50'
5/31/211€ 16 45.80' 43.51 11.63 4 C6 10.63 2.53 14.64
6282006 15 59.86' 56.87 19.52 5.48 14.14 3.40: 1432
;DATE HE MWH _System(95%of Actual Peak)'Residential G1 G2 Other TOU
•
721/2005 14 58.21 55.30 32.93% 9.33% 23 51% 6.53% 27.70%I 100.00%
829/2005 16 58.74': 55801 35.33% 9.05%; 23.36% 627% 25.99%I 100.00%'
9292005 16 55.69! 52.90` 3087%! 8.93% 22.20%. 585%- 32.15% 100.013%I
10162005 16 48.62. 46.19.
25.33% 9.76% 25.28% 6.38% 33.25% 100.00%'
11/12005 14 41.67 39.58 19.29% 9.00% 27.23%: 5.68%. 38.80%i 100.00%
12/132005 19 36.70: 3486: 3555% 7,64% 21.22% 463% 30.96% 100.85%:
1242006 14 3524 3348 17.94% 8.51% 27.34% 5.03% 41.18%: 100.00%
2/92006 15 37.621 35 73' 18 06% 8.92%; 27.10% 5.49% 40.44%! 100.00%
3242006 14 36.34, 34.52 17 35%I 8.76%i 26.55% 5.47% 41.86% 185.85%`
4/132006 15 36.39 34.57! 18.53%; 9.28% 27.57% 557% 39.05% 100.00%I
5/312006 16 45.80: 43.51' 26.73%' 9.37%: 24.44% 5.81%i 33.66% 100.00%'
628/2006 15 59.86 56.87 34.33% 9.64% 24.86% 5.98% 25.19% 100.00%i
Winter average 2235% 8.90%' 25.84% 5 51%, 3740%! 100.00%
Summer average 33.36%' 9.24% 23.48% 6.16% 27.76% 100.00%'
Annual average 26.02% 9.02% 25.05% 5.72%, 34.19% 100.00%I
Table 2:Aggregated MWh Consumption By Customer Class:
Rate Study(Simulated MWh Usages)
Winter(Otto-May) DOM-SIM GS-1 ' GS-2 OTHER TOU
Total , 44,694 11,797 35,616 7,293 55,017 154,417
Mid 18,254 5,892 17,915 3,644 26,757 72,462
Off 26,440 5,905 17,701 i 3249 28260 81,955
Summer(Jun-Sept) DOM-SIM GS-1 , GS-2 OTHER TOU
Total 30,793 7,440 22,172 4,966 30,879 96,250
On 7,066 1,999 5,397 .__` 1,333 7,081 22,877
Mid 9,658 2,498 7,570 1,666 ; 10,419 31,812
Off 14,069 2,943 , 9204 1,966 13,378 41561
DOM-SIM GS-1 GS-2 OTHER TOU TOTAL
Jul-05 8,321 1 901 5,641 1,331 7 698 24,892
Aug-05 8,409 1,980 5228 1,371 8,188 25776
Sep-05 _ 6,648 1,641 4234 1,076 7,696 21296
Oct-05 5,974 1596 4220 1,044 7509 20,942
Nov-05 5,527 1,445 4,324 913 7,026 19,235
Dec-05 5,947 1521 4,561 921 6,471 19,420 '
Jan-06 5,796 1,487 4,430 879 6740 19,332
Feb-06 _ 5,138 1250 3,998831 6,405 17722
Mar-06 5,568 1,509 4,574 ' 942 6,987 19,580
Apr-06 4,959 1282 4297 829 6,463 17,932
May-06 5,785 1,5074,613 934 7,416 20254
Jun-06 7,415 1,917 _ 5269 1,188 7297 23,687
250,667
074
Step 2—Allocate Revenue Requirements Based on Cost of Service Principles
There are seven cost"buckets" to be recovered and the proposed cost allocation
methodology is described below.
The seven cost"buckets" are:
1. Purchased power
2. Transmission
3. Distribution
4. Customer Service
S. General Fund Contribution
6. Depreciation
7. Interest payment on bonds
The allocation methodologies for each one of the cost buckets are described below:
1. Purchased Power
Historically, the purchased power cost is about 84% fixed (or capacity related) and 16%
variable (or energy related). Thus the allocation methodology is as follows:
Capacity related cost (84%of the purchased power cost) is allocated to each customer class
based on 12 Coincident Peak (CP) methodologies. Further, the capacity related costs are
shaped on a monthly basis to reflect the differing values of capacity throughout the year
(summer capacity is of much higher value than winter capacity)
Energy related cost (16% of the purchased power cost)is allocated to each customer class
based on the aggregated annual MWh consumption by each customer class.
2. Transmission
Transmission cost in the CAISO markets is based on MWh consumption. Thus,
transmission cost is allocated to each customer class based on the aggregated annual MWh
consumption by each customer class.
3. Distribution
Distribution related cost is allocated to each customer class based on 12 Coincident Peak
(CP) methodology as distribution infrastructure costs in general relate to peak consumption.
4. Customer Service
Customer service related cost is allocated 50%based on 12 Coincidental Peak and 50% to
aggregated MWh consumption. Further refinement is possible to allocate the customer
075
•
service cost based on customer class counts. As an initial pass of the allocation, staff is using
50/50 allocation between 12 CP and aggregated MWh consumption
5. General Fund Contribution
As the GF contribution is based on MWh consumed, thus allocation based on aggregated
consumption by each customer class is appropriate
6. Depreciation
As depreciation is infrastructure related, thus allocation based on 12-CP seems appropriate
7. Interest Payment on Bonds
As interest payment is related to debt on infrastructure, thus allocation based on 12-CP
seems appropriate
Step 3- The Application of the Above Principles and Data to FY 06-07 Financials
The allocation principles in Step 2 were applied to the FY 06-07 estimated actual financials
using the data gathered in Step 1 to gauge the revenue allocation among customer classes.
The following summarize the findings.
FY 07-08 Estimated Actuals
Purchased Power $17,345,280
Transmission $1 377,720;`
Distribution $4,500,000
Customer Services $1500.000,
GF Transfer $2,860,000:
Depreciation $1,000,000.
Debt Services (interest) $500,000
Total $29,083,000
076
1. Purchased Power Allocation
MMEISMENIN
Category 1 84%Fixed based on 12 Coincident Peaks with monthly shaping to reflect the value of capacity
Total to be recovered= $14,570,035
Allocation Methodology
Monthly Monthly Fixed
Shaping Factor Recovery Residential GI G2 Other TOU
Jan, 6.70% $976,192 17.94% 8.51% 27.34% 5.03% 41.18%
Feb5.00% $728,502 18.06% 8.92% 27.10% 5.49% 40.44%
Mar 5.00% $728,502 17.35% 8.76% 26.55% 5 47% 41.86%
Apr 5.80% $845,062 18.53% 9.28% 27.57% 5.57% 39.05%
May 6.30% 5917,912 26.73% 937% 24.44% 581% 33.66%
Jun 8.30% 51,209,313 34.33% 9.64% 24.86% 5.98% 25.19%
Juli 1580% $2,302066 32.93% 9.33% 23.51% 6.53% 27.70%
Aug 17.50% 522,549,756 35.33% 9.05% 23.36% 6.27% 25.99%
Sep; 11.70% $1,704,694 30.87%. 8.93% 2220% 5.85% 32.15%
Oct 5.80% $845%2. 25.33% 9.76% 25.28% 6.38% 33.25%
Nov'. 6.30% $917,912 1929% 9.00% 27.23% 5.68% 38.60%
Dec 580% $845,062 35.55% 7.64% 2122% 4.63% 30.96%
Monthly Monthly Fixed
Shaping Factor Recovery Residential 01 G2 Other TOU
Jan 6.70% 5976,192 $175,122 $83,059 $266,905 $49,072 $402,035
Feb; 5.00% 5728,502 $131,567 564,967 $197,395 539,987 5294,586
Mar 510% 5728,502 5126,425 563,850 5193,401. $39,876 5304,949
Apr, 5.80% $845,062 $156,632 $78,416 5232,952 $47,052 1333,010
May. 6.30% $917,912 5245,372 585,984 $224,304 $53,303 .53178,950
Jun 8.30% 51,209,313 . 5415,166 5116,563 5300,663 $72,271 $304,609
Jul, 15.80% $2,302,066 5758,050 $214,766 $541,313 $150,319 1637,596_
Aug'; 17.50% $2,549,756 $900,814 $230,852 $595,532 $159,902 $662,757
Sep 11.70% $1,704,694 5526,201 $152,176 $378,467 $99,781 $548,068
Oct, 5.80% $845,062 1214026 $82,474 $213,664 $53921 $280,978
Nov 6.30% $917,912 $177,034 582,597 $249,938 552,176 $3 6,167
Dec 5.80% 5845,062 $300,409 $64,591 $179,293 , $39,106 $261,563
Total 514,570,035 $4,126,817 $1,320,336 $3,573,845 5856,667 54,692.368
28.32% 9.06% 24.53% 5.88% 32.21%
Category 2 16%Variable based on MWh sales
Total to be recovered= $2,775,245
Residential 01 G2 Other TOU
MWh Sales 75,487 19,237 57,789 12,259 05,896
%MWh Sales 30.11% 7 67% 23.05% 4 B9% 3427%
Revenue Allocation 5835,744.62 $212,983.32 $639,804 57 $135,720.49 5950,991.80
2. Transmission
Total to be recovered= $1,377,720
Residential GI G2 Other TOU
MWh Sales 75,487 19,237 57,789 12,259 85096
%MWh Sales 30.11% 7.67% 23.05% 4.89% 34.27%
Revenue Allocation 5414,890.28 $105,731.71 $317,619.39 $67,375.98 5472,102.65
077
•
3. Distribution
Total to be recovered= .54,500,000' _ _... . .. .. .
Monthly Fixed
Recovery _' Residential G1 G2 Other TOU
Jan. $375,000 17.94% . 8.51% 27.34% 5.03% 41.18% 100.00%
Feb 5375,000 18.06% 8.92% 27.10% 5.49% 40.44% 100.00%
Mar 5375000 - 17.35% i 876% 26.55% 547% 4186% 1000%
Apr 5375000 18.53% ! 9.28% 2757% 5.57% 39.05% 100.0%
May 5375,000 26.73% 937% 24.44% 5.81% 33.65% 100.00%
Jun 5375,000 34.33% 9.64% 24.86% 5.98% 25.19% 100.00%
Jul_ 5375,000 ,, 32.93% 933% 23.51% 653% 27.70% 10000%
Auj, $375,000 35.33% 905% 23.36% 6.27% 25.99% 10000%
Sep 5375,000 3187% j 8.93% 22.20% . 5.85% 32.15% 10000%
Oct 5375,000 25.33% 9.76% 25.28% 6.38% 33.25% 100.00%
Noe. 5375,000 19.29% 900% 27.23% 5.68% 38.80% 1131.10%
Dec 5375000 35.55% 754% 21.22% 4.63% i 30.96% ... 100.00%
Monthly Fixed
Recovery ! Residential G1 G2 .. Other TOU
Jan $375,000 567272 '_. $31,907 5102,530 518,851 $154,440 $375000
Feb' 5375000 $67,725 $33,442 - $101,610 520584 9151,639 $375000
Mar 5375 goo . 565,078 532567 599,554 520,527 5156,974 $375,000
Apr 5375,000 569,506. i $34,798 5103,373 - 520,880 $146,444 5375,000
May 5375,000 5100,243 535,127 591,635 $21,776 $126,217 5375.000
Jun 5375,000 5128,740 536,152 $933240 $22,411 594,457 5375,000
Jul 5375,000 5123,484 $34,988 $60,178 524,487 5103063 $375011
Aug:... 5375000 $132,485.. ,. $33,952 $67,587 523,503 597,474 5375000
Sep _ 5375003 $115,754 533476 $83,255 521850 5120,564 5375,000
Oct ..5375,000 594,975 $36,598 $94,814 $23,928 5124585 5375,000
Nor: 5375000 $72,325 533,744 5102.108 521,316 5145,507 5375,000
Dec 5375,000 $133,308 $28,662 579,562 _..517,354 $116,114 5375000
Total $4,500000 51,170,895 $405,714 $1,127,449 $257,563 51,538,378 $4,500000
4. Customer Service
§MINNEEMINSIBRIENMENEle based on MWh sales
Category I . 50%Fixed based on 12 Coincident Peaks
Total to be recovered= $750,000,
Monthly Fixed
Recovery Residential G1 G2 Other TOU
Jan. 562,500 17.94% 8.51% 27.34% 5.03% 41.18%
Feb': 562,500 18.06% 8.92% 27 10% 549% 40.44% .
Mar, 662,500 17.35% 8.76% 26.55% 5.47% 41.86%
Apr; 562,500 18.53% 9.28% 27.57% 5.57% 39.05%
May 562,500 26.73% 9.37% 24.44% 5.81% 33.66%
Jun: 562,500 34.33% 9.64% 24.86% 5.98% 25.19%
Jul! $62,500 32.93% 9.33% 23.51% 653% 27.70%
Aug. 562,500 35.33% 9.05% 23.36% 6.27% 25.99%
Sep, 562,500 3187% 8.93% 2220% 5.85% 32.15%
Oct; 562,500 25.33% 9.76% 25.23% 6.38% 33.25%
Nov; 562,500 19.29% 9.00% 27.23% 5.68% 38.80%
Dec 562,500 35.55% 7.64% 21.22% 4.63% 3196%
Monthly Fixed
Recovery Residential 61 G2 Other TOU
Jan: 562,500 511,212 55,318 517,088 $3,142 $25,740
Feb 562,500 511,287 $5,574 $16,935 $3,431 $25,273
Mar, 562,500 510,646 $5,478 $16,592 $3,421 526,162
Apr $62,500 $11584 $5,800 $17,229 $3,480 $24,407
May; $62,500 $16,707 55,855 $15,273 53,629 $21036
Jun 562,500 521,457 56,025 515,540 53,735 $15,743
Jul 562,500 520,581 55,831 $14,696 54,081 $17,310
Aug. $62,500 522581 $5,659 514598 $3,917 $16,246
Sep 562,500 $19,292 $5,579 $13,876 $3,658 520,094
Oct' 562,500 515,829 56,100 515,802 $3,988 520,781
Nov; 562,500 112,054 $5,624 $17,018 $3,553 $24,251
Dec; 562,500 $22,218 $4,777 $13,260 $2,892 $19,352
Total 5750500 5195,149 $67,619 5187,908 $42,927 5256,396
Category 2 50%Variable based on MWh sates
Total to be recovered= 5750,000
Residential G1 G2 Other TOU
MWh Sales 75,487 19237 57,789 12,259 85,896
%MWhSales 30.11% 7.67% 23.05% 4.89% 34.27%
Revenue Allocation 5225,057.00 557,557.98 5172,904.90 $36,677.98 $257,002.14
078
5. General Fund Contribution
NEEMBESSUINIESIBMENIMINIMINIS
Notal to be recovered= 12.860,000
Residential 01 G2 Other TOU
MWh Sales 75,487 19,237 57,789 12,259 85,8%
_ i%MWhSales 3111% 7.67% 23.05% 4.89% 34.27%
Revenue Allocation 5861,268.03 $219,487.77 $659,344.02 $139,865.35 $980,034.82
6. Depreciation
MINEIVESOMINIMMEIVEINS
Total to be recovered= $1,000,000!
Monthly Fixed
Recovery Residential 01 G2 Other TOU
Jan $83,333 17.94% 8.51% 27.34% 5.03% 41.18%
Feb $83,333 18.06% 8.92% 27.10% 5.49% 40.44%
Mar $83333 1735% 8.76% 26.55% 5.47% 41.86%
Apr. 183333 18.53% 9.28% 27.57% 557% 3905%
May; 183,333 26.73% 9.37% 24.44% 5.81% 33.66%
Jun $83,333 34.33% 9.64% 24,86% 5.98% 25.19%
Jul' $83,333 32.93% 9.33% 23.51% 6.53% 27.70%
Aug' 383333 35,33% 905% 23.36% 6.27% 25.99%
Sep, $83,333 3187% 893% 22.20% 5.85% 32.15%
Oct; $63,333 25.33% 9 76% 25.28% 638% 33.25%
Nov $83,333 19.29% 9.00% 27.23% 5.68% 38.80%
Dec; $83,333 35.55% 7.64% 21.22% 4.63% 30.96%
Monthly Fixed
Recovery Residential G1 G2 Other TOO
Jan $83,333 114,949 $7,090 822,784 $4,189 134,320
Feb 583,333 315,050 $7,432 $22,580 $4,574 133,698
Mar 183,333 $14,462 57,304 $22,123 $4,561 $34,883
Apr $83,333 115446 87,733 322372 84,640 $32,543
May $83,333 $22,276 17,806 $20,364 $4,839 $28,048
Jun $83333 128,609 $8,034 $20,720 $4,980 $20,991
Jul' $83333 127441 17,775 $19,595 15441 $23,081
Aug', $83,333 $29,441 $7,545 $19,464 $5,223 $21,661
Sep, $83,333 625,723 $7439 518,501 $4.878 _$26,792
Oct 883,333 521,106 $8,133 $21,070 $5,317 827,708
Nov, 883,333 $16,072 87,499 $22,691 $4,737 132,335
Dec 183,333 529,624 $6,369 117,680 13,056 525,803
Total $1,000,000 $260,199 $90,159 $250544 $57,236 $341$62
079
7. Interest Payment
ISOMEMINEMISMOINIESEMEMNEMI
Total to be recovered= $500,000
Monthly Fixed
Recovery Residential G1 G2 Other TOU
Jan! 541,667 17.94% 8.51% 27.34% 5.03% 41.18%
Feb. $41,667 18.06% 8.92% 27.10% 5.49% 40.4.4%
Mar $41,667 17.35% 8 76% 26.55% 5 47% 41.86%
Apr $41667 18.53% 9.28% 27.57% 5.57% 39,05%
May $41,667 26.73% 9.37% 24.44% 5.81% 33.66%
Jun': $41,667 34.33% 9.64% 24.86% 5.98% 25.19%
Jul $41,667 32.93% 9.33% 23.51% 6.53% 27.70%
Aug': $41667 35.33% 905% 23.36% 6.27% 25.99%
Sep $41,667 30.87% 8.93% ' 22.20% 585% 32.15%
Oct $41,667 25.33% 9.76% 25.28% 638% 33.25%
Nov'; 541,667 19.23% 900% 27.23% 5.68% 38.80%
Dec $41,667 35.55% 7.64% 21.22% 4.63% 30.96%
Monthly Fixed
Recovery Residential 01 G2 Other TOU
Jan $41,667 $7,475 $3,545 511,392 $2695 $17,160
Feb; $41667 57,525 $3,716 511,290 $2287 $16649
Mar. $41,667 $7231 $3,652 $11,062 $2281 $17,442
Apr $41,667 $7,723 $3,866 $11,486 $2,320 $16,272
May $41,667 $11,138 $3,903 $10,182 $2,420 $14024
Jun!, $41,667 $14304 $4,017 $10,360 $2,490 $10,495
Jul; $41,667 $13,720 $3 : $9,798 $2,721 $11,540
Aug. $41,667 $14,721 $3,772 $9,732. $2611. $10,830
Sep; $41.667 $12962 $3,720 $9,251 $2,439 513,396
Oct $41,667 $10553 $4,066 $10,535 $2,659 $13654
Nov! $41,667 $8,03 $3,749 $11345 $2368 516,167
Dec, $41667 $14,812 53,185 $8,840 $1,928_ $12,902_
Total) $500,000 $130,099 545,079 $125272 $28,618 $170,931
Summary of Revenue Requirement Allocation Based on Cost of Service Principles:
Total Revenue Requirement Allocation
Residential 01 G2 Other TOU Total
Purchased Power
Fixed $4,126617 51320,338_ 53573645 $856667 $4,692368 $14,570,035
Variable $835,745 $212,983 5639,805 $135,720 $950,992 52,775245
Transmission $414,890 $105,732 5317,619 $67,376 $472,103 51,377,720
Distribution 51,170,895 $405,714 $1,127,449 $257,563 $1,538,378 54,500,000
Customer Services 50
Fixed 5195,149 $67,619 $187,908 $42,927 5256,396 $750,000
Variable $225,857 $57 558 $172,905 $36678 5257,002 $750,000
GF Transfer $861,268 $219,488 $659,344 $139,865 5980,035 52,860,000
Depreciation $260,199 I $90,159 $250,544 $57,236 $341,862 51,000,000
Debt Services(interest) $130,099. $45,079 $125,272 528,618 $170,931 $500,000
Total $8220,919 $2,524,670 57,054,692 $1,622,652 $9,660,067 $29683,000
%Revenue Requirement 28.27% 8.68% 24.26% 5.58% 33.22%
Thus based on cost of service principles, the percent of incremental revenue requirement
should be allocated to each customer class based on the following percentages:
Residential customers 28.27%
GI customers 8.68%
G2 customers 24.26%
Municipal customers 5.58%
TOU customers 33.22%
080
Applying the above percentages to a 5%revenue enhancement or about$1,500,000 per year
produces the following rate increases:
Residential customers $424,050 4.6%
G1 customers $130,200 5.0%
G2 customers $363,900 5.5%
Municipal customers $ 83,700 7.0%
TOU customers $498,300 6.0%
081
RESOLUTION NO. •
A RESOLUTION OF THE CITY COUNCIL OF THE CITY
OF AZUSA,CALIFORNIA,TO ADOPT NEW ELECTRIC
RATES EFFECTIVE OCTOBER 1, 2007.
WHEREAS, the May 2006 electric utility financial projections projected a need to
enhance electric utility revenue base starting in fiscal year 07-08 to fund various legislative and
regulatory mandates; and to provide sufficient funds to pay for higher wholesale cost of
electricity and operation and maintenance costs; and
WHEREAS, the July 2007 updated financial projections continue to show the need to
enhance electric utility revenue base in fiscal year 07-08 and beyond; and
WHEREAS, a cost of service study was conducted to fairly allocate the revenue
requirement increase among the various City customer classes; and
WHEREAS, the findings of the need to enhance revenue requirement and the allocation
of the revenue requirement among customer classes were presented to Utility Board at it regular
meeting on July 23`d, 2007;
NOW, THEREFORE, THE CITY COUNCIL OF THE CITY OF AZUSA DOES HEREBY
RESOLVE AS FOLLOWS:
SECTION 1. Adoption of Electric Rate Schedule. That the electric rate schedule
attached hereto and incorporated as Exhibit A is hereby adopted and that
the new electric rates shall be effective on the dates set forth in Exhibit A.
SECTION 2. Effective Date. This Resolution shall become effective upon its adoption.
SECTION 3. Authorization. The Mayor shall sign and the City Clerk shall certify to the
passage and adoption of this Resolution.
PASSED, APPROVED AND ADOPTED THIS 24th day of September, 2007.
Joseph Rocha, Mayor
ATTEST:
Vera Mendoza, City Clerk
EFFbCTIVE 10/01/2007
Electric Rate Schedule- 1
082
STATE OF CALIFORNIA )
COUNTY OF LOS ANGELES ) ss.
CITY OF AZUSA )
I HEREBY CERTIFY that the foregoing Resolution was duly adopted by the Utility Board/City
Council of the City of Azusa at a regular meeting of the Azusa Light& Water Utility Board on
the 24th day of September, 2007.
AYES: COUNCILMEMBERS:
NOES: COUNCILMEMBERS:
ABSENT: COUNCILMEMBERS:
Vera Mendoza, City Clerk
EFFECTIVE 10/01/2007
Electric Rate Schedule-2
083
EXHIBIT A
ELECTRIC RATE SCHEDULES
SCHEDULE D
RESIDENTIAL SERVICE
Applicability:
This schedule is applicable to domestic service including lighting, heating, cooking, and
power or combination thereof in a single-family accommodation.
Territory:
Within the electric service territory of the City of Azusa.
Rate:
Minimum Charge: per meter per month $3.31 $3.49
Energy Charge:
First 250 kWh, per kWh l0.114 10.61¢
All excess kWh, per kWh 134460 13.604¢
Special Conditions:
1. The above rates are subject to fuel cost adjustment.
2. A State Surcharge Tax may be added to the above rates.
3. A State Public Benefit Program Charge may be added to the above rates.
EFFECTIVE 10/01/2007
Electric Rate Schedule-3
084
•
SCHEDULE WH/SH
RESIDENTIAL SERVICE FOR WATER AND/OR SPACE HEATING
Applicability:
This schedule is applicable to domestic use of electricity as sole source of energy,other than
solar for water and/or space heating. It is supplemental to Schedule D.
Territory:
Within the electric service territory of the City of Azusa.
Rate:
Minimum Charge: per meter per month $3.34$3.49
Energy Charge:
First 250 kWh, per kWh 10.14 10.61¢
Allowance for water heating, per month
250 kWh, per kWh 10.14¢ 10.61¢
Allowance for space heating, per month*
550 kWh, per kWh 10.14 10.61¢
All excess kWh, per kWh ¢ 13.604¢
*From November 1 to April 30
Special Conditions:
1. The above rates are subject to fuel cost adjustment.
2. A State Surcharge Tax may be added to the above rate.
3. Residence requesting discount rate shall be verified by City employee of its heating
equipment on premises.
EFFECTIVE 10/01/2007
Electric Rate Schedule-4
085
SCHEDULE RL
RESIDENTIAL SERVICE WITH LIFE-SUPPORT DEVICES
This schedule is applicable to residential use of electricity for life-support devices in addition to
lighting, heating, cooking and power or combination thereof in a single-family accommodation.
Territory:
Within the electric service territory of the City of Azusa
Rate:
Minimum Charge: per meter per month $3.34$3.49
Energy Charge:
First 250 kWh, per kWh 10.140 10.61¢
Additional allowance for Life Support
Device, per month 10.110 10.610
All excess kWh, per kWh -1-3.006¢ 13.6040
Special Conditions:
1. Each eligible residential customer may be allowed an additional lifeline quantity of
electricity, upon application to the utility where such customer provides certification that
full-time resident of the household regularly requires the use of an essential life-support
device which is defined below including heating and/or cooling as medically required for
listed serious illnesses:
Aerosol Tents IPPB Machines Pressure Pumps
Compressors Iron Lungs Quadriplegia
Compromising Immune Life-threatening Illnesses Respirators (all types)
System Illnesses Motorized Wheelchairs Scleroderma
Hemodialysis Machines Multiple Sclerosis Suction Machines
Electrostatic Nebulizers Paraplegia Ultrasonic Nebulizers
Electric Nerve Stimulators Pressure Pads
EH hCTIVE 10/01/2007
Electric Rate Schedule-5
086
Schedule RL (continued)
Procedure for Certification:
The Utility may require that:
a. The customer have a medical doctor or osteopath licensed to practice medicine in the
State of California provide the Utility with a letter, acceptable to the Utility,
describing the type of regularly required life-support device and the utilization
requirement in detail; or
b. County, State or Federal agencies,using an established notification letter to electric
utilities, provide the Utility with information relative to patients who regularly
require the use of a life-support device in the house.
Upon the above certification,the Utility shall estimate the monthly consumption of
the particular life-support device,given the usual hours of operations per month,and
within 30 days add the incremental estimated monthly usage to the customer's
lifeline quantity. The Utility may require a new or renewed application and/or
certification, when needed in the opinion of the Utility.
2. Verification: Not more than one lifeline quantity will be allowed for each single-family
dwelling or accommodation on the premises. However,where there are multiple life-support
devices at such single-family dwelling or accommodation, all such devices shall be totaled
for one lifeline quantity. The number of single-family accommodations on the premises and
the existence of the specified end use equipment required to obtain certain lifeline quantities
of electricity, as set forth on the applicable rate schedules are subject to verification by the
Utility.
3. Termination of Use: Customers shall give the Utility notice of termination of use of
equipment or devices. In the event the Utility ascertains that the customer is not eligible for
such additional lifeline quantity, such customer may be re-billed as if no such additional
lifeline quantity had been allowed.
4. The above rates are subject to fuel cost adjustment.
5. A State Surcharge Tax may be added to the above rates.
EH-bCTIVE 10/01/2007
Electric Rate Schedule-6
087
SCHEDULE G
GENERAL SERVICE
Applicability:
Applicable to single and three-phase general service including lighting and power.
Territory:
Within the electric service territory of the City of Azusa.
Rate G-1:
Customer Charge: per meter per month $6 6.37
Energy Charge (to be added to customer charge)
First 500 kWh, per kWh 15.16¢ 15.92¢
All excess kWh, per kWh 12.13¢ 13.05¢
Minimum Charge:
The monthly minimum charge shall be the monthly customer charge.
Rate G-2:
Demand Charge:
First 20 KW or less of billing demand No Charge
Additional KW of billing demand, per KW $7.28 7.68
Energy Charge:
First 500 kWh, per kWh 4-546¢ 15.99¢
Next 4,500 kWh, per kWh 13.350 14.080
Additional kWh, per kWh 844¢ 8.690
Minimum Charge:
The monthly minimum charge shall be $145.53 153.53 if the energy charge is less
than$115.53 153.53.
EH-hCTIVE 10/01/2007
Electric Rate Schedule-7
088
Schedule G (continued)
Special Conditions:
1. Service will be supplied at one standard voltage through one meter.
2. Rate G-2 is applicable when a demand meter is installed in accordance with Condition 3.
3. A maximum demand meter will be installed when, in the opinion of the Utility, the
customer's load and use characteristics indicate that the maximum demand may exceed 20
KW or when the customer requests a demand rate.
4. The billing demand of the month shall be the maximum kilowatt measured in the 15-minute
interval in that month, but not less than 50% of the highest demand established in the
preceding 11 months. Billing demand shall be determined to the nearest 1/10 KW.
5. When the use of energy is seasonal or intermittent, no adjustment will be made for a
temporary discontinuance of service. Any customer, prior to resuming service within 12
months after such service was discontinued,will be required to pay all charges which would
have been billed if.service had not been discontinued.
6. The above rates are subject to fuel cost adjustments.
7. A State Surcharge Tax may be added to the above rates.
EH-ECTIVE 10/01/2007
Electric Rate Schedule-8
089
SCHEDULE GL •
LARGE GENERAL SERVICE
Applicability:
Applicable to single and three-phase general service including lighting and power. This
schedule is mandatory for all customers whose monthly maximum demand has exceeded 200
KW for any 3 months during the preceding 12 months and whose average demand for the
preceding 12 months also exceeds 200 KW. Any customer whose monthly maximum
demand has fallen below 200 KW for any 3 months during the preceding 12 months and
whose average demand for the preceding 12 months also is less than 200 KW may be
required to take service on Schedule G-2.
Territory:
Within the electric service territory of the City of Azusa.
Rate:
(Identical to Rate G-2 with the exception of minimum charge and power factor adjustment.)
Minimum Charge: The monthly minimum charge shall be the monthly demand charge or
$$145.53 153.53, whichever is greater.
Special Conditions:
1. Service will be supplied at one standard voltage through one meter.
2. Billing Demand: The billing demand in any month shall be the average kilowatt input
indicated or recorded by instruments to be supplied,owned and maintained by the utility and
at the Utility's expense upon the consumer's premises adjacent to the watt-hour meter,in the
15-minute interval in which the consumption of electric energy is greater than in any other
15-minute interval in the month,but not less than 50%of the highest billing demand in the
preceding 11 months. Billing demand shall be determined to the nearest KW. Whenever the
measured maximum demand has exceeded 400 KW for 3 consecutive months and thereafter
until it has fallen below 300 KW for 12 consecutive months, a 30-minute interval will be
used. Where the demand is intermittent or subjected to violent fluctuations,the maximum
demand may be based on a shorter interval.
E1-1-bCTIVE 10/01/2007
Electric Rate Schedule-9
090
Schedule GL (continued)
3. Power Factor Adjustment: When the billing demand has exceeded 200 KW for 3
consecutive months, a kilovar-hour meter will be installed as soon as practicable. The
charges will be increased for each KVAR in excess of 60% of the billing demand in the
amount of 46¢ per KVAR.
The kilovars of reactive demand shall be calculated by multiplying the kilowatts of measured
maximum demand by the ratio of the kilovar-hours to the kilowatt-hours. Demands in
kilowatts and kilovars shall be determined to the nearest 1/10 (0.1) unit. A ratchet device
will be installed on the kilovar-hour meter to prevent its reverse operations on leading power
factors.
4. Voltage Discount: The charges before power factor and fuel cost adjustments will be
reduced by 4% for service delivered and metered at 12 KV.
5. Temporary Discontinuance of Service: When the use of energy is seasonal or intermittent,
no adjustments will be made for a temporary discontinuance of service. Any customer prior
to resuming service within 12 months after such service was discontinued will be required to
pay all charges which would have been billed if service had not been discontinued.
6. The above rates are subject to fuel cost adjustments.
7. A State Surcharge Tax may be added to the above rates.
EH-bCTIVE 10/01/2007
Electric Rate Schedule- 10 q
09 1
SCHEDULE TOU
TIME-OF-USE
General Service
Demand Metered
Applicability:
Applicable to single and three-phase general service, including lighting and power. This
schedule is mandatory for all customers whose monthly maximum demand has exceeded 200
KW for any 3 months during the preceding 12 months and whose average demand for the
preceding 12 months also exceeds 200 KW. Any customer whose monthly maximum
demand has fallen below 200 KW for any 3 months during the preceding 12 months and
whose average demand for the preceding 12 months also is less than 200 KW may be
required to take service on Schedule G-2.
Territory:
Within the electric service territory of the City of Azusa.
Rates: Per Meter per Month
Summer Winter
Customer Charge: $36.38 38.56 $36.38 38.56
Demand Charge
All kW of Maximum Demand, per KW
(Non-time Related Component) 389 4.12 3-89 4.12
Time Related Component
(To be added to Non-time Related Component)
All KW of on-peak maximum demand per KW 648 6.87 n/a
Plus all KW of mid-peak maximum demand, per KW 1.13 1.20 0:89 0.94
Plus all KW of off-peak Maximum Demand, per KW 0.00 0.00
Energy Charge
All on-peak kWh, per kWh $0.13340 0.14140 n/a
All mid-peak kWh, per kWh $0.09096 0.09642 0.1.0309.10928
All off-peak kWh, per kWh $0.06061 0.06428 0.06064.06428
Charges for energy are calculated for customer billing using the components shown below.
E}FbCTIVE 10/01/2007
Electric Rate Schedule- 11
092
•
TOU Rate (continued)
Special Conditions:
1. Time period are defined as follows:
On-peak: Noon to 6:00 p.m. summer weekdays except holidays.
Mid-peak: 8:00 a.m. to noon and 6:00 p.m. to 11:00 p.m. summer weekdays except
holidays, and 8:00 a.m. to 9:00 p.m. winter weekdays except holidays.
Off-peak: All other hours.
Off-peak holidays are New Year's Day,(January 1)Washington's Birthday(third Monday in
February),Memorial day(last Monday in May),Independence Day(July 4),Labor Day(first
Monday in September),Veterans'Day(November 11),Thanksgiving Day(fourth Thursday
in November) and Christmas Day(December 25).
The summer season shall commence at 12:00 a.m. on the first Sunday in June and continue
until 12:00 a.m. of the first Sunday in October of each year. The winter season shall
commence at 12:00 a.m.on the first Sunday in October of each year and continue until 12:00
a.m. of the first Sunday in June of the following year.
2. Voltage: Service will be supplied at one standard voltage.
3. Maximum Demand: Maximum demands shall be established for the on-peak,mid-peak,and
off-peak periods. The maximum demand for each period shall be the measured maximum
average KW-input indicated or recorded by instruments to be supplied by the City, during
any 15-minute metered interval.
4. Billing Demand: The demand charge shall include the following billing components: The
time related components shall be for the kW of maximum demand recorded during the
monthly billing period for each of the on-peak, mid and off-peak time periods.
5. Power Factor Adjustment: When the billing demand has exceeded 200 KW for 3
consecutive months, a kVAR-hour meter will be installed as soon as practicable. The
charges will be increased for each kVAR in excess of 48.4% of the billing demand in the
amount of 46¢ per kVAR.
The kVAR of reactive demand shall be calculated by multiplying the KW of measure
maximum demand by the ratio of the kVAR-hours to the kW-hours. Demands in KW and
kVAR shall be determined to the nearest 1/10 (0.1)unit. A ratchet device will be installed
on the KVAR-hour meter to prevent its reverse operation on leading power factors.
ENNbCTIVE 10/01/2007
Electric Rate Schedule- 12
093
TOU Rate (continued)
6. Voltage Discount: The charges before power factor and fuel cost adjustments will be
reduced by 4% for service delivered and metered at 12 kVAR.
7. Temporary Discontinuance of Service: When the use of energy is seasonal or intermittent,
no adjustments will be made for a temporary discontinuance of service. Any customer prior
to resuming within 12 months after such service was discontinued will be required to pay all
charges which would have been billed if service had not been discontinued.
8. The above rates are subject to fuel cost adjustment.
9. A State surcharge tax may be added to the above rates.
E1-1•ECTIVE 10/01/2007
Electric Rate Schedule- 13
•
SCHEDULE MS
MUNICIPAL SERVICE
Applicability:
Applicable to single or three-phase service which supplies electricity to the City of Azusa
Municipal Agency(including City of Azusa water pumping service).
Territory:
Within the electric service territory of the City of Azusa.
Rate:
Customer Charge, per meter per month $6447 6.49
Energy Charge(to be added to customer charge)
Each kWh per meter per month 9.9¢ 10.59¢
Minimum Charge:
The monthly minimum charge shall be the Monthly Customer Charge
Special Conditions:
1. The above rate shall be subject to fuel cost adjustment.
2. A State Surcharge Tax may be added to the above rate.
EH-bCTIVE 10/01/2007
Electric Rate Schedule- 14
095
•
SCHEDULE S
STANDBY
Applicability:
Applicable to single or three-phase service where the entire electrical requirements on the
Customer's premises only operate in emergency or are not regularly supplied by the Utility.
Territory:
Within the electric service territory of the City of Azusa.
Rate:
Standby Charge:
All KW of demand, per KW per month $2.55
Regular Schedule Charges (to be added to Standby Charge)
All charges of the General Service Rate G-1
Minimum Charge:
The monthly minimum charge shall be the Standby Charge plus the regular schedule
customer charge.
Special Conditions:
1. When the connected load cannot be determined in KW,the connected load will be estimated
by the Utility based on tests and other information available.
2. This schedule shall apply only to service expected to operate for at least one year or longer.
3. The above rate shall be subject to fuel cost adjustment.
4. A State Surcharge Tax may be added to the above rate.
EFFECTIVE 10/01/2007
Electric Rate Schedule- 15096
96
SCHEDULE SL-1
STREET LIGHTING SERVICE
DEPARTMENT-OWNED LIGHTING DISTRICTS
Applicability:
Applicable to lighting districts for street and highway lighting service where the Utility owns
and maintains the street lighting equipment.
Territory:
Within the electric service territory of the City of Azusa
Rates: Avg kWh per Month Per Lamp per Month
Incandescent
4,000 Lumen(300W) 104 $13.35 14.02
Mercury Vapor
7,000 Lumen(175W) 60 13.71 14.40
11,000 Lumen (250W) 86 17.70 18.59
20,000 Lumen (400W) 138 24,26 25.47
High-Pressure Sodium
9,500 Lumen(100W) 35 12.13 13.05
22,000 Lumen(220W) 76 17.2818.14
25,500 Lumen(250W) 86 48:4919.41
Special Conditions:
1. The above rate is subject to fuel cost adjustment.
2. A State Surcharge Tax may be added to the above rate.
3. Hours of Service: approximately 4140 hours per year.
4. Other than Standard Equipment: Where the customer requests the installation of other than
the standard equipment furnished by the Utility and such requested equipment is acceptable
to the Utility,the Utility will install the requested equipment provided the customer agrees to
advance the estimated difference in installed cost between such equipment and standard
equipment. Advances made for this purpose will not be refunded. Facilities installed in
connection with such agreements become and remain the sole property of the Utility.
El-FhCTIVE 10/01/2007
Electric Rate Schedule- 16
097
SCHEDULE SL-2 •
STREET LIGHT AND OUTDOOR AREA LIGHTING SERVICE
CUSTOMER OWNED LIGHTING DISTRICTS
Applicability:
Applicable to un-metered,controlled for dusk-to-dawn operation of outdoor area lighting for
purposes, such as bus shelters, street and highway lighting service parking lots, pedestrian
walkways, monuments, and decorative areas where the customer owns and maintains the
lighting equipment.
Territory:
Within the electric service area of the City of Azusa.
Rates:
1. Customer charge per location per month is$3.34$3.51.
2. Energy charge 94)0 10.08 cents per kWh.
Avg kWh per Month Per Lamp Per Month
Incandescent
4,000 Lumen (300W) 104 $13.77 14.46
Mercury Vapor
7,000 Lumen (175W) 60 9.13 9.90
11,000 Lumen (250W) 86 12.03 12.63
20,000 Lumen (400W) 138 17.24 18.10
High-Pressure Sodium
9,500 Lumen(100W) 35 6784 7.15
22,000 Lumen (220W) 76 10.98 11.53
25,500 Lumen(250W) 86 12.03 12.63
Special Conditions:
1. The above rate is subject to fuel cost adjustment.
2. A state surcharge tax may be added to the above rate.
3. Hours of service: Approximately 4140 hours per year, 345 hours per month.
EFFECTIVE 10/01/2007
Electric Rate Schedule- 17
098
Schedule SL-2 (continued)
4. For bus shelter and other services with more than one lamp per location. The applicable rate
bases on the total wattage of the lamps installed.
5. The customer will comply, furnish, and install at their expense all necessary equipment
required by local building codes.
6. All customer-owned un-metered facilities beyond the utility's point of delivery will be
maintained, and operated by the customer.
7. For service at this schedule, the utility may, at its option, provide an additional point of
delivery, separate from any other point of delivery provided under any other applicable rate
schedule.
8. Voltages: Service under this schedule will be delivered at 120, 120/240 volts or at the option
of the utility at 120/208 or 277/480 three-wire single-phase.
a. Installation of additional utility facilities shall be under existing Electric Utility Rule
No. 15.
•
EF HCTIVE 10/01/2007
Electric Rate Schedule- 18
099
SCHEDULE SL-3
STREET LIGHTING SERVICE
CUSTOMER-OWNED LIGHTING
MAINTAINED BY AZUSA LIGHT & WATER
Applicability:
Applicable to un-metered electric service for street and highway lighting where the Customer
owns lighting facilities on private property and contracts with Azusa Light & Water to
maintain the street lighting equipment.
Territory:
With the electric service territory of the City of Azusa.
Rates:
Avg kWh per Month Per Lamp Per Month
High-Pressure Sodium
9,500 Lumen(100W) 35 $12.13 13.05
25,500 Lumen(250W) 86 18.49 19.41
Special Conditions:
1. The above rate is subject to fuel cost adjustment.
2. A State Surcharge Tax may be added to the above rate.
3. Hours of Service: approximately 4140 hours per year.
4. The customer will furnish and install at their expense all necessary equipment including the standard
equipment required and accepted by Azusa Light&Water according to street lighting codes.
5. The customer will own the equipment,but contract with Azusa Light&Water to replace burned-out
lamps and otherwise maintain the luminaire during regular daytime working hours, as soon as
practicable following notification by the customer. The customer will be billed the cost of time and
materials to their street light account.
6. Normal maintenance shall not include any replacement of posts or post parts when such damage is
coincident with or is a result of partial or total demolition of post or when caused by riots, fire,
explosions,earthquakes, disasters of major magnitude or acts of God,nor shall normal maintenance
include that due to equipment developing defects in test or in service due to faults in design,
manufacturing, or installation until such defects have been satisfactorily corrected.
ErrbCTIVE 10/01/2007
Electric Rate Schedule- 19
100
• SCHEDULE OL
OUTDOOR AREA LIGHTING SERVICE
Applicability:
Applicable to outdoor area lighting service, other than street and highway lighting service,
where the Utility owns and maintains the area lighting equipment.
Territory:
Within the electric service area of the City of Azusa.
Rates:
Mercury Vapor Existing Pole New Pole
7,000 Lumen(175W) $13.95 14.65 $17.35 18.22
20,000 Lumen(400W) 25.47 26.74 28.86 30.30
High Pressure Sodium
9,500 Lumen(100W) 12.43 13.05 15.82 16.61
25,500 Lumen(250W) 17418.47 20.99 22.04
Special Conditions:
1. The Utility will, at its own expense, install, operate and maintain its standard overhead
outdoor lighting equipment. Facilities will consist of a luminaire with a photo-electric switch
control and a support, mounted on a Utility-owned pole at which 120V service is readily
available. All facilities will be owned and maintained by the Utility.
2. The Utility will replace burned-out lamps and otherwise maintain the luminaire during
regular daytime working hours as soon as practicable following notification by the customer.
3. This service will be furnished only if the installation is considered by the Utility to be of a
permanent and established character. If the customer requests the removal of service during
the first two years of service,there will be a$4-5-1-.-60 159.18 charge to remove the facilities,
or$606.38 636.70 charge if removal of the pole is required.
4. The above rate is subject to a fuel cost adjustment.
5. A State Surcharge Tax may be added to the above rate.
EFFECTIVE 10/01/2007
Electric Rate Schedule-20
101
Schedule OL (continued) •
6. Energy: The Utility will supply the energy which is included in the monthly rate on the
previous page.
7. Hours of Service: Burning hours will be from dusk to dawn, aggregating approximately
4,080 hours per year. Credit will not be allowed for lamp outages.
E1.1-:CTIVE 10/01/2007
Electric Rate Schedule-21
102
SCHEDULE FCA-SJ
FUEL COST ADJUSTMENT—SAN JUAN RESOURCE
(Adopted by Resolution No. 04-057)
Background:
The City's San Juan Unit 3 resource is its single largest resource providing up to 75% of
City's annual energy requirement.
Due to the sunk cost nature of San Juan resource,the cost incurred in procuring replacement
power when the unit is derated, or unavailable due to scheduled or forced outages is an
addition to the power resource cost that must be recovered. This rate schedule would ensure
timely and prudent recovery of the replacement power costs for San Juan Unit 3 resource.
Applicability:
Applicable to all electric services.
Territory:
Within the electric service territory of the City of Azusa.
Rate Determination:
Energy Charge: As determined by the methodology below.
Rate:
The Azusa Light and Water shall determine the fuel cost adjustment component associated
with its San Juan unit 3 resource pursuant to the following methodology each quarter. The
Director of Utilities shall notify the City Council of the new fuel cost component associated
with its San Juan unit 3 each quarter.It shall be applied to all electric bills beginning the first
billing cycle of each quarter.
1. Determine the base San Juan replacement power.cost for the quarter through the
following calculation:
(A) = Base San Juan Replacement Power Cost in $ = 30 x (N#of days during the
quarter) x 24 x 0.15 x 40.
2. Determine the actual San Juan replacement power cost in $ incurred during the
quarter(B).
3. Determine other San Juan associated costs (+) or credits (-), e.g. outage insurance
premium payment(+), outage insurance payout(-) incurred during the quarter(C).
EH ECTIVE 10/01/2007
Electric Rate Schedule-22
103
4. Derive the amount of Replacement Power Cost (RPC) eligible to be recovered
through the following calculation:
RPC = (A)—(B)+(C)
5. Adjust the RPC in accordance with the following to derive Adjusted Replacement
Power Cost(ARPC):
(i) If RPC< -$750,000, then ARPC=-$750,000
(ii) If-$750,000<RPC<-$100,000, then ARPC=RPC
(iii) If-$100,000<RPC<+$100,000, then ARPC=$0
(iv) If$100,000<RPC<+$750,000, then ARPC=RPC
(v) If RPC>+$750,000, then ARPC=+$750,000
6. Derive Replacement Power Cost Balancing Account(RPCBA)by subtracting ARPC
from RPC, i.e., RPCBA=RPC-ARPC.
7. Forecast the retail sales for the immediately succeeding quarter(R).
8. Derive the fuel cost adjustment associated with the San Juan unit 3 resource by
dividing ARPC by(R).
9. Any balance remaining in RPCBA shall be added to the RPC of the immediately
succeeding quarter for recovery or credit. Subject to City Council's approval, the
Director of Utilities may establish a minimum RPCBA threshold to be retained for
the purposes of reducing the fluctuations in fuel cost adjustment.
This rate schedule is applicable to San Juan energy resource only. To the extent a need
arises to apply FCA provision to energy resources other than San Juan, the Director of
Utilities may implement it with the approval of the Utility Board.
EFFECTIVE 10/01/2007
Electric Rate Schedule-23
• 104
AZUSA
IIGNT R WATER
AGENDA ITEM
TO: HONORABLE CHAIRPERSON AND MEMBERS OF THE AZUSA UTILITY BOARD
AND AZUSA CITY COUNCIL
FROM: JOSEPH F. HSU, DIRECTOR OF UTILITIES`v
DATE: SEPTEMBER 24, 2007
SUBJECT: ADJUSTMENT OF REPLACEMENT WATER COST ADJUSTMENT FACTOR
RECOMMENDATION
It is recommended that the Utility Board/City Council authorize staff to increase the
Replacement Water Cost Adjustment Factor by $0.1132 per hundred cubic feet of water to
recover the increased cost of purchasing water from the Metropolitan Water District.
BACKGROUND
The existing water rates of the Azusa Water Utility include an annual adjustment factor called
the "Replacement Water Cost Adjustment Factor (RWCAF)." This adjustment factor was
implemented following the severe drought that occurred around 1990. Each year the RWCAF
is adjusted in June for subsequent fiscal year to recover replacement or purchased water costs
due to water supply fluctuations, and this fiscal year's RWCAF equates to $0.1306 per
hundred cubic feet (ccf) of water.
Due to historically low rainfall this past winter and other water supply shortfalls, the City has
been forced to make water purchases from the Metropolitan Water District (MWD) under a
agriculture water rate, which is provided through an outlet connected to the San Gabriel River
commonly referred to as the "USG-3" connection near Morris Dam. Water purchases from
this source are much more expensive than water purchased from local districts and it is
recommended that the added costs be recovered through a bi-monthly adjustment to the
RWCAF.
Water purchases from MWD began in July and continue. The incremental cost above normal
replacement water was $90,060.51 in July, and $106,182.39 in August. Based on forecasted
consumption by consumers in October and November, the RWCAF should be increased by
$0.1132 per ccf to pay for the added cost of water. If approved, the adjustment will be
effective for bills rendered on or after October 1, 2007, and be in effect for two months. The
RWCAF would be reviewed at the end of November for an adjustment effective December 1,
2007.
il/IA. D 4
FISCAL IMPACT
This will raise the RWCAF to a total of $0.2438 per ccf and recover much of the incremental
purchased water costs incurred in July and August of about $196,000. If the City experiences
heavy rainfall or customers reduce consumption substantially, actual cost recovery would be
reduced. The effective period of two months is appropriate since residential customers
outside the City are billed every two months.
Prepared by:
Cary Kalscheuer, Assistant to the Director of Utilities
RWCAF.doc.x is _
•
215
INCREMENTAL INCREASE IN WATER COST TO
AZUSA LIGHT &WATER CUSTOMER-2007 DROUGHT •
Water Consumption October November
City of Azusa-ccf 503,749 454,854
Azusa Valley- ccf 428,665 363,220
Total 932,414 818,074
Incremental Purchased Water Costs $90,060.51 $106,182.39
Cost per ccf $0.0966 $0.1298
AVERAGE COST/CCF $0.1132
216
AZUSA
IIGNT i WATEN
INFORMATIONAL ITEM
TO: HONORABLE CHAIRPERSON AND MEMBERS OF THE AZUSA UTILITY BOARD
AND AZUSA CITY COUNCIL
FROM: JOSEPH F. HSU, DIRECTOR OF UTILITIES
DATE: SEPTEMBER 24, 2007
SUBJECT: QUARTERLY FUEL COST ADJUSTMENT FOR SAN JUAN RESOURCE
On July 26, 2004, the Utility Board approved a fuel cost adjustment mechanism for San Juan
power plant. This mechanism is intended to credit customers with cost savings that are
realized when our power plant operates reliably and replacement power costs are avoided,
and conversely, allow the Utility to increase revenues to recover a portion of our replacement
power costs when the San Juan resource experiences outages.
This report encompasses replacement power costs incurred for the San Juan resource during
the period of June 16, 2007 through September 15, 2007. For reasons stated below, staff
recommends that NO Fuel Cost Adjustment be assessed on customer electric billings for the
period of October 1, 2007 through December 31, 2007.
The availability of the San Juan unit #3 during the period of June 16, 2007 through September
15, 2007 was 88%, higher than the budgeted availability of 85%. The average cost of
replacement power was $55.40/MWh as compared to the budgeted cost of $40/MWh,
resulting in a net charge of $40,170 for Fuel Cost Adjustment for the quarter, and when
combined with the carry over from the previous quarter of $336,628 it resulted in a total FCA
credit of $296,458.
Normally, when FCA credits exceed $150,000 the amount would be credited back to
customers on their electric bills in the immediately following quarter. However, given the
anticipated large San Juan replacement power costs in the first quarter of 2008 due to
planned San Juan unit 3 major maintenance outage staff continues to recommend the FCA
credits be carried over to offset the foreseeable large San Juan FCA charges early next year.
Prepared by: Bob Tang, Assistant Director of Resource Management
Attachment , p/vtalt-
0,1 I�
SJ FCA Q4_07.xls /0)-(i
U
224
San Juan Fuel Cost Adjustment Calculation for Q4 2007
June 16-July August September(*)
Actual SJ Output 30,576 18,500 9,265
Actual SJ Replac Energy Cost $179,234 $181,231 $77,145 $55.40
Maximum Output 33,120 22,320 10,800
Unavailable SJ Output 2,544 3,820 1,535 11.92%
% Outage Rate 7.68% 17.11% 14.21%
Base SJ Output @ 85% 28,152 18,972 9,180
Unavailable SJ Output 4,968 3,348 1,620
% Outage Rate 15.00% 15.00% 15.00%
Base SJ Replac Energy Cost @$40/MWh $198,720 $133,920 $64,800
Actual - Base SJ Replac Energy Cost -$19,486 $47,311 $12,345
San Juan Insurance Premium Recovery $0 $0 $0
San Juan Insurance Payout $0 $0 $0
Cumulative Quarterly Difference (CQD) $40,170
Q2 2007 Carry-Over -$336,628
If I(CQD)k4100,000, then adjustment=0
If I(CQD)1>$750,000, then adjustment=+-$750,000
or else adjustment= CQD -$296,458
October November December
Forecast Retail Sales (MWh) 21,660 20,406 20,437
SJ FCA for Q4 2007 (cents/KWh) -0.47
(*) Through September 15th, 2007
L\)
NI
CJI
rr
_ _
LIGHT i WATER
INFORMATION ITEM
TO: HONORABLE CHAIRPERSON AND MEMBERS OF THE AZUSA UTILITY BOARD
AND AZUSA CITY COUNCIL
FROM: JOSEPH F. HSU, DIRECTOR OF UTILITIES
DATE: SEPTEMBER 24, 2007
SUBJECT: WORKSHOP ON SOLID WASTE AND RECYCLING ISSUES
In order to brief new members of the Utility Board in more detail on a few items concerning
solid waste management in the City of Azusa, staff is planning a workshop to immediately
follow the January 28, 2008, regular Utility Board meeting. The draft agenda is as follows:
1. Introductions
2. Solid Waste Contract Issues
a. Background on Athens Services Contract
b. Pros and Cons of Athens Contract, including Evergreen Clause
c. Athens Services' Perspective
3. Challenges
a. Legislative Trends
b. Continued Compliance with AB 939
c. Closure of Puente Hills Landfill in Oct 2013
d. Disposal of Universal Wastes (Hazardous Wastes)
4. Utility Board Discussion/ Direction
Representatives from Athens Services will be invited to make a presentation on their future
plans to serve their contract cities and how they plan to dispose of waste after the Puente
Hills Landfill closes in October 2013.
The closure of Puente Hills landfill will have multiple ramifications, including compliance with
AB 939, the state's recycling mandate. For instance, yard waste will no longer be taken to
Puente Hills and the City will loose recycling credit for this portion of the waste stream.
Individual Board members may wish to have additional items placed on the above draft
agenda prior to the meeting.
Prepared by: 01 .1 11f)
jyt-)
Cary Kalscheuer, Assistant to the Director of Utilities °\\. /; I
242