HomeMy WebLinkAboutUndergrounding-Conversion of Select LI Lighting Co Overhead Electric Lines by NYS Dept of Public Service Mar-93
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'ARNOLD R. PUJl/AM
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New York State ",
Department of Public Service,.
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Undergrounding_., ,
Conversion of Select
Long Island Lighting Company
Overhead Electric Lines
A Study to Assess the Cost Effectiveness
Of Undergrounding's Potential to Mitigate
LILCO Service Interruptions Caused
By Catastrophic Storms
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Staff Report ",F
MAY 0 6 1998
Southold Town .
Planning Board
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UNDERGROUNDING
CONVERSION OF SELECT LONG ISLAND LIGHTING COMPANY
OVERHEAD ELECTRIC LINES
A STUDY TO ASSESS THE COST EFFECTIVENESS
OF UNDERGROUNDING'S POTENTIAL TO MITIGATE
L1LCO SERVICE INTERRUPTIONS CAUSED
BY CATASTROPHIC STORMS
NEW YORK STATE
DEPARTMENT OF PUBLIC SERVICE
STAFF REPORT
MARCH 1993
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TABLE OF CONTENTS
Foreword
Executive Summary
Introduction
L1LCO Service Territory
History of Commission Undergrounding Proceedings
Selection of Undergrounding Scenarios
Substation Circuit Undergrounding Design
Assumptions
Substation Circuit Undergrounding Methodology
- Cost Estimate
- Rate Impact
Costs to Underground and Resulting Rate Impacts
- Indian Head Substation
- Buell Substation
- Amagansett to Montauk Transmission Line
- Undergrounding All L1LCO Facilities
Undergrounding Constraints and Benefits
Conclusion
Appendix A: Input Data for Strategic Financial Planning Model
Appendix B: Rate Impact Worksheets
Appendix C: Indian Head Worksheets
Appendix D: Buell Worksheets
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FOREWORD
This report on the study group's findings is brief and written without the
extensive use of technical jargon. Where possible, we have included
photographs of various equipment and locations to provide better references
and clearer explanations. Since the subject of undergrounding is multi-faceted,
we have tried to include only the areas pertinent to our study. However, we
are aware that this report may foster additional questions and the study team,
as well as the support team assembled by L1LCO, is prepared to give a
presentation on our efforts and hopefully answer any outstanding questions.
This presentation will include a discussion of the types of analyses conducted
by both staff and L1LCO.
Below are the members of the study team and the L1LCO support team:
Study Team
Communications Division: Ambrose Hock
Consumer Services Division:
Policy & Compliance - Raj Addepalli
Office of Energy Efficiency and the Environment:
Environmental Compliance and Operations - Arnold Putnam
Energy and Water Division:
Power Rates & Valuation - Harold Glasser
Power System Operations - Alan Elberfeld - Project Leader
Power System Operations - Michael Worden
LILCO Support Team
Facilities Planning Department:
Design & Reliability Division - Ronald Ammon
Area Planning Division - Frederick Albinus
Electric Lines Department: Bruce Cocks
Electrical Engineering Department: Thomas Spatz
We also wish to acknowledge the contribution of the Office of
Accounting and Finance for providing the forecast capital structure input
assumptions required to finance the undergrounding scenarios.
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EXECUTIVE SUMMARY
Introduction
Catastrophic storms during 1991, including the March Ice Storm and
Hurricane Bob, caused three-quarters of a million electric customers in New
York State to lose service for significant periods of time. These storms
impacted four of the seven major electric utilities. Catastrophic storms include
hurricanes and ice storms that impact service to numerous customers for
extended periods of time.
Hurricane Bob, which ravaged Long Island on August 19, 1991, resulted
in renewed cries for undergrounding all, or portions of, L1LCO's overhead
electric facilities. The Consumer Protection Board, supported by the Office of
the Attorney General, petitioned the Public Service Commission to analyze the
costs and benefits of undergrounding vulnerable areas of L1LCO's electric
service territory. In early 1992, commissioners, including the Chairman, asked
staff to conduct such a study.
In March 1992 the former Power Division, now part of the Energy and
Water Division, took the lead in conducting a study to assess undergrounding's
potential to mitigate L1LCO service interruptions caused by catastrophic storms.
We chose L1LCO for the underground study because of its vulnerability to both
hurricanes and ice storms. Staff from the Communications Division, the
Consumer Services Division, and the Office of Energy Efficiency and the
Environment, joined with the Power Division to form the study group. L1LCO
formed a parallel group to assist and facilitate the study. At the same time, a
study was undertaken to assess whether enhanced tree trimming by utilities
would increase service reliability during catastrophic storms. That report is
issued as a companion to this report.
This study was conducted independent of the ongoing line extension
case (Cases 29389/92-M-0607), although most of the study team members are
involved in that proceeding. In contrast to the potentially more expansive
coverage of conversion from overhead to underground anticipated for the
generic line extension case, this study was limited in scope to an evaluation of
undergrounding as a means of mitigating catastrophic storm-inflicted damage
to L1LCO's distribution system. Secondly,this study had begun and was nearly
completed before consideration of conversion was addressed in the generic
proceeding. Further information about that proceeding is included later in this
summary .
Background
In developing the workplan for the underground study, the primary
concern was on what could be done to prevent damage to overhead electric
facilities during catastrophic storms, and the focus of this study was L1LCO's
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45,000 cable miles of overhead distribution lines'. As a practical matter, if
electric utilities were to undertake a program to underground existing overhead
facilities, the disposition of telephone and cable facilities would have to be
addressed. It was recognized that telephone and cable facilities coexist on
poles with the electric system, but in order to keep the scope of the study to
a reasonable size, it was decided to focus on electric facilities.
Approximately 95,000 of L1LCO's customers are served by underground
facilities, as contrasted to 907,000 being served by overhead facilities.
However, new construction for L1LCO's distribution system shows an increase
in the installation of underground lines. In 1990-1991 L1LCO connected 4,997
new customers served by overhead lines and 3,796 new customers served by
underground lines. In terms of new line construction, 1990-1991 saw 45 cable
miles of new overhead lines and 186 cable miles of new underground lines.
L1LCO has 45,000 cable miles of overhead distribution and 11,000 cable miles
of underground distribution.
Approach
The initial premise of the study was to locate specific areas of the island
that were most prone to damage from catastrophic storms. L1LCO provided
damage patterns on catastrophic storms covering a 20-year period. The
damage location data available from L1LCO is somewhat broad-based, because
the focus following catastrophic storms is restoration, not data collection.
Nonetheless, L1LCO still has the most comprehensive data available among New
York State utilities. Unfortunately, this data revealed that no particular area
consistently experienced storm damage. This is due to the fact that the landfall
of the eye of the hurricane is the deciding factor in where the most severe
damage will occur. There is no way to determine where landfall will occur on
a statistical basis with the data available. Hurricane winds blow counter-
clockwise with the highest wind speeds occurring in the northeast quadrant.
If the eye of the storm has a landfall near the center of the island, the south
shore bears the brunt of the storm. If the eye passes east of the island, the
easternmost part of the north shore becomes the hardest hit area. Damage
from ice storms, on the other hand, impacts the north-west to north-central
part of the island. Finally, the One Hundred- Year Storm of December 11 and
12, 1992, caused the most severe damage in the north and south coastal areas
of the western portion of the Island.
The study group then examined whether undergrounding distribution
lines along the shorelines of the island, which one would expect to be more
susceptible to storm damage, would provide the looked-for litmus test.
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The study only addresses undergrounding of electric lines; telephone, cable
television, and street lighting facilities are assumed to remain overhead on
existing poles. There are more than one-half million L1LCO and New York
Telephone poles on the island, none of which are jointly owned. Around 84
percent of these poles contain both telephone and electric facilities. Cable
television facilities are on approximately 75 percent of the poles.
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Difficulties arose with this approach in that circuits meander north, south, east,
and west and appropriate cut-off points for undergrounding were not .available.
Staff also looked at whether undergrounding to improve reliability could
be combined with road widening projects or other rebuilding programs.
Although the cost of undergrounding portions of circuits involved with these
projects would be partially offset by the avoided cost of moving the existing
overhead lines to the outer limits of the roadway, the cost differential,
depending on type and location of construction, remains three to five times as
great. In addition, most of these projects involve only small segments of
circuits. Thus, customers served by the underground circuit portion would be
vulnerable to interruptions from the remaining overhead circuit segments. For
these reasons, staff does not find this to be a viable alternative.
Ultimately, staff investigated four scenarios in some depth. The first two
scenarios evaluated the premise of undergrounding all circuits emanating from
two particular substations. After analyzing a number of substations, we
selected the Indian Head Substation located near Smithtown and the Buell
Substation located in East Hampton for the first two undergrounding scenarios.
In terms of size and composition of customers, these substations were
considered representative of L1LCQ's 150 major substations. Indian Head,
serving almost 14,000 customers in the northern part of Western Suffolk, is in
an area which could be impacted by both hurricanes and ice storms. Indian
Head also has a relatively high population density and serves both residential
and light commercial/industrial customers. The Buell Substation serves almost
10,000 customers on the south fork of the Island. Buell serves a
predominantly residential customer load.
The third undergrounding scenario chosen by the study group was a
project that is currently planned by L1LCQ to begin in 1993. This project
involves undergrounding almost 12 miles of overhead transmission lines that
run from Amagansett to Montauk--the easternmost portion of the Island's south.
fork. This project is being undertaken for a variety of reasons, including
aesthetics, environmental concerns, reliability, public relations, and operating
considerations.
The last scenario chosen by the study group entailed updating an earlier
L1LCQ study that assessed the cost of undergrounding L1LCQ's entire system.
The update also included select, partial undergrounding scenarios. Staff used
these partial scenarios to augment the substation scenarios to provide a wide
range of possible options.
Factors and Assumptions
Rate impacts2 were developed for an 11-year study period (1993-2003)
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The additional costs of undergrounding telephone, cable television, and street
lighting services are not included in the cost projections.
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which is the output limit of the Strategic Financial Planning model used in the
analysis. Since the estimated installation period for undergrounding substation
feeders is 10 years, the model was compatible. However, since the installation
period for the entire undergrounding scenario is 25 years, we can only project
rate impacts for the first 11 years of installation. Thus, additional monthly
increases would occur for the remaining 14 years of the installation period.
The Base Case used in the study reflects increases due to the L1LCO
Ratemaking and Performance Plan, as modified in Opinion No. 91-25 (Case 91-
E-1185).
The costs individual customers would incur for service laterals in order
to connect to L1LCO's secondary distribution system are included in the total
costs indicated in this undergrounding study. Normally, the customer/builder
would pay an electrician several hundred dollars to connect the service lateral
to the meter. For purposes of this study, mainly because of the magnitude of
the underground costs that would ultimately be borne by the customer, we
thought it useful to present a complete package of the cost/rate impact that the
ratepayers would bear. For an underground program of this magnitude, staff
assumed that L1LCO would utilize contractors whose price includes certified
electricians who are licensed to connect the service lateral to the meter.
Hence, the contractor's price would be a complete package deal for connecting
service laterals up to the electric meter.
The consequences of effecting early retirement of its overhead
distribution plant due to installation of replacement underground plant may
require special accounting/financing treatment. There may be a need for rapid
amortization of the loss in order to be consistent with accepted accounting
practice. An amortization period shorter than the normal period during which
the overhead plant would otherwise be depreciated will increase the utility's
revenue requirements, thus resulting in the need for still further increases to
customers' bills.
Summary of Results
The cost to underground all distribution lines emanating from each
substation approximated $150 million. Based on the number of customers
served, the rate impact to customers within the substation service territory
would be to raise the average monthly residential rate between $1 29 and $1 80
depending on the substation.
In contrast, undergrounding 12 miles of east-end transmission line will
cost ratepayers $10.6 million. The principle difference in cost between
undergrounding transmission lines as opposed to distribution lines is that the
former consists of point-to-point, Le., substation-to-substation cable
terminations as opposed to the myriad of distribution connections required for
each household service lateral. Another factor keeping the cost of the east-end
transmission line relatively low is that it consists of direct-buried cable that is
~ plowed-in along the shoulder of Montauk Highway-:-'There are few bends, trees,
and crossings along the proposed cable route.
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L1LCO estimates the cost to underground its entire distribution system
to be $20 billion. This estimate appeared reasonable to staff and WaS used in
our rate impact calculations. All of the costs are predicated on the latest
underground design standards currently employed by L1LCO and a 25-year
installation period. This criteria basically employs "looped" underground cables,
which greatly enhance underground system service reliability. The rate impact
based on $20 billion would be to raise the average monthly residential rate by
$108, from $83 to $191 during the first 11 years, or an average yearly
increase of about 7.9 percent. Over the 25 years required to underground the
system, an increase in rates of 569 percent solely due to undergrounding would
be realized. The rate impact on the other service classes would also be about
569 percent, exclusive of additional increases due to all other causes.
The study team also examined undergrounding select components of the
distribution system, as L1LCO did in its 1978 study. The options presented
focused on rear lot facilities, which sustain significant damage during
catastrophic storms, and are among the last facilities to be repaired. This
approach is more balanced than the substation approach because it benefits a
wider customer group. However, it would not benefit all customers and would
not eliminate all interruptions. The options presented range in cost from $689
million to just over $1.9 billion, with an annual rate impact on the order of 4.8
to 8.4 percent over each of the first 11 years of installation.
There are cost savings to lILCQ associated with undergrounding,
primarily reduced tree trimming, storm restoration, and storm insurance
premium costs. These savings would be on the order of $17 million to $35
million per year for conversion of the entire distribution system. There are also
secondary impacts, which the study team did not quantify, that would include
business losses and real property damage.
Under a 25-year total undergrounding plan, lILCO would need to finance
at least $0.8 billion per year. Our finance personnel advise that a construction
program of this magnitude would require L1LCO to continually go to the capital
market. They advise that such a program would undoubtedly cause cash flow
problems for the company which could adversely affect the rate at which
L1LCO could access the capital market, or in a worse case scenario, impede its
access to the capital markets.
Other Effects of Undergrounding
There are pros and cons to underground lines regarding reliability during
normal operating conditions. Although overhead lines are not inherently
unreliable, underground lines on lILCO's system are about five times more
reliable on a composite basis. This basis is composed of the recently adopted
Commission reliability standards that address both frequency and duration of
service interruptions. The frequency of interruptions to L1LCQ's overhead
system is roughly 10 times greater than that of underground. However, it
takes twice as long to return underground lines to service as it does overhead
lines. Although there are not many negatives associated with underground
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reliability, the service life of underground cables on L1LCQ's system has
generally been less than 30 years, and replacement costs are' 3 to 5 times
greater than overhead replacement costs. Overhead cable normally has a
service life in excess of 50 years.
Studies in Other Jurisdictions
In a June 1988 study by R. W. Beck and Associates, entitled Toronto
Hydro Study of Distribution Options, undergrounding was examined as an
option for replacing Toronto Hydro's obsolete 4 kV overhead distribution
system in the City of Toronto. The study estimated the cost of an all
underground system to be $2.038 billion, compared to $295 million for an all
overhead 13.8 kV system. Toronto Hydro has approximately 217,500
customers. An estimated 80 percent are served by the obsolete 4 kV system.
Toronto Hydro decided to install a hybrid overhead/underground system,
with all primary wires and transformers underground at a 1988 cost of $854
million. As of the end of 1991, the cost projection had escalated to $1.5
billion. Toronto Hydro has since reduced the scope of the undergrounding
program due to public outcries over the cost of the endeavor.
We also reviewed two recent undergrounding studies from other states.
The first study, conducted by the Florida Public Service Commission, was
released in December 1991. The study entitled, Report On Cost-Effectiveness
of Underground Electric Distribution Facilities, concluded that undergrounding
of existing facilities was not cost-effective. The second study, conducted by
City Public Service, a San Antonio, Texas, utility was entitled, Feasibility Study
Conversion to a Total Underground System. The cost to underground City
Public Service's system was $16.9 billion; the company decided against
undergrounding and said:
Conversion to an underground system would require
additional revenues with resultant rate increases, thus
placing the financial burden upon ratepayers.
Current Under grounding Proceeding
The current line extension case is studying the potential of
undergrounding under various scenarios. In fact, the Commission, on
September 15, 1992, issued proposed rules for comment in Case 92-M-0607
that provide for a Visually Significant Resources (VSR) undergrounding
program. This program applies to the new construction of distribution lines,
service lines, and appurtenant facilities on public and private land in VSRs. The
program will remain in effect for a period of five years after its effective date.
Under the proposed annual program, L1LCO would be required to allocate at
least $2.4 million (subject to adjustment for inflation) to a VSR undergrounding
J fund and would be obligated to spend such amounts on the cost of installing
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such new construction underground. Any unspent portion of L1LCQ's maximum
obligation in a given year would be carried over to the next year. The VSR
program would be evaluated by the Commission after the program has been in
effect for two years and L1LCQ would be required to provide details of its
experience as the staff and/or Commission may request.
In addition, staff is involved in Case 29389, Proceeding on Motion of the
Commission as to the Regulations Regarding the Installation of Distribution
Lines, Service Lines, and Appurtenant Facilities by Electric and Telephone
Contractors and Municipalities. Proposals before the Administrative Law Judge
include conversion of lines from overhead to underground within VSRs, as well
as the conversion of all overhead facilities. Staff found no significant overlap
between distribution facilities located in VSRs and ones in areas that are
particularly vulnerable to catastrophic storm damage.
Conclusion and Recommendations
The results of this study point to excessive costs, when compared to
reliability benefits, as being the prohibitive factor precluding the large scale
undergrounding of existing overhead facilities for the purpose of improving
reliability during catastrophic storms.
:stuntl ollce he average
L1LCQ customer loses service only once every seven .~years due to these
catastrophic storms. As explained previously, there is no data that indicates
which customers would lose service due to the random damage from these
storms. However, this study also shows that for specific situations, Le., the
Amagansett to Montauk transmission line, other factors (such as aesthetics,
environmental concerns, reliability, operational practices, public relations and
economics) can off-set the high cost of undergrounding.
As a practical matter, it is not reasonable to propose that L1LCQ
underground all its facilities. The most effective undergrounding from a
reliability standpoint would be the entire substation/circuit approach. The
drawback to this approach is that only a small portion of L1LCQ's customers
would benefit, even though the costs would have to be spread among all
customers. For example, in simplistic terms, if each of L1LCQ's one million
customers were charged an additional $150 per year for undergrounding, and
assuming no cost increases or inflation, $150 million would be available ($1 00
million after taxes). At that rate, it would take 200 years to underground all of
L1LCQ's distribution facilities.
If undergrounding were limited to areas with rear lot overhead lines, it
would cost a total of $1.5 billion and at $150 per year per customer ($100
million after taxes) would require 15 years to be completed. In our estimation,
overall this is a more feasible approach, but given the high cost, limited
benefits, and expected resistance from the customer due to landscape
disruption, we do not recommend it.
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From a strict cost-benefit standpoint, staff cannot recol11mend any
systematic undergrounding program for preventing damage from catastrophic
storms. While total costs are difficult to estimate with precision, it is even
more difficult to estimate the benefits to customers, or the "value" customers
place on increased reliability. There are conflicting survey results as to what
customers are willing to pay for improved reliability. Customer perceptions and
preferences for conversion and what they would be willing to pay may be
explored in more detail in the conversion phase of the generic line extension
proceeding, currently in progress.
In the companion report on tree trimming, staff found that the best way
to combat the effects of a catastrophic storm is to have an adequate
emergency response plan that is practiced in an emergency drill at least yearly.
The Department has taken an increasingly active role in emergency planning in
recent years. Last year, the Commission adopted a new rule (16 NYCRR, Part
105) concerning electric emergency plans that strengthened, among other
things, training, communication, and damage assessment requirements.
Although these plans cannot prevent service interruptions, we believe that
outage durations can be effectively reduced when proper planning, training, and
execution of emergency response plans are performed.
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INTRODUCTION
New York State electric utilities were impacted by two catastrophic
storms during 1991, resulting in the loss of electric service to over three-
quarters of a million customers3. These storms were: the March ice storm,
which resulted in the loss of service to 310,000 customers of Rochester Gas
& Electric (RG&EI. New York State Electric and Gas (NYSEGI. and Niagara
Mohawk Power Corporation (NMPC); and Hurricane Bob, which impacted the
Long Island Lighting Company's (L1LCO) system on August 19, which resulted
in a loss of service to 477,000 customers. The satellite photo on page 12
shows the magnitude of Hurricane Bob.
In the aftermath of Hurricane Bob, the Commission was petitioned by the
Consumer Protection Board (CPB) on August 27,1991 to, among other items,
conduct analyses of the costs and benefits of undergrounding vulnerable areas
of electric service territories. The Office of the Attorney General supported the
CPB's petition. At the January 8, 1992 Commission session, during which
staff's Hurricane Bob report was presented, commissioners, including the
Chairman, asked how effective undergrounding certain overhead electric lines
would be in mitigating damage from catastrophic storms. The former Power
Division, now part of the Energy and Water Division, committed to undertake
a study that would portray the pluses and minuses of selective undergrounding
scenarios. The Power Division's System Operations Section was designated
as having lead responsibility and was supported by the Rates and Valuation
Section. In addition, the power Division sought, and received, assistance from
the Communications Division, the Consumer Services Division and the Office
of Energy Efficiency and the Environment. Staff from each area formed the
Undergrounding Study Team.
The scenarios included in this study follow:
o Undergrounding all overhead distribution facilities
emanating from L1LCO's Indian Head Substation.
o Undergrounding all overhead distribution facilities
emanating from L1LCO's Buell Substation.
o Undergrounding L1LCO's overhead transmission line
from Amagansett to Montauk.
o Update of a previous L1LCO study assessing the cost
of undergrounding all L1LCO facilities, as well as
certain other select undergrounding scenarios.
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Catastrophic storms are generally hurricanes, ice storms, major tornadoes, etc.
that cause widespread damage and result in outside forces being brought in to
assist utility forces.
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L1LCO SERVICE TERRITORY
L1LCO's service territory encompasses 1,230 square miles including
Nassau County, Suffolk County, and the Fifth Ward of Queens County (the
Rockaway Peninsula). This area represents less than 3 percent of the area of
New York State. However, approximately 2.8 million people, or 15 percent of
the state's population, reside in this location. L1LCO's electric customers
number slightly in excess of one million. L1LCO has divided the territory into
four operating divisions (see below): Queens/Nassau, Central, Western Suffolk,
and Eastern Suffolk.
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Although much of L1LCQ's service area is suburban, the eastern portion
of Suffolk County is a principal agricultural and recreational site. Long Island
residents have a strong interest in local control of environmental affairs,
particularly air and water quality, audible noise, and aesthetics. As a result,
L1LCO facilities have adopted unusually stringent design standards.
Environmental pressure and the high population density of the service territory
have forced virtually all new transmission underground in Nassau and part of
Western Suffolk County.
L1LCQ's base transmission system operates at voltages of 69 kV, 138
kV, and 345 kV. Thirty-five percent of all 138 kV transmission is comprised
of underground cables. The last major transmission project (69 kV) occurred
in eastern Suffolk County in 1991. It entailed connecting South old Substation
on the north fork of the Island to Buell Substation on the south fork via an
undersea/underground/undersea cable that crossed Shelter Island. The Town
of Shelter Island mandated that the cable be installed underground and be
nitrogen, rather than oil, filled.
There are approximately 500,000 poles on Long Island, of which L1LCQ
owns 325,000, the remainder being New York Telephone's. None of the poles
are jointly owned. Eighty-four percent of these poles contain both telephone
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and electric facilities, while cable television facilities are attached to 75 percent
of the poles. L1LCO, at present, serves approximately 907,000 customers via
overhead facilities, with about 95,000 being served via underground facilities.
However, in 1990-1991 L1LCO connected 4,997 new customers served by
overhead lines and 3,796 new customers served by underground lines. In
terms of new line construction, 1990-1991 saw 45 cable miles of new
overhead lines and 186 cable miles of new underground lines. L1LCO has
45,000 cable miles of overhead distribution lines and 11,000 cable miles of
underground distribution lines in its system.
Numerous town/village undergrounding ordinances are currently in effect
on Long Island (most deal with undergrounding in new subdivisions). However,
according to L1LCO, it is generally not restricted by these regulations from
installing new single overhead services in existing residential areas, and in many
cases, undergrounding exemptions are received to avoid having recently-paved
roads excavated to install underground electrical facilities.
Below is a sketch of a typical L1LCO transmission and distribution
system.
.SIl!P-UP Transtcaner
Generator
T"nsmis~un Line
Distribution
Pole line
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HISTORY OF COMMISSION UNDERGROUNDlNG PROCEEDINGS
The Commission's earnest consideration of undergrounding' utility
facilities began with proceedings initiated in 1969. The purpose of the
proceedings was to determine the advisability of adopting rules pertaining to
underground electric facilities (Case 25352) and to underground communication
facilities (Case 25396). While the proceedings were initially intended to
address contractor and developer complaints about the widely disparate utility policies
and practices then in use respecting the undergrounding of new distribution lines in
subdivisions, environmental and aesthetic considerations soon came to be the
central focus. Shortly after the two proceedings began, they were combined
and hearings were held concurrently. To facilitate consideration of the diverse
complex issues involved, the proceeding was separated into four phases.
I - New residential subdivisions with five or more units
(initially four or more) and new multiple-occupied
dwellings.
I-A - New commercial and industrial customers and new
residential subdivisions with less than five units.
II - Conversion of existing overhead distribution facilities
to underground.
III - Undergrounding of new transmission facilities to
which Article VII of the Public Service Law did not
apply.
By Opinion and Order issued December 28, 1971 the Commission
established rules and regulations pertaining to underground electric and
telephone facilities for new residential subdivisions (Phase I). The Commission
concluded that, The case for compulsory undergrounding of distribution lines in new
subdivisions is extremely strong and that iUWption of uniform rules governing the
underground practices and policies of the various utilities in the State was the best
way to achieve an orderly growth in undergrounding.
The Commission also noted:
The growing awareness of the need to preserve the scenic
amenities of our environment, as well as recent technologi-
cal advances, have resulted in a pronounced trend toward
under grounding of utility distribution lines. Undoubtedly,
this trend will continue. This is especially true in new
residential subdivisions where the undergrounding of
distribution lines involves little, if any, replacement of
existing facilities in contrast to the extensive construction
necessitated in developed areas and where, accordingly,
the cost of under grounding can be held to a minimum.
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Early experience with the Phase I rules demonstrated that slight
modification to the rules would measurably benefit their application. The
appropriate modifications were made by Commission Opinion No. 73-27, issued
August 10, 1973.
Continued consideration of the remaining phases in the proceeding
resulted in an Examiner's recommended decision with respect to Phase II
(conversion of existing overhead distribution facilities to underground!, issued
January 20, 1972 and a recommended decision with respect to Phase IA (new
construction not governed by Phase I rules!. issued June 26, 1972.
On October 17, 1972 a recommended decision was issued relating to
Phase III (Undergrounding transmission facilities not subject to Article VII of the
Public Service Law!. On March 26, 1975 the Commission issued rules and
regulations for Phase III requiring that, where aesthetic considerations prevail,
the advantages and disadvantages of underground construction must be
considered.
Next, having determined that the wide range of individual circumstances
present with respect to the customer classes subject to Phase I-A made generic
rules impractical, the Commission by Order issued January 10, 1983 closed the
proceeding with respect to Phase IA.
On September 5, 1986 the Commission initiated Case 29389 to examine
the desirability of changes to the electric line extension regulations (16 NYCRR
Parts 98-100! to evaluate the impact of changes in the costs of installing
overhead and underground lines and to review again the basis for allocating
costs between applicants and the utility's general body of ratepayers. The
Order instituting the proceeding closed Case 25352 (dealing with the
undergrounding of electric facilities! and directed that matters previously
considered in Case 25352 be dealt with in the new proceeding. Accordingly,
the yet unresolved Phase II (conversion! became an issue in Case 29389.
On December 9,1988 the Commission issued an Order Clarifying Scope
of Proceeding which declared conversions to be within Case 29389 but that
scheduling of its consideration be left up to the Administrative Law Judge. On
May 15, 1989 the judge ruled that consideration of the conversion issue would
be set aside for a later phase of the proceeding. In the interim, work on
developing proposed regulations to replace the existing electric line extension
regulations continued. On December 21, 1989 the Commission issued an order
expanding the scope of the hearing to include telephone companies and also
issued for comment proposed rules with respect to both electric and telephone
line extensions. Of particular note in these proposed rules was that special
consideration be accorded to undergrounding new lines in specified areas to
preserve the aestheticS of those areas. The specified areas are referred to as
Visually Significant Resources. or VSRs. The proposed regulations were
subsequently modified and, under a neW case number (92-M-0607!. were
reissued for comment in September 1992. The ccmments are currently being
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evaluated; the Commission is expected to issue the regulations in final form in
early 1993.
Activities with respect to conversion were initiated by the Administrative
Law Judge at a July 5, 1992 hearing conference. Submission of proposed
regulations for conversion to the Commission is tentatively scheduled for early
1993.
The current undergrounding proceeding is studying the potential of
undergrounding under various scenarios. In fact, the Commission, on
September 15, 1992, issued proposed rules for comment that provide for a
VSR undergrounding program. This program applies to the new construction
of distribution lines, service lines and appurtenant facilities on public and private
land in VSRs. The program would remain in effect for a period of five years
after its effective date. Under this proposed annual program, L1LCO would be
required to allocate at least $2.4 million (subject to adjustment for inflation) to
a VSR undergrounding fund and would be obligated to spend such amounts on
the cost of installing such new construction underground. Any unspent portion
of L1LCO's maximum obligation in a given year would be carried over to the
next year. The VSR program would be evaluated by the Commission after the
program has been in effect for two years and L1LCO would be required to
provide details of its experience as the staff andlor Commission may request.
It should be noted that this study was conducted independent of
Commission undergrounding proceedings, although most of the study team
members are involved in Cases 29389/92-M-0607.
Below is a picture of subdivision undergrounding with a pad-mounted
transformer in the foreground.
.........~
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SUBDIVISION UNDER GROUNDING
17
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SELECTION OF UNDERGROUNDING SCENARIOS
The objective in the selection of certain overhead facilities as candidates
for undergrounding was rooted in the desire to ascertain which lines were more
prone to catastrophic storm damage. It was understood that any
undergrounding scenario would result in improved aestheticS although a
significant loss of street trees would result from the underground installation.
It was also desirable to have the chosen scenarios representative of L1LCO'S
system.
Undergrounding would have to begin at a substation in order to improve
reliability in a meaningful way during catastrophic storms. To underground a
section of overhead line whose supply was overhead would have limited value
in terms of reliability. L1LCO provided us with storm damage locations from
1973 to 1992. The data available is somewhat broad-based, because the
focus following catastrophic storms is restoration, not data collection.
Nonetheless, L1LCO still has the most comprehensive data among New York
State utilities. Our review of the data showed that during a December 1973
ice storm, primary line damage occurred in the Central and Western Suffolk
Divisions. Specifically, this damage was concentrated in the heavily-treed areas
in the northwestern portion of the villages of Stony Brook and Saint James.
These areas sustained relatively little damage during Hurricane Belle (1976) and
the January 1978 ice storm.
The eye of Hurricane Belle passed just west of the Nassau-Suffolk
County border causing 85 percent of the damage to be concentrated in Suffolk
County, especiallY in the sparsely-treed areas in towns along the Great South
Bay and in the heavily-treed areas east of Smithtown.
The damage which occurred during the January 1978 ice storm tended
to concentrate within L1LCO'S Central and Western Suffolk Divisions, especially
in the heavily-treed areas of Huntington and the treed areas of Plainview,
Plainedge, and Levittown.
The almost 20 years of storm data we reviewed covered the entire
island with damaged locations. Thus, we found there was no clear-cut area
that was more prone to damage. However, one certainty was that the eastern
portion of Long Island is always impacted hardest by hurricanes, with ice
storms impacting the north-west to north-central portion of the island. A
compounding problem with hurricanes is that if the eye of the storm passes
through the center of the island, as Hurricane Gloria did in 1985, the south
shore of the island is hardest hit. But, if the eye of the storm passes east of
Montauk, as Hurricane Bob did in 1991 , the eastern portion of the north shore
of the island joins the south shore as being hardest hit (due to the counter-
clockwise wind rotation heaviest damage is always recorded east/northeast of
the eye of the storm). The One Hundred- Year Storm of December 11 and 12,
1992, left western portions of the north and south shore devastated. Flooding
in the Bayville/Ashroken/Eaton's Neck area cf the north shore and
,
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Massapequa/Ocean Beach, Fire Island area of the south shore was most severe.
The study group then proceeded to examine whether undergrounding
distribution lines along the shorelines of the island would provide the looked-for
litmus test. Difficulties arose with this approach in that circuits meander north,
south, east, and west and appropriate cut-off points for undergrounding were
not available.
The following photographs depict damage from Hurricane Bob.
HURRICANE BOB - AUGUST 19, 1991
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19
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HURRICANE BOB - AUGUST 19, 1991
Staff also looked at whether undergrounding could be combined with
road widening projects or other rebuilding programs. Although the cost of
undergrounding portions of circuits involved with these projects would be
partially offset by the avoided cost of moving the existing overhead lines to the
outer limits of the roadway, the cost differential remains three to five times as
great. In addition, most of these projects involve only segments of circuits,
thus the customers served by the underground circuit portion will be vulnerable
to interruptions occurring in the overhead parts of the circuit. For these
reasons, staff does not find this to be a viable alternative.
I
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i
Since no particular area stood out as a certainty to be impacted by
catastrophic storms, it was decided to determine the cost and benefits of
undergrounding all circuits emanating from a substation. Although both
transmission and distribution lines are constructed according to National Electric
Safety Code standards, overhead transmission line feeds to substations are less
prone to catastrophic storm damage due to enhanced design criteria, as well
as more stringent line clearance or tree trimming practices.
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The two substations chosen were Indian Head in the northern part of the
Western Suffolk Division and Buell, located on the south fork of L1LCO's
Eastern Suffolk Division. L1LCO has 150 major substations in its system". The
relative location of the two substations is shown on the following page.
Indian Head Substation, located in the Town of Smithtown, has six
distribution feeders serving 13,850 customers. The overhead facilities include
5,430 poles, 36 miles of primary mains, and 110 miles of branch lines. Indian
Head was considered a "typical" L1LCO substation.
INDIAN HEAD AREA
Buell Substation, located in the Town of East Hampton, has four
distribution feeders serving 9,300 customers. The overhead facilities include
4,780 power poles, 31 miles of primary mains, and 86 miles of branch lines.
Buell was considered a typical "east-end" substation.
J
BUELL AREA
21
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INDIAN HEAD SUBSTATION
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AMAGANSETT.
MONTAUK LINE
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!~/LCO SERVICE TERRITORY
The substation cost estimates developed in the study should be
indicative of most areas in Eastern Nassau and all of Suffolk County. L1LCO
estimates, however, that circuits in the densely-populated west NassaLi area
and Queens could cost up to 30 percent more to underground due to the need
for more manhole and duct systems, more paving, and more below-grade
transformers and switchgear.
The undergrounding of the existing overhead transmission line from
Amagansett to Montauk, a project that L1LCO will begin to construct in 1993,
was the third undergrounding scenario chosen.
In addition to these two substations and the undergrounding of the
Amagansett to Montauk transmission line, L1LCO's 1978 study involving the
undergrounding of L1LCO's entire system, was updated to a 1992 cost basis.
It is surprising to note that technological advancements since 1978 have not
significantly reduced the cost of installing underground cable. This is due to
more stringent design criteria. The criteria includes manually operated "looped"
cable runs for reliability, which substantially adds to the amount of cable
installed; larger cable sizes to handle overloads and future growth; and
sectionalizing portions of circuits to allow for isolation of faulted cables and
faster restoration time.
While Phase II of the line extension proceeding would be an appropriate
forum to discuss these scenarios, when the decision to do this study was
made, Phase I was not resolved and it was not clear when Phase II would
commence. Findings were anticipated in this study rather soon compared to
the lengthy generic line extension proceeding. For example, Phase I has been
ongoing for over six years. In addition, the scope of the L1LCO underground
study was rather limited in that it was to review the costs and benefits of
overhead conversions to mitigate catastrophic storm damages whereas Phase
II had not developed the rationale for conversion although it was to be more
comprehensive.
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AMAGANSETT-MONTAUK OVERHEAD TRANSMISSION LINE
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-- ---- --.------" -~_.__._---
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SUBSTATION CIRCUIT UNDERGROUNDlNG DESIGN ASSUMPTIONS
The detailed layouts for the Indian Head circuit and the Buell circuit are
based on L1LCO's latest design standards for Commercial, Industrial Parks
Underground Development (CIPUDl and Residential Underground Development
(RUD1.
The underground circuit main essentially follows the same route as the
overhead main and has the same overall length. In some instances, it was
anticipated that the main would be rerouted if it were determined that a parallel
route would be more advantageous from a cost standpoint, have less impact
on traffic, or have greater accessibility for locating pad mounted switchgear.
For the circuits in both the Indian Head and Buell Substation areas, a direct
buried cable was assumed. In other areas, especially business districts which
are completely paved with sidewalks and have buildings immediately adjacent
to each other, a manhole and duct system would be required to facilitate
maintenance and future expansion with minimum impact on area disruptions.
Pad Mounted Housing (PMHl switchgear would be located every 1,000
to 1,500 feet in order to provide sectionalizing points on the circuit main and
take-off points for the CIPUD and RUD fused looped branches. The switches
would be manually operated with the exception that circuit midpoint and tie
point PMH gear would have supervisory sectionalizing capability similar to the
overhead system whereby faults on the circuit main can be isolated to one-half
of the circuit, thereby allowing rapid restoral of service to the remaining half.
It has also been assumed that suitable locations would be found for the pad
mounted switchgear. However, this may not always be the case. Pad
mounted transformers and switchgear are L1LCO's standard installation practice
for underground cable. Below-grade and direct-buried units are more difficult
to locate and maintain, more difficult to keep dry, and more expensive to
install.
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In addition to the circuit main, there are two types of fused looped
branches that supply pad mounted 13 kV to 120/240 Volt transformers: three-
phase CIPUD loops for commercial/industrial load, and single-phase RUD I.oops
for residential load. Both fused loops are designed with sectionalizing at each
transformer such that the failure of a transformer or cable can be isolated,
permitting the restoral of service to the remaining transformers on the loop.
On some streets the three systemsncircuit main, CIPUD loop, and RUD
100P--would be adjacent to each other. Unlike overhead systems, considerable
advanced planning is required to ensure that unanticipated operating
contingencies are appropriately addressed in underground designs. For these
reasons, present L1LCO standards require significant numbers of padmounted
sectionalizing devices and branch cable loops to enable quick restoration of
customer service.
In L1LCO's existing CIPUD loops each commercial/industrial load has its
own transformer. In some of the older commercial areas with small stores
adjacent to each other, one transformer would supply two or three stores. In
applying the RUD system designs, it is assumed that if the cable does not loop
back on the same street, pad mounted transformers on one side of the street
would supply houses on the other side by bringing secondary cable across the
street. This secondary pattern would then supply the service pedestals that
connect the various house services to the system.
The overhead system would remain in service until each area was
converted, and the other utilities (telephone and cable TV) had undergrounded
its facilities. Removal of the overhead facilities includes removal of all poles,
which assumes that service to municipal street lighting would also be
undergrounded.
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SUBSTATION CIRCUIT UNDERGROUNDING METHODOLOGY
Cost Estimate
The methodology employed by L\LCO in pricing out the undergrounding
of the overhead facilities related to each substation is listed below:
A detailed undergrounding analysis and layout was made of
a selected circuit from each substation which contained a
representative mix of residential and commercial/industrial
load. Indian Head circuit 6HL-816 and Buell circuit 9E-992
were the selected circuits. All circuit main and branch taps,
including PMH switchgear and transformers, were laid out
in accordance with current CIPUD and RUD design
standards.
PMH Gear
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The methodology was to take the results of a detailed
analysis of one circuit from each substation and ap!>>y it to
the other circuits in the substation to arrive at an overall
cost for undergrounding the entire substation area. The
costs to install each component associated with
~-~"._. ~,~,,~
undergrounding the circuit mains, fused branches, and
individual services were estimated based on unit cost
estimates developed by L1LCO's Area Planning Division and
reviewed by the Customer Design Services Department,
and the Electric Lines Department. Removal costs include
complete removal of all overhead facilities, including poles.
The study has assumed all other facilities (Le., NY
Telephone, cable TV and municipal street lighting) would
also be undergrounded at the same time. The additional
cost of this undergrounding is not included in the cost
estimate.
A summary of the total cost to underground each of the
two candidate circuits was prepared by counting each
specific piece of equipment on the circuit and applying the
unit cost estimates explained above.
To determine the costs for the remaining circuits, a
residential and commercial cost per connected kV A was
calculated for the transformer capacity from the two
selected circuits and applied to the equivalent overhead
transformer capacity on the remaining circuits. The costs
for the installation of the circuit main and fused loops were
compared to the totals of overhead mains and branches on
the selected circuits and a corresponding cost ratio
developed. This was applied to the corresponding amount
of overhead circuit main and branches on the remaining
circuits.
Rate Impact
The cost estimate together with additional L1LCO source data was used
to develop inputs for the Strategic Financial Plan (SFPl computer model used
by both staff and the company. The Base Case used in the study reflects
increases due to the L1LCO Ratemaking and Performance Plan, as modified in
Opinion No. 91-25 (Case 91-E-1185l. The SFP model produced the stream of
future annual revenue requirements which would be required for the various
undergrounding scenarios. Using the revenue requirements, we derived the
average percent increases to ratepayer bills in all service classifications. As an
example of rate impact, we computed the percent increase of the average
annual bill of an average residential customer (monthly usage of 600 kWh).
The composite undergrounding information inputs to the SFP model are
shown in Appendix A. The summary of the revenue requirements and the
concomitant rate impacts for each of the scenarios evaluated are included on
the corresponding spreadsheets in Appendix B.
A
27
COSTS TO UNDERGROUND AND RESULTING RATE IMPACTS
The costs associated with undergrounding were derived by L1LCOand
reviewed by the study team.
The cost/rate impact data for both the $20 billion updated L1LCO 1978
study and that for undergrounding the Indian Head and Buell substations
includes the cost for both customer service laterals and the costs to connect
these service laterals to the electric meters located on the outside of the house.
Normally the customer/builder would pay an electrician to connect the service
lateral to the meter. For purposes of this study, mainly because of the
magnitude of the underground costs which would ultimately be borne by the
customer, we thought it useful to present a complete package of the cost/rate
impact which the ratepayers would bear. For an underground program of this
magnitude, staff assumed that L1LCO would utilize contractors whose price
includes certified electricians, who are licensed to connect the service lateral
to the meter. Hence, the contractor's price would be a complete package.
The additional costs of undergrounding telephone, cable television, and
street lighting services are not included in the cost projections. Rate impacts
were developed for an 11-year study period (1993-2003) which is the output
limit of the Strategic Financial Planning model used in the analysis. Since the
estimated installation period for undergrounding substation feeders is 10 years,
the model was compatible. However, since the installation period for the entire
undergrounding scenario is 25 years, we can only project rate impacts for the
first 11 years of installation. Thus, additional monthly increases would occur
for the remaining 14 years of the installation period.
The rate impact of undergrounding L1LCO's entire distribution system
would be to raise the average monthly residential rate by $108, from $83 to
$191 during the first 11 years, or an average yearly increase of about 7.9
percent. Over the entire 25 years required to underground the entire system,
a 569 percent increase in rates solely due to undergrounding would be realized.
The rate impact on the other service classes would also be about 569 percent,
exclusive of additional increases due to all other causes.
Under a 25-year plan, L1LCO would need to finance at least $0.8 billion
per year. Our finance personnel advised that a construction program of this
magnitude would require L1LCO to continually access the capital market. They
further indicated that such a program would undoubtedly cause cash flow
problems for the company which could adversely affect the rate at which
L1LCO could access the capital market, or in a worse case scenario, impede its
access to the capital market.
The consequences of effecting early retirement of all overhead
transmission and distribution plant due to installation of replacement
underground plant may require special accounting/financing treatment. There
may be a need for rapid amortization of the loss in order to be consistent with
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accepted accounting practice. An amortization period shorter than the normal
period during which the overhead plant would otherwise be depreciated will
increase the utility's revenue requirements, thus resulting in the need for still
further increases to customers' bills.
The cost/rate impact of undergrounding the entire distribution system is
the aggregate of undergrounding all of L1LCO's 150 major substations. By
deriving the impacts for two individual substations (Buell and Indian Head) we
give a sense of the rates that would impact all of L1LCO's ratepayers, based on
undergrounding the entire system in conformance with current L1LCO design
standards.
INDIAN HEAD SUBSTATION
As mentioned previously, Indian Head Substation employs six circuits to
serve 13,850 customers (of 1,005,000) over 146 miles of main and branch
lines supported by 5,430 power poles. During Hurricane Bob, 1,400 customers
lost electric service. During Hurricane Gloria in 1985 all customers lost electric
service. The Indian Head Substation is pictured below.
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The cost in 1992 dollars to underground all circuits, as well as the cost
to remove the overhead lines including salvage, is $156,707.000." The
undergrounding installation is projected to be performed in equal segments over
ten years. with additions entered to plant-in-service for each of the years. The
detailed work sheets supporting this figure can be found in Appendix C.
Rate Impacts
The summary computer run for the rate impacts that would result from
undergrounding all primary and secondary distribution lines from the substation,
including customer service laterals, is detailed in Appendix B. Undergrounding
the Indian Head circuits will increase L1LCQ's cumulative revenue requirements
by nearly $299 million over the study period (1993-20031.
Alternative #1: RATEPAYERS SERVED FROM THE SUBSTATION PAY ALL COSTS
The impacts on Indian Head customers who would benefit directly, solely due
to the cost of undergrounding would be to:
o Increase the average residential customer's present monthly bill
($83 for 600 kWh usagel by $129 by the year 2003, which is an
increase of 155 percent.
UNDERGROUND INDIAN HEAD SUBSTATION
Impact on Residential Monthly Bills
Indian Head Customers Only
Dollars
300
Cents/KwH
50.00
100
41.67
250
33.33
200
............................ ....
25.00
150
16.67
8.33
50
0.00
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1992
1994
1996
1998
2000
2002
_ W/O Undergroundlng -;- With Undergroundlng
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Alternative #2: ALL L1LCO RATEPAYERS PAY THE COSTS
The impacts on all L1LCO customers solely due to the cost of undergrounding
the lines emanating from the Indian Head Substation would be to:
o Increase the average residential customer's present monthly bill ($83)
by $2 by the year 2003, which is an increase of 2.4 percent.
BUELL SUBSTATION
The Buell Substation utilizes four circuits to serve 9,300 customers over
117 miles of main and branch lines supported by 4,780 power poles. During
both Hurricane Bob and Hurricane Gloria all customers lost electric service. The
Buell Substation is pictured below.
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_._ ._.___.______..__,____~.._____..__..._._.~_".____c....._~....~_..__....~.~,_____...
The cost in 1992 dollars to underground all circuits, as well as the cost
to remove the overhead lines including salvage, is $147,355,600. The
undergrounding installation is projected to be performed in equal segments over
ten years, with additions entered to plant-in-service for each of the years. The
detailed work sheets supporting this figure can be found in Appendix D.
Rate Impacts
Undergrounding all Buell circuits will increase L1LCQ's revenue
requirements by nearly $281 million over the study period (1993-2003).
Alternative #1: RATEPAYERS SERVED FROM THE SUBSTATION PAY ALL COSTS
The impacts on Buell customers who would benefit directly, solely due to the cost
of undergrounding would be to:
o Increase the average residential customer's present monthly bill ($83
for 600 kWh usage) by $180 by the year 2003, which is an increase
of 217 percent.
UNDERGROUND BUELL SUBSTATION
Impact on Residential Monthly Bills
Buell Customers Only
250
Cents/KwH
50.00
Dollars
300
41.67
33.33
200
100
25.00
150
.......................-.......--...............-...
16.67
8.33
50
0.00
o
1992
1994
1996
1998
2000
2002
_ W/o Undergroundlng -i- With Undergroundlng
Alternative #2: ALL L1LCO RATEPAYERS PAY THE COSTS
The impacts on all L1LCO customers solely due to the cost of undergrounding
the lines emanating from the substation would be to:
o Increase the average residential customer's present monthly bill ($83)
by $2 by the year 2003, which is an increase of 2.4 percent.
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AMAGANSETT TO MONTAUK TRANSMISSION LINE
At the outset of this study, L1LCO personnel were preparing to go before
the Board of Directors with a plan to replace the existing two circuits of 23 kV
overhead transmission lines, which run from the Amagansett Substation to the
Montauk Substation, with two 23 kV underground circuits. The
undergrounding installation is projected to be performed in equal segments over
six years, with additions entered to plant-in-service for each of the years. The
Board of Directors has approved the project, and construction of the line is
scheduled to commence early in 1993 and conclude in 1998. Since the driving
force behind this project was enhanced reliability during major storms, aesthetic
gains resulting from the removal of the overhead lines, and relief of the
overloaded overhead lines, it was decided to include this project as one of our
scenarios. The preliminary cost estimate for the two 11.5 mile circuits and the
removal of the existing overhead facilities in 1992 dollars is approximately
$10,600,000. The total revenue requirements are calculated to be $14.5
million for the six-year period. The costs of a transmission line are allocated to
all (1,005,000) L1LCO ratepayers. This amount would, accordingly, have a de
minimus impact on rates.
HISTORY
The existing transmission line between the Amagansett and Montauk
Substations consists of a double circuit overhead 23 kV pole line, most of
which runs through an extremely environmentally-sensitive wetland area (see
below).
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During 1991 's Hurricane Bob, one of the wooden transmission poles
broke, thereby causing the loss of power in both circuits for several days. This
effectively caused outages to all points east of the broken pole. Repair of the
pole was extremely difficult since the area was flooded. and L1LCO could not
obtain a permit to bring mechanized equipment into the environmentally-
sensitive area. Shortly after this incident, L1LCO embarked on its
undergrounding plan. L1LCO's decision was based on the following:
Environmental Concerns - Based on the existence of the line in an
environmentally-sensitive area, continued maintenance, repair, and
reconstruction would be costly, time consuming, and difficult.
Reliabilitv - Reliability to the east-end substations will be greatly
enhanced by placing circuits underground. Five substations that
relied on a single double-circuit pole line will now be served by
underground cables.
Visuallmoact - The existing overhead pole line is in an area where
predominant foliage consists of small pine trees, wetlands, and
scrub oak, and is highly visible. The area's predominant business
is tourism.
Removal of the overhead pole line will greatly enhance the scenic
aspects of the area.
Public Relations Considerations - The Town of East Hampton has
requested the undergrounding of the facilities for environmental,
reliability, and tourist reasons.
..
EXISTING AMAGANSETT TO MONTAUK OVERHEAD LINE
34
PRESENT STATUS
The first phase of the project calls for one new cable to be placed.along
Montauk Highway from the Amagansett Substation east to the general vicinity
of Montauk State Parkway and Old Montauk Highway - a distance of
approximately five miles. The plan is to complete the first underground circuit
and have it in service before the summer peak load period in 1993. At that
time, the two existing overhead circuits will be combined into one circuit.
The second phase of cable installation will start later in 1993 and will
continue the cable all the way to the Montauk Substation. The underground
circuit and diversity of route will improve reliability to the Montauk area. During
the 1994 to 1998 time period, the second underground circuit will be installed.
When the second circuit has been placed in service and has demonstrated its
service reliability, the existing overhead line between Amagansett and Montauk
will be removed.
r
-'
. .
../
~
35
For comparison purposes, we asked L1LCO to estimate the cost of
removing the double-circuited portion of the line which runs through the
wetlands and erecting it as an overhead line on Montauk Highway. L1LCO
estimated the cost at $6,251,000; however, L1LCO points out that all recent
attempts to obtain permission to install overhead transmission in the Town of
East Hampton have met with rejection by the Town.
~
EXISTING AMAGANSETT TO MONTAUK"OVERHEAD LINE
~
36
UNDERGROUNDING ALL L1LCO FACILITIES
In 1978 L1LCO conducted a study that estimated the cost of
undergrounding all L1LCO facilities to be $6.7 billion. In 1990 L1LCO updated
that study to $13 billion. The undergrounding installation was projected to be
performed in equal segments over 25 years, with additions entered to plant-in-
service for each of the years. The study group has applied an 8.5 percent,
two-year inflation factor to the 1990 L1LCO estimate, yielding a total of $14.2
billion. It should be noted, however, that the new, more stringent design
criteria adopted by L1LCO has not been factored into this update. In addition,
no dollar allowance has been made for overhead lines constructed during the
last two years to be converted to underground. Thus, by employing only an
inflation update, the cost of undergrounding L1LCO's entire system is
understated. L1LCO estimates that the total cost including the more stringent
design criteria for its distribution system alone would approximate $20 billion.
For comparison purposes, if one multiplied the $150 million per substation
figure by L1LCO's 150 substations, the total cost of distribution undergrounding
would be $22.5 billion. Thus, L1LCO's estimate of $20 billion appears
reasonable. It should be noted that L1LCO's total net utility plant approximates
$3 billion.
Using L1LCO's $20 billion distribution undergrounding estimate we
updated the cost of various partial undergrounding scenarios. The results in
1992 dollars follow:
Replace existing rear lot overhead branch $1,473,281,000
lines with standard RUD type underground cable.
Replace existing rear lot primary overhead $ 689,327,000
branch lines with underground primary in sidewalk
areas but retain overhead transformers,
secondaries, and rear lot services.
Replace existing rear lot primary branch $ 781,717,650
overhead with underground primary in sidewalk
areas. Replace existing overhead transformers
with pad-mounted units at street property lines.
Retain overhead secondaries and rear lot services.
Replace existing overhead branch primary on $1,933,128,000
highways (4,015 miles) with underground cable
in sidewalk area. Retain overhead transformers,
secondaries, and services on highways.
"
~
37
Rate Impacts
The summary computer run for the rate impacts that would result from
undergrounding L1LCO's entire distribution system is detailed in Appendix B.
Undergrounding will increase L1LCO's cumulative revenue requirements by
approximately $18.5 billion over the 11 year study periocf (1993-2003).
However, it must be noted that the installation period for this scenario is 25
years. The rate impact depicted here represents only the first 11 years of
costs. Additional monthly increases would continue for the remaining 14 years
of the installation period.
The impacts on all customers solely due to undergrounding by year 2003
would be to:
o Increase the average residential customer's present monthly bill
($83 for 600 kWh usage) by $108 by 2003, which is an increase
of 130 percent.
There are cost savings associated with undergrounding, primarily reduced
tree trimming, storm restoration, and storm insurance premium costs.
However, these savings, which would be on the order of $17 million per year,
are dwarfed by the costs of undergrounding.
The study team also examined undergrounding select components of the
distribution system, as L1LCO did in its 1978 study. The options presented
focused on rear lot facilities, which sustain significant damage during
catastrophic storms, and are among the last facilities to be repaired. This
approach is more balanced than the substation approach because it benefits a
wider customer group; however, it would not benefit all customers and would
not eliminate all interruptions. The options presented range in cost from $656
million to just over $1.9 billion, with an annual rate impact on the order of 4.8
to 8.4 percent over the first 11 years of installation.
4
Eleven years is the maximum period for which the computer model is
designed to accept inputs.
J
38
UNDERGROUNDING CONSTRAINTS AND BENEFITS
The following construction, operating, and maintenance considerations
impact on undergrounding:
The cost of undergrounding existing overhead lines is in many cases
prohibitive. A major problem is the siting of PMH switchgear and in some
cases, pad mounted transformers. It is anticipated that there would be
extensive negotiations required for easements. It is also anticipated that there
would be many instances of legal action on the part of the public to prevent the
location of above-grade facilities on or near their property. Also, many
municipalities may enact ordinances to prohibit, or as a minimum, limit the
installation of above-grade facilities.
Under the assumption that other utilities (telephone, cable TV, municipal
street light services, and traffic signal services) would be undergrounded along
with electric, there is the problem of providing special utility corridors in the
road for each utility. This is necessary to maintain the integrity of each system.
This presents problems on some roads where there are existing gas, water,
storm drains, and sewer facilities, which limit the ability to establish these
corridors.
The Communications Division points out that the conversion of existing
overhead to underground facilities is fraught with difficulties because of fences,
hedges, driveways, sidewalks, and other residential property enhancements
which add substantially to undergrounding costs and will generally adversely
affect the company's public relations image. Costs will multiply because of the
fact that when power lines are placed underground, telephone and cable TV
would most likely follow. Furthermore, future replacement of buried plant is
extremely costly and difficult. Much of the telephone wire which was buried
(not in conduit) years ago and is presently deteriorating and in need of
replacement is being placed overhead because the homeowner does not want
the landscape disrupted. Since the wire was buried, homeowners have placed
shrubs, driveways, trees, lawns, sidewalks, etc., on top of the buried plant and
are not at all interested in replacing or repairing their property after it has been
worked over by a utility crew. Neither is a utility willing to foot the high cost
of making these changes, nor is it willing to consider the liability in these
scenarios should something go wrong.
In many instances, municipal, county, and state road widenings, storm
drain installations, and sewer projects affect L1LCO facilities. By law, L1LCO
must move these facilities at ratepayers' expense. In an all-underground area,
many of these projects entail installing new facilities and abandoning existing
facilities.
Cable failures on an underground circuit main place more of a strain on
surrounding circuits than on an equivalent overhead system. As is the case on
the overhead system, faults on the circuit main "are isolated and the load
temporarily transferred to surrounding circuits. However, where overhead
~
39
faults can be located and repaired in a matter of hours, some underground
failures could take days to locate and repair. It is, therefore, more critical to
assure that surrounding circuits can handle the emergency loading for longer
periods. This could be a major problem in cold weather where snow and ice
conditions could make fault location and repair very difficult and time
consuming.
The service life of underground facilities is less than overhead facilities
(30 years versus 50 years), and the initial installation costs and replacement
costs are higher.
A frequently-cited benefit of undergrounding distribution facilities is
avoidance of the visual intrusion imposed by overhead systems. Additionally,
undergrounding also eliminates the sometimes conspicuous and objectionable
appearance resulting from tree trimming necessary to insure safe and reliable
operation. Of course, appearance is a subjective matter and overhead systems
can vary greatly in its visual impact depending upon such factors as design,
location and exposure to view. Thus, depending on the specifics of the
situation, the perceived degree of visual improvement of an underground
system in contrast to an overhead system can be quite variable. Since
underground systems do not require the extensive tree trimming operations
necessary to insure the safe and reliable operation of overhead systems, the
cost of maintaining such operations would consequently decrease.
~
HURRICANE BOB DAMAGE
Avoided insurance premiums are also a benefit of undergrounding. L1LCO
reacquired hurricane insurance in 1989. L1LCO's deductible was $5,000,000,
with coverage of $25 million above the deductible. L1LCO's premium prior to
August 19, 1991 (Hurricane Bob) was $1,119,000. Damage sustained during
Hurricane Bob amounted to approximately $27 million. However, L1LCO
remains in danger of having its insurance canceled. L1LCO's latest premium of
$5,200,000 provides for $37 million of coverage above a $5,000,000
deductible.
The undergrounding of distribution facilities, however, offers certain
advantages not found in overhead systems. One such advantage is the virtual
elimination of outages, and accompanying repair expenses, caused by weather-
related impacts, including strong winds, snow, and ice storms. Additionally,
the decreased exposure of an underground system reduces the probability of
outages caused by motor vehicles and other foreign objects coming into
contact with the system. As a result, underground construction can be viewed
as enhancing the reliability of the distribution system's operation.
Reliability, especially in the early years of an underground cable's service
life {30 years estimated!. is greater in terms of frequency of interruptions (a
recently adopted Commission performance standard). The offshoot, though,
is that the other recently adopted reliability standard-duration of interruption is
considerably longer for underground than for overhead facilities. Data indicate
that interruptions involving the underground CIPUD/RUD system account for
approximately .9 percent of L1LCO's total customer interruptions. The average
customer was affected by an interruption to the overhead distribution system
once every 8.6 months compared to once every 7 years for a customer
affected by failure of a CIPUD/RUD component. On the basis of frequency
only, therefore, underground service in L1LCO's service territory is about ten
times more reliable than overhead service. Restoration time, however, for a
CIPUD/RUD system outage is about twice that of overhead. On a composite
reliability basis, therefore, underground systems are roughly five times more
reliable than overhead systems.
Customer expectations research shows that reliability of service is a very
important factor to customers. However, there is no accepted dollar value of
how much customers are willing to pay for improved reliability. While there
have been several theoretical and empirical studies on this topic, including one
recently conducted by Resource Management International for Niagara Mohawk
Power Corporation, the Commission has never endorsed any dollar value or any
particular methodology for evaluating the value customers place on enhanced
reliability. The Commission has also not endorsed any explicit dollar value for
improvements in aesthetics.
~
41
, '.. ....,.,",.,.------...-...,.,.-"..---------
OTHER FACTORS RELATED TO RELIABILITY
Although hurricanes and ice storms cause the largest number of service
interruptions, the chart below shows that there have been only ten catastrophic
storms since 1960, or one about every three years. However, the average
customer is interrupted as a result of these storms about once every seven
years.
HURRICANES AND ICE STORMS
1960 - 1991
STORM
!DONNA
9/12/60
ESTHER
9/21/61
11/12/68'j
8128171 iiI
12/17/73.~
BELLE
8/9176
ICE STORM
1/13/78
DAVID
9/6/79
GLORIA
9/27/85
!BOB
8/19/91,
o 200 400 600 800 1,000 1,200
THOUSANDS OF CUSTOMERS
. GUST INTERRUPTED. GUST SERVED I
~
42
Customer interruptions also stem from other events, as the chart below
shows.
CAUSES OF CUSTOMER INTERRUPTIONS
Unknown
Failed Connectors 70/.
Fuses, Transf, etc 0
6%
Potheads/Splices
7%
Cable Failures
8%
Trees
26%
Miscellaneous
9%
Birds/Squirrels
4%
Lightning
10%
Motor Vehicles
10%
Hot Line ClamplTaps
13%
~
43
. .
,
There are reliability measures, other than undergrounding. which can be
employed by utilities. lILCO has embarked on a distribution system upgrade
program to improve service reliability. lILCO's expenditures in the area of
distribution upgrades are shown below. The goal of L1LCO's program is to
improve both the frequency and duration of outages to customers by 40 to 50
percent by the mid-to-Iate 1990's.
MAJOR UPGRADE PROGRAM EXPENDITURES
(ANNUAL AVERAGES IN CONSTANT 1990 $'s)
//
30 /
26
CJ)
z 20'
o
..J
..J15.'
:2
><
_Ill 10 .'
*
4,].
/
/
25 .
5'
- ~-: -' .
'. ~ - -:. "" .
_. _u "/
- .
~-- ~; ~ ..;
. ";; .-"--.- {
. !
. ~" - ~ . i -
- '. .
//
/
0"
1980 - 1988
1989 . 1991
1992 . 1999
~
44
The results of this spending program in millions of dollars can be seen
below. .
UPGRADE PROGRAM
ACCOMPLISHMENTS AND EXPENDITURES
1989 - 1991
ACCOAq;;:"'!5H~gE}~7S
$!~ ;: ~~-:;~~~:;~7J~
Distribution Tree Trim 5,360 Miles Trimmed 21.6
Hot Line Clamp Replacements 103,300 Clamps Replaced 15.5
12,835 Line Breakers Removed
Supervisory Controlled 250 Switches Installed 10.5
Switches
Covered Wire 160 Miles of Bare Wire Replaced 11.6
Primary Cable Replacements 18 Miles of Cable Replaced 4.9
Lightning Arresters 1..600 Silicone Carbide 0.7
Arresters Replaced
Infrared Surveys Surveyed Entire Transmission System 0.5
and 300 Distribution Circuits Yearly
Replace Potheads 104 Potheads Changed Out 0.2
Elbow Xrays, Splicer Training,
etc.
10.7
76.2
~
45
i,!
.__,.. ...._..,..._,._--'-._M__'-~.~"--.+_'.'-'_._~...~..___._..~_.._~~
--
, "._..n_""__. __".,...,
~"'_"J""
CONCLUSION
The purpose of this study was to assess undergrounding's potential to
mitigate L1LCO service interruptions caused by catastrophic storms. The result
of the study, which was not unexpected, was that undergrounding would most
definitely reduce, to a significant degree, service interruptions during
catastrophic storms. Overhead systems bear the brunt of the ravages of
hurricanes and ice storms, while underground systems remain relatively
protected. Not surprisingly, it is the exorbitant costs of undergrounding
existing overhead lines which has always precluded massive undergrounding
measures and will probably continue to do so. As this study showed, the rate
impact on the consumer of any significant undergrounding scenario prohibits
the pursuit of most undergrounding proposals.
L1LCO's major weapon in preventing service interruptions from major
storms is its enhanced reliability programs. These programs are proving
successful in reducing service interruptions throughout L1LCO's territory.
However, during catastrophic storms, such as hurricanes and ice storms, even
these measures are not effective in preventing interruptions. Fortunately, the
catastrophic storms occur infrequently. In addition, L1LCO has the most
comprehensive Emergency Response Plan in the state, which enhances the
company's ability to rapidly recover from storm devastation.
Although this study, which pertains only to L1LCO's facilities, shows the
rate shock which results from massive undergrounding, it also shows that for
certain specific situations, undergrounding an overhead line is not only viable
but may be the preferred course of action. The undergrounding of the Island's
east-end transmission line is being undertaken for visual, aesthetic, reliability,
maintenance, and public relations reasons, as well as to meet future load
growth requirements on the South Fork, and appears to have been the proper
choice. Although not detailed in the study, L1LCO does underground certain
portions of existing overhead lines, albeit on a far smaller scale, for exactly the
same reasons. The feasibility of this approach to undergrounding was not
within the scope of this study, but could well be included in the Commission':;
generic proceeding on undergrounding.
Another possible approach to undergrounding existing overhead facilities
lies in the Commission's recently adopted reliability performance criteria. Each
utility must, among other things, report annually on the worst-performinG
circuits (in terms of frequency and duration of interruptions) and indicate the
planned corrective actions. In this regard, the utilities could be made to
evaluate the benefits/cost ratio for undergrounding said circuits. This area
could be further studied in the ongoing ,Phase II undergrounding proceeding.
~
4.fl
Inout Data for StrateQic Financial PlanninCl Model
General AssumDtions
Return on equity/debt per Opinion 91-25 L1LCO C. 90-E-1185
Installation work on each scenario commences January 1, 1993
Average Service Life (ASL) of UG distribution & transmission
= 30 years (w/zero salvage)
Input data amounts are in 1992 dollars unless stated otherwise
Prospective inflation rate for UG is 4.2%
(approx. GDP inflation +0.5%*)
* L1LCO T&D generally tracks 0.5% to 1.0% above GDP
UG Cost Elements as % of investment
Composite O&M = 3.6%
Admin & General = 3.3% **
Property Tax = 6.5% **
GRT = 5.5%
* * to be modified when respective projected A&G and property taxes reach
saturation levels
Caoital Structure
Additional capital to finance UG (50% debt, 50% equity)
O&M UG Costs vs. O&M Savinas for OH (overheadllines reo laced
(based on actual 1991 data)
Additional Cost
UG
$/mile
Savings
OH
$/mile
routine O&M
emergency service
tree trim
$1 ,521
545
286
$1,096
3,550
1.807
$6,453
TOTAL O&M/mile
$2,352
~
Scenario AssumDtions
1. UG lines Buell + Indian Head Substations
Capital Construction (excl. AFC)
Indian Head Substation
Buell Substation
- UG Distribution lines emanating from substation
incl. services and removal of OH lines'
- Installation in equal segments over 10 years
- Assume each year's CWIP is closed to plant-in
service
2. UG all L1LCO overhead facilities2
Capital Construction (excl. AFC)
- UG Distribution = Trans. lines + Service Laterals
+ Street Lights and remove OH lines
- Installation in equal segments over 25 years
- Assume each year's CWIP is closed to plant-in
service
1 No costs are included to reflect the early retirement of the overhead lines.
$ millions
$156.7
147.4
$ billions
$20.0
2 Based on the updated cost for the 1978 study which is understated because of significant
~
changes in design specifications.
~
.
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
SAMPLE CALCULATIONS FOR EXECUTIVE SUMMARY
Ratiol%
Notes/Source Data
Effect of only UnderQroundinQ on
Residential Rates for initial 11 years
initial rates= $83/mo. ; final rates= S191/mo.
"
increase ratio=191/83=
average yearly increase=7.9%;
check: (1.079) ^ 11 =2.308; rounded
2.30
"
2.30
%increase in rates in 11 years
=0ncrease ratio-1)*100= (2.3-1)*100
check: (191-83)*100/83= 130%
130%
""
Effect of only UnderQroundinQ on
Residential Rates for initial 25 years
increase ratio= (1.079) ^ 25=
6.69
Initial Rates = $83/mo.
final rates=6.69*83/mo.= $55527/mo.
%increase in rates in 25 years
=(increase ratio-l)*100= (6.69-1)*100
569%
""
* source data= Appendix B; worksheet titled Scenerio #1
....the rates of all service classifications will increase by approximately this percentage
lIlCO\Undergro\Exec-SUm.wk3
~
,
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
DECEMBFR 1992
SCENARIO #1 TOTAL OF BASE CASE +
INCREMENTAL EFFECT OF INCREMENTAL EFFECT OF
BASE CASE. UNDERGROUNDING ENTIRE SYSTEM.' SCENARIO #1
Approx.
Approx. InCLlo Approx.
Base Base Resident.
Residential IncLlo Incr. to Resident. Total
Base Base Monthly Base Base Monthly Avg. Monthly
Revenue Revenue Bin'" Revenue Revenue BIII"""4 Revenue BlII".
YEAR ($M) (c/KwH) ($) ($M) (c/KwH) ($) (c/KwH) ($)
$2,234
2,341
2,462
2,595
2,723
2,859
3,002
3,038
3,050
3,185
3,301
3,480
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
I
I
2017 UIIl"
NoIOS:
1110 Oas8 Case assumption, undorlylng IhelLCO Rale Moderallon plan 8S modlllod In Opinion 91 - 25,
was updated 10 roflect nec8s8Bfy caplals,,"ucllIO modlflcallons fOf Scenario II 1.
... undorgoundlnglnslalJollonw:. $ 20 billIon (1092 OOllo(8)- 10 be Inslalled In equal sogments OV'Of 25 VOIfS
".. assumos monthlv U80 per realdonUal customer d 600 KwU
..... glvon an Incroase o. $108 In mo. hills solely duo 10 uder(Joundlng from $H3/mo 10 $19'/mo.- or 8n Inaoase 0' 130% In 11 years; tho avorage Incroase
to monlhly billa would be 7.9 " compounded annually solely due 10 under(Joundlng, I.e. In addillon to Iho base caso Inaoases Indlcaled
"'"",,'" ;$Y'l3n<tS 'G'ii~1c.;'msnt. a~(; ri?lt6F.fP.:'{er ~i1~ ~"1l!8 continue 10 increase unlit undorgroundlng compkrUon In 2011
13.84
14.39
14.96
15.57
16.16
16.79
17.45
17.47
17.32
17.87
18.29
19.05
$83
$86
$90
$93
$97
$101
$105
$105
$104
$107
$110
$114
$0
178
436
704
1,005
1,324
1,640
1.992
2,354
2,652
2,962
3,292
$18.538
Sub-Total
nla
1.09
2.66
4.22
5.97
7.78
9.54
11.45
13.36
14.88
16.42
18.02
nla
$7
16
25
36
47
57
69
80
89
98
13.84
15.48
17.62
19.79
22.13
24.57
26.99
28.92
30.68
32.75
34.71
37.07
108 ..u
$83
93
106
119
133
147
162
174
184
197
208
222
.
\
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
AUGUST 1992
SCENARIO #2B
EFFECT OF UNDERGROUNDING (UG) DISTRIBUTION LINES
FROM INDIAN HEAD SUBSTATION"
IlllCrnstlives
IN-HD RATEPAYERS SERVED FROM ALL ULCO RATEPAYERS
UNES INDIAN HEAD BEAR THE BEAR THE
BASE CASE. UG Ui'jQERGROUND/NG COSTS UNDERGROUNDING COSTS
Approx. Approx.
Approx. Iner. Iner. New Iner. New
Res/d. 10 to tner. to Resld. 10 Iner. 10 Res/d.
Base Avg. Month. Bese Base Base Month. Base Basa Month.
Revenue Revenue Bill." Rev. Rev. Revenue Bill""" Rev. Revenue Bill".
YEAR ($M) (e/KwH) ($) ($M) (e/Kw~ (%) ($) (e/KwH) (%) ($)
1992 $2,234 13.84 $83 n/a nla nla $83 0.000 nla $83
1993 2,341 14.39 86 $1.5 0.69 5.0% 91 0.010 0.1% 86
1994 2,462 14.96 90 7.7 3.43 19.0% 110 0.047 0.3% 90
1995 2,595 15.57 93 11.3 4.97 10.3% 123 0.060 0.1% 94
1996 2,723 16.16 97 15.5 6.70 11.1% 137 0.092 0.2% 98
1997 2,059 16.79 101 20.1 8.62 11.9% 152 0.118 0.2% 101
1998 3,002 17.45 105 25.8 10.94 13.8% 170 0.150 0.2% 106
1999 3,038 17.47 105 31.4 13.20 13.0% 184 0.181 0,2% 106
2000 3,050 17.32 104 37.1 15.39 12.5% 196 0.211 0.2% 105
2001 3,185 17.87 107 44.3 18.15 16.0% 216 0.249 0.2% 109
2002 3,301 18.29 110 50.0 20.22 11.6% 231 0.277 0.2% 111
2003 3,480 19.05 114 53.6 21.42 6.6% UH 243 0.293 0.1% 116
Total $298.3
Notes:
The Base Case assumpllon, underlying the lIlCO Rale Moderallon plan as modllted In OpinIon 91- 25,
was updated 10 rell9Ct necessary capllal structure modl/lcallons for Scenarlo '28.
undergroundlng to be Installed In equaleogmenls ovor 10 years
assumes monthly use per resldenllal cuslomor or 600 KwH
~ ~ u ~olallncree.se 10 t?3'O' ff;es by ysa, :<::;03 Is 193% !llndlsn Head ,ntopayers bear the UG cosls
.
,
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
AUGUST 1992
SCENARIO #2A
EFFECT OF UNDERGROUNDING (UG) DISTRIBUTION LINES
FROM BUELL SUBSTATION ..
111lernnli....es
BUELL RATEPAYERS SERVED FROM ALL ULCO RATEPAYERS
UNES BUELL BEAR THE BEAR THE
BASE CASE' UG UNDERGROUNDING COSTS UNDERGROUNDING COSTS
Approx. Approx.
Approx. Iner. Iner. New Iner. New
Resld. to to Iner. to Resid. to Iner. to Resld.
Base Avg. Month. Base Base Base Monlh. Base Base Month.
Revenue Revenue Bill."" Rev. Rev. Revenue Bill"'.. Rev. Revenue Bill'"
YEAR ($M) (e/KwH) ($) ($M) (e/Kwf (%) ($) (e/KwH) (%) ($)
1992 $2,234 13.84 $83 nla nla n/a $83 0.000 n/a $83
1993 2,341 14.39 86 $1.5 0.97 7.0% 92 0.009 0.1% 86
1994 2,462 14.96 90 7.3 4.80 26.6% 119 0.044 0.2% 90
1995 2,595 15.57 93 10.7 6.96 14.4% 135 0.064 0.1% 94
1996 2,723 16.16 97 14.5 9.38 15.6% 153 0.086 0.1% 97
1997 2,859 16.79 101 18.9 12.07 16.6% 173 0.111 0.2% 101
1998 3,002 17.45 105 24.2 15.31 19.3% 197 0.141 0.2% 106
1999 3,038 17.47 105 29.6 18.48 18.2% 216 0.170 0.2% 106
2000 3,050 17.32 104 34.9 21.55 17.5% 233 0.198 0.2% 105
2001 3,185 17.87 107 41.7 25.42 22.4% 260 0.234 0.2% 109
2002 3,301 18.29 110 47.0 28.32 16.2% 280 0.260 0.1% 111
2003 3,480 19.05 114 50.4 30.00 9.2% u""" 294 0.276 0.1% 116
TOlal $280.6
Noles:
The Base Case assumplloll, underlying Ihe UlCO Rale MOderallon plan 8S modified In Opinion 91-25,
was updated 10 rellect necessary capllal structure modlrlcallons for ScenarIo N2A.
.. undorgroundlng 10 be Installed In equal segments ovor 10 years
... - assumes monthly use per ros/danllal customo, 01 600 KwH
lolallncreaso to base rates by yoar 2003 Is 254% II Buell ratepayers bear Ilia UO costs
,
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
DECEMBER 1992
f3ASE c~
INCflEMENTAl EFFECT OF nEPIACING
nEAn LOT on tiNeS
WITll STD. nUD TVD6 UNOEnGnOUNl}yAULt~
TOT At OF BASE CASE +
INCIlEMENTAI.. fTfECT OF
PA!:!!~UNnEI~onOUNDING
Approx.
Base
Residential
Base Base Monthly
Revenue Revenue Bill'"
YEAR ($M) (c/KwH) ($)
Approx.
Incr. to
Base
Incr. to Incr. to Resident.
Base Base Monthly
Revenue Revenue BillA-U
($M) (c/KwH) ($)
Avg.
Approx.
Resident.
Total
Monthly
BII''''
Revenue
(c/KwH)
($)
1992 $2,234 13.84 $83 $0 nla nla 13.84 $83
1993 2,341 14.39 $86 12 0.Q7 $0 14.46 87
1994 2,462 14.96 $90 29 0.17 1 15.13 91
1995 2,595 15.57 $93 46 0.28 2 15.85 95
1996 2,723 16.16 $97 66 0.39 2 16.55 99
1997 2,859 16.79 $101 87 0.51 3 17.30 104
1998 3,002 17.45 $105 108 0.63 4 18.08 108
1999 3,038 17.47 $105 131 0.75 5 18.22 109
2000 3,050 17.32 $104 155 0.88 5 18.20 109
2001 3,185 17.87 $107 175 0.98 6 18.85 113
2002 3,301 18.29 $110 195 1.08 6 19.37 116
2003 3,480 19.05 $114 217 1.19 7 .... 20.24 121
I Sub- Total $1,223
I
2017 t.UH
Noles:
TI10 Base Caso assumpUon, UndlYlylng IheLLCO Ralo Mod9'alfon plan as modmed In Opinion 91-25,
was updalod 10 reflect noc8s9l1'Y caplal sluchn modlllcaUons tOf' Sconarlo Ii 1.
unde-goundlng InslaUadon= $ 1.32 bllllon (1992 OOIl..-s) - to bolnslalled In eqUal segmenls over 25 yoars
.... assumes monthly use per residential customer ol600 KwH
...u given an Inaea.. of $ 7 In mo. billa solely due 10 udergroundlng trom S83/mo to S90/mo.- or an IflCfeas8 0' 8.4 " In 11 yoalS; Ihe average Incroase
;0 monlhly bllts would be 0.74 'J(, compoundod annually 80101., due 10 UndOflJ'oUndlng, 1.0. In addltfon 10 Ihe base case Inao8so8 IndleJl\ted
.......... I:'ev.g.r~u". t"!,-,;o""oem~N:s .no:: ".a~0~Z:Yo/ ~m3 "VI:! co.,~r~....l!' 10 IrH;"''J'.?!$ao ~~W undergroU!nd1ng complotlon In 29H
\
..--JJA8E CASE'
DECEMBER 1992
LONG ISLAND LIGHTING COMPANY
UNDERGROUNDING STUDY
INCREMENTAL EFFECT OF AfPtACING
REAR tor PRIMARY au tiNES WITH
UO PfUMAHY IN SIDEWALK AHEAS AND RHAIN
011 TRANSfORMER SfeONllAfIIfS AND SEfJY!l;fS~
TOTAL OF BASt CASE;
INeflfMfNTJlI. Hrfer Of
PARTiAl UNOfllal!~~QlliQ.
Approx,
Base
Reeldsflllal
Base Base Monthly
Revenue Revenue Bill"""
YEAR ($M) (e/KwH) ($)
Approx,
tncr, 10
Base
tneLlo Iner. to Residant.
Bass Bass Monthly
Rsvenue Revenue Bill"'"""
($M) (e/KwH) ($)
$2,234
2,341
2,462
, 2,595
2,723
2,869
3,002
3,036
3,050
3.165
3,301
3,460
13,64
14.39
14,96
10.57
16.16
16,79
17.45
17.47
17.32
17.67
16.29
19,05
$63
$66
$90
$93
$97
$101
$105
$105
$104
ST07
$110
$114
$0
6
14
23
33
44
54
65
77
67
97
106
$609
n/a
0.04
0.09
0.14
0,20
0,26
0,31
0.3f
0.41
0.41
0.5\
o,m
Avg,
Revenue
(c/KwH)
n/n
so
1
1
1
2
2
2
3
3
3
Approx,
11esident.
rotat
Mont/lly
Bill'"
($)
1992
1993
1994
1995
1996
1997
1996
1999
2000
2001
2002
2003
I
I
2017 """""""""
Nolos:
TllO BaSI) Caso "ssUrT\!JDOn, l.Il,dOl'lylng theLI.CO nata ModOfallon plan as modlllodln OphlionI1-25.
was updatodlU foiled nlu;li9SIlf y caplalstlJCluro JIlOlllltaltolls IOf Sconwlo IJ I.
UII(J(JfgOUIUJil'fJ Ins'allotlon '" $ 0.7 billion (1992 CkIUiWS)- 10 bo Installed In oqIJ81 segrnullts 0191' 25 year,
.... assurnos llIo,IIhlVJ90 W H.sJeklnUal cUIlI\lnu.ll (II fHX) KNU
..... \Jlvon an Ina.a,.o of' .. hi mo. billa ftOl.l~ due 10 udOI{poufllJlnu hom $83/mu u S81/mt.- Of an lncruasfl 01 4.6 '" In 11 V'oa'8: Iho ItIIUfalJU IflaOsae
10 OIC>lllh'Y hlllll *uuld be 0.4:1 'H> comlloundud allnllallV' aOI.I, dun 10 undOfyr.)'JIldiflU. Ie. III add/lion 10 'ho b..so c.se Inaoasos Indlctlhtct
.......... ~f]v'1~'V(l lfJ'."'J~ ym-:OrJ.. ,.,,,~ ,1!'.~"'r,,~~e1' bl!!'1. 'i"'11! c"I\:lnuu Iu D~Q'OJM.O unlll undOf (JI'oundlOO clmlllellon In 20,1'
Sub- Total
13.64
144:1
15,05
15.71
16.36
17.05
17.76
17.85
17.76
16.36
18.83
19.64
4 ..........
$83
67
90
94
98
102
t07
107
107
110
113
118
,
MAY, 1992 PSC STUDY
DETAll.ED ANALYSIS OF
COST TO UNDERGROUND
SUBST A nON SUMMARY SHEET
INDIAN HEAD
COST TO INSTALL COST TO REMOVE
CIRCUIT UNDERGROUND OVERHEAD * TOTAL COST
6HL- 811 $20,832,700 $2,733,900 $23,566,600
6HL - 812 $31,143,000 $4,023,400 $35,166,400
6HL - 813 $24,052,300 $3,183,200 $27,235,500
6HL - 814 $27,158,200 $3,539,000 $30,697,200
6HL - 815 $17,639,700 $2,256,700 $19,896,400
6HL - 816 $17,869,500 $2,275,400 $20,144,900
TOTAL:
$138,695,400
$18,011,600
$156,707,000
* - OVERHEAD REMOVAL COSTS INCLUDE SALVAGE VALUE
OF OVERHEAD CONDUCTORS.
~
REV. 06/30/92
MAY, 1992 PSC STUDY
DET All..ED A..NAL YSIS OF
COST TO UNDERGROUND
($ X (00)
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONAlIZING UNITS
CAPACITORS
MISC. EQUIPMENT
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
~
CIRCUIT:
COST TO INSTALL
3,676.2
1,255.4
50.1
0.0
0.0
0.0
0.0
2,566.0
44.5
618.7
84.0
0.0
0.0
0.0
0.0
0.0
7,812.0
544.9
2,929.5
1,251.4
0.0
0.0
0.0
0.0
0.0
TOTAL:
6HL- 811
SUBTOTAL
$4,981.70
$3,313.2
$12,53'1.8
$20,83:>.f
PAGE 1 OF 3
REV. 06/30/92
r ' .
,
MAY, 1992 PSC STUDY
DETAiLED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 811
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 48.5
2 PHASE 5.1
1 PHASE 95.1
SUBTOTAL
$148.7
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
18.7
2.8
49.2
23.1
10.8
0.0
0.0
0.0
0.0
0.0
$104.6
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
8.7
62.7
63.9
24.6
0.0
1,315.4
1,031.7
0.0
0.0
TOTAL:
$2,507.0
$2,760.3
~
PAGE 2 OF 3
MAY, 1992 PSC STUDY
DETAIT...ED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL- 811
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $20,832.7
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $2,760.3
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
($26.4)
TOTAL COST:
$23,566.6
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUr"L)
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 201,600 CONDUCTOR FEET OF WIRE AND 11,000 KVA
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DET All.ED ANAL YSrS OF
COST TO UNDERGROUND
($ X (00)
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONAUZING UNITS
CAPACITORS
MISC. EQUIPMENT
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
#
CIRCUIT:
COSTTO INSTALL
5,395.8
1,842.6
175.6
0.0
0.0
0.0
0.0
3,766.1
73.5
1,096.7
320.0
0.0
0.0
0.0
0.0
0.0
11,466.0
965.8
4,299.8
1,741.1
0.0
0.0
0.0
0.0
0.0
TOTAL:
6HL - 812
SUBTOTAL
$7,414.00
$5,256.3
$18,472.7
$31,143.0
PAGE 1 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
SUBSTATION: INDIAN HEAD
FACILITIES TO BE REMOVED:
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE
2 PHASE
1 PHASE
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
~
CIRCUIT:
COST TO REMOVE
88.6
6.1
103.5
27.5
4.9
87.2
33.9
19.2
0.0
0.0
0.0
0.0
0.0
12.7
111.0
79.2
43.5
0.0
1,930.7
1,514.2
0.0
0.0
TOTAL:
6HL - 812
SUBTOTAL
$198.2
$172.7
$3,691.3
$4,062.2
PAGE 2 OF 3
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 812
1. COST TO INSTALL NEW UNDERGROUND
DiSTRIBUTION SYSTEM
. . . . . . .. $31,143.0
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $4,062.2
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
($38.8)
TOTAL COST:
$35,166.4
THIS is THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 296,200 CONDUCTOR FEET OF WIRE AND 19,500 KVA
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06{30{92
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1. 3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
~
CIRCUIT:
COST TO INSTALL
4,298.8
1,468.0
139.9
0.0
0.0
0.0
0.0
3,000.5
60.8
864.4
189.2
0.0
0.0
0.0
0.0
0.0
9,135.0
761.3
3,425.6
708.8
0.0
0.0
0.0
0.0
0.0
TOTAL:
6HL - 813
SUBTOTAL
$5,906.70
$4,114.9
$14 Q',("1 "/
1'<'" ..-.,
$24,O~,~U;
PAGE 1 OF 3
REV. 06/30/92
MAY, 1992 PSC STIJDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 813
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 90.1
2 PHASE 1.1
1 PHASE 46.6
SUBTOTAL
$137.8
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
21.9
3.9
68.7
27.0
15.1
0.0
0.0
0.0
0.0
0.0
$136.6
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
10.2
87.5
63.1
34.3
0.0
1,538.2
1,206.4
0.0
0.0
$2,939.7
TOTAL: $3,214.1
~ PAGE 2 OF 3
MAY, 1992 PSC STIJDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 813
1. COST TO INSTAll NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $24,052.3
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $3,214.1
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
($30.9)
TOTAL COST:
$27,235.5
THIS IS THE ESTIMATED TOTAL COST TO INSTAll AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 237,000 CONDUCTOR FEET OF WIRE AND 15,400 'r<YA
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X (00)
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
CIRCUIT:
6HL - 814
COSTrO INSTALL
SUBTOTAL
4,713.9
1,609.7
153.4
0.0
0.0
0.0
0.0
$6,477.00
3,290.2
64.2
995.3
238.7
0.0
0.0
0.0
0.0
0.0
$4,588.4
10,017.0
876.6
3,756.4
1,442.8
0.0
0.0
0.0
0.0
0.0
$16,092.8
TOTAL $27,158.2
PAGE 1 OF 3
~ REV. 06/30/92
MAY, 1992 PSC STUDY
DET All..ED ANALYSIS OF
COST TO UNDERGROUND
($ X (00)
SUBSTATION: INDIAN HEAD
FACILITIES TO BE REMOVED:
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE
2 PHASE
1 PHASE
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
~
CIRCUIT:
COST TO REMOVE
68.0
1.8
118.4
24.0
4.4
79.1
29.6
17.4
0.0
0.0
0.0
0.0
0.0
11.1
100.8
69.2
39.5
0.0
1,686.7
1,322.9
0.0
0.0
TOTAL:
6HL - 814
SUBTOTAL
$188.2
$154.5
$3,230.2
$3,572.9
PAGE 2 OF 3
. ,
MAY, 1992 PSC STUDY
DET All..ED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 814
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $27,158.2
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $3,572.9
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
." ........
($33.9)
TOTAL COST:
$30,697.2
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 259,800 CONDUCTOR FEET OF WIRE AND 17,700 KYA
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06{30{92
.
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONAUZING UNITS
CAPACITORS
MISC. EQUIPMENT
MAY, 1992 PSC STUDY
DETAll.ED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
~
CIRCUIT:
COST TO INSTALL
2,952.8
1,008.5
96.1
0.0
0.0
0.0
0.0
2,061.0
40.2
757.7
249.4
0.0
0.0
0.0
0.0
0.0
6,274.8
667.3
2,353.1
1,178.8
0.0
0.0
0.0
0.0
0.0
TOTAL:
6HL - 815
SUBTOTAL
$4,057.40
$3,108.3
$10,474.0
$17,639.7'
PAGE 1 OF 3
REV. 06/30/92
-,~~~#-~~~~~.,:;;;h~-t.;J::1:j~:~~::':.'"."'~",'~~:'~'~ "",_.~,.~,.,_v"~", . . ,.
_ _, __. _ _ ~_,.__,~ g-~':"'S:.F.~--''':lEJ.:.u:.~;.':;,i.:-'"~''':~-' ,.'. ~ - -,"""~<':Li~';<;''''.':'",;;-,,, ,," ';}'}'r,"" '{ '.., ....'.-- ,--. .,. "..:.a.>L-.c..:.-.'--_"''--~,",..",..",;,:.
- ,'-
MAY, 1992 PSC STUDY
DETAll..ED ANALYSIS OF
COST TO UNDERGROuND
($ X 000)
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 815
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 34.4
2 PHASE 4.4
1 PHASE 86.3
SUBTOTAL
$125.1
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
15.0
3.4
60.2
18.5
13.3
0.0
0.0
0.0
0.0
0.0
$110A
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
7.0
76.7
43.3
30.1
0.0
1,056.6
828.7
0.0
0.0
TOTAL:
$2,042.4
$2,277.9
~
PAGE 2 OF 3
,
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 815
1. COST TO INSTAll NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $17,639.7
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $2,277.9
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
... ........
($21.2)
TOTAL COST:
$19,896.4
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 162,300 CONDUCTOR FEET OF WIRE AND 13,500 ~A
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06/30/92
ii
I
Ii
II
,
SUBSTATION: INDIAN HEAD
FACILITIES TO BE INSTALLED:
1. 3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
SECTIONALlZING UNITS
TRANSFORMERS
SERVICES
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
~
CIRCUIT:
COST TO INSTALL
2,964.7
1,012.4
96.5
0.0
0.0
0.0
0.0
2,069.3
40.4
896.7
335.4
0.0
0.0
0.0
0.0
0.0
6,300.0
789.7
2,362.5
1,001.9
0.0
0.0
0.0
0.0
0.0
TOTAL:
6HL - 816
SUBTOTAL
$4,073.60
$3,341.8
$10,454.1
$17,869.5
PAGE 1 OF 3
REV. 06/30/92
. .
MAY, 1992 PSC STUDY
DETAilED ANALYSIS OF
COST TO UNDERGROm.rn
($ X (00)
SUBSTATION: INDIAN HEAD CIRCUIT:
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 55.6
2 PHASE 1.1
1 PHASE 45.6
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
~
15.1
4.0
71.3
18.6
15.7
0.0
0.0
0.0
0.0
0.0
7.0
90.8
43.5
35.6
0.0
1,060.8
832.0
0.0
0.0
TOTAL:
6HL - 816
SUBTOTAL
$102.3
$124.7
$2,069.7
$2,296.7
PAGE 2 OF 3
MAY, 1992 PSC STUDY
DETAILED A.NALYSIS OF
COST TO UNDERGROUND
($ X (00)
CIRCUIT SUMMARY SHEET
SUBSTATION: INDIAN HEAD
CIRCUIT:
6HL - 816
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $17,869.5
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $2,296.7
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
($21.3)
TOTAL COST:
$20,144.9
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 163,000 CONDUCTOR FEET OF WIRE AND 15,950 KYA
OF DISTRIBUTION TRANSFORMER CAPACITY.
~
PAGE 3 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DETAll..ED ANALYSIS OF
COST TO l!NTIERGROUND
SUBSTATION SUMMARY SHEET
BUELL
COST TO INSTALL COST TO REMOVE
CIRCUIT UNDERGROUND OVERHEAD * TOTAL COST
9E - 934 $49,436,000 $4,062,000 $53,498,000
9E - 985 $29,995,700 $2,392,900 $32,388,600
9E - 991 $9,445,900 $764,600 $10,210,500
9E - 992 $47,405,700 $3,852,800 $51,258,500
TOTAL:
$136.283,300
$11.072.300
$147.355.600
* - OVERHEAD REMOVAL COSTS INCLUDE SALVAGE VALUE
OF OVERHEAD CONDUCTORS.
~
REV. 06/30/92
. ,
SUBSTATION:
BUELL
MAY, 1992 PSC STUDY
DETAll.ED At"lAL YSIS OF
COST TO UNDERGROUND
($ X 000)
FACILITIES TO BE INSTALLED:
1. 3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
CIRCUIT:
COST TO INSTALL
14,085.7
1,072.5
102.3
0.0
0.0
0.0
0.0
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE 953.0
SECTIONALlZING UNITS 600.3
TRANSFORMERS 163.8
SERVICES 482.0
MISC. EQUIPMENT 0.0
0.0
0.0
0.0
0.0
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
LB CTA
21,412.8
2,436.3
6,857.0
1,180.1
0.0
90.2
0.0
0.0
0.0
TOTAL:
9E - 934
SUBTOTAL
$15,260.50
$2,199.1
$31,976.4
$49,436.0
PAGE 1 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DETAILED A~AL YSIS OF
COST TO UNDERGRotJND
($ X 000)
SUBSTATION:
BUELL
FACILITIES TO BE REMOVED:
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE
2 PHASE
1 PHASE
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WlRE
SERVICES
MISC. EQUIPMENT
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WlRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
CIRCUIT:
9E - 934
COST TO REMOVE
106.7
8.1
140.4
12.9
4.1
7.9
21.8
0.8
0.0
0.0
0.0
0.0
0.0
7.4
212.3
151.7
106.2
0.0
3,173.0
274.2
0.0
0.0
TOTAL:
SUBTOTAL
$255.2
$47.5
$3,924.8
$4,227.5
PAGE 2 OF 3
-
MAY, 1992 PSC STUDY
DETAll..ED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION:
BUELL
CIRCUIT:
9E - 934
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . ., $49,436.0
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . ., $4,227.5
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
... ........
($165.5)
TOTAL COST:
$53,498.0
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 391,950 CONDUCTOR FEET OF WIRE AND 25,500KVA
OF DISTRIBUTION TRANSFORMER CAPACITY.
PAGE 3 OF 3
REV. 06/30/92
~ "
SUBSTATION:
BUELL
MAY, 1992 PSC STIJDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X (00)
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
CIRCUIT:
COST TO INSTALL
8,398.3
639.5
61.0
0.0
0.0
0.0
0.0
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE 568.2
SECTIONALIZING UNITS 357.9
TRANSFORMERS 124.0
SERVICES 152.7
MISC. EQUIPMENT 0.0
0.0
0.0
0.0
0.0
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
LBCTA
~
12,766.9
1,843.9
4,088.3
941.2
0.0
53.8
0.0
0.0
0.0
TOTAL:
9E - 985
SUBTOTAL
$9,098.80
$1,202.8
$19,694.1
$29,995.7
PAGE 1 OF 3
REV. 06/30192
- --
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
SUBSTATION:
BUELL
CIRCUIT:
9E - 985
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 68.3
2 PHASE 0.0
1 PHASE 81.3
SUBTOTAL
$149.6
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
7.7
3.1
5.9
13.0
0.6
0.0
0.0
0.0
0.0
0.0
$30.8
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWT')
REMOVE POLE (RP)
4.4
160.7
90.4
0.9
0.0
1,891.8
163.5
0.0
0.0
TOTAL:
$2,311.7
$2,491.(\
~
PAGE 2 OF 3
,.". ~.,<'-"~"".~"-"'~.'. ,''''~-~'_'~''''~,..,~.<"-~"_.,,..-..,,.~~._.,..~~.-.---- -. -~
. ...~..,,,.,.,,. " ""...,~'" "..., 'q'
,. -'_._'""-'.'-'~'.""'''
. I
.
MAY, 1992 PSC STUDY
DETAlLED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
SUBSTATION:
BUELL
CIRCUIT:
9E - 985
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $29,995.7
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . .. $2,491.6
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
($98.7)
TOTAL COST:
$32,388.6
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 233,550 CONDUCTOR FEET OF WIRE AND 19,200 KVA
OF DISTRIBUTION TRANSFORMER CAPACITY.
PAGE 3 OF 3
REV. 06/30/92
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
cosr TO UNDERGROUND
($ X (00)
2. 3 PHASE SUPPUES (LOOPED & RADIAL)
PRIMARY CABLE 182.5
SECTIONAUZING UNITS 115.0
TRANSFORMERS 30.8
SERVICES 111.8
MISC. EQUIPMENT 0.0
0.0
0.0
0.0
0.0
SUBSTATION:
BUELL
FACILITIES TO BE INSTALLED:
1. 3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
LB CT A
-
CIRCUIT:
COST TO INSTALL
2,697.5
205.4
19.6
0.0
0.0
0.0
0.0
4,100.8
458.6
1,313.2
193.4
0.0
17.3
0.0
0.0
0.0
TOTAL:
9E - 991
SUBTOTAL
$2,922.50
$440.1
$6,083.3
$9,445JJ
PAGE 1 OF 3
REV. 06/30/92
~
. j
MAY, 1992 PSC STUDY
DET AILED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
SUBSTATION:
CIRCUIT:
BUELL
FACILITIES TO BE REMOVED: COST TO REMOVE
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE 32.8
2 PHASE 0.0
1 PHASE 3.3
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
2.8
0.8
1.5
4.2
0.2
0.0
0.0
'0.0
0.0
0.0
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS 1.4
TRANSFORMERS 40.0
SECONDARY WIRE 29.1
SERVICES 20.0
MISC. EQUIPMENT 0.0
REMOVE POLE (HWY) 607.7
REMOVE POLE (RP) 52.5
0.0
0.0
TOTAL:
9E - 991
PAGE 2 OF 3
SUBTOTAL
$36.1
$9.5
$750.7
$796.3
--
.
.
MAY, 1992 PSC STUDY
DETAILED ANALYSIS OF
COST TO UNDERGROUND
($ X (00)
CIRCUIT SUMMARY SHEET
SUBSTATION:
BUELL
CIRCUIT:
9E - 991
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $9,445.9
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
$796.3
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
... ........
($31.7)
TOTAL COST:
$10,210.5
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 75,000 CONDUCTOR FEET OF WIRE AND 4,800 KNA
OF DISTRIBUTION TRANSFORMER CAPACITY.
PAGE 3 OF 3
REV. 06/30/92
--
. ,
.
SUBSTATION:
BUELL
MAY, 1992 PSC STUDY
DEfAll..ED ANALYSIS OF
COST TO UNDERGROUND
($ X (00)
FACILITIES TO BE INSTALLED:
1.3 PHASE U.G. MAIN
PRIMARY CABLE
SECTIONALlZING UNITS
CAPACITORS
MISC. EQUIPMENT
CIRCUIT:
COST TO INSTALL
13,288.4
1,011.8
96.5
0.0
0.0
0.0
0.0
2. 3 PHASE SUPPLIES (LOOPED & RADIAL)
PRI MARY CABLE 899.1
SECTIONALlZING UNITS 566.3
TRANSFORMERS 160.6
SERVICES 479.5
MISC. EQUIPMENT 0.0
0.0
0.0
0.0
0.0
3. 1 PHASE SUPPLIES (LOOPED & RADIAL)
PRIMARY CABLE
TRANSFORMERS
SECONDARY CABLE
SERVICES
MISC. EQUIPMENT
LB CT A
-
20,200.8
2,388.5
6,468.9
1,760.2
0.0
85.1
0.0
0.0
0.0
TOTAL:
9E - 992
SUBTOTAL
$14,396.70
S2,105.G
$30,903.5
$47,405.'/
PAGE 1 OF 3
REV. 06/30/92
,.
,
. ,
.
MAY, 1992 PSC STUDY
DET All..ED ANALYSIS OF
COST TO UNDERGROUND
(S X 000)
SUBSTATION:
BUELL
FACILITIES TO BE REMOVED:
1. OVERHEAD PRIMARY CONDUCTORS
3 PHASE
2 PHASE
1 PHASE
2. 3 PHASE EQUIPMENT
SWITCHES
CAPACITORS
3 PHASE TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
3. BRANCH LINE EQUIPMENT
FUSED CUTOUTS
TRANSFORMERS
SECONDARY WIRE
SERVICES
MISC. EQUIPMENT
REMOVE POLE (HWY)
REMOVE POLE (RP)
CIRCUIT:
COST TO REMOVE
93.2
7.6
148.4
12.2
4.0
7.7
20.6
0.8
0.0
0.0
0.0
0.0
0.0
7.0
208.1
143.1
104.1
0.0
2,993.4
258.7
0.0
0.0
TOTAL:
III U
9E - 992
SUBTOTAL
$249.2
$~t~.~'~
"'3 -,'<(. (.
~l..1 I..,
$4,ooe.p
PAGE 2 OF 3
...,
.
MAY, 1992 PSC STUDY
DET AlLED ANALYSIS OF
COST TO UNDERGROUND
($ X 000)
CIRCUIT SUMMARY SHEET
;UBSTATION:
BUELL
CIRCUIT:
9E - 992
1. COST TO INSTALL NEW UNDERGROUND
DISTRIBUTION SYSTEM
. . . . . . .. $47,405.7
2. COST TO REMOVE EXISTING OVERHEAD
DISTRIBUTION SYSTEM
. . . . . . " $4,008.9
3. SALVAGE VALUE
OVERHEAD CONDUCTORS
... .........
($156.1)
TOTAL COST:
$51,258.5
THIS IS THE ESTIMATED TOTAL COST TO INSTALL AN UNDERGROUND
DISTRIBUTION SYSTEM THAT WOULD BE REQUIRED TO REPLACE AN
EXISTING OVERHEAD DISTRIBUTION SYSTEM COMPRISED OF
APPROXIMATELY 370,000 CONDUCTOR FEET OF WIRE AND 24,900KVA
OF DISTRIBUTION TRANSFORMER CAPACITY.
-
PAGE 3 OF 3
REV. 06/30/92