HomeMy WebLinkAbout1994-11-29 Packet CITY OF UKIAH
CITY COUNCIL AGENDA
Regular Adjourned Meeting
CIVIC CENTER COUNCIL CHAMBERS
300 Seminary Avenue
Ukiah, CA 95482
November 29, 1994
4:00 p.m.
o
.
Roll Call
AUDIENCE COMMENTS ON NON-AGENDA ITEMS
The City Council welcomes input from the audience. In order for everyone to be heard, please
limit your comments to three (3) minutes per person and not more than ten (10) minutes per subject.
The Brown Act regulations do not allow action to be taken on audience comments.
3. NEW BUSINESS
a. Workshop with Discussion Concerning Electric Utility Operations and Issues
i. Northern California Power Association Orientation Regarding Direct Process and Risk Assessment
Study (Retail Wheeling)
ii. Undergrounding of Utilities - Review and Recommendations
iii. Lake Mendocino Hydroelectric Plant Operations
iv. Electric Distribution Operation - Review and Recommendations
v. Revenue Requirements and Generation - Review and Recommendations
vi. Customer Rate Paying Policies - Review and Recommendations
b. Possible City Council Direction Regarding Issues Reviewed and Discussed During Workshop
4. ADJOURNMENT
The City of Ukiah complies with ADA requirements and will attempt to reasonably accommodate individuals
with disabilities upon request.
M E M 0 R A N D U M
DATE:
TO:
FROM:
January 20, 1988
Honorable Mayor and Councilmembers
D. Kent Payne, City Manager
SUBJECT: REPORT ON UNDERGROUNDING OF CITY ELECTRIC FACILITIES
UNFINISHED BUSINESS - 9b
MEMORANDUM
DATE:
TO:
FROM:
January 6, 1988
D. Kent Payne, City Manager ~
Maurice K. Koper, Director of Electric Utilit.
SUBJECT: City Council Goals - Undergrounding of Electric Facilities on State
Street within the City limits
At the September 3, 1987 meeting~ith the City Council to discuss City Council
goals we presented a memorandum and a map outlining a construction schedule
along with estimates for undergrounding State Street within the City limits.
This proposal was well received by the City Council and, in fact, they asked
that we revise our proposal to include the undergrounding of the three main
feeders into the City from the freeway on Perkins, Gobbi, and Talmage Road.
This has now been done and the revised schedule along with today's costs and
future costs based on a 5% escalation per year is provided for the Council's
consideration.
Scheduled Construction Location
Today's Cost
Cost at time
of construction
Phase 1 1989
Perkins St. $ 241,141.00
$ 272,955.00
Phase 2 1991
State, Clay
to Gobbi St.
158,000.00
189,600.00
Phase 3 1994 Gobbi St. 282,837.00 381,830.00
Phase 4 1998 State, Henry 270,560.00 419,368.00
to Low Gap Rd.
Phase 5 2000
State, Low Gap
~ Empire Dr.
360,000.00
594,000.00
Phase 6 2002
Phase 7 2005
State, Gobbi
to Laws Ave.
Talmage Rd.
626,000.00
211,814.00
1,095,500.00
402,446.00
TOTAL COSTS
$2,150,352.00
$3,355,699.00
As with our previous memo, these estimates include the immediate area of State
Street and do not extend on to the side streets any significant amount.
Should it be necessary to extend some of the side streets, this could increase
the costs as shown in these estimates. We believe the eJtimates are
reasonably accurate and should provide the Council with a planning tool to
determine how they might want to approach the undergrounding of these
facilities in the future. This does not account for any costs for cable
television or telephone costs. These would be their responsibility. It is
also our intent to suggest that after the Council reviews this information
that we would be approaching the Council to set up undergrounding districts so
that other agencies such as cable television, telephone, and P.G.and E. would
be able to schedule their activities in such a matter as to coordinate with
the City's undergrounding plans.
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}i E M O R A N D U M
DATE:
TO:
FROM:
January 20, 1988
Honorable Mayor and Councilmembers
D. Kent Payne, City Manager
SUBJECT: REPORT ON UNDERGROUNDING OF CITY ELECTRIC FACILITIES
UNFINISHED BUSINESS - 9b
MEMORANDUM
DATE:
TO:
FROM:
January 6, 1988
D. Kent Payne, City Manager ~
Maurice K. Roper, Director of Electric Uttlit.
SUBJECT: City Council Goals - Undergrounding of Electric Facilities on State
Street within the City limits
At the September 3, 1987 meeting~ith the City Council to discuss City Council
goals we presented a memorandum and a map outlining a construction schedule
along with estimates for underground~ng State Street within the City limits.
This proposal was well received by the City Council and, in fact, they asked
that we revise our proposal to include the undergrounding of the three main
feeders into the City from the freeway on Perkins, Gobbi, and Talmage Road.
This has now been done and the revised schedule along with today's costs and
future costs based on a 5% escalation per year is provided for the Council's
consideration.
Scheduled Construction Location
Today's Cost
Cost at time
of construction
Phase 1 1989 Perkins St. $ 241,141.00 $ 272,955.00
Phase 2 1991
State, Clay
to Gobbi St.
158,000.00
189,600.00
Phase 3 1994
Gobbi St. 282,837.00 381,830.00
Phase 4 1998
State, Henry
to Low Gap Rd.
270,560.00
419,368.00
Phase 5 2000
State, Low Gap
~ Empire Dr.
360,000.00
594,000.00
Phase 6 2002
State, Gobbi
to Laws Ave.
626,000.00
1,095,500.00
Phase 7 2005
Talmage Rd.
211,814.00
402,446.00
TOTAL COSTS
$2,150,352.00
$3,355,699.00
As with our previous memo, these estimates include the immediate area of State
Street and do not extend on to the side streets any significant amount.
Should it be necessary to extend some of the side streets, this could increase
the costs as shown in these estimates. We believe the e~timates are
reasonably accurate and should provide the Council with a planning tool to
determine how they might want to approach the undergrounding of these
facilities in the future. This does not account for any costs for cable
television or telephone costs. These would be their responsibility. It is
also our intent to suggest that after the Council reviews this information
that we would be approaching the Council to set up undergroundtng districts so
that other agencies such as cable television, telephone, and P.G.and E. would
be able to schedule their activities in such a matter as to coordinate with
the City's undergrounding plans.
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MEMORANDUM
DATE:
TO:
FROM:
SUBJECT:
NOVEMBER 23, 1994
CITY COUNCIL
CHARLES L. ROUGH, JR., CITY MANAGER ~
NOVEMBER 29, 1994 ELECTRIC UTILITY WORKSHOP
The November 29 workshop is intended to provide basic information regarding the
Electric Utility, forecasts relative to the medium range future of the Utility, and background
data for the pending rate modification. It will also be an opportunity to discuss the City's
position within the Northern California Power Association (NCPA).
The topics to be considered at the workshop include:
1
m
3.
4.
5.
1
Direct Access (Retail Wheeling) and Ongoing Risk Assessment Study
by NCPA
Undergrounding Projects
Lake Mendocino Operation
Electric Distribution Operation
Revenue Requirements and Revenue Generation
a. Cost of Service
b. Generation
c. Transmission
d. Distribution
e. Depreciation
f. Non-Energy Related
Customer Rate Paying Policies
lm
DIRECT ACCESS (RETAIL WHEELING) AND ONGOING RISK ASSESSMENT
STUDY BY NCPA
Mike McDonald, General Manager of NCPA, and members of his staff, will be in-
attendance at the workshop to provide the Council with a presentation on Direct
Access and its possible implication for our Electric Utility, and the Risk Assessment
study being compeleted under their directions.
2-5.
UNDERGROUNDING PROJECTS, LAKE MENDOClNO OPERATION, ELECTRIC
DISTRIBUTION OPERATION, AND REVENUE REQUIREMENTS AND REVENUE
GENERATION
These items are outlined or discussed in detail in the November 28, 1994 report
"Revenue Requirement Analysis for the City of Ukiah Electric Utility" prepared by
Darryl Barnes, Director of Electric Utility (Attachment No. 1, pages 3-34). Darryl
will be discussing these matters with the Council at the workshop.
6. CUSTOMER RATE PAYING POLICIES
Attachment No. 2 (pages 35-38) discusses current and proposed policies relative
to the manner in which customer service and billing are processed.
Recommendations for modifications are presented for City Council consideration.
mfh:adrnin
ELECTRIC WORKSHOP
2
REVENUE REQUIREMENT ANALYSIS
CITY OF UKIAH
ELECTRIC UTILITY
NOVEMBER 28, 1994
Mendocino Operation
Complete repair of damaged plate and
reinforcement of existing plate in
December 1994- $110,000 contracted
Contract for routine maintenance and
periodic equipment inspections -
$30,000 to $50,000 annual contract
Contract for FERC required annual
penstock inspection and maintenance
program- $7,000 to $10,000 annual
contract
Operation and maintenance of dissolved
oxygen system and Corps pre-flood
inspection work- $120,000 annually
ake Mendocino Operation
Upgrade and maintain SCADA system
for remote operation of power plant -
$30,000
Operation of water supply system to
state fish hatchery- $30,000 generation
loss annually
Continual correspondence, reporting
and coordination of operation with:
a) COrps of Engineers
b) Federal Energy Regulatory
Commission
c) California Department of Fish and
Game
Design, process and construct revenue,
.redevelopment and upgrade projects -
$200,000 annually on contract basis
Design and reconductor main circuits to
standards - $100,000 annually for 5
years on contract basis
Re-configure underground system-
$60,000 annually for 5 years
Eliminate PCB high risk equipment-
$50,000 annually for 3 years
Protection scheme of system
Operation manual of system
UNDERGROUNDING
PROJECTS
PHASE I- GOBBI STREET TO
SEMINARY- $400,000
FOUR ADDITIONAL PHASES OVER
NEXT FIVE YEARS - $1,800,000
SYSTEM IMPACTS - AESTHETICS
-COST $80 vs. $20 PER FOOT
-INCREASED OUTAGE TIME
- EMPLOYEE SAFETY
REQUIREMENTS
-REDUCED CABLE LIFE
- ACQUIRE EASEMENTS
POLICY ISSUES
- REQUIRE OWNER TO
UNDERGROUND SERVICE
- PURCHASE 2,400 ft~ OF UTILITY
EASEMENT
GOBBI TO SEMINARY STATUS
- INITIAL DESIGN COMPLETE
-PENDING STATE STREET
CONTOUR DESIGN
- PENDING FINAL EASEMENTS
EXECUTIVE SUMMARy
The completion of the Fiscal 1994-1995 Electric Utility Budget gave indications that with
the currently planned level of expenditures, and the expiration of the Power Sale Contract with
the Western Area Power Administration, additional revenues would be required to cover an
anticipated operating loss. It is anticipated that the shortfall will be approximately $349,879 in the
current operating year. This will translate into a revenue requirement increase of 3.3% for this
year.
In order to obtain an indication of the effect of this revenue requirement increase on future
years and to determine what future revenue requirements can be expected, an analysis was
conducted to determine the future revenue requirement for a five year period covered by the fiscal
years 1994-1995 through 1998-1999. Expected operating expenses and non-rate generated
revenue increases were assumed based on anticipated furore revenue projects and operating
requirements. The results of this analysis are defined in Section 6 of this report. The results
indicated that a total of $891,402 of increased revenues will be required over the five year study
period. Should the Council elect to increase annual revenues by the $349,879 indicated in the
1994-1995 and 1995-1996 fiscal year, an additional $541,523 will be required during this time
period.
The comparisons in Section 6 reflects an effort to determine the magnitude and timing of
various revenue requirement increases in an effort to determine which program will require the
least amount of revenue increases over the study period to give Council an indication of the
possible furore impacts of various alternatives.
Should the Council elect to adopt the 3.3% increase for the 1994-1995 fiscal year, a
determination will be required as to the amount of increase that will be required by each rate class.
Section 7 of this report reflects staffs recommendation relative to meeting this requirement.
A model of customer's monthly use patterns was formulated for the three rate classes of
customers. These classes are Residential, General Services, and General Services with Demand.
The General Service Class is our small commerical customers, such small retail stores and offices.
The General Services with Demand, represents our larger commercial customers such as Wal-
Mart and K-Mart, that have a large power demand requirement.
The recommendations in Section 7 are as follows:
1) Increase the Residential Tier 1 energy charge by 3.5%, and not increase the Tier 2 energy
charge. In addition, staff would recommend decreasing the summer energy lifeline allowance from
410 KWH to 360 KWH. This change fits with our energy conservation goals and will reduce the
cost advantage of an all electric residence. In addition, the winter lifeline rate should be reduced
from 772 KWH to 660 KWH again to reduce the cost advantage of an all electric residence.
These changes would result in an overall 2.8% increase in residential rates and would
produce approximately $109,621 in additional annual revenues. This will maintain a revenue
requirement approximately 7.3% below Pacific Gas and Electric Company's current residential
rates.
2)
It is recommended that the General Service rate class be restructured to reflect the
seasonal cost requirements of the utility. Energy is least cosily in the winter and most costly in the
summer. Therefore, it is recommended that the Winter energy cost be reduced 2.7% and that the
Summer energy charge be increased 8.2%. This change will produce an annual increase in
revenues from this class of $92,307 or 3.3%. These changes will bring the class in line with our
tree cost of service. These changes will place this rate class approximately 7.1% below Pacific
Gas and Electric Company.
3) In the General Service with Demand rate class it is recommended that the Winter energy
charge be increased by 3.0% to reflect our seasonal cost of energy. It is recommended that the
Summer energy charge remain at the current level. The other area in which seasonal cost should
be reflected is in the Winter and Summer Demand Charge. Currently the charge has been
distributed at the $3.60 / KW-Month for both Winter and Summer. It is recommended that this
charge be structured to reflect our actual cost for Summer and Winter, and that the Winter
Demand rate be held at the $3.60 / KW-Month and that the Summer Demand rate be increased to
$5.75 / KW-Month. These changes would result in an increase of revenues for this rate class of
$128,677 or 4.3%.
All of these changes will result in an increase of annual revenues of approximately
$349,879 which reflects an overall revenue increase of 3.3% and that this revenue increase will
cover all expected expenses for this fiscal year.
- /D---
SECTION
Introduction
The purpose of this analysis is to evaluate the current rate structure of the Electric Utility
and to recommend changes and adjustments to the rate schedules to satisfy the current and future
revenue requirements. The Electric Utility will experience increased revenue requirements
beginning with the 1994-1995 Fiscal Year, as result of the expiration of the Western Area Power
Administration Power Sale Agreement relative to the Lake Mendocino Hydro Project and the
increased funding required for the Underground District Projects and other planned projects over
the next five year operating period.
An effort will be made in this analysis to determine the cost of service for the electric
utility and the cost for each area of expenditure that contributes to that cost of service. This
determination will become important as cost cutting measures become important relative to
keeping the Electric Utility competitive with other service providers. It will also give us a
benchmark to evaluate the economic performance of the utility. This will become very important
as the world of direct access and retail wheeling unfolds in the fututre. Even if the requirements
for retail wheeling are not probable in the near furore, the world of competition will remain a
concern in the electric utility industry, as consumers become more aware of their bargaining
power for utility services.
Cost of Service
The following Tables show the total cost of providing service to our electric customers.
This cost of service is based on the anticipated expenditures for each area of the utility. As can be
seen, expenses for the utility are separated into five classes. They are Generation, Distribution,
Transmission, Depreciation and Non-Energy. The first three items are directly related to the
production and transportation of our product. Depreciation is an expense that is collected and
pooled for the replacement of capital equipment and projects. The Non-Energy items are those
expenses that relate to services and other costs of doing business, and are reflected as
departmental transfers and allocations.
As can be seen in Table 1-1 our current five year plan was designed to hold the cost of
service to our customers constant over the time period. Table 1-2 reflects the cost of service as a
percentage for each area of expenditure. It can clearly be seen that the cost of generation is by far
the largest component of our business. As such any small change in this component could
significantly alter the cost of service and the related revenue requirements. The Non-Energy
expenses is the next largest component of expense to the. cost of service.
TABLE 1-1
·
COST OF SERVICE - S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Generation 0.079 0.079 0.078 0.077 0.076
Transmission 0.002 0.002 0.002 0.002 0.002
Distribution 0.007 0.007 0.007 0.007 0.007
Depreciation 0.009 0.009 0.009 0.009 0.009
Non-Energy 0.016 0.017 0.017 0.017 0.017 ,,,
Total 0.113 0.114 0.113 0.112 0.111
TABLE 1-2
PERCENT CONTRIBUTION
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Generation 69.9 69.3 69.0 68.8 68.5
Transmission 1.8 1.8 1.8 1.8 1.8
Distribution 6.2 6.1 6.2 6.3 6.3
Depreciation 8.0 7.9 8.0 8.0 8.1
Non-Energy 14.1 14.9 15.0 15.1 15.3
Table 1-3 represents the total expected expenditure for each class of expense for the five
year study period. It is expected, that these revenue requirements will increase at the rate of
approximately 1.5% annually. This increase reflects the anticipated increase in salaries for City
of Ukiah employees as they relate to the Electric Department and Northern California Power
Agency staff. In addition, the Non-Energy area is also related to services provided by other City
of Ukiah Departments and is directly related to salaries.
TABLE 1-3
Fiscal Year
Generation
Transmission
Distribution
Depreciation
Non-Energy
Total
1994-1995
8,263,400
200,600
722,000
890,000
11,779,879
ANNUAL REVENUE REQU/REMENTS
1995-1996
8,306,200
182,800
739,000
905,000
1,759,368
11,892,368
1996-1997
8,394,200
185,000
756,400
921,667
1,790,712
12,047,979
1997-1998
8,435,600
185,000
774,300
938,334
1,823,984
12,.157,218
1998-1999
8,478,200
187,000
792,600
957,000
1,854,202
12,269,002
The Depreciation expense reflects the increased requirement for funding as additional
capital equipment and projects are added to the assets of the Electric Utility.
SECTION 2
Generation
The cost of generation is composed of three components, Ukiah owned generation that is
operated by the Northern California Power Agency, Ukiah owned and operated, and purchased
power. In all cases the capacity and energy for each class except the Ukiah owned and operated
units are dispatched by the Northern California Power Agency. The Ukiah owned and operated
unit represents the Lake Mendocino Hydro Project, from which the energy and capacity is
scheduled based on the water requirements of Sonoma County and the Corp of Engineers for
flood control and is placed directly into the City of Ukiah electric distribution system. This
capacity and energy reduces the amount of purchased power required that would be required
from other sources.
Currently the City of Ukiah holds a participation share of the following projects:
Geothermal Projects 1 and 2
Hydro Project 1
Combustion Turbine 1
The City of Ukiah currently has power purchase agreements with the following:
Western Area Power Administration
Washington Water and Power
Seattle City Light
Midway Sunset Co-Generation
The participation units which represent City of Ukiah ownership have an average cost to
the system of $ 0.1070/ KWH. It is anticipated, that these costs will increase slightly in the
future, due to the reduced output of the geothermal units caused by the loss of pressure in the
steam field. However, it is expected that the cost of power from NCPA will remain fairly
constant over the study period. Alternatives are being explored relative to maintaining unit
operations to cover the debt service period. These options include, the addition of low pressure
turbine operation, water injection at the steam fields and unit shut downs in an effort to save
steam field pressure.
The purchase contract with the Western Area Power Administration is based on a ten (10)
year contract. This contract was renewed and will run from July 1, 1994 through June 30, 2004.
The cost of the purchase power under this contract is $ 0.028/KWH. It is expected that the cost
of this power will increase slightly over the contract term. However, this could change
significantly, depending on various options being explored by congress relative to the various
power marketing districts, Any additional requirements relative to improving fish habitat, or
water quality concerns such as the Bay-Delta requirements could have a significant impact on the
cost of WAPA power. The largest impact could occur due to the effort to install the temperature
control device at Lake Shasta in to reduce the bypass water currently required for fish, that
reduces the amount of water that can be used for generation.
The Lake Mendocino Hydro Project represents $ 0.1665/KWH toward the cost of
generation. The primary cost component of the project, is the debt service of $2,000,000
annually. Other factors are the requirement of oxygen addition to the river for fish habitat, that is
a requirement of our operating license and results in an annual expenditure of $100,000 for
oxygen. The annual royalty paid to the Federal Energy Regulatory Commission for the use of
government facilities of approximately $20,000 annually.
TABLE 2-1
_ANNUAL ENERGY - KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 13,254,000 13,254,000 13,254,000 13,254,000 13,254,000
Western 45,727,200 45,727,200 45,727,200 45,727,200 45,727,200
NCPA 44,758,300 46,828,000 48,939,100 51,092,400 52,190,600
Total 103,739,500 105,809,200 107,920,300 110,073,600 111,171,800
The energy estimates for the Lake Mendocino Projects are based on an average dry year
generation. It is expected that the generation will remain minimum from the Lake Mendocino
project over the five year period of this study. Although this assumption is considered
conservative, it will allow for a margin of safety relative to the expenses for generation.
The energy supplied by the Western Area Power Administration is expected to be at
contract maximums during this study period.
The additional energy required for meeting the City of Ukiah load requirements will be
supplied through City owned units or through purchased power contracts.
TABLE 2-2
ENERGY COSTS - DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 2,164,000 2,150,000 2,150,000 2,150,000 2,150,000
Western 1,300,000 1,339,000 1,379,200 1,420,600 1,463,200
NCPA 4,799,400 4,817,200 4,865,000 4,865,000 4,865,000
Total 8,263,400 8,306,200 8,394,200 8,435,600 8,478,200
The cost of service for generation is that cost that contributes to the total cost of service to
our customers. As can be seen, although the cost of the Lake Mendocino energy is high relative
to other sources, the amount supplied to meet our load is small, and therefore contributes only
slightly to the total cost of service.
TABLE 2-3
COST OF SERVICE- S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 0.163 0.162 0.162 0.162 0.162
Western 0.028 0.029 0.030 0.031 0.032
NCPA 0.107 0.103 0.099 0.095 0.093
Total 0.079 0.079 0.078 0.077 0.076
The cost of NCPA power will increase slightly over the study period. This is due to the
assumption that California will continue to remain in a drought condition and therefore will not
be able to generate maximum output from the hydro projects. In addition, it assumes that the
output from the geothermal units will continue to decline as the steam field pressure continues to
drop. Projects are underway that could reduce the impact of the steam reductions. One option is
the Lake County effluent pipleline projects. This project Will pump Lake County effluent to the
Geyers Steam field and inject the water into the wells in an effort to increase the amount of steam
production. A second option that is being considered, is the combination of NCPA and Pacific
Gas and Electric Company's steam field and the shutdown of some of the generating units, in an
effort to maintain the existing steam at higher pressures. This would of course be done on some
cost/benefit sharing basis.
The NCPA cost of service includes all NCPA charges, including administration, dispatch
services and member services in addition to the generation related expenses.
SECTION 3
Transmission
The City of Ukiah's participation in the California- Oregon Transmission Project (COTP)
through our membership in the Transmission Agency of Northern California has provided the City
with the ability to access power sources in the Northwest and Southwest. This should provide
two benefits: 1) lower cost hydro power on peak and 2) the advantage of seasonal differences,
which means power is available when our system peaks. The City of Ukiah is currently receiving
energy from a contract with Washington Water and Power Company and will receive energy
through a seasonal exchange agreement with the Seattle City Light.
The City of Ukaih's participation also provides the ability to sell power and transport it on
the transmission system to potential markets, without having to pay wheeling charges to other
utilities for use of their transmission facilities.
Currently the City's annual expense for our share of the California - Oregon Transmission
Project and the South of Tesla portion of the transmission project is shown in Table 3-1.
TABLE 3-1
TRANSMISSION COST-DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
SOT 13,400 10,000 10,000 10,000 12,000
COTP 187,200 172,800 175,000 175,000 175,000
TOTAL 200,600 182,800 185,000 185,000 187,000
The City of Ukiah is currently utilizing the South of Tesla portion of the transmission line
to transport energy from Midway Sunset to the City of Ukiah.
TABLE 3-2
TRANSMISSION COST OF SERVICE - S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
SOT 0.00013 0.00009 0.00009 0.00009 0.00011
COTP 0.00180 0.00163 0.00162 0.00159 0.00157
TOTAL 0.00193 0.00172 0.00171 0.00168 0.00168
The annual cost for transmission in this study were taken from the NCPA 1994 and 1995
budget and projected transmission requirements for our loads through the study period.
SECTION4
Distributio~i
This area of the analysis covers the cost of upgrading and maintaining the distribution
system within the city. This is a very important part of the total utility system, since this system
is needed to service our customers. The condition of this system determines the amount of
outages related to system failure which directly impact our customers. The Ukiah system is in
need of upgrades. Aged poles and thermally stressed conductors result in poor system reliability
and a large number of damage claims. The lack of system protection equipment continues to be a
concern. It is important that we continue to work to upgrade our distribution system. As a result,
we should be directing a portion of our operation and maintenance budget to the replacement of
electrical infrastructure.
Fiscal Year
Overhead
Underground
Admin &
General
TABLE 4-1
DISTRIBUTION COST- DOLLARS
1994-1995
157,000
195,000
320,000
50,000
722,000
0.0070
1995-1996
161,700
200,900
326,400
50,000
739,000
0.0070
1996-1997
166,600
206,900
332,900
50,000
756,400
0.0070
1997-1998
171,600
213,100
339,600
50,000
774,300
0.0070
1998-1999
176,700
219,500
346,400
50,000
792,600
0.0071
The majority of the cost reflected in this section is related to salaries. The Overhead and
Underground portion of the costs represent salaries only. The Administration and General
reflects the salaries of the Director, Distribution Engineer and the Operations Supervisor. Other
costs that are adminstration related include, JPA Related Travel, Bulk Meter Rentals from both
NCPA and the Western Power Administration, Telephone Costs and other similial- type of
expenses that relate to the administration of the electric utility.
Depreciation
The other major expense in this section is the cost of depre~ciation for the utility.
Table 4-2 outlines the capital projects that are planned for the study period and their related effect
on the depreciation expense. It is anticipated, that approximately $300,000 of annual projects
would be preformed by contract. This will allow a rapid increase in system improves, without
having to staff up for a short term (less than five years) construction program.
TABLE 4-2
CAPITAL PROJECTS - DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Capital
Projects 650,000 450,000 500,000 500,000 560,000
Depreciation 890,000 905,000 921,667 938,334 957,000
S/KWH 0.0086 0.0086 0.0085 0.0085 0.0086
Capital Projects included over the next five year period will include system improvemnets
such as reconductoring of feeders, removal of 4Ky systems, Low Gap Intersection up-grade and
Underground District work planned over the study period.
SECTION
_Non - Energy Related Expense
The expenses outlined in this area are related to services provided by other departments
and charges to the electric utility through allocated transfers. These include: Utility Billing,
Purchasing, Garage, General Governmental Services, Finance Services and Dispatch Services.
These allocated transfer will amount to $1,703,879 in the 1994 - 1995 fiscal year. These are
expenses that are allocated to the Electric Department.
TABLE 5-1
NON-OPERATING EXPENSES-DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Meter
Reading 80,423 83,640 86,986 90,465 90,466
Utility 183,770 189,283 194,496 200,810 206,835
Billing
Purchasing 75,811 78,085 80,428 82,841 85,326
General
Government 588,704 606,365 624,556 643,293 662,592
Dispatching 22,359 23,253 24,183 25,151 26,157
Garage 42,759 44,042 45,363 46,724 48,126
Uncollected
Bills 55,000 60,000 60,000 60,000 60,000
In Lieu Fee 655,053 674,700 674,700 674,700 674,700
Total 1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
S/KWH 0.0164 0.0166 0.0166 0.0166 0.0167
The meter reading expe, nses, purchasing and warehousing, general governmental
charges, dispatching, are directly related to salaries. Therefore, it was assumed that these cost
would increase based on an annual salary increase of approximately 4%.
Garage charges include the cost of fuel and parts in addition to salaries. Therefore, it was
assumed that this component would increase less rapidly as the other charges.
It was assumed that the amount of uncollected bills would remain approximately the
same over the study period. However, it should be noted that the electric utility has no control
over the amount required for uncollected bills.
The In Lieu Fee was based on the assumption that no additional revenue requirement
would be required after this fiscal year.
SECTION 6
Revenue Re~_uirements
The revenue requirements based on the 1994 - 1995 fiscal budget and projects for the next
four fiscal years are shown in Alternate 1. The results, indicate that an additional revenue
requirement of approximately $350, 000 will be required in order to place the electric operations
in a positive cash-flow position for fiscal year 1994-1995. In addition, this increase will allow
rates to cover expected expenditures, provided that there are no significant increases in the
utility's operational costs or any significant changes in the cost of generation. With the current
regulatory atmosphere relative to market rates for Western Area Power Administration
customers and the outlook for the geothermal steam fields, this is not a f'u'm assumption.
However, staff does not see any significant changes in WAPA policy and pricing over the study
period.
The Base Case indicates the results of operations without an increase in revenues in the
1994-1995 fiscal year. The results show a $349,879 revenue short-fall. Alternate 1 represents
the results assuming a 3.30% revenue increase in 1994-1995, assuming the revenues will not be
generated until December 1, 1994.
In order to utilize the ending balance reserve, it was assumed that a rate adjustment
would not occur until the ending balance goes negative. On this basis, the study indicates that
another revenue increase will be required in the 1996-1997 fiscal year of approximately 3.8% as
shown in Alternate 1-B.
Alternates 1-A through 1-D represent various options for timing the revenue increase over
the five years. The option that would produce the lowest overall rate increase over the five year
period would be the best planned increase. The results are as follows:
Alternate 1-A requires 6.2% or $672,408
Alternate 1-B requires 7.1% or $778,043
Alternate 1-C requires 8.4% or $935,251
Alternate 1-D requires 5.5% or $628,650
Alternate 2-A requires 7.4% or $822,805
Therefore, the best alternative to minimize the revenue increase to the electric customers
over the next five years would be a total increase in the 1994-1995 fiscal year of 5.5% or
Alternate 1-D. The next best alternative would be to increase revenues 3.3% in 1994-1995 and
2.46% in 1995-1996 as described in Alternate 1-A. The other alternatives will delay additional
rate increases, but the result will be higher revenue requirements over the five year time period.
Base Case-No Revenue Increase
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERA TIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERA TING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TO TAL REVENUES
TO TAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE
CUMMULATIVE BALANCE
571,500
1994-1995
1,300,000
4,799,400
2,164,000
8,263,400
1995-1996 1996-1997 1997-1998 1998-1999
1,339,000 1,379,200 1,420,600 1,463,200
4,817,200 4,865,000 4,865,000 4,865,000
2,150,000 2,150,000 2,150,000 2,150,000
8,306,200 8,394,200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536,618 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
10,917,600 10,917,600 10,917,600 10,967,600 10,992,600
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,000
132,400 0 0 0 0
11,430,000
11,779,879
11,252,600 11,252,600 11,302,600 11,327,600
11,892,368 12,047,979 12,157,218 12,269,002
0.00% 0.00% 0.00% 0.00% 0.00%
0 0 0 0 0
0 0 50,000 25,000 50,000
11,430,000 11,252,600 11,302,600 11,327,600 11,377,600
-349,879 -639,768 -745,379 -829,618 -891,402
571,500 221,621 0 0 0
221,621 -418,147 -745,379 -829,618 -891,402
221,621
-418,147 -1,163,526 -1,993,144 -2,884,546
ALTERNATE 1
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
EN DING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1~5
1,300,000
4,799,400
2,1~,000
8,2~,400
1995-1996 1996-1997 1997-1998 1998--1999
1,339~0 1.379,200 1,420,600 1,463,200
4,817,200 4.865J300 4,865J300 4,865~)0
2,150,000 2,150,000 2,150,000 2,150,000
8,306200 8,394,200 8,435,600 8,478,200
13,400 10.000 10,000 10,000 12~
187,200 172.800 175~00 175,000 175,000
200,600 182,800 1 &.5,[~C]O 185,000 187,000
722.000 739,000 756,400 774,300 792,600
1,703,879 1.759,368 1,790,712 1,823,984 1,854,202
890.000 905,000 921,667 938,334 957,000
3,315,879
11,779,879
3,403,368 3,468,779 3,536,618 3,603,802
11,892,368 12,047,979 12,157,218 12,269,C]02
10,917,600 11,121,696 11,267,479 11,317,479 11,842,479
110,000 65,CZ~] 65,CI~ 65,000 65,C00
270,a00 270,000 270,000 270,000 270,000
182,400 0 0 0 0
11.430 J~30
11.779,879
11,456,696 11,602,479 11,652,479 11,677,479
11,892.368 12,047.979 12,157,218 12,260J:302
3.30% 0.00% 0.00% 0.00% 0.00%
204.096 0 0 0 0
0 145,783 50J300 25J330 50J:]00
11,634J396 11,602,479 11,652A79 11,677,479 11.727.479
-145,783 -289,889 -395,500 -479,739 -541£23
571,500 425,717 7,639 85,065 78.252
425,717 135.828 -,387,861 -394,674 ~163,27 !
ALTERNATE 1 -A
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571 ,,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-.1999
1,300,0O0
4,799,400
2,164,000
8.263,40O
1,339,000 1,379,200 1,420,600 1,463,200
4,817,200 4,865,000 4,865,[K]0 4,865,[]00
2,150,000 2,150,000 2,150,000 2,150,000
8,306200 8,394200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,[I]0
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957
3,315,879 3,403,368 3,468,779 3,536,618 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
10,917,600 11,121,696 11,590,008 11,640,008 11,665,D08
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270X]C]0 270,C00
132,400 0 0 0 0
11,430,[]00 11,456,696 11,925,008 11,975,D08 12,000,008
11,779,879 11,892,368 12,047,979 12,157,218 12,269,[]02
3.30% 2.90% 0.00% 0.00% 0.00%
204,096 322,529 0 0 0
0 145,783 50,[X]O 25,000 50,000
11,634,096 11,925,008 11,975,008 12,000,008 12,050~8
-145,783 32,640 -72,971 -157,210 -218,994
571,500 425,717 458,357 385,386 228,176
425,717 458,357 385,386 228,176 9,182
ALTERNATE I-B
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-.1999
1,300,000
4,799,400
2,164,000
8,263,400
1,339.000 1,379,200 1.420,600 1,463,200
4,817,200 4,865.000 4,865.[X]0 4,865,000
2,150,000 2,150.000 2,150.000 2,150.000
8,306,200 8,394,200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,aCK]
187,200 172,800 175,000 175,000 175,000
200.600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774 ,,:.'.'.'.'.'.'.'.'~0 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536,618 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12.269.002
10,917,600 11,121.696 11,267,479 11,745,643 11,770,643
110,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,000
182.400 0 0 0 0
11,430,000 11,456,696 11,602,479 12,080,643 12,105,643
11,779,879 11,892,368 12,047,979 12,157,218 12.269,[~2
3.30% 0.00% 3.80% 0.00% 0.00%
204,096 0 428,164 0 0
0 145,783 50,000 25,000 50,000
11,634,096 11,602,479 12,080,643 12,105,643 12,155,643
-145,783 -289,889 32,664 -51 275 -113,359
571,500 425,717 135,828 168,492 116,917
425,717 135,828 168,492 116,917 3,558
ALTERNATE 1-C
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1,300J:]00 1,339J:X]O 1,3792200 1,420~:~0 1~1632200
4,799JK]0 4,8172200 4,865J:]00 4,865J:~)0 4,865J:]00
2,164,000 2,150,000 2,150,000 2,150.000 2,150,000
8.263,400
8,3062200 8,3942200 8,435,600 8,4782200
13 ~ 10,000 10 ,CX30 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187.000
722,000 739,000 756,400 774.300 792,600
1,703,879 1,759.368 1,790.712 1,823,984 1,8542202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403~68 3~168,779 3,536~18 3,603,802
11,779,879 11,892~68 12,047,979 12,1572218 12,269J:]02
10,917,600 11,121~96 11,267~179 11,599,166 11,809,753
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,000
132,400 0 0 0 0
11,430,000 11,456,696
11,779,879 11,892,368
11,602,479 11,934,166 12,144,753
12,047,979 12,1572218 12,269~]02
3.30% 0.00% 2.50% 1.60% 1.00%
204,096 0 281,687 185,587 118,098
0 145,783 50,000 25,000 50,000
11,634J~6 11,602A79 11,934,166 12,144,753 12,312,850
-145,783 -289,889 -113,813 -12~65 43,848
571,500 425,717 135,828 22,015 9,550
425,717 135,828 22,015 9,550 53,398
ALTERNATE 1-D
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOClNO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERA TIN(~ EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300~30
4,799~100
2,164i]00
8,263~]0
1,339.000 1,379,2.00 1,420,600 1,468200
4.817,200 4,865,0CX3 4,865,C]00 4,865.000
2,150,000 2,150.000 2,150.000 2,150,000
8,306,200 8,394,200 8,435.600 8,478,200
13,400 10,000 10,O2K] 10,000 12
187,200 172,800 175,000 175~ 175fl:X]0
200,600 182,800 185.033 185,000 187,a00
722,000 739fl2l]0 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,91M 1,854,202
890~00 905,000 921,667 938,834 957~00
3,315,879 3~Z]3,368 3~168,779 3~536~18 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269..002
10,917,600 11.284,310 11.546250 11,596,250 11.621,250
110,000 65.0[X] 65,CK]0 65,000 65,000
270.000 270,000 270,000 270,Cl~ 270,02)0
132,400 0 0 0 0
11,430~210 11,619,310 11,881,250 11,931,250 11,956,250
11,779,879 11,892,368 12,047,979 12,157,218 12,269.1302
5.50% 0.00% 0.00% 0.00% 0.00%
366,710 0 0 0 0
0 261,940 50,000 25,CX]0 50,000
11,796,710 11,881,250 11,931,250 11,956,250 12,006,.250
16,831 -11,118 -116,729 -200,968 -262,752
571,500 588,331 577,213 460~84 259,516
588,331 577,213 460,484 259,516 ~,236
ALTERNATE 2-A
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOClNO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300~)0
4,799/K]0
2,164~00
1,339~]0 1,379,200 1,420/:~]0 1,463,200
4,817,200 4,865~]0 4,865~X]0 4,865~]0
2,150i]00 2,150,000 2,150,CK]0 2,150,000
8,263A00 8,306200 8,394200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854202
890,000 905,a00 921,667 938,334 957,000
3,315,879 3,403~68 3,468,779 3,536/>18 3,603,802
11,779,879 11,892~68 12,047,979 12,157,218 12,269~]02
10,917/~]0 10,917,600 11,343~86 11,790A05 11,815,405
110,000 65,000 65,000 65,000 65,000
270,(l]0 270,000 270,000 270,Cl]0 270,000
132,400 0 0 0 0
11,430~]0 11,252/:~0 11,678,386 12,125,405 12,150~I]5
11,779,879 11,892~68 12,047,979 12,157,218 12,269~]02
0.00% 3.9C~o 3.50% 0.00% 0.00%
0 425,786 397,019 0 0
0 0 50,000 25,000 50,000
11,430~]0 11,678,386 12,125/105 12,150/105 12,200,405
-349,879 -213,982 77,426 -6,813 -68,597
571,500 221,621 7,639 85,065 78,252
221,621 7,639 85,065 78,252 9,655
SECTION 7
Revenue Generation
An attempt was made to generate the required revenues equally between the three rate classes on
a percentage basis. In addition, each rate structure was modified to reflect actual cost of service
requirements, the effect on conservation policies, and reflect the true market conditions of the
electric utility. Therefore, the following changes are requested:
Residential
The first change in this rate class is to set all of the baseline energy rate equal to 360
Kilowatt-Hours except for the All Electric Winter Rate which will be reduced to 660 KWH from
772. This will level the playing field for customer with Electric Air-conditioning and Gas
Heating. The winter rate although reduced will aid customers with electric heat.
The second change will be to increase the Tier 1 energy rate 3.5% to $0.1074 / KWH.
This will bring the rate closer to the total cost of service for the rate class. The Tier 2 energy rate will remain unchanged.
These changes are forecasted to produce approximately $109,621 of increased revenues.
Resulting in a 2.8% increase in revenue from this class.
General Service
It is recommended that the monthly service charge for this rate class remain unchanged.
The energy cost of this class should be changed to reflect our true cost of service.
Therefore, it is recommended that the Summer rate increase $0.01126 / KWH. This results in an
increase of 8.2%. In addition, it is recommended that the Winter energy rate decrease $0.00302 /
KWH or 2.7%. These changes will result in an over all increase in revenues for this rate class of
$92,307 or a 3.3% increase.
General Service with Demand
The Winter Energy rate for this rate class should increase by 3.0% to $0.07876 / KWH. The
demand rate for the Summer rate should increase to $5.75/KW-MO from $3.60/KW-MO. This
change will more truely reflect our actual seasonal cost. Although the PG&E winter rate xvas
reduce to $1.65/KW-MO the $3.60/KW-MO truly reflect our demand cost in the xvinter months.
These chnages will result in an increase of $128,677 in revenues, a 4.3% increase in revenues.
Municipal
The changes made to both the General Services and General Services with Demand will cause
the Municipal rate class to increase by approximately $19,275 or 3.0%.
The results of these changes will generate the required revenue increase of $349,879
annually, which would result in an overall 3.4 % increase in revenue requirements.
ALTERNATE 1
RESIDENTIAL
EXISTING PROPOSED S DIFF
% DIFF
BASELINE:
BASIC WINTER 356 360 4 1.1
BASIC SUMMER 325 360 35 10.8
ALL ELECT. WINTER 772 660 -112 -14.5
ALL ELECT. SUMMER 410 360 -50 -12.2
ENERGY RATE:
TIER 1 0.10375 0.1074 0.00365 3.5
TIER 2 0.13667 0.13667 0 0.0
REVENUE* $3,917,560 $4,027,181 $109,621 2.8
PG&E
348
332
658
348
0.11950
0.13737
$4,322,382
%DIFF
-3.3
-7.8
-0.3
-3.3
11.3
0.5
7.3
GENERAL SERVICE
MONTHLY CHARGE:
1 PHASE 7.50 7.50 0 0.0
3 PHASE 8.75 8.75 0 0.0
ENERGY RATE:
WINTER 0.11269 0.10967 -0.CX]302 -2.7
SUMMER 0.13654 0.1478 0.01126 8.2
REVENUE* $2,795,475 $2,887,782 $92,307 3.3
8.10
12.00
0.10967
0.15999
$3,091,995
8.0
37.1
0.0
8.2
7.1
GENERAL SERVICE WITH DEMAND
MONTHLY CHARGE 63.00 63.00 0
ENERGY RATE:
WINTER 0.07647 0.07876 0.00229
SUMMER 0.09782 0.09782 0
DEMAND RATE;
WINTER 3.60 3.60 0
SUMM ER 3.60 5.75 2.15
REVENUE* $3,025,076 $3,153,753 $128,677
MUNICIPAL
REVENUE' $640,826 $660,101 $19,275
0.0
3.0
0.0
0.0
59.7
4.3
3.0
75.00
0.08015
0.09816
1.65
6.70
$3,035,909
$690,113
19.0
1.8
0.3
°54.2
16.5
-3.7
4.5
TOTAL REVENUE* $10,378,937 $10,728,816 $349,879
*BASED ON 5/93 -4/94
3.4
$11,140,397
3.8
ALTERNATE 1-A
RESIDENTIAL
EXISTING PROPOSED $ DIFF
% DIFF
BASELINE:
BASIC WINTER 356 360 4 1.1
BASIC SUMMER 325 360 35 10.8
ALL ELECT. WINTER 772 660 -112 -14.5
ALL ELECT. SUMMER 410 360 -50 -12.2
ENERGY RATE:
TIER 1 0.10375 0.1135 0.00975 9.4
TIER 2 0.13667 0.13737 0.13007 0.5
REVENU E* $3,917,560 $4,212, i 10 $294,550 7.5
PG&E
348
332
658
348
0.11950
0.13737
$4,32~,3~2
%DIFF
-3.3
-7.8
.-0.3
-3.3
5.3
0.0
2.6
GENERAL SERVICE
MONTHLY CHARGE:
1 PHASE 7.50 7.50 0 0.0
3 PHASE 8.75 8.75 0 0.0
ENERGY RATE:
WINTER 0.11269 0.10967 ~].00302 -2.7
SUMMER 0.13654 0.155 0.01846 13.5
REVENUE* $2,795~75 $2,966,608 $171,133 6.1
8.10
12.00
0.10967
0.1599~
$3,091,993
8.0
37.1
0.0
3.2
4.2
GENERAL SERVICE WITH DEMAND
MONTHLY CHARGE 63.00 70.00 7 11.1
ENERGY RATE;
WINTER 0.07647 0,08015 0.00368 4.8
SUMMER 0.09782 0.09816 0.00034 0.3
DEMAND RATE:
WINTER 3.60 3.60 0 0.0
SUMMER 3.60 6.25 2.65 73.6
REVENUE* $3,025,076 $3,208,789 $183,713 6.1
MUNICIPAL
REVENU E* $640,826 $669,975 $29,149
4.5
75.00
0.08015
0.09816
1.65
6.70
$3,035,909
$690,113
7.1
0.0
0.0
-54.2
7.2
-5.4
3.0
TOTAL REVENUE* $10,378,937 $11,057,482 $678,545
*BASED ON 5/93 -4/94
6.5
$11,140,397
0.7
Attachment #2
ELECTRIC UTILITY WORKSHOP
BILLING AND COLLECTIONS
The "General Service Demand Metered" rate schedule 1602-DM is
available for commercial service customers. This rate schedule is
intended for larger users. There has not been a minimum qualifying
usage established for this rate schedule. P.G.& E. requires usage
of at least 50,000 kwh per year to qualify for their comparable
rate schedule. Staff recommends adoption of a minimum usage of
50,000 kwh per year to qualify for this rate.
The "Domestic Service" rate schedule 1600 is available for single
family residential units. Staff is recommending the rewording of
the applicability statement from: "This is applicable to domestic
lighting, heating, cooking and single phase domestic power service
in single family dwellings and in flats and apartments separately
metered by the City." to "This is applicable to single phase
domestic power service in single family dwellings and in flats and
apartments separately metered by the City."
Part of the "Domestic Service" rate schedule provides for Life
Support Devices. The current wording is general or nonspecific in
several areas. Staff is recommending establishment of a separate
Life Support rate schedule and rewording of the descriptions of the
service:
General:
A "life support" device is any medical equipment which is
essential to sustain life or relied upon for mobility.
Life support devices include, but are not limited to,
respirators, iron lungs, hemodialysis machines, electric
nerve simulators, pressure pads and pumps, aerosol tents,
electrostatic and ultrasonic nebulizers, compressors,
IPPB machines and motorized wheelchairs.
ADDlicability:
This is rate applicable to a residential customer (full-
time resident of the household) who require a life
support device. The utility department requires written
certification from a physician or osteopath, licensed to
practice medicine in the State of California, that a
particular "life support" device is essential to sustain
life or is relied upon for mobility. Service under this
schedule is subject to City of Ukiah service policies.
Devices used for therapy rather than life support
generally do not qualify.
The life support rate does not guarantee continuance of
service if the account becomes delinquent.
Attachment #2
Service provided under this section will allow for a
uniform monthly lifeline allowance of 500 kwh per month
per eligible device in addition to the baseline
allowance. Eligibility for this service must be
recertified at least every two years.
The authority to make arrangements with customers for payment of
past due amounts is established by administrative procedure. Staff
recommends bringing back to Council a proposed policy for payment
arrangements and collection procedures.
Proposed Customer Payment Extension Policy:
1. There will be a limit of two (2) extensions per customer per
year. Where a customer has had several accounts within the same
year, the cumulative number of extensions on all the accounts would
apply.
2. The account must have been open for at least one year and have
reasonably good credit history before any extensions may be
granted. "Reasonably good: credit history shall be comprised of
the following:
1. No more than six "Past Due" incidents.
2. No more than three "Delinquent" notices.
3. No more than one "Final" notice.
If the customer's account has not been open for one year
but has established one year's credit with the City by
having other accounts which may add up to one year's
service, this is acceptable.
3. Extensions may only be granted with the understanding that the
entire account balance is to be paid in full at the culmination of
the extension period.
4. The normal extension granted for any one instance will be for
no more than 5 working days. The maximum extension shall be for no
more than 10 working days...in extreme circumstances.
5. If the terms of the extension are violated, the account is to
be disconnected immediately. No additional extensions will be
granted and no partial payments will be accepted. No additional
notice, such as a 48 Hour Notice/Final Notice will be given.
6. There will be a limit of one extension per incident.
Additional extensions may no be requested or granted, unless the
customer contacts our office in advance PRIOR TO THE DUE DATE in a
timely manner to re-negotiate the terms, but only if within the 5-
10 day limit as stated in item #4.
Attachment #2
The preceding information is not to be considered a recommendation
but rather, the adopted policy of this department. Customers
should not be given the impression that this policy can be
overridden by the Director of Finance. If a customer wishes to
lodge a complaint against this policy, they may do so through
normal channels for managing citizen complaints.
Citizen complaints are normally handled by the Finance Director or
in his/her absence, another finance employee may step in to help
resolve the situation. If the customer still feels he/she needs to
speak with someone at a higher level they are referred to the City
Manager's office. '
Payment Arrangements:
Payment arrangements are made by any member of the customer service
department by use of the above extension policy. However, if a
customer is in a unique situation and/or has had good prior credit
history, special terms may be arranged. Currently, our software
system does allow staff to manage and maintain these transactions
through the system and thus resolve any missed payments or
arrangements. If these special terms are not kept, immediate
termination of service could result. However, each case is handled
and viewed separately by the customer service staff and decisions
are made based on each account's history and current events. The
hope is to resolve any customer complaints quickly and fairly for
both the customer and the City.
There are numerous questions which tend to be legal in nature that
should be considered. Staff will pursue these questions with the
City Attorney. Some, if not all, of these questions should be
included in the Electric Customer Service Policy revisions.
1. Does the City have the authority to require a copy of
a lease?
2. Does the City have the authority to disconnect
current service for previous unpaid bills whether or not
the service is at the same address?
3. Does the City have the authority to deny changing
service to another person's name when the current named
customer continues to reside at the address? This
appears to be an attempt to avoid paying a delinquent
account.
4. Roommate situations - who is really liable for the
bill? Does the City have the authority to require all
adult occupants to sign the application for service? Are
all occupants liable for the bill even if they have not
signed the application for service?
Attachment #2
The schedule of delinquency dates and notices which lead up to
ultimate service disconnection for non-payment are established only
in administrative procedure. Perhaps they should be outlined in a
Council adopted policy.
Billinq and Collection Cycle:
Step 1. Bill is issued. Bill is delinquent if not paid within 25
days.
Step 2. On the 36th day after the date the bill was issued, a
delinquent letter is issued. This letter gives the customer 9 days
in which to pay.
Step 3. If payment is still not received, a "Final Notice" is
issued on the 46th day after the date of the bill. This notice
gives the customer 7 days from the date of the'notice to pay the
account in full or the service will be disconnected. A $5.00 Final
Notice fee is added to the account when this notice is prepared.
Step 4. If payment is still not received, the Utility Services
attendant is dispatched to disconnect the service. A $35.00
disconnect fee is added to the account at this time.
To restore service, the full account balance, including the
additional billings for services, must be paid in addition to a new
deposit and a $7.50 reconnect fee.
A second months services would have been billed between steps 1 and
2. A third months services would be billed about the same time
that the Step 4 disconnect would take place.
CITY OF UKIAH
CITY COUNCIL AGENDA
Regular Adjourned Meeting
CIVIC CENTER COUNCIL CHAMBERS
300 Seminary Avenue
Ukiah, CA 95482
November 29, 1994
4:00 p.m.
.
Roll Call
AUDIENCE COMMENTS ON NON-AGENDA ITEMS
The City Council welcomes input from the audience. In order for everyone to be heard, please
limit your comments to three (3) minutes per person and not more than ten (10) minutes per subject.
The Brown Act regulations do not allow action to be taken on audience comments.
3. NEW BUSINESS
a. Workshop with Discussion Concerning Electric Utility Operations and Issues
i. Northern California Power Association Orientation Regarding Direct Process and Risk Assessment
Study (Retail Wheeling)
ii. Undergrounding of Utilities- Review and Recommendations
iii. Lake Mendocino Hydroelectric Plant Operations
iv. Electric Distribution Operation - Review and Recommendations
v. Revenue Requirements and Generation - Review and Recommendations
vi. Customer Rate Paying Policies - Review and Recommendations
b. Possible City Council Direction Regarding Issues Reviewed and Discussed During Workshop
4. ADJOURNMENT
The City of Ukiah complies with ADA requirements and will attempt to reasonably accommodate individuals
with disabilities upon request.
MEMORANDUM
DATE:
TO:
FROM:
SUBJECT:
NOVEMBER 23, 1994
CITY COUNCIL
CHARLES L. ROUGH, JR., CITY MANAGER ~
NOVEMBER 29, 1994 ELECTRIC UTILITY WORKSHOP
The November 29 workshop is intended to provide basic information regarding the
Electric Utility, forecasts relative to the medium range future of the Utility, and background
data for the pending rate modification. It will also be an opportunity to discuss the City's
position within the Northern California Power Association (NCPA).
The topics to be considered at the workshop include:
lm
1
3.
4.
5.
Sm
Direct Access (Retail Wheeling) and Ongoing Risk Assessment Study
by NCPA
Undergrounding Projects
Lake Mendocino Operation
Electric Distribution Operation
Revenue Requirements and Revenue Generation
a.
b.
Cw
Cost of Service
Generation
Transmission
Distribution
e. Depreciation
f. Non-Energy Related
Customer Rate Paying Policies
1
DIRECT ACCESS (RETAIL WHEELING) AND ONGOING RISK ASSESSMENT
STUDY BY NCPA
Mike McDonald, General Manager of NCPA, and members of his staff, will be in
attendance at the workshop to provide the Council with a presentation on Direct
Access and its possible implication for our Electric Utility, and the Risk Assessment
study being compeleted under their directions.
2-5. UNDERGROUNDING PROJECTS, LAKE MENDOClNO OPERATION, ELECTRIC
DISTRIBUTION OPERATION, AND REVENUE REQUIREMENTS AND REVENUE
GENERATION
Sm
These items are outlined or discussed in detail in the November 28, 1994 report
"Revenue Requirement Analysis for the City of Ukiah Electric Utility" prepared by
Darryl Barnes, Director of Electric Utility (Attachment No. 1, pages 3-34). Darryl
will be discussing these matters with the Council at the workshop.
CUSTOMER RATE PAYING POLICIES
Attachment No. 2 (pages 35-38) discusses current and proposed policies relative
to the manner in which customer service and billing are processed.
Recommendations for modifications are presented for City Council consideration.
mfh:admin
ELECTRIC WORKSHOP
REVENUE REQUIREMENT ANALYSIS
CITY OF UKIAH
ELECTRIC UTIIJITY
NOVEMBER 28, 1994
Lake Mendocino Operation
Complete repair of damaged plate and
reinforcement of existing plate in
December 1994- $110,000 contracted
Contract for routine maintenance and
periodic equipment inspections -
$30,000 to $50,000 annual contract
Contract for FERC required annual
penstock inspection and maintenance
program- $7,000 to $10,000 annual
contract
Operation and maintenance of dissolved
oxygen system and Corps pre-flood
inspection work- $120,000 annually
Lake Mendocino Operation
Upgrade and maintain SCADA system
for remote operation of power plant-
$3O,OOO
Operation ofwater supply system to
state fish hatchery- $30,000 generation
loss annually
Continual correspondence, reporting
and coordination of operation with:
a) COrps of Engineers
b) Federal Energy Regnlatory
Commission
c) California Department of Fish and
Game
Electric Distribution Operation
Design, process and construct revenue,
redevelopment and upgrade projects -
$200,000 annually on contract basis
Design and reconductor main circuits to
standards - $100,000 annually for 5
years on contract basis
Re-configure underground system-
$60,000 annually for 5 years
Eliminate PCB high risk equipment-
$50,000 annually for 3 years
Protection scheme of system
Operation manual of system
, UNDER GR 0 I/NDING
PROJECTS
PHASE I- GOBBI STREET TO
SEMINARY- $400,000
FOUR ADDITIONAL PHASES OVER
NEXT FIVE YEARS - $1,800,000
* SYSTEM IMPACTS - AESTHETICS
- COST $80 vs. $20 PER FOOT
- INCREASED OUTAGE TIME
- EMPLOYEE SAFETY
REQUIREMENTS
-REDUCED CABLE LIFE
- ACQUIRE EASEMENTS
POLICY ISSUES
- REQUIRE OWNER TO
UNDERGRO~ SERVICE
- PURCHASE 2,400 ft~ OF UTILITY
EASEMENT
GOBBI TO SEMINARY STATUS
- INITIAL DESIGN COMPLETE
-PENDING STATE STREET
CONTOUR DESIGN
- PENDING FINAL EASEMENTS
EXECUTIVE SUMMARY
The completion of the Fiscal 1994-1995 Electric Utility Budget gave indications that with
the currently planned level of expenditures, and the expiration of the Power Sale Contract with
the Western Area Power Administration, additional revenues would be required to cover an
anticipated operating loss. It is anticipated that the shortfall will be approximately $349,879 in the
current operating year. This will translate into a revenue requirement increase of 3.3% for this
year.
In order to obtain an indication of the effect of this revenue requirement increase on future
years and to determine what future revenue requirements can be expected, an analysis was
conducted to determine the future revenue requirement for a five year period covered by the fiscal
years 1994-1995 through 1998-1999. Expected operating expenses and non-rate generated
revenue increases were assumed based on anticipated future revenue projects and operating
requirements. The results of this analysis are defined in Section 6 of this report. The results
indicated that a total of $891,402 of increased revenues will be required over the five year study
period. Should the Council elect to increase annual revenues by the $349,879 indicated in the
1994-1995 and 1995-1996 fiscal year, an additional $541,523 will be required during this time
period.
The comparisons in Section 6 reflects an effort to determine the magnitude and timing of
various revenue requirement increases in an effort to determine which program will require the
least amount of revenue increases over the study period to give Council an indication of the
possible furore impacts of various alternatives.
Should the Council elect to adopt the 3.3% increase for the 1994-1995 fiscal year, a
determination will be required as to the amount of increase that will be required by each rate class.
Section 7 of this report reflects staffs recommendation relative to meeting this requirement.
A model of customer's monthly use patterns was formulated for the three rate classes of
customers. These classes are Residential, General Services, and General Services with Demand.
The General Service Class is our small commerical customers, such small retail stores and offices.
The General Services with Demand, represents our larger commercial customers such as Wal-
Mart and K-Mart, that have a large power demand requirement.
The recommendations in Section 7 are as follows:
1) Increase the Residential Tier 1 energy charge by 3.5%, and not increase the Tier 2 energy
charge. In addition, staff would recommend decreasing the summer energy lifeline allowance from
410 KWH to 360 KWH. This change fits with our energy conservation goals and will reduce the
cost advantage of an all electric residence. In addition, the winter lifeline rate should be reduced
from 772 KWH to 660 KWH again to reduce the cost advantage of an all electric residence.
These changes would result in an overall 2.8% increase in residential rates and would
produce approximately $109,621 in additional annual revenues. This will maintain a revenue
requirement approximately 7.3% below Pacific Gas and Electric Company's current residential
rates.
2) It is recommended that the General Service rate class be restructured to reflect the
seasonal cost requirements of the utility. Energy is least cosily in the winter and most cosily in the
summer. Therefore, it is recommended that the Winter energy cost be reduced 2.7% and that the
Summer energy charge be increased 8.2%. This change will produce an annual increase in
revenues from this class of $92,307 or 3.3%. These changes will bring the class in line with our
tree cost of service. These changes will place this rate class approximately 7.1% below Pacific
Gas and Electric Company.
3) In the General Service with Demand rate class it is recommended that the Winter energy
charge be increased by 3.0% to reflect our seasonal cost of energy. It is recommended that the
Summer energy charge remain at the current level. The other area in which seasonal cost should
be reflected is in the Winter and Summer Demand Charge. Currently the charge has been
distributed at the $3.60 / KW-Month for both Winter and Summer. It is recommended that this
charge be structured to reflect our actual cost for Summer and Winter, and that the Winter
Demand rate be held at the $3.60 / KW-Month and that the Summer Demand rate be increased to
$5.75 / KW-Month. These changes would result in an increase of revenues for this rate class of
$128,677 or 4.3%.
All of these changes will result in an increase of annual revenues of approximately
$349,879 which reflects an overall revenue increase of 3.3% and that this revenue increase will
cover all expected expenses for this fiscal year.
SECTION 1
Introduction
The purpose of this analysis is to evaluate the current rate structure of the Electric Utility
and to recommend changes and adjustments to the rate schedules to satisfy the current and future
revenue requirements. The Electric Utility will experience increased revenue requirements
beginning with the 1994-1995 Fiscal Year, as result of the expiration of the Western Area Power
Administration Power Sale Agreement relative to the Lake Mendocino Hydro Project and the
increased funding required for the Underground District Projects and other planned projects over
the next five year operating period.
An effort will be made in this analysis to determine the cost of service for the electric
utility and the cost for each area of expenditure that contributes to that cost of service. This
determination will become important as cost cutting measures become important relative to
keeping the Electric Utility competitive with other service providers. It will also give us a
benchmark to evaluate the economic performance of the utility. This will become very important
as the world of direct access and retail wheeling unfolds in the fututre. Even if the requirements
for retail wheeling are not probable in the near future, the world of competition will remain a
concern in the electric utility industry, as consumers become more aware of their bargaining
power for utility services.
Cost of Service
The following Tables show the total cost of providing service to our electric customers.
This cost of service is based on the anticipated expenditures for each area of the utility. As can be
seen, expenses for the utility are separated into five classes. They are Generation, Distribution,
Transmission, Depreciation and Non-Energy. The first three items are directly related to the
production and transportation of our product. Depreciation is an expense that is collected and
pooled for the replacement of capital equipment and projects. The Non-Energy items are those
expenses that relate to services and other costs of doing business, and are reflected as
departmental transfers and allocations.
As can be seen in Table 1-1 our current five year plan was designed to hold the cost of
service to our customers constant over the time period. Table 1-2 reflects the cost of service as a
percentage for each area of expenditure. It can clearly be seen that the cost of generation is by far
the largest component of our business. As such any small change in this component could
significantly alter the cost of service and the related revenue requirements. The Non-Energy
expenses is the next largest component of expense to the cost of service.
TABLE 1-1
COST OF SERVICE - S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Generation 0.079 0.079 0.078 0.077 0.076
Transmission 0.002 0.002 0.002 0.002 0.002
Distribution 0.007 0.007 0.007 0.007 0.007
Depreciation 0.009 0.009 0.009 0.009 0.009
Non-Energy 0.016 0.017 0.017 0.017 0.017
Total 0.113 0.114 0.113 0.112 0.111
TABLE 1-2
PERCENT CONTRIBUTION
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Generation 69.9 69.3 69.0 68.8 68.5
Transmission 1.8 1.8 1.8 1.8 1.8
Disu'ibution 6.2 6.1 6.2 6.3 6.3
Depreciation 8.0 7.9 8.0 8.0 8.1
Non-Energy 14.1 14.9 15.0 15.1 15.3
Table 1-3 represents the total expected expenditure for each class of expense for the five
year study period. It is expected, that these revenue requirements will increase at the rate of
approximately 1.5% annually. This increase reflects the anticipated increase in salaries for City
of Ukiah employees as they relate to the Electric Department and Northem California Power
Agency staff. In addition, the Non-Energy area is also related to services provided by other City
of Ukiah Departments and is directly related to salaries.
TABLE 1-3
ANNUAL REVENUE REQUIREMENTS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Generation 8,263,400 8,306,200 8,394,200 8,435,600 8,478,200
Transmission 200,600 182,800 185,000 185,000 187,000
Distribution 722,000 739,000 756,400 774,300 792,600
Depreciation 890,000 905,000 921,667 938,334 957,000
Non-Energy 1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
Total 11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
The Depreciation expense reflects the increased requirement for funding as additional
capital equipment and projects are added to the assets of the Electric Utility.
SECTION 2
Generation
The cost of generation is composed of three components, Ukiah owned generation that is
operated by the Northern California Power Agency, Ukiah owned and operated, and purchased
power. In all cases the capacity and energy for each class except the Ukiah owned and operated
units are dispatched by the Northern California Power Agency. The Ukiah owned and operated
unit represents the Lake Mendocino Hydro Project, from which the energy and capacity is
scheduled based on the water requirements of Sonoma County and the Corp of Engineers for
flood control and is placed directly into the City of Ukiah electric distribution system. This
capacity and energy reduces the amount of purchased power required that would be required
from other sources.
Currently the City of Ukiah holds a participation share of the following projects:
Geothermal Projects 1 and 2
Hydro Project 1
Combustion Turbine 1
The City of Ukiah currently has power purchase agreements with the following:
Western Area Power Administration
Washington Water and Power
Seattle City Light
Midway Sunset Co-Generation
The participation units which represent City of Ukiah ownership have an average cost to
the system of $ 0.1070/ KWH. It is anticipated, that these costs will increase slightly in the
future, due to the reduced output of the geothermal units caused by the loss of pressure in the
steam field. However, it is expected that the cost of power from NCPA will remain fairly
constant over the study period. Alternatives are being explored relative to maintaining unit
operations to cover the debt service period. These options include, the addition of low pressure
turbine operation, water injection at the steam fields and unit shut downs in an effort to save
steam field pressure.
The purchase contract with the Western Area Power Administration is based on a ten (10)
year contract. This contract was renewed and will run from July 1, 1994 through June 30, 2004.
The cost of the purchase power under this contract is $ 0.028/KWH. It is expected that the cost
of this power will increase slightly over the contract term. However, this could change
significantly, depending on various options being explored by congress relative to the various
power marketing districts, Any additional requirements relative to improving fish habitat, or
water quality concerns such as the Bay-Delta requirements could have a significant impact on the
cost of WAPA power. The largest impact could occur due to the effort to install the temperature
control device at Lake Shasta in to reduce the bypass water currently required for fish, that
reduces the amount of water that can be used for generation.
The Lake Mendocino Hydro Project represents $ 0.1665/KWH toward the cost of
generation. The primary cost component of the project, is the debt service of $2,000,000
annually. Other factors are the requirement of oxygen addition to the river for fish habitat, that is
a requirement of our operating license and results in an annual expenditure of $100,000 for
oxygen. The annual royalty paid to the Federal Energy Regulatory Commission for the use of
government facilities of approximately $20,000 annually.
TABLE 2-1
ANNUAL ENERGY - KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 13,254,000 13,254,000 13,254,000 13,254,000 13,254,000
Western 45,727,200 45,727,200 45,727,200 45,727,200 45,727,200
NCPA 44,758,300 46,828,000 48,939,100 51,092,400 52,190,600
Total 103,739,500 105,809,200 107,920,300 110,073,600 111,171,800
The energy estimates for the Lake Mendocino Projects are based on an average dry year
generation. It is expected that the generation will remain minimum from the Lake Mendocino
project over the five year period of this study. Although this assumption is considered
conservative, it will allow for a margin of safety relative to the expenses for generation.
The energy supplied by the Western Area Power Administration is expected to be at
contract maximums during this study period.
The additional energy required for meeting the City of Ukiah load requirements will be
supplied through City owned units or through purchased power contracts.
TABLE 2-2
ENERGY COSTS - DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 2,164,000 2,150,000 2,150,000 2,150,000 2,150,000
Western 1,300,000 1,339,000 1,379,200 1,420,600 1,463,200
NCPA 4,799,400 4,817,200 4,865,000 4,865,000 4,865,000
Total 8,263,400 8,306,200 8,394,200 8,435,600 8,478,200
The cost of service for generation is that cost that contributes to the total cost of service to
our customers. As can be seen, although the cost of the Lake Mendocino energy is high relative
to other sources, the amount supplied to meet our load is small, and therefore contributes only
slightly to the total cost of service.
TABLE 2-3
COST OF SERVICE - S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Lake
Mendocino 0.163 0.162 0.162 0.162 0.162
Western 0.028 0.029 0.030 0.031 0.032
NCPA 0.107 0.103 0.099 0.095 0.093
Total 0.079 0.079 0.078 0.077 0.076
The cost of NCPA power will increase slightly over the study period. This is due to the
assumption that California will continue to remain in a drought condition and therefore will not
be able to generate maximum output from the hydro projects. In addition, it assumes that the
output from the geothermal units will continue to decline as the steam field pressure continues to
drop. Projects are underway that could reduce the impact of the steam reductions. One option is
the Lake County effluent pipleline projects. This project will pump Lake County effluent to the
Geyers Steam field and inject the water into the wells in an effort to increase the amount of steam
production. A second option that is being considered, is the combination of NCPA and Pacific
Gas and Electric Company's steam field and the shutdown of some of the generating units, in an
effort to maintain the existing steam at higher pressures. This would of course be done on some
cost/benefit sharing basis.
The NCPA cost of service includes all NCPA charges, including administration, dispatch
services and member services in addition to the generation related expenses.
SECTION 3
Transmission
The City of Ukiah's participation in the California - Oregon Transmission Project (COTP)
through our membership in the Transmission Agency of Northem California has provided the City
with the ability to access power sources in the Northwest and Southwest. This should provide
two benefits: 1) lower cost hydro power on peak and 2) the advantage of seasonal differences,
which means power is available when our system peaks. The City of Ukiah is currently receiving
energy from a contract with Washington Water and Power Company and will receive energy
through a seasonal exchange agreement with the Seattle City Light.
The City of Ukaih's participation also provides the ability to sell power and transport it on
the transmission system to potential markets, without having to pay wheeling charges to other
utilities for use of their transmission facilities.
Currently the City's annual expense for our share of the Califomia- Oregon Transmission
Project and the South of Tesla portion of the transmission project is shown in Table 3-1.
TABLE 3-1
TRANSMISSION COST-DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
SOT 13,400 10,000 10,000 10,000 12,000
COTP 187,200 172,800 175,000 175,000 175,000
TOTAL 200,600 182,800 185,000 185,000 187,000
The City of Ukiah is currently utilizing the South of Tesla portion of the transmission line
to transport energy from Midway Sunset to the City of Ukiah.
TABLE 3-2
TRANSMISSION COST OF SERVICE - S/KWH
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
SOT 0.00013 0.00009 0.00009 0.00009 0.00011
COTP 0.00180 0.00163 0.00162 0.00159 0.00157
TOTAL 0.00193 0.00172 0.00171 0.00168 0.00168
The annual cost for transmission in this study were taken from the NCPA 1994 and 1995
budget and projected transmission requirements for our loads through the study period.
SECTION 4
Distribution
This area of the analysis covers the cost of upgrading and maintaining the distribution
system within the city. This is a very important part of the total utility system, since this system
is needed to service our customers. The condition of this system determines the amount of
outages related to system failure which directly impact our customers. The Ukiah system is in
need of upgrades. Aged poles and thermally stressed conductors result in poor system reliability
and a large number of damage claims. The lack of system protection equipment continues to be a
concern. It is important that we continue to work to upgrade our distribution system. As a result,
we should be directing a portion of our operation and maintenance budget to the replacement of
electrical infrastructure.
TABLE 4-1
DISTRIBUTION COST- DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Overhead 157,000 161,700 166,600 171,600 176,700
Underground 195,000 200,900 206,900 213,100 219,500
Admin &
General 320,000 326,400 332,900 339,600 346,400
Ill
Conservation 50,000 50,000 50,000 50,000 50,000
Total 722,000 739,000 756,400 774,300 792,600
S/KWH 0.0070 0.0070 0.0070 0.0070 0.0071
The majority of the cost reflected in this section is related to salaries. The Overhead and
Underground portion of the costs represent salaries only. The Administration and General
reflects the salaries of the Director, Distribution Engineer and the Operations Supervisor. Other
costs that are adminstration related include, JPA Related Travel, Bulk Meter Rentals from both
NCPA and the Western Power Administration, Telephone Costs and other similiai: type of
expenses that relate to the administration of the electric utility.
Depreciation
The other major expense in this section is the cost of depreciation for the utility.
Table 4-2 outlines the capital projects that are planned for the study period and their related effect
on the depreciation expense. It is anticipated, that approximately $300,000 of annual projects
would be preformed by contract. This will allow a rapid increase in system improves, without
having to staff up for a short term (less than five years) construction program.
TABLE 4-2
CAPITAL PROJECTS - DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Capital
Projects 650,000 450,000 500,000 500,000 560,000
Depreciation 890,000 905,000 921,667 938,334 957,000
S/KWH 0.0086 0.0086 0.0085 0.0085 0.0086
Capital Projects included over the next five year period will include system improvemnets
such as reconductoring of feeders, removal of 4Ky systems, Low Gap Intersection up-grade and
Underground District work planned over the study period.
SECTION 5
Non - Energy Related Expense
The expenses outlined in this area are related to services provided by other departments
and charges to the electric utility through allocated transfers. These include: Utility Billing,
Purchasing, Garage, General Governmental Services, Finance Services and Dispatch Services.
These allocated transfer will amount to $1,703,879 in the 1994 - 1995 fiscal year. These are
expenses that are allocated to the Electric Department.
TABLE 5-1
NON-OPERATING EXPENSES-DOLLARS
Fiscal Year 1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
Meter
Reading 80,423 83,640 86,986 90,465 90,466
Utility 183,770 189,283 194,496 200,810 206,835
Billing
Purchasing 75,811 78,085 80,428 82,841 85,326
General
Go v emment 588,704 606,365 624,556 643,293 662,592
Dispatching 22,359 23,253 24,183 25,151 26,157
Garage 42,759 44,042 45,363 46,724 48,126
Uncollected
Bills 55,000 60,000 60,000 60,000 60,000
In Lieu Fee 655,053 674,700 674,700 674,700 674,700
Total 1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
S/KWH 0.0164 0.0166 0.0166 0.0166 0.0167
The meter reading expe, nses, purchasing and warehousing, general governmental
charges, dispatching, are directly related to salaries. Therefore, it was assumed that these cost
would increase based on an annual salary increase of approximately 4%.
Garage charges include the cost of fuel and parts in addition to salaries. Therefore, it was
assumed that this component would increase less rapidly as the other charges.
It was assumed that the amount of uncollected bills would remain approximately the
same over the study period. However, it should be noted that the electric utility has no control
over the amount required for uncollected bills.
The In Lieu Fee was based on the assumption that no additional revenue requirement
would be required after this fiscal year.
SECTION 6
Revenue Reauirements
The revenue requirements based on the 1994- 1995 fiscal budget and projects for the next
four fiscal years are shown in Alternate 1. The results, indicate that an additional revenue
requirement of approximately $350, 000 will be required in order to place the electric operations
in a positive cash-flow position for fiscal year 1994-1995. In addition, this increase will allow
rates to cover expected expenditures, provided that there are no significant increases in the
utility's operational costs or any significant changes in the cost of generation. With the current
regulatory atmosphere relative to market rates for Western Area Power Administration
customers and the outlook for the geothermal steam fields, this is not a f'u'm assumption.
However, staff does not see any significant changes in WAPA policy and pricing over the study
period.
The Base Case indicates the results of operations without an increase in revenues in the
1994-1995 fiscal year. The results show a $349,879 revenue short-fall. Alternate 1 represents
the results assuming a 3.30% revenue increase in 1994-1995, assuming the revenues will not be
generated until December 1, 1994.
In order to utilize the ending balance reserve, it was assumed that a rate adjustment
would not occur until the ending balance goes negative. On this basis, the study indicates that
another revenue increase will be required in the 1996-1997 fiscal year of approximately 3.8% as
shown in Alternate 1-B.
Alternates 1-A through 1-D represent various options for timing the revenue increase over
the five years. The option that would produce the lowest overall rate increase over the five year
period would be the best planned increase. The results are as follows:
Alternate 1-A requires 6.2% or $672,408
Alternate 1-B requires 7.1% or $778,043
Alternate 1-C requires 8.4% or $935,251
Alternate 1-D requires 5.5% or $628,650
Alternate 2-A requires 7.4% or $822,805
Therefore, the best alternative to minimize the revenue increase to the electric customers
over the next five years would be a total increase in the 1994-1995 fiscal year of 5.5% or
Alternate 1-D. The next best alternative would be to increase revenues 3.3% in 1994-1995 and
2.46% in 1995-1996 as described in Alternate 1-A. The other alternatives will delay additional
rate increases, but the result will be higher revenue requirements over the five year time period.
Base Case-No Revenue Increase
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERA TIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERA TING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE
CUMMULATIVE BALANCE
571,500
1994-1995
1,300,000
4,799,400
2,164,000
8,263,400
1995-1996 1996-1997 1997-1998 1998-1999
1,339,000 1,379,200 1,420,600 1,463,200
4,817,200 4,865,000 4,865,000 4,865,000
2,150,000 2,150,000 2,150,000 2,150,000
8,306,200 8,394,200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879
11,779,879
3,403,368 3,468,779 3,536,618 3,603,802
11,892,368 12,047,979 12,157,218 12,269,002
10,917,600 10,917,600 10,917,600 10,967,600 10,992,600
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,000
132,400 0 0 0 0
11,430,000
11,779,879
11,252,600 11,252,600 11,302,600 11,327,600
11,892,368 12,047,979 12,157,218 12,269,002
0.00% 0.00% 0.00% 0.00% 0.00%
0 0 0 0 0
0 0 50,000 25,000 50,000
11,430,000 11,252,600 11,302,600 11,327,600 11,377,600
-349,879 -639,768 -745,379 -829,618 -891,402
571,500 221,621 0 0 0
221,621 -418,147 -745,379 -829,618 -891,402
221,621
-418,147 -1,163,526 -1,993,144 -2,884,546
ALTERNATE 1
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE
571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE,
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300,000
4,799,400
2,164,000
8.263,400
1,339J:]00 1,379200 1~120Z~:]0 1 X163,200
4,817200 4,865~00 4,865~]0 4,865J:X]0
2,150,000 2,150,000 2,150,000 2,150,[]00
8,306200 8,394200 8.435.600 8,478200
13,400 10,000 10,000 10,000 12 J:]00
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,a00
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536Z>18 3,603,802
11,779,879 11,892,368 12,047,979 12,157.218 12,269J302
10,917,600 11,121,696 11,267,479 11,317,479 11,342,4.79
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,a00
132,400 0 0 0 0
11 ~130~300 11,456Z)96 11,602~179 11 ~52A79 11 ~77X179
11,779,879 11,892,368 12,047,979 12.157.218 12.269~02
3.30% 0.00% 0.00% 0.00% 0.00%
204,096 0 0 0 0
0 145.783 50.000 25,000 50,000
11,634.096 11,602,479 11,652,479 1 ! .677/179 11.727A79
-145,783 -289,889 -395,500 -479.739 -541,523
571,500 425,717 7,639 85,065 78.252
425.717 135,828 -387J~61 -394Z>74 -463.27 !
ALTERNATE 1 -A
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300~:]00
4,799~400
2,164,000
1,339~30 1,379,200 1,420Z)00 1,463200
4,817,200 4,865~K]0 4,865~X]0 4,865~X]0
2,150~:X]0 2,150~30 2,150J300 2,150~30
8,263,400 8,306.200 8,394200 8,435,600 8,478.200
13 ~0 10,000 10,000 10,000 12,1300
187,200 172,800 175,000 175,1300 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,834 957,000
3,315,879 3~103,368 3,468,779 3,536Z>18 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
10,917Z:~30 11,121~96 11,590~308 11,640~:]08 11,665~:]08
110,000 65,000 65,000 65,000 65,000
270,1300 270,000 270,000 270X]00 270,000
132,400 0 0 0 0
11,430~]0 11,456,696 11,925~]08 11,975~08 12,000~308
11,779,879 11,892,368 12,047,979 12,157,218 12,269~]02
3.30% 2.90% 0.00% 0.00% 0.00%
204,096 322,529 0 0 0
0 145,783 50,1300 25,000 50,000
11,634~396 11,925~08 11,975~X]8 12,000~308 12,050X]08
-145,783 32,640 -72,971 -157,210 -218,994
571,500 425,717 458,357 385,386 228,176
425,717 458,357 385,386 228,176 9,182
ALTERNATE 1-B
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTA/.
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE
571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300,000
4,799,400
2.164.000
1,339,[]00 1,379,200 1,420,600 1,463.200
4,817,200 4,865.[][]0 4,865,[]00 4,865.000
2,150,000 2,150,000 2,150.000 2,150.000
8,263,400 8,306200 8,394200 8,435,600 8.478200
13,400 10,000 10,000 10,O00 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536,618 3.603,802
11,779,879 11.892,368 12,047,979 12,157,218 12.269.002
10,917,600 11,121,696 11,267,479 11,745,648 11.770.643
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,030
182,400 0 0 0 0
11,430,000 11,456,696 11,602,479 12,080,643 12,105,643
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
3.30% 0.00% 3.80% 0.00% 0.00%
204,096 0 428,164 0 0
0 145,783 50,000 25,000 50,000
11,634,096 11,602,479 12,080,643 12,105,643 12,155,643
-145,783 -289,889 32,664 -51 275 -113,359
571,500 425,717 135,828 168~92 116,917
425,717 135,828 168,492 116,917 3,558
ALTERNATE 1-C
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE
571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1~4-1995 1995-1996 199~19971997-1998 199~1999
1,3~,,000
4,799,400
2,1~,000
8,2~,400
1,339~00 1,379,200 1,420J~0 1,463,200
4,817,200 4,865~30 4,865~K]0 4,865~:X]0
2,150,000 2,150,000 2,150,000 2,150,,000
8,306,200 8,394,200 8,435,600 8,478,200
13,400 10,000 10,000 10,000 12,000
187,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,800 792,600
1,708,879 1,759~68 1,790,712 1,823,984 1,854,202
890,a00 905,000 921,667 938,334 957,000
3,315,879 3,403~68 3,468,779 3,536~18 3,608,802
11,779,879 11,892~68 12,047,979 12,157,218 12,269~:X]2
10,917~:~K] 11,121~96 11,267,479 11,599,166 11,809,753
110,aO0 65,000 65,000 65,000 65,a00
270,a00 270,000 270,000 270,000 270,000
132,400 0 0 0 0
11~0~:]0 11,456~96 11,602,479 11,934,166 12,144,753
11,779,879 11,892,368 12,047,979 12,157,218 12,269~]02
3.30% 0.00% 2.50% 1.60% 1.00%
204,096 0 281,687 185,587 118,098
0 145,783 50,000 25,000 50,000
11,634~]96 11,602,479 11,934,166 12,144,753 12,312,850
-145,783 -289,889 -113,813 -12,465 43,848
571,500 425,717 135,828 22,015 9,550
425,717 135,828 22,015 9,550 53,398
ALTERNATE 1-D
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,300,000
4,799,400
2,164,000
8,263,4OO
1,339,000 1,379,200 1,420,600 1,463,200
4,817,200 4,865,000 4,865iX]0 4,865,000
2,150,000 2,150,000 2,150,000 2,150,CKX]
8,306,200 8,394,200 8,435,600 8,478,200
13,400 10,000 10,a00 10,000 12,000
187,200 172,800 175,[X]0 175,CK]0 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,00C] 756,400 774,,,'.'.'.'.'.'.'.'.'~0 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854,202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536,618 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
10,917,600 11,284,310 11,546,250 11,596,250 11,621,250
110,C00 65,1333 65,000 65,1330 65,000
270,000 270,1333 270,000 270,1330 270,000
132,400 0 0 0 0
11,430,[]00 11,619,310 11,881,250 11,931 ,250 11,956,250
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
5.50% 0.00% 0.00% 0.00% 0.00%
366,710 0 0 0 0
0 261,940 50,000 25,000 50,000
11,796,710 11,881,250 11,931,250 11,956,250 12,006,250
16,831 -11,118 -116,729 -200,968 -262,752
571,500 588,331 577,213 460,484 259,516
588,331 577,213 460,484 259,516 4,236
ALTERNATE 2-A
PURCHASED POWER
WESTERN
NCPA
LAKE MENDOCINO
TOTAL
TRANSMISSION
SOUTH OF TESLA
COTP
TOTAL
OPERATIONS
DISTRIBUTION
NON-ENERGY EXPENSES
DEPRECIATION
TOTAL
TOTAL OPERATING EXPENSES
REVENUES
BASE REVENUES
DEVELOPMENT COST
INTEREST INCOME
MISCELLANEOUS
TOTAL REVENUES
TOTAL EXPENSES
RATE INCREASE
REVENUE INCREASE
INCREASE IN SALES
TOTAL REVENUES
INCOME
BEGINNING BALANCE
ENDING BALANCE 571,500
NOTE: 1994-1995 REVENUE INCREASE
REPRESENTS REVENUES FROM DECEMBER 1
OF 1994-1995 INCREASE.
1994-1995 1995-1996 1996-1997 1997-1998 1998-1999
1,3OO,OOO
4,799,400
2,164iX]0
8,263,4OO
1,339,000 1,379,200 1,420,600 1,463.200
4,817,200 4,865,0[]0 4,865,000 4,865,000
2,150,000 2,150,000 2,150,000 2,150,000
8,306.200 8,394.200 8,435,600 8,478.200
13,400 10,000 10,000 10,000 12,000
187 ,200 172,800 175,000 175,000 175,000
200,600 182,800 185,000 185,000 187,000
722,000 739,000 756,400 774,300 792,600
1,703,879 1,759,368 1,790,712 1,823,984 1,854.202
890,000 905,000 921,667 938,334 957,000
3,315,879 3,403,368 3,468,779 3,536,618 3,603,802
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
10,917,600 10,917,600 11,343,386 11,790,405 11,815,405
110,000 65,000 65,000 65,000 65,000
270,000 270,000 270,000 270,000 270,000
182,400 0 0 0 0
11,430,000 11,252,600 11,678,386 12,125,405 12,150,405
11,779,879 11,892,368 12,047,979 12,157,218 12,269,002
0.00% 3.90% 3.50% 0.00% 0.00%
0 425,786 397,019 0 0
0 0 50,000 25,000 50
11,430,000 11,678,386 12,125,405 12,150,405 12,200,405
-349,879 -213,982 77,426 -6,813 -68,597
571,500 221,621 7,639 85,065 78,252
221,621 7,639 85,065 78,252 9,655
SECTION 7
Revenue Generation
An attempt was made to generate the required revenues equally between the three rate classes on
a percentage basis. In addition, each rate structure was modified to reflect actual cost of service
requirements, the effect on conservation policies, and reflect the true market conditions of the
electric utility. Therefore, the following changes are requested:
Residential
The first change in this rate class is to set all of the baseline energy rate equal to 360
Kilowatt-Hours except for the All Electric Winter Rate which will be reduced to 660 KWH from
772. This will level the playing field for customer with Electric Air-conditioning and Gas
Heating. The winter rate although reduced will aid customers with electric heat.
The second change will be to increase the Tier 1 energy rate 3.5% to $0.1074 / KWH.
This will bring the rate closer to the total cost of service for the rate class. The Tier 2 energy rate will remain unchanged.
These changes are forecasted to produce approximately $109,621 of increased revenues.
Resulting in a 2.8% increase in revenue from this class.
General Service
It is recommended that the monthly service charge for this rate class remain unchanged.
The energy cost of this class should be changed to reflect our true cost of service.
Therefore, it is recommended that the Summer rate increase $0.01126 / KWH. This results in an
increase of 8.2%. In addition, it is recommended that the Winter energy rate decrease $0.00302 /
KWH or 2.7%. These changes will result in an over all increase in revenues for this rate class of
$92,307 or a 3.3% increase.
General Service with Demand
The Winter Energy rate for this rate class should increase by 3.0% to $0.07876 / KWH. The
demand rate for the Summer rate should increase to $5.75/KW-MO from $3.60/KW-MO. This
change will more truely reflect our actual seasonal cost. Although the PG&E winter rate was
reduce to $1.65/KW-MO the $3.60/KW-MO truly reflect our demand cost in the winter months.
These chnages will result in an increase of $128,677 in revenues, a 4.3% increase in revenues.
Municipal
The changes made to both the General Services and General Services with Demand will cause
the Municipal rate class to increase by approximately $19,275 or 3.0%.
The results of these changes will generate the required revenue increase of $349,879
annually, which would result in an overall 3.4 % increase in revenue requirements.
ALTERNATE 1
RESIDENTIAL
.BASELINE:
BASIC WINTER
BASIC SUMMER
ALL ELECT. WINTER
ALL ELECT. SUMMER
ENERGY RATE:
TIER 1
TIER 2
REVENUE*
EXISTING
356
325
772
410
0.10375
0.13667
$3,917,560
pROPOSED
360
360
660
360
0.1074
0.13667
$4,027,181
PG&E
$ DIFF % DIFF EXISTING %DIFE
4 1.1 348 -3.3
35 10.8 332 -7.8
-112 -14.5 658 -0.3
-50 -12.2 348 -3.3
0.00365 3.5 0.11950 11.3
0 0.0 0.13737 0.5
$109,621 2.8 $4,322,382 7.3
GENERAL SERVICE
MONTHLY CHARGE:
1 PHASE
3 PHASE
ENERGY RATE:
WINTER
SUMMER
REVENUE*
7.50
8.75
0.11269
0.13654
$2,795,475
7.50
8.75
0.10967
0.1478
$2,887,782
0 0.0 8.10 8.0
0 0.0 12.00 37.1
-0.00302 -2.7 0.10967 0.0
0.01126 8.2 0.15999 8.2
$92,307 3.3 $3,091,993 7.1
GENERAL SERVICE WITH DEMAND
MONTHLY CHARGE
ENERGY RATE:
WINTER
SUMMER
DEMAND RATE:
WINTER
SUMMER
REVENUE*
MUNICIPAL
REVENUE*
~3,00
0.07647
0.09782
3.60
3.60
$3,025,076
$640,826
63.00
0,07876
0.09782
3.60
5.75
$3,153,753
$660,101
0 0,0 75.00 19.0
0.00229 3.0 0.08015 1.8
0 0.0 0.09816 0.3
0 0.0 1.65 -54.2
2.15 59.7 6.70 16.5
$128,677 4.3 $3,035,909 -3.7
$19,275 3.0 $690,113 4.5
TOTAL REVENUE*
*BASED ON 5/93 -4/94
$10,378,937
$10,728,816
$349,879 3.4 $11,140,397 3.8
ALTERNATE 1-A
RESIDENTIAL
EXISTING PROPOSED $ DIFF
% DIFF
BASELINE:
BASIC WINTER 356 360 4 1.1
BASIC SUMMER 325 360 35 10.8
ALL ELECT. WINTER 772 660 -112 -14.5
ALL ELECT. SUMMER 410 360 -5O -12.2
ENERGY RATE;
TIER 1 0.10375 0.1135 0.00975 9.4
TIER 2 0.13667 0.13737 0.0007 0.5
REVENUE* $3,917,560 $4,212,110 $294,550 7.5
PG&E
EXISTING
348
332
658
348
0.11950
0.13737
~,322,382
%DIFF
-3.3
-7.8
-0.3
-3.3
5.3
0.0
2.6
GENERAL SERVICE
MONTHLY CHARGE:
1 PHASE 7.50 7.50 0 0.0
3 PHASE 8.75 8.75 0 0.0
ENERGY RATE:
WINTER 0.11269 0.10967 -0.00302 -2.7
SUMMER 0.13654 0.155 0.01846 13.5
REVENUE* $2,795~,75 $2,966,608 $171,133 6.1
8.10
12.00
0.10967
0.15999
$3,091,993
8.0
37.1
0.0
3.2
4.2
GENERAL SERVICE WITH DEMAND
MONTHLY CHARGE 63.00 70.00 7 11.1
ENERGY RATE:
WINTER 0.07647 0.08015 0.00368 4.8
SUMMER 0.09782 0.09816 0.00034 0.3
DEMAND RATE:
WINTER 3.60 3.60 0 0.0
SUMMER 3.60 6.25 2.65 73.6
REVENU E* $3,025,076 $3,208,789 $183,713 6.1
MUNICIPAL
REVENUE* $640,826 $669,975 $29,149
4,5
75,00
0.08015
0.09816
1.65
6.70
$3,o,.'~,9o9
$690,113
7.1
0.0
0.0
-54.2
7.2
-5.4
3.0
TOTAL REVENUE* $10,378,937 $11,057~182 $678,545
*BASED ON 5/93 -4/94
6.5
$11,140,397
0.7
Attachment #2
ELECTRIC UTILITY WORKSHOP
BILLING AND COLLECTIONS
The "General Service Demand Metered" rate schedule 1602-DM is
available for commercial service customers. This rate schedule is
intended for larger users. There has not been a minimum qualifying
usage established for this rate schedule. P.G.& E. requires usage
of at least 50,000 kwh per year to qualify for their comparable
rate schedule. Staff recommends adoption of a minimum usage of
50,000 kwh per year to qualify for this rate.
The "Domestic Service" rate schedule 1600 is available for single
family residential units. Staff is recommending the rewording of
the applicability statement from: "This is applicable to domestic
lighting, heating, cooking and single phase domestic power service
in single family dwellings and in flats and apartments separately
metered by the City." to "This is applicable to single phase
domestic power service in single family dwellings and in flats and
apartments separately metered by the City."
Part of the "Domestic Service" rate schedule provides for Life
Support Devices. The current wording is general or nonspecific in
several areas. Staff is recommending establishment of a separate
Life Support rate schedule and rewording of the descriptions of the
service:
General:
A "life support" device is any medical equipment which is
essential to sustain life or relied upon for mobility.
Life support devices include, but are not limited to,
respirators, iron lungs, hemodialysis machines, electric
nerve simulators, pressure pads and pumps, aerosol tents,
electrostatic and ultrasonic nebulizers, compressors,
IPPB machines and motorized wheelchairs.
Applicability:
This is rate applicable to a residential customer (full-
time resident of the household) who require a life
support device. The utility department requires written
certification from a physician or osteopath, licensed to
practice medicine in the State of California, that a
particular "life support" device is essential to sustain
life or is relied upon for mobility. Service under this
schedule is subject to City of Ukiah service policies.
Devices used for therapy rather than life support
generally do not qualify.
The life support rate does not guarantee continuance of
service if the account becomes delinquent.
Attachment #2
Service provided under this section will allow for a
uniform monthly lifeline allowance of 500 kwh per month
per eligible device in addition to the baseline
allowance. Eligibility for this service must be
recertified at least every two years.
The authority to make arrangements with customers for payment of
past due amounts is established by administrative procedure. Staff
recommends bringing back to Council a proposed policy for payment
arrangements and collection procedures.
Proposed Customer Payment Extension Policy:
1. There will be a limit of two (2) extensions per customer per
year. Where a customer has had several accounts within the same
year, the cumulative number of extensions on all the accounts would
apply.
2. The account must have been open for at least one year and have
reasonably good credit history before any extensions may be
granted. "Reasonably good: credit history shall be comprised of
the following:
1. No more than six "Past Due" incidents.
2. No more than three "Delinquent" notices.
3. No more than one "Final" notice.
If the customer's account has not been open for one year
but has established one year's credit with the City by
having other accounts which may add up to one year's
service, this is acceptable.
3. Extensions may only be granted with the understanding that the
entire account balance is to be paid in full at the culmination of
the extension period.
4. The normal extension granted for any one instance will be for
no more than 5 working days. The maximum extension shall be for no
more than 10 working days...in extreme circumstances.
5. If the terms of the extension are violated, the account is to
be disconnected immediately. No additional extensions will be
granted and no partial payments will be accepted. No additional
notice, such as a 48 Hour Notice/Final Notice will be given.
6. There will be a limit of one extension per incident.
Additional extensions may no be requested or granted, unless the
customer contacts our office in advance PRIOR TO THE DUE DATE in a
timely manner to re-negotiate the terms, but only if within the 5-
10 day limit as stated in item #4.
Attachment #2
The preceding information is not to be considered a recommendation
but rather, the adopted policy of this department. Customers
should not be given the impression that this policy can be
overridden by the Director of Finance. If a customer wishes to
lodge a complaint against this policy, they may do so through
normal channels for managing citizen complaints.
Citizen complaints are normally handled by the Finance Director or
in his/her absence, another finance employee may step in to help
resolve the situation. If the customer still feels he/she needs to
speak with someone at a higher level, they are referred to the City
Manager's office.
Payment Arrangements:
Payment arrangements are made by any member of the customer service
department by use of the above extension policy. However, if a
customer is in a unique situation and/or has had good prior credit
history, special terms may be arranged. Currently, our software
system does allow staff to manage and maintain these transactions
through the system and thus resolve any missed payments or
arrangements. If these special terms are not kept, immediate
termination of service could result. However, each case is handled
and viewed separately by the customer service staff and decisions
are made based on each account's history and current events. The
hope is to resolve any customer complaints quickly and fairly for
both the customer and the City.
There are numerous questions which tend to be legal in nature that
should be considered. Staff will pursue these questions with the
City Attorney. Some, if not all, of these questions should be
included in the Electric Customer Service Policy revisions.
1. Does the City have the authority to require a copy of
a lease?
2. Does the City have the authority to disconnect
current service for previous unpaid bills whether or not
the service is at the same address?
3. Does the City have the authority to deny changing
service to another person's name when the current named
customer continues to reside at the address? This
appears to be an attempt to avoid paying a delinquent
account.
4. Roommate situations - who is really liable for the
bill? Does the City have the authority to require all
adult occupants to sign the application for service? Are
all occupants liable for the bill even if they have not
signed the application for service?
Attachment #2
The schedule of delinquency dates and notices which lead up to
ultimate service disconnection for non-payment are established only
in administrative procedure. Perhaps they should be outlined in a
Council adopted policy.
Billing and Collection Cycle:
Step 1. Bill is issued. Bill is delinquent if not paid within 25
days.
Step 2. On the 36th day after the date the bill was issued, a
delinquent letter is issued. This letter gives the customer 9 days
in which to pay.
Step 3. If payment is still not received, a "Final Notice', is
issued on the 46th day after the date of the bill. This notice
gives the customer 7 days from the date of the notice to pay the
account in full or the service will be disconnected. A $5.00 Final
Notice fee is added to the account when this notice is prepared.
Step 4. If payment is still not received, the Utility Services
attendant is dispatched to disconnect the service. A $35.00
disconnect fee is added to the account at this time.
To restore service, the full account balance, including the
additional billings for services, must be paid in addition to a new
deposit and a $7.50 reconnect fee.
A second months services would have been billed between steps 1 and
2. A third months services would be billed about the same time
that the Step 4 disconnect would take place.