HomeMy WebLinkAboutA Review of Electric Utility Undergrounding Policies and Practices by Resource Mgmt International Jun-99UPA
Long Island Power Authority
333 Earle Ovington Boulevard
Suite 403
Uniondale, NY 11553
(516) 222-7700 Fax (516) 222-9137
http://www, lipa.state.nyus
July 16,1999
Honorable Jean W. Cochran
Supervisor, Town of Southold
Town Hall, P.O. Box 1179
Southold, NY 11971oc~ ~[~
Dear Supervisor C__an: ~
The subject of undergrounding existing electric facilities has been a topic of discussion
throughout Long Island for many years.
Many communities have expressed interest in undergrounding facilities in downtown
business districts while others have explored the possibility of burying lines where aesthetic,
safety, or reliability concerns exist.
In certain, specific areas LIPA has agreed to underground lines where clear issues of
safety and reliability are paramount.
LIPA recently commissioned the attached study, "A Review of Electric Utility
Undergrounding Policies & Practices", by our engineering consultants, RMI.
I thought you might like a copy of the study so that you and others in your community
who are interested in the subject can understand the issues we confront at LIPA when
considering undergrounding requests.
If you have any questions, please don't hesitate to call me directly.
Chairman
Long Island Power Authority
Attachment
2 6 1999
SUPERVISORS OFFICE
TOWN OF SOUTHOLD
A REVIEW OF
ELECTRIC UTILITY
UNDERGROUNDING POLICIES
AND PRACTICES
RMI
RESOURCE MANAGEMENT
INTERNATIONAL~ INC.
A REVIEW OF
ELECTRIC UTILITY
UNDERGROUNDING POLICIES AND
PRACTICES
Prepared For
LONG ISLAND POWER AUTHORITY
Prepared By
RM!
RESOURCE MANAGEMENT
INTERNATIONAL, INC.
JUNE 1999
TABLE OF CONTENTS
A REVIEW OF ELECTRIC UTILITY
UNDERGROUNDING POLICIES & PRACTICES
Section Page
EXECUTIVE SUMMARY ............................................ ' ................................................................ ES-1
1. INTRODUCTION ..................................................................................................................... 1-1
OVERVIEW ............................................................................................................................ 2-1
REGULATORY HISTORY ................................................................................................... 2-1
CURRENT LIPA PRACTICES ........................................................................................... 2-7
INDUSTRY PRACTICE ........................................................................................................... 3-1
OVERVIEW ............................................................................................................................ 3-1
BRIEF ACCOUNn~ OF EXPERIENCES OF OTHER UTILITIES ................................ 3-11
4. RELIABILITY IMPACTS ......................................................................................................... 4-1
OVERVIEW ............................................................................................................................ 4-1
SAFETY ISSUES ........................................................................................................................ 5-1
OVERVIEW ............................................................................................................................ 5-1
ELECTRICAL CONTACTS ................................................................................................. 5-1
POLE HITS ............................................................................................................................. 5-4
6. ECONOMIC ISSUES ................................................................................................................ 6-1
OVERVIEW ............................................................................................................................
COST TO CONVERT T&D SYSTEM TO UNDERGROUND .........................................
COSTS TO CUSTOMERS IF CONVERTING TO UNDERGROUND ...........................
COORDINATION WITH PUBLIC wORKS PROJECTS .................................................
ANNUAL O&M EXPENSES ...............................................................................................
LOST REVENUE DUE TO OUTAGES ...............................................................................
5-1
5-1
5-5
5-6
5-9
5-9
7. FINDINGS ................................................................................................................................. 7-1
APPENDIX A - LIPA SERVICE AGREEMENT TARIFFS ....................................................... A-1
APPENDIX B - REFERENCES ..................................................................................................... B-1
EXECUTIVE SUMMARY
In December 1998, Resource Management International, Inc., (RMI) issued a report entitled
"Assessment of Transmission & Distribution Construction Practices and Their Impact on
Public Safety" ("Construction Practices Report") to the Long Island Power Authority
(LIPA). This report reviewed trends in electrical contact cases on Long Island since 1970
and identified and discusse? various alternative construction practices available to LIPA.
These construction practices were compared and contrasted in categories, which included
construction costs, environmental impacts, reliability impacts, and their effectiveness in
reducing injuries due to contact.
The findings outlined in the Construction Practices Report were presented to the LIPA
Board of Trustees at the Board's December 1998 meeting. As a result of this presentation,
the Board requested additional information related to the advantages and disadvantages
surrounding the undergrounding of the transmission and distribution (T&D) system.
The following report provides the LIPA Board with additional in.formation regarding the
costs and benefits associated with underground versus overhead construction of the Long
Island T&D System.
Several utilities, communities, and governmental agencies were contacted or researched for
this report. Each entity addressed the issue of whether or not to underground transmission
and distribution facilities from a different perspective. However, in general the focus of
the evaluations centered on all or a combination of system reliability, public safety,
aesthetics and economics. The following summarizes the key information provided in this
report.
Numerous studies have been performed on the state level within New York, by the
individual utilities, and by outside consultants. In each case, the findings have
consIstently found that even though there are benefits inherent to an underground
electrical system, t_he costs associated with constructing and operating such a system far
outweigh these benefits.
Local community concerns with aesthetics were often the primary driver behind
decisions to underground new or existing T&D facilities. However in each case, the
local community was also willing to fund the construction through increased rates.
Examples referenced In the report include; Fort Collins, Colorado; Westerville, Ohio;
Maple Grove, Minnesota; and Richmond, Indiana.
Table ES-! lists the general pros and cons noted by the various entities researched for
this report as they Investigated the issue of overhead versus underground construction.
ES-1
EXECUTIVE SUMMARY
Table ES-1
Comparison of Overhead versus Underground Construction
Pros to Underground Construction Cons to Underground Construction
Less susceptible to storm conditions and in Significantly higher cost.
general a reduction in interruption frequency.
Improved aesthetics. Installation is more difficult and
disruptive to the environment.
Reduction in tree trimming costs. Faults are more difficult to locate, costlier
to repair and result in longer interruption
durations.
Reduction in costs associated with storm Conductor has a shorter life expectancy
damage. (30-40 years for underground compared
to 50-60 years for overhead)
Less exposure of conductors to general public.
Increased need for easements on private
property for padmount transformers and
switchgear.
Improvement in power quality (fewer Susceptible to dig-ins, foreign
momentary outages), contaminants such as salt water etc.
Less environmental impact after construction. Greater inconvenience to customers when
repairing faults due to extended
restoration time.
Undergrounding T&D facilities will not eliminate outages due to weather. An
improvement in reliability would be expected as outages from trees and vehicular
accidents will be minimized. However, based on the experiences of both Long Island
and Florida, outages will still occur on underground systems due to moisture seeping
into the lines. Hurricanes can still cause outages as salt-water intrusion into the
conductors occurs. Salt-water intrusior~s ca~ severely reduce a conductor's life
expectancy.
ES-2
EXECUTIVE SUMMARY
Outage durations will be longer on an underground system. This is due to the time
necessary to locate a fault on an underground line. Normally, a fault on an overhead
line is easily identified by visual inspection. However, an underground fault cannot be
readily seen unless the failure was catastrophic in nature. Normally, an underground
failure requires special equipment and trained workmen to locate and the use of
excavation equipment in order to expose and repair the damage.
Undergrounding T&D facilities will not necessarily result in fewer accidental contacts.
Based on LIPA's history, the contact rate for the underground system is 33% higher
than for the overhead system over the last seven years. This trend is not unique to
Long Island as it has been found in other states as well.
An underground system would significantly reduce the number of vehicular accidents
with the T&D system. However, removing poles as hazards will only eliminate a small
percentage of roadside vehicular accidents. In fact, the vast majority of these roadside
accidents actually occur when vehicles collide with trees, not utility poles. In 1996 as
an example, based on the Roadside Hazards Report issued by the Insurance Institute
for Highway Safety, out of a total of 1 million accidents with fixed objects, only 20
percent involved a vehicle hitting a pole or a post. Of the total accidents, less than one
percent resulted in a fatality. In addition, in the majority of roadside vehicular
accidents, there are extenuating circumstances that a utility company cannot protect
itself from such as the fitness or competence of the driver.
Experience shows that even if only individual areas are targeted for conversion, the
costs for these smaller areas are not minor. Selectively undergrotmding one area and
not another, for the sake of safety, reliability, or even aesthetics, would likely raise
concerns from the customers that are subsidizing the cost but not receiving the benefit.
For this reason the current LIPA tariff allows undergrounding as an option to a
customer or a local community, but it is at that customer's or community's expense.
In addition to the costs to the utility to underground facilities, there is also the cost to
the customer directly associated with the conversion. These costs have been estimated
consistently at $200 to $1000 per residential customer and significantly higher for
commercial customers. These costs are only for the electric service conversion and do
not reflect any additional costs for underground~g the cable or telephone service.
Plus, there are the indirect costs the customers and con'u~urdties would incur due to the
congestion associated with the construction and the repairs on roads and yards that
would take time and money to bring back to current conditions.
ES-3
EXECUTIVE SUMMARY
LIPA could "piggy-back" on public works projects to convert a portion of the existing
overhead system. However, a review of past projects indicates that while this is a good
idea in theory, it does not work often in practical application. Most public works
projects are small in nature and would only affect a few poles. In addition, the trenches
opened for most public works projects would not readily work for undergrounding the
typical overhead facilities - transmission, distribution, phone, and cable television -
necessitating additional trenching, thus resulting in minimal savings.
Currently, LIPA incurs the costs associated with the relocation of their T&D facilities,
when such facilities cause interference with Public Works Improvements. If electric
lines are installed underground, they will be more susceptible to interference with
future Public Works Improvements. The need to relocate underground facilities will
likely add significantly to the cost of future relocations.
There will be a need to site distribution facilities (i.e. padmount transformers,
switchgear) on private property, which will trigger the need for easements at costs,
which could approach several thousand dollars per installation.
ES-4
SECTION I
INTRODUCTION
In December 1998, Resource Management Intemational, Inc., (RMI) issued a report entitled
"Assessment of Transmission & Distribution Construction Practices and Their Impact on Public
Safety" ("Construction Practices Report") to the Long Island Power Authority (LIPA). This
report reviewed trends in electrical contact cases on Long Island since 1970 and identified and
discussed various alternative construction practices available to LIPA. These construction
practices were compared and contrasted in categories, which included construction costs,
environmental impacts, reliability impacts, and their effectiveness in reducing injuries due to
contact.
The findings outlined in the Construction Practices Report were presented to the LIPA Board of
Trustees at the Board's December 1998 meeting. As a result of this presentation, the Board
requested additional information related to the advantages and disadvantages surrounding the
undergrounding of the transmission and distribution (T&D) system.
Specifically LIPA staff and R_MI were directed to provide addi//onal information in the
following areas:
Provide more industry-wide detailed information on the costs and benefits associated with
underground versus overhead construction of a T&D System. Focus attention on the
differences in reliability impacts, safety impacts, construction costs, revenue losses due to
outages, customer property impacts, impacts to other util/ties, and environmental impacts;
Identify the improvement potential in reliability and the restoration costs for underground
versus overhead construction;
Review the proposed T&D System construction budget and provide guidance on how
undergrounding could be incorporated into future budgets;
Identify the advantages and disadvantages associated with joint efforts to underground
overhead utility facilities in cormection with Public Works Improvement projects such as
new roads or road-widenings; and
Identify the Public Safety Implications for overhead versus underground construction.
Based on RMI's research into the underground issue, four primary factors emerge as the drivers
behind utility and regulators efforts to consider undergrounding either new or existing
overhead electrical lines. These factors are system reliability, aesthetics, public safety and
economics. The following report was prepared with a focus on these factors.
1-1
SECTION 2
NEW YORK STATE EXPERIENCE
This section briefly discusses the history of undergrounding of T&D facffities in New York
State, and the pertinent regulations within the State that governs when a utility must
construct new lines underground. A review of State regulations indicates that there is no
mandate to convert existing overhead facilities to underground.
In addition, this section provides a brief overview of the practices and standards followed
by LIPA with respect to new construction and the conversion of existing T&D facilities as
underground. Currently, LIPA meets all State and local requirements for undergrounding
new facilities. In addition, where undergrounding is not required for new construction,
LIPA offers an approved tariff for customers that would like the utility to construct new
lines underground. A mechanism involving the conversion of existing facilities is not
directly addressed in the current tariff. Individual customers or communities who wish to
explore this option can do so at their expense.
REGULATORY HISTORY
The regulatory interest in the issues associated with the undergrounding of utility facilities
in State of New York began in the late 1960's. Early development of State rules focused on
new construction in residential subdivisions. In addition, there were rules passed
pertaining to transmission facilities as well. In March 1975, Part 102 of the State of New
York Code of Rules and Regulations Title 16 became effective. This law regulates the
construction of transmission facilities at voltages of 65 kV or higher which are not covered
under Article VII (Siting of Major Utility Transmission Facilities) of the New York State
Public Service Laws. Part 102 mandates that a report of any proposed construction be filed
prior to the construction of overhead transmission facilities that are not covered under
Article VII. Both Part 102 and Article VII charge the State's Public Service Commission
with the assessing the need and siting for the proposed transmission facilities. Included in
this assessment is an evaluation of whether or not part or all of the proposed facilities
should be placed underground.
By the 1980s and 1990s, the State regulators became interested in assessing the cost and
benefit of converting.~existing overhead electric lines to underground construction. In
September 1986, the Public Service Commission initiated Case 29389 to investigate the
potential of making changes to the electric line extension regulations (State of New York
Codes Rules and Regulations Title 16- Parts 98-100). This was done to evaluate the impact
2-1
NEW YORK STATE EXPERIENCE
of the associated costs dealing with the installation of overhead and underground electric
lines and the allocation of these costs to the applicants requesting underground service.
Case 29389 was designed to enact rules pertaining to underground electric facilities. As
part of this Case, the New York Public Service Commission considered the issue of
converting the existing facilities. Proposed rules regarding undergrounding lines in
Visually Significant Resources (VSR's) were also added to th.is proceeding. These c.~anges
and proposed regulations became a new Case 92-M-0607.
For the purposes of Case 29389, a VSR was defined as various categories of scenic sites in
the State. Examples of VSRs include the Adirondack Park scenic vistas, scenic roads, State
wild and scenic rivers, areas of exceptional scenic beauty, State nature and historic areas,
State Parks, and other similar places within the State that generally attract tourists.
Case 92£M-0607 was a significant milestone in the evolution of NY State policy with respect
to the undergrounding electric facilities. A number of major r~fllngs were issued as a result
of this Case. The regulations discussed below are currently a part of the LIPA tariff.
C.~s]~ 92-M-0607
Phase I
Phase I of this proceeding focused on the undergrounding of utility facilities in new
residential subdivisions and specified that special consideration be given to
undergrounding new distribution lines in VSR areas. As a result of Phase I of this case,
Opinion No. 93-20 was issued in September 1993. 2'his Opinion lead to the rewriting of
Parts 98, 99 and 100 of the existing regulations. The revised regulations represented a
major change in the regulatory philosophy associated with new T&D construction. The
following is a brief summary of these new rules.
Part 98 - General Provisions Relating to the Extension of Facilities by Electric
Corporation and Municipalities.
This rule lists the obligations, for both the applicant and the utility, associated with
providing electric service. Specifically, it defines the guidelines associated with providing
such service via either underground or overhead. It also details the information each
utility is required to subrrfit in an annual report by May 1" of each year. This annual report
is to provide .detailed information on variou.~ costs and amounts (line lengths) of new
distribution and service lines installed throughout the service area.
The ufility's obligations include furnishing, constructing, operating and maintaining the
electric facilities required to supply service to customers, within certain guidelines such as
2-2
NEW YORK STATE EXPERIENCE
the ability to utilize necessary rights of way and appropriate footage allowances. All
electric applicants are obligated to provide necessary right of way agreements or agree to
pay the utility for costs incurred in obtaining these rights of way and agree to pay for
materials and installation costs that exceed utility, allowances and f-m-nish reasonable
security as to the performance of their agreement, if required.
This section also provides details on the footage allowances granted by the uti~ty for
variou.5 tmderground and overhead scenarios across all classes of customers. It also details
the responsibilities of apphcants who either exceed the allowance or request a different
type of service (i.e., underground) than would normally be supphed. These provisions and
requirements are explained m extensive detail m each utility tariffs.
Part 99 o New Construction of Distribution Lines, Service Lines and Appurtenant
Facilities in certain Visually Significant Resources outside Residential Subdivisions.
Part 99 was put in place to implement a five-year program that affected the construction of
new distribution lines in VSR areas. The basis for this program was to underground new
lines in areas where aesthetics had high importance. This program called for a certain
amount of funding to be set aside each year by every utility. This ftmding was to be used
to augment the cost of installing new facilities in VSR areas. Any ftmding not used would
be carried over to following years. The VSR program outlined in Part 99 was to remain in
place for five years from its effective date in October 1993. A joint New York State Utility
report was to be submitted to the PSC two years after the project's effective start date. This
report was intended to assist the Commission in evaluating the effectiveness of the
program.
This five-year program expired in November 1998. The success associated with this
regulation was minimal. In the two-year report, only one project had been completed
(Niagara Mohawk territory). Considerable time and effort was spent by the utilities
working with the various agencies on determlnfi~g what areas were to be identified as
VSR's and the guidelines that were to be used for new underground construction. LILCo
spent approximately $62,000 dollars working with the Depax'taxent of Environmental
Conservation to visit potential sites and define clear borders for VSR's. There were four
sites on Long Island that LILCo identified as VSR's. They were the following:
Oak Brush Plain State Preserve In Greenlawn Quadrangle;
David A. Samoff Pine Barrens (Riverhead and Eastport Quadrangles);
Rocky Point Natural Resource Area ( Middle Island Quadrangle); and
Barcelona Neck (Sag Harbor/Greenport Quadrangle).
2-3
NEW YORK STATE EXPERIENCE
Visits to these sites uncovered very limited opportunities for new underground projects
due in part to the remoteness of these particular areas and the criteria developed between
LILCo and the Depa~,,,ent of Environmental Conservation. On Long Island during the
five-year pilot program, no opportunities for new underground construction arose within
the established boundaries of the aforementioned VSR sites. At this tmte the program has
expired and there is no indication that there vail be a renewed effort to mandate similar
programs within statewide regulations.
Part 100 - New Construction of Distribution Lines, Service Lines and Appurtenant
Facilities in Residential Subdivisions
Part 100 requires that all new distribution lines, service lines and appurtenant facilities to
be ufil~Ted fgr permanent electric service for one or more multiple occupancy units (four or
more dwelling units) or residential subdivisions with five or more units be installed
underground for any of the following criteria.
The residential subdivision will require no more than 200 trench feet of facilities per
planned dwelling unit within the subdivision; or
A utility's tariff provides for such underground service without contribution; or
A governmental authority having jurisdiction to do so has required undergrounding;
or
~ An apphcant requests undergrounding.
Criteria were provided in this section by which a utility would not have to underground its
facilities or could petition the Secretary of the Commission for an exception. A utility.
would be allowed to install overhead facilities in a residential subdivision fi:
The developer of the subdivision was not actively involved in construction;
i No goverrunental authority having jurisdiction required underground construction;
and
Certain criteria involving a time lag in sales of lots were not met.
In addition, potential environmental and economic factors could allow either the utility or
an applicant to apply for a special ruling from the. Commission. New underground
construction in residential subdivisions is one of the few areas where consistent
undergrounding of utilities can be found on Long:Island.
2-4
NEW YORK STATE EXPERIENCE
Phase II
Phase II of this proceeding (Case 92-M-0607) addresses the conversion of existing overhead
lines to underground. Previously, there were no existing programs or regulations
governing the conversion of existing overhead electric facilities to umderground.
All activity on these issues, Within these proceedings, were evaluated strictly from an
aesthetic point of view and focused on who would be responsible for funding such a large
project. In this proceeding, several agencies, such as the Depa~Lent of Environmental
Conservation, Scenic Hudson Inc. and Adirondack Park Agency believed the utilities and
thus the customers should be responsible for the costs associated with any large-scale
conversion. In fact, the Department of Environmental Conservation likened it to visual
pollution by which the party responsible for the pollution should be responsible for the
remediation. These agencies had proposed that the electric utilities in the State be
mandated to spend one percent of net revenues on a conversion program. Further, the
DEC wanted to pool all of the utility funds into a central fund and use that money
statewide.
The agencies previously mentioned wanted to concentrate on conversion in VSR areas.
Based on a study done in 1993, Long Island had less than one percent of New York's total
for electric overhead lines in a VSR area. The Staff of the PSC had recommended that the
general ratepayer base pay conversions in VSR areas. In addition, the customers who
directly benefit from the conversion would fund non-VSR areas.
The utilities believed that the taxpayers should be responsible for funding any wide scale
effort to underground electric facilities. They believed it should be viewed and weighed
against comparable road or public improvement projects, where the public through theiz
elected officials could decide where their tax money was most needed.
The utilities also argued that general ratepayer funding would act like a regressive tax
because all residential ratepayers would pay a fixed charge, which was independent of
income level. The utilities believed that the individual customers or municipalities should
fund the conversions if they desired the conversion. A study done by Rochester Gas &
Electric Company in 1993 revealed that 70 percent of residential customers were not
interested in paying higher bills for conversion to underground solely for the sake of
aesthetics.
The remaining 30 percent of the customers indicated that on average they would be willirtg
to pay a 5 percent surcharge. If this study was assumed to be indicative of today's attitude
on Long Island, an estimated $15 million could be raised annually from residential
customers. Although this is a significant amount of money to put towards converting the
2-5
NEW YORK STATE EXPERIENCE
overhead facilities on Long Island, it would fi. md only 1.5 percent of the estimated $19.7
billion cost to convert the entire Island over 30 years. (assuming 4% inflation rate, 7%
return on capital over 30 years).
In August of 1993, after listening to the positions of all parties involved, an administrative
law judge recommended that the issue of mandated conversion was to be closed with no
further action planned. In his decision, the Administrative Law Judge (ALJ) stated that
"...investments for beautification's sake are more properly the province of the Legislature,
and the cost of recover the mandated conversion belongs in taxes rather than utility rates."
Since that time very little activity regarding mandated rules for underground conversion of
utility facilities has been approached in the State of New York.
Despite the ALJ's ruling, the Commission looked to further expand on developing an
underground conversion program. The Commission looked at instituting a five-year pilot
program that would deal with the conversion of existing overhead facilities to
underground. This would have entailed using funding equal to 0.5 percent of each utility's
net annual revenues for this process. The program called for 70 percent of this annual
funding to be used for conversion in VSR areas and the remaining 30 percent to be used for
conversion in non-VSR areas. This proposal was outlined in a report dated November 4,
1993 and prepared by the senior staff of the NYPSC.
Per a March 31, 1994 NYPSC Order the parties were directed to provide additional
information regarding undergrounding electric facilities. In response to the Commission
Order for additional information, National Economics Research Associates ("NERA") was
retained in order to address the cost and benefits associated with varying levels of
converting overhead facilities to underground. Their report was issued in July 1994. This
Report concentrated on a cost-benefit analysis of converting overhead facilities from an
aesthetic and recreational point of view within the State of New York. In this study, N-ERA
concluded that the "conversion of existing Electric Utility overhead distribution lines
would decrease the overall welfare of New York residents.'"
The outcome of the 1994 NERA study demonstrated significant expenditures associated
with a general mass conversion of existing electric facitities, which would ultimately have a
negative impact on the ratepayers of New York.
Since then, there has been no concerted effort mandated by New York State reg~.dations to
actively pursuit general conversion of overhead facilities. Current New York State
' National Economics Research Associates, "Benefits and Costs of Underground Conversion of
Overhead Distribution Lines in New York State", July 1994, p.32
2-6
NEW YORK STATE EXPERIENCE
regulations only require a utLlity to underground electric facilities in new residential
subdivisions that meet certain criteria, if required by a governmental authority having
jurisdiction or by an applicant's request. These options require various levels of
contribution by the applicants. These contribution requirements are fully explained in
LIPA's tariff and are summarized in Appendix A.
CURRENT LIPA PRACTICES
The policies and procedures followed by LIPA today are driven by the currently approved
tariffs. These tariffs provide information to all existing or prospective customers and are
used to assure that each and every customer is treated fairly and consistently. Appendix A
summarizes the LIPA's Tariffs that apply to providing underground electrical services.
As part of the tariff, LIPA addresses various issues surrounding the types of electrical
service that are available to customers and the various responsibilities and costs, for both
LIPA and the customer, that are associated with these options. The LIPA tariff has various
mechanisms in place that allow applicants to determine what kind of electric service they
would prefer (overhead vs. underground) for new construction. Depending on factors
such as governmental jurisdiction, current regulations, type of existing electric distribution
system, environmental impacts, engineering designs and costs will determine to what
extent, ff any, LIPA will contribute to the costs associated with the preferred service
installation. For example a customer (residential or non-residing), whose new service
request is in an existing overhead area and decides they want an underground service
would be given an allowance equal to the cost of an overhead service, within particular
footage constraints. The customer then would be responsible for any additional
incremental costs. As for the customer that is located in a primary feed underground area,
LIPA would bear the full cost of providing the underground service, up to a particular
footage. Any costs above the particular footage would be the responsibility of the
customer.
In addition, there are areas on Long Island where LIPA mandates that new electric service
be installed underground. These areas, such as small commercial business districts and
network areas may be predominantly underground now or may warrant the use of
underground distribution in the future due to potential load density. These areas are
clearly demarcated by the Town in the LIPA Rules and Regulations for Electric
Installations.
2-7
SECTION 3
INDUSTRY PRACTICES
This section provides a broad picture of how other utilities, regulators and communities
across the country have addressed the issue of overhead versus underground construction
of electric lines. One thei..2 that comes through when reviewing utility practices and
procedures, is that if left to their own choice, and allowing economics to drive the decision,
the utility would choose overhead construction instead of underground - regardless of the
size of the utility. This preference is driven by the lower costs to construct overhead
facilities, plus the lower operating and maintenance costs for overhead lines. Finally, since.
it is the utillty's desire to maintain electrical connection to their customers, the utilities
prefer overhead due to the fact that finding a problem during an outage is much quicker for
over head than underground.
Typically, where utilities have moved towards the underground option, external forces
such as customer demand or local and State regulators drove them to it. RMI's review of
large, multi-community electric utilities though not exhaustive, did not find any utility that
had adopted a system-wide undergrounding program. Where we found utilities making a
wholesale conversion was in smaller, municipally-owned systems in which the local City
legislature determined that the utility in that con'maunity would construct all or a portion of
the system underground - typically, for aesthetic reasons.
In addition to the direct costs associated with undergrounding, an electric utility would
need to work with local ordinances to acquire appropriate permits for the work, plns they
would have to coordinate with the other utilities they share poles with. This effort is
difficult and time consuming for a small locally owned utility, but the problems are
significantly compounded when it is required of a large system. Such a system will have to
coordinate with numerous localities and their assodated permitting agencies, the State
permitting agencies, and often times more than one phone and cable television firm. Each
of these difficulties is not insurmountable, but they do add sigrtificantly to the time and cost
necessary to complete a wholesale underground conversion.
The State of Florida
The Florida Public Service Commission, mandated by the Florida legislature, did an
extensive study in 1991 to determine the cost effectiveness of requiring the undergrounding
of electric facilities. They examined the cost effectiveness for four different scenarios:
Underground installation for new construction;
Underground conversion when rephcement or relocation of existing facilities is
required; and
3-1
INDUSTRY PKACTICES
Underground conversion of all existing facilities.
In order to determine the cost effectiveness, criteria such as the costs of accidental
electrocutions, vehicle accidents, disabling injuries, tree trim elimination, storm damage,
insurance and other O&M costs were evaluated. Aesthetics was deemed by the legislature
to be too subjective and was not factored into me cost benefit analysis. If the Commission
determined that underground conversion was cost effective the funding for the program
would come through general rate increases across all customer classes.
Each of the previously mentioned scenarios was also evaluated for five different types of
distribution systems with varying load densities:
Main Line Urban Feeder;
Urban Residential Feeder;
Rural Residential Feeder;
Residential Subdivision; and
High Density Residential Subdivision.
Life cycle cost analysis was used to determine the cost effectiveness of undergrounding vs.
overhead. The total costs consisted of direct costs or revenue requirements plus external
costs such as storms, accidents etc. These costs were then converted to a net present value
for comparison. The investor owned utilities that provided many of the details assodated
with this study had an average of 625,000 customers while the munidpallties that provided
information had an average of 150,000 customers.
The following graph shows the results for an Investor Owned Utility Base Case. For this
graph, a 30-year life cycle for both underground and overhead, a 4 percent inflation rate
and an 8.45 percent discount rate were assumed. The following graph shows the difference
in Costs (i.e., in net present value - NPV) between an overhead and underground system
for the various scenarios studied. A positive NPV indicates that the underground cost is
higher than overhead cost and consequently not cost effective.
For most areas of Long Island, the Residential Subdivision and the Urban Residential
Scenario are comparable and are representative of the distribution system configuration
found on Long Island. The Urban Residential Scenario would be more representative of
areas with small stores and homes currently found in local towns while the Residential
Subdivisions are more representative of the residential developments.
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INDUSTRY PRACTICES
Net Present Value-Base Case-IOUs
$800
$6oo-
$400-
$~00-
$0
Main Line Urban Rural Residential Residential
Urban Residential Residential Sub Sub HD
[] New Construction · Relocation [] Replacement [] Con~rsion i
J
· Note underground relocation costs were not included in the 2 residential subdivision scev. arios
As depicted in the above graphs, while new construction was the most cost effective of the
underground scenarios, in no scenario was undergrounding a cost-effective alternative to
overhead construction. Based on these results, the Florida PSC was unable to conclude that
any of the underground conversion scenarios examined were cost effective.
MINNESOTA- NORTHERN STATES POWER
Northern States Power Company ("NSP') is a large investor-owned electric utility
providing service to ratepayers in Minnesota and portions of Wisconsin. They are similar
in size to LIPA with a combined electric plant-in-service totaling approximately $6 billion
and electric revenues of approximately $2 billion per year. They have a combined T&D
annual expense of approximately $130 million. Their customer base co~:sists of roughly 1.2
million total customers with approximately 1 million residential customers. They have an
estimated 29,000 miles of distribution lines Including about 12,000 miles of underground
lines. In addition, they have about 5,000 miles of transmission lines with voltages ranging
from 34.5-kV up to 500-kV.
In reaction to severe storm activity In the spring and summer of 1998, NSP undertook a
study to evaluate the effects of placing electric facilities underground.
A five-year evaluation by NSP from January 1993 to July 1998 reported the following
reliability statistics:
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INDUSTRY PRACTICES
Annual Annual Average Average
Outages Frequency Frequency Duration Duration
With Storms Without With Storms Without Storms
Storms (Hours) (Hours)
UG feeder 0.3 0.3 1.0 1.0
OH main(<4m.iles) 0.9 0.6 0.4 0.2
OH main(> 4 miles) 2.0 1.1 2.1 0.4
UG Tap 0.08 0.07 4.7 3.0
OH Tap 0.19 0.12 8.7 2.4
UG service 0.010 0.006 3.0 2.3
OH service 0.020 0.003 18.5 2.7
A 100 percent overhead system, including storms, would result in an average interruption
frequency of 1.1, while a 100 percent underground system would result in an average
interruption frequency of 0.4. In other words, for every outage an underground fed
customer has, an overhead fed customer has 2.75 outages.
Including storm impacts, a 100 percent overhead system would result in an average outage
duration of 2.4 hours to all customers, while a 100 percent underground system would
result in an average outage duration of 0.7 hours. The outage duration predicted for the
underground system is 3.5 times more reliable when major storms are counted.
Based on these statistics, the average 100 percent underground system experiences
approximately 1.7 hours less interruption time than a 100 percent overhead system.
Assuming a usage of 650 kWh/month and using NSP's residential rate of 7.5 cents per
kilowatt-hour, 11.25 cents per customer would be gained for a I00 percent underground
system. For a conversion of one million customers, this savings per customer would
represent an estimated increase in annual revenue of $112,000.
Excluding storms, a 100 percent overhead system, would result in an average interruption
frequency of 0.7 outages, while a 100 percent underground system would result in an
average interruption frequency of 0.4. This demonstrates that there is minimal to no impact
to underground systems during storms, while there was a 36 percent improvement in the
interruption frequency on the overhead system when storms were discounted.
In general, for every outage experienced by umderground customer, an overhead customer-
experiences 1.75 outages. A 100 percent overhead system would result in an average outage
duration of 0.4 hours, while a 100 percent underground system would result in an average
outage duration of 0.5 hours. If major storms were discounted, an average underground
customer would experience six additional minutes of outage a year. The underground
3-4
INDUSTRY PKACTICES
system is 1.25 th-nes less reliable than the overhead system in regards to outage duration.
NSP found that the number one cause of customer interruptions on their system is line
damage due to wind and trees. Their second highest cause of customer interruptions is
failed underground lines.
Finally, NSP's study indicated the total cost for converting the metropolitan area of
Minneapolis would be approximately $3 billion and result in only a marginal reliability
improvement. This margin,~i improvement itl reliability would require an increase in rates
of over 50 percent for conversion of the entire metropolitan area. In addition, individual
customers would have to make necessary changes to their electrical equipment at an
estimated additional cost of $500 million. NSP concluded that the mass conversion of
overhead facilities was not a cost-effective use of ratepayer funds.
After evaluating alternatives to undergrounding, NSP decided it would be more cost
effective to increase their 1999 tree trim budget by $3 million and revise their current tree
trimming practices in order to improve the reliability of their overhead system, especially
during storms.
In conclusion, NSP stated the following:
While outage frequency and duration are negatively impacted by storms for overhead
systems, customers on average experience less than one inten-uption per year;
During non-storm conditions, which in Mirmesota on average is 350+ days per year,
underground systems experience fewer interruptions but longer durations once an
outage occurs;
Without customer contributions, the rates would increase by over 50 percent; and
Based on the reliability and cost analysis, NSP did not feel a comprehensive conversion
plan would be a cost-effective use of ratepayer funds.
Their current policy allows customers to convert to underground service provided they pay
the added costs of installing and providing t. his service. In addition, all underground
supplied residential customers pay a $2 per month surcharge to offset the higher ongoing
costs of providing underground service.
OI~FrAI~.IO I'IY'I)RO
Ontario Hydro is one of the largest electric utilities in North America. It directly serves
over ! million customers in Canada and indirectly serves another 3 r~illion customers
through 305 municipal ufflities. Ontario Hydro has approxL~nately $50 billion (Canadian $)
3-5
INDUSTRY PRACTICES
in assets of which about $11 billion (Canadian $) are T&D facilities. The utility's revenue is
approximately $9 billion (Canadian $). Throughout the service territory, Ontario Hydro
operates about 68,000 miles of distribution lines and 20,000 miles of transmission circuits.
For a period of five days in January 1998, Eastern Ontario residents bore the brunt of a
disastrous ice storm (100 year storm) that left 'nore than 600,000 people out of a population
of 1.2 million without power, some for as long as 19 days. Over 10,500 poles, 1,700 miles of
wire and 1,800 transformers had to be replaced as result or this storm. As a result of this
event, Ontario Hydro had to answer questions about the effect an underground system
would have had if it had been in place in enhancing reliability. They estimate the cost at
nearly $6 billion to underground their distribution system and another $5 bilhon to
underground their transmission system. Meanwhile, the cost associated with repairing
storm damage on the distribution system was $83 million and on the transmission system
$35 million. The net revenue loss to Ontario Hydro was $1.1 million, after subtracting the
reduction in production and distribution costs.
The total cost to Ontario Hydro is in the order of $140 to $150 million. The repair costs
associated with this devastating "100-year storm" represent approximately 1.5 percent of
the total cost to underground the entire T&D system. As a general rule of thumb, they state
that it costs 10 percent a year in interest, depreciation and O&M costs to finance capital
expenditures or each billion of new capital investment generates $100 million of annual
costs. The impact on all Hydro customers to underground eastern Ontario would represent
a rate increase of over 11 percent. Ontario Hydro believes that the high costs associated
with this project in response to this rare weather event are not justified.
CITY OF MAPLE GROVE, MINNESOTA
The City of Maple Grove, Minnesota is a bedroom community of the Minneapolis-St. Paul
metropolitan area. It has a population of approximately 50,000' residents. NSP is the
p ,rSmary electric service provider to the residents and businesses of Maple Grove.
In some situations, a local utility has no choice but to construct their facilities underground
as the overhead option has been removed by the local munidpality. The City of Maple
Grove is such a community. The City took this step in the belief that underground facilities
were more reliable and fit into the aesthetics of their community.
According to the City's Ordinance No. 305, "all existing overhead distribution lines fifteen
thousand volts or more will be eliminated as soon as possible, and that distrib/ation lines
and systems used in the supplying of electricity as well as communication of similar
association services be placed, constructed and installed underground. This ordinance goes
on to identify electric, communications, street lighting, and cable television lines as covered
by this law. The City requires the utilities to u~ili~e public works jobs for undergrounding
3-6
INDUSTRY PRACTICES
unless the City Engineer determines it to not be technically or economically feasible. No
provision within this Ordinance provides for compensation to the utilities by the City for
expenditures to meet the demands of the Ordinance.
CITY OF FORT COLLINS, COLORADO
The City of Fort Collins, Colorado is served by the municipally owned electric util/ty and
has approximately 46,000 customers and a City population of about 100,000 people. The
utility serves an area approximately 44 square miles. The utiLity has approximately 240
miles of distribution lines and 6 miles of ll5-kV transmission lines. The utiLity's sales are
currently about 1,000,000 MWh. Their current residential rate is $31.09 for a typical usage
of 500 kWh or 6.2 cents/kWh.
Though most utilities contacted for this report used the cost of undergrounding as the key
factor in deciding not to pursue such a strategy, there are utilities where underground
facilities are the norm and not the exception. The City of Fort Collins Colorado is one such
utility. In 1968, the City Council passed an ordinance, stating that all new construction of
utilities had to be placed underground.
Further, the City began the conversion of existing utilities to underground in 1986. The
City CotmcLl approved the use of funds that were in the utility's surplus of reserves. The
initial program began with a $500,000 annual funding level, which in 1989 grew to $1
million per year or 2 percent of the utiLity's total budget. This program is scheduled to last
for 15 }'ears. The major factors driving this decision were reliability, aesthetics and safety.
In a four-year study the utiLity conducted in the late 1980% they concluded that reliability
on the underground system was on average 6.8 times more reliable than overhead when
storms were included and that the underground was 2.5 times more reliable than overhead
when storms were excluded. Excluding storms, the average outage time per overhead
customer per year was 39 minutes. This number increased to 108 minutes when storm data
was included. The average underground customer experienced an outage of 16 minutes
per year indudIng stomas.
Therefore, reliability was one of the issues Fort Collins examined when considering the
conversion of their city's facilities to underground. Their 1988 reliability was 99.986
percent. This index measures the ratio of customer hours service was available to the total
customer service hours possible. From strictly a reliability standpoint, Fort Collins had a
difficult time justifying underground conversion. They pointed to the fact that nearly
three-fourths of their customers outage time was during storm events. They used this
storm reliability statistic as one of the factors in going forward with their evaluation of an
underground conversion program.
3-7
INDUSTRY PRACTICES
Cost of conversion was also a significant factor in the utility's consideration of
undergrounding their system. Their cost study indicated that it would cost 2 times more
for underground conversion compared to building new overhead lines and maintaining
them. This study indicated that it would take $16.5 million to convert all remaining
overhead lines to underground and $8.2 million to rebuild and maintain the overhead
system.
When the utility started the conversion program in 1986 program, 68 percent of their
facilities were already underground due to the ordinance passed in 1968 for new
construction. At the end of 1997, a total of 3,700 of the 7,300 overhead services had been
converted at an average cost of $2,868 per service. The completion goal for 100 percent
underground is the year 2004. According to the utility, the customers of Fort Collins
benefit from the increased reliability and an added aesthetic value to their city.
Since the conversion was funded through the utillty's internally generated cash reserves
from operations, the utility touts the fact that it has not incurred a rate increase as a direct
result of this conversion program. However, at current sales levels, the $! million per year
for the conversion program reflects spending of about 1 to 2 percent of the utility's annual
revenues that could have been used to offset rate increases over the years that were
necessary to fund other programs.
In 1998 the Cape Cod Commission investigated the value of converting the existing
overhead T&D facilities on Cape Cod and Martha's Vineyard to underground. Their
interests focused largely on increased reliability, improvement of aesthetics and safety. In
order to underground the over 2,900 miles of electric lines in this area, Commonwealth
Electric Company (ComElectric) has estimated that it would cost over $2.2 billion or an
average cost of $750,000 per mile for cable installed in conduit and $1.7 billion or $580,000
per _.a~)i!' e for direct burial. They estimated that it would take 20 years to accomplish the
undergrourtding. Ctu-rently, CornElectric spends $4 million a year to maintain wires on
Cape Cod. They also spend $1.2 million annually in tree trimming. To date, 20 percent of
Cape Cod and Martha's Vineyard's distribution lines are installed underground. Most of
this work has been done over the past 30 years in new residential developments.
Developers have picked up most of the cost in this area.
Recognizing the high costs of underground, the Commission is currently identifying
projects and the sources for ftmding these projects. As part of Cape Cod's study, the utility
compared their system to that of the systems in other countries that had been aggressively
moving towards underground systems. Pointing to a benefit of undergrounding, the
average ComElectric customer undergoes an average of 3 hours of outage a year, while the
3-8
INDUSTRY PP,~CTIC ES
average customer in the European country of Holland, where over 95 percent of their lines
are buried, experiences an average of 19 minutes of outage. By contrast, in 1998 the average
LIPA customer experienced an average of less than one hour, excluding major storms. ALso,
the utilities in Denmark have seen interruptions cut in half due to undergrounding.
Under existing Massachusetts State Law Chapter 166, a two-percent surcharge could be
utilized to fund this program. This rarely invoked (i.e., only two instances for minor
conversions) 30-year-old la.. provides a mechanism, which allows communities to fund
undergrounding utilities. The down side is that it forces communities to wait until enough
funds have accrued to pay for the project. It does not allow bonding, which would allow
the improvements to be constructed and the costs amortized over a period of time.
Through the use of Chapter 166 in its present state approximately $3.7 million per year
could be raised, which would cause the conversion program to take 540 years to complete.
Two bills are presently pending before the state legislature. One involves planning and
funding of projects associated with highway projects and the other deaLs with establishing
a mechanism where local communities could use municipal bonding for payment of
underground conversion.
The first bill (Senate #1692, Senate Docket #524) is designed to incorporate into highway
planning procedures an assessment of burying the utility lines in conjunction with the
project. Not only does it call for the conversion of the utility's facilities to be considered in
the planning and design of the project, it aLso proposes a formula for funding. This
proposed bill calls for a 25 percent contribution from state authorized funds with the
remaining costs to be borne by the utilities and local town or municipality.
The second bill (Senate $$949, Senate Docket #525) would amend a current law and allow
municipal bonding for projects that involve underground conversion of utility's facilities.
]~/CHMOND,
Richmond, Indiana is on the eastern edge of Indiana located along the Interstate 70. The
population of Richmond is approximately 40,000 people. The utility serving the City is
municipally owned with about 22,000 customers. The utility has an electric-plant-in-service
of approximately $100 million of which about $70 million is T&D. The utility has annual
revenues of about $50 million. It has T&D expenses each year in the neighborhood of $10
million. The utility has about 350 miles of distribution lines, of which about 70 miles are
underground - primarily along major corridors and in residential areas. They aLso have
about 40 miles of overhead 69-kV transmission lines.
In 1990, the State of Indiana began the widening of U.S. Highway 40, known in Richmond,
Indiana as East Main Street, from two lanes to five lanes. Prior to this project, the
municipal utility and Ameritech had used traditional line construction along this route,
3-9
INDUSTRY PRACTICES
which consisted of overhead construction. However, the new road-widening project was
anticipated to be a show place for the City to kick-off it's city beautification and efforts to
entice new commercial businesses to locate along this corridor. The primary focus of the
City was on the image presented to people driving into the City along this corridor.
Therefore, the aesthetics of the lack of wires drove the underground decision for the City.
The municipal utility, directed by the City Council, designed a new distribution system
along this modernized corridor that included new underground facilities. An effort was
made to coordinate with Ameritech and TCI, the local CATV provider, to u~liTe joint
trenches wherever possible. Due to the additional costs, these other utilities were not as
motivated as the local municipal was to move their facilities underground.
The new underground system consisted primarily of conduits for future expansion as
opposed to direct burial that would have required new trenches when changes were
required. With fore thought, the utilities also ran radial conduit under the new highway in
strategic locations as a preparation for future load growth. This fore thought reduced the
need to add new roadway cuts after the highway project was completed.
This corridor was a critical route for Ameritech. As a result, there were sections of the
route in which Ameritech lines consisted of numerous trunk lines containing many
conductors. This presented an economic problem for the City and Ameritech in that the
conversion to underground these circuits was cost prohibitive. As a result, there are
sections along this new highway in which Ameritech moved the circuits from the front of
properties lining the highway to the back of these properties. The result was improved
aesthetics while minimizing the total cost of the project.
WESTERVILLE, OHIO
The City of Westerville's electric service provider is its own municipal utility. The City has
a population of about 40,000 people. The utility has about 14,000 electric customers. The
utility's distn~oution system is divided between 140 miles Of overhead lines and 150 miles of
underground lines. In addition, there are about 10 miles of 69-kV transmission lines with
one mile of underground.
In the late 1990s, the City of Westerville, Ohio annexed a section of property that will be
used in 1998 and 1999 to construct a new five-lane road that will provide a major east-west
artery connecting Westerville to other cities to the west. Along this corridor, there are plans
for major commercial growth. In addition, there are plans for new restaurants and hotels
along this new artery.
The City of Westerville made the decision to install all of the utilities in this area as
underground instead of overhead facilities. According to the local manager of the electric
3-10
INDUSTRY PRACTICES
utility, the one overriding reason for going underground was aesthetics. The cost of the
underground construction was considered briefly, however the planned growth in the area,
and the concern over visual impact was more important to the City than the added costs.
The City of Westerville has a h.istory of evaluating underground versus overhead and has
always used aesthetics as the impetus for its decisions to underground. A recent project
included the undergrounding of approximately one-mile of double circuit 69-kV
transmission line. The difference between underground and overhead construction was
approximately $700,000 with the cost of the underground being $1 mill/on. The utility
provided a benefit to the citizens of the community by constructing a two-lane bike path
over the buried circuits. Additional projects such as this one are anticipated in the near
future. A 13-kV circuit is expected to be placed underground later this year with a bike
path built over it.
Safety was cited in a recent project to move a steel 69-kV pole due to its proximity to the
roadway. This move occurred after a local resident came into contact with the pole. The
cost to move the pole was $15,000.
BRIEF ACCOUNTS OF EXPERIENCES OF OTHER UTILITIES
The following is a series of "mini-examples" of the experiences of other utilities, regulators,
and communities with respect to the quest/on of underground versus overhead
COnstruction:
In Anaheim California, a 40-year underground conversion program estimated to cost
$500 million began in 1992. In order to accomplish this task, a 4 percent surcharge is
paid by electric customers. The other affected utilities are paying the cost for burying
their lines.
California Public Utilities Commission has a mandate known as Rule 20A, which
provides the funding for the undergrounding of electric distribution facilities. The
governing body of the city or county where the work is to be done determines which
area is to be converted. Pacific Gas & Electric is o.u-rently converting facilities
(completion in March 1999), which involved approximately 2 miles of trenching at a
cost of $1.6 million.
The Georgia Transmission Corporation (GTC) is planning to build an overhead three-
mile ll5-kV transmission line along the Cherokee-Fulton county border. The utility
estimates it costs at about $1 million per mile to install transmission facgities in the
metropolitan area and $600,000 per mile in ru.ral areas. Undergrounding these Lines
results in an increased cost over overhead facilities in a range from 300 to 1000 percent.
Maintenance costs are higher for the underground facilities as well as an increase in
3-11
INDUSTRY PRACTICES
time to locate and repair damaged facilities, which could have a severe impact on
reliability.
NSP and Dairyland Power Cooperative are planning to construct a 38 mile 230-kV
overhead transmission line ("The Chisago Project") in order to meet the energy
demands in Northern Wisconsin. The project is estimated to cost $46 million. The cost
associated with undergrounding a portion near scenic St. Croix Valley for aesthetic
reasons would add $4 to $15 million (10 to 30 percent of the total project) to the project
costs.
During a road widening project in Oregon in 1997 by the Oregon DOT, Salem Electric
incurred costs of $400,000 to move the utility poles and associated wires. The estimated
cost to place the lines underground during this road widening project would be over 6
times that or approximately $2.5 million. Other projects are planned for
undergrounding the electric facilities, at cost, to the City of Keizer. In respect to
undergrounding, they report that the incidence of acddental dig-ins is higher than
accidents due to cars hitting poles.
In order to satisfy community opposition to a planned ll5-kV transmission line in
Clark County Washington, Clark Public Utilities designed an alternate plan, which was
more aesthetically pleasing. This involved placing 1.06 miles of the circuit
underground. This would cost an additional $1.5 million on that segment compared to
an original estimate of $200,000 for an overhead circuit or approximately 7.5 times
greater.
In order to meet growing demands, Arizona Public Service will be installing new lines
and substations. They estimate the cost to place the lines underground at
approximately $1 willlon per mile. To pay for this added cost compared to overhead
construction, a state law allows the residents the option of forming a utility
improvement district, which in effect allows them to tax themselves and pay for the
difference between overhead and underground costs.
A joint study between Western Area Power Administration and Platte River Power
Authority evaluated the alternative of underground construction for the upgrade of a
69-kV line to 15-kV in Estes Park Colorado. Disadvantages such as the initial cost (5 to
10 times per mile more than overhead construction), expense required to locate and
repair faults, and associated expected service life (25-30 years for underground versus
40-50 years for overhead).
Orcas Power and Light Cooperative, a San Juan coop that serves 10,000 customers
across 20 islands started a conversion program 9 years ago. Their actions were largely
in response to numerous customer interruptions as a result of storms and high winds.
3-12
INDUSTRY PRACTICES
A recent storm caused more than 200,000 customers in surrounding regions, while only
causing 200 customers to lose power in their operating area. The project is 80 percent
complete with 330 miles of lines being converted so far at a total cost of $2.5 million. In
order to fund this project, a surcharge of ~A of a cent per kWh for five years has been
implemented.
In Palo Alto, a program to improve the aesthet/cs of a residential area by eliminating
approximately 70 poles and associated attachments. This project will affect the service
of 192 homes at a total cost of $2.8 m/Ilion. In addition to the conversion costs, each
homeowner has ro pay to convert their own electrical equipment, at a cost of
approximately $ 2,500. In order to pay for this, customers have the option of borrowing
funds from the city and repaying it, with interest, over a 10-year period. This
residential area is the 38~' section of the city to be placed underground since 1965. The
city chooses the areas to be converted and the local phone and Cable Company must
agree to the project in order for work to begin.
In 1988 an agreement was reached between Paradise Valley, Arizona and Arizona
Public Service Co. to convert over 55 miles of electric lines underground. This contract
hold APS responsible for 45 percent of the $22 million cost and the community
responsible for the remaining 55 percent. The project is broken into 36 conversion
districts. For a conversion district to be accepted under the contract, 50 percent of the
non-hillside homeowners and 75 percent of hillside homeowners must agree to pay. As
of October 1998, 33 of the 36 conversion districts agreed to the project.
Entergy Corporation provides electricity to the residents of Arkansas, Louisiana, Texas,
and Mississippi. Entergy was recently hits with severe storms that caused the utility
and State regulators to consider the need for converting the overhead lines in these
states to underground. However, siting the cost to convert and the significantly slower
restoration times during outages, the utility successfully argued against conversion.
DIFFICULTY IN ENCOURAGING THE OTHER NON-ELECTRIC UTILITIES TO CONVERT TO
UNDERGROUND
As previously mentioned, LIPA is not the sole owner and user of utility poles on Long
Island. If LIPA decided to convert overhead electric facilities to underground, a
mechanism would be required to mandate other utilities (phone and CATV) to also convert
their facilities to underground. This mechanism would probably require some form of
mandatory legislation that would require them to do so. If the phone and cable companies
were not required to convert to underground construction, the aesthetic and safety benefits
would not be fully rgalized. In order for a conversion program of this magnitude to work,
it would be economically prudent and create fewer inconveniences to the general public ff
3-13
INDUSTRY PRACTICES
all utility facilities were converted to underground at the same time. This would require
setting up a planning mechanism where all affected utilities could address their issues and
concerns.
3-14
SECTION 4
RELIABILITY IMPACTS
OVERVIEW
In general, an electric system's reliability will improve when the lines are buried
underground instead of run overhead from poles and towers. LIPA's experience In 1998
found that approximately 130,000 customer outages occurred due to tree related outages.
Another 78,900 customer outages occurred due to accidents on the system that may have
been avoided if the system had been underground.
The conversion to underground should not be considered a panacea. Undergrounding the
facilities will not result In the elimination of outages due to weather. An improvement In
reliability can be expected as outages from trees and vehicular accidents will be virtually
eliminated. However, as found from the experiences of both Long Island and Florida,
outages will still occur on underground systems due to moisture seeping into the lines.
Cable failures and splice failures. Hurricanes can still cause outages as salt-water intrusion
Into the conductors occurs.
In addition, when an outage does occur, they will be extended on an underground system
as compared to one that is constructed overhead. This is due to the time necessary to locate
a fault on an underground line. In almost all cases, a fault on an overhead line will be
identified easily either by a utility worker or the general public. In most cases, the faults
result in visual damage to the overhead lines.
However, a' fault on an underground system cannot be readily seen unless the failure was
extremely catastrophic in nature. In normal faults, the failure requires special equipment
and traIned workmen to locate it. Then the repairs require the use of excavation
equipment that takes more time to set up and repair the damage.
In general, though studies have found that underground systems are generally more
reliable, this Increased reliability is achieved by a very large economic penalty to the
customers. As will be discussed In Section 6 of this report, the large rate increases
necessary to fund underground construction will only result in minimal improvement to
non-storm related reliability given that the existing overhead system is already performing
at the highest reliability levels In the State of New York. The randomness of major storm
events In frequency, location and severity makes it very difficult to justify the high cost of
conversion.
Overhead lines and equipment are more susceptible to certaIn types of weather-related
exposure and damage than underground systems. Perhaps the biggest contributor 'to
customer Interruptions is damage caused by trees. As can be seen from the chart below,
trees caused 18 percent of sustained customer interruptions on the LIPA T&D
4-1
RELIABILITY IMPACTS
system in 1998. During major storm events, this percentage can be significantly higher.
Last year there were approximately 806,000 sustained cus!omer interruptions on the LIPA
T&D System (major storm events not included). If major storm events were included, the
customer interruptions were approximately 1.14 million.
Cause of Fore d Distribution Interruptions . 1798
Equip, .Ea'ors
6% Lightning
11%
If all tree-related outages were eliminated (assuming all other factors remained constant), it
would have eliminated approximately 130,000 of the 806,000 interruptions during 1998. In
1998, LIPA's year-end SAIZ-I value, whic~t is a measure of the average interruption
frequency, was 0.77. In other words, the average customer experiences a sustained
interruption every 15.6 months. If the aforementioned elimination of interruptions from
trees were fully realized, that would have reduced the SALFI to 0.65 or a sustained
interruption every 18.4 months.
In order to combat the problem associated with trees and their negative impact on the
reliability of the electric system, LIPA currently has an aggressive tree trim program. For
1999, a budget amount of $14.1 million is allocated for tree trimming. Currently, this
program is undergoing a change where the cycles for trimming a particular circuit are
dependent on the characteristics of the individual circuit rather than a generic five-year
cycle for all circuits. Circuits will now be trimmed on either a three, five, or eight year
cycle depending upon the growth rate of the trees and the interference they cause. This
change is expected to have positive effects on the Interruption rate especially during storm
events. The following chart demonstrates thc impact t.hat trees have had on the reliability
of the LIPA T&D system excluding storm activity.
RELIABILITY IMPAC'P:3
40%
3O%
2O%
10%
0%
Percentage of interruptions attributed
to trees
1992 1993 1994 1995 1996 1997 1998
While over 81 percent of LIPA's conductor miles on the 1.2I~A distribution system are
overhead, it's reliability compares favorably with the average reliability of other New York
State utilities, with comparable makeup. The following graph shows the frequency of
interruptions in terms of month s between interruptions (inverse of SAIFI).
Months Between Interruptions
18
1992 1993 1994 1995 1996 1997 1998
'
i · LIPA -.-~---NYS Average
Another component commonly used to measure reliability is the average outage duration
(CAlX)I). This is a measure of the average length of time for an interruption. LtPA's
average outage duration, as seen in the following graph, compares favorably to other New
York State Utilities.
4-3
RELIABILITY LMPACTS
120
110
100
9O
8O
7O
6O
50
Average Outage Duration
1992 1993 1994 1995 1996 1997 1998
I · LIPA --~--NYS AmrageJ
Another way of representing reliability is througli the use of SAIDI or System Average
Interruption Duration Index. This index measures the average time of interruption seen by
every customer over a certain time period. In New York, reliability indices disregard the
interruptions caused by major storms because these events, while few in number, have
severe impacts on the overall statistics. The electric service of the average Long Island
customer is noticeably better than the rest of New York State. The average LIPA customer
experienced 59 minutes of outage during !998 while the rest of New York, Con Ed
excluded, experienced 102 minutes of outage. Consolidated Edison is routinely excluded
in comparisons of reliability issues. Approximately 75 percent of their customers and 85
percent of their load is supplied from a network system. Due to its design, it is inherently
more reliable than a radial system.
Based on the results from NERA's report discussed previously, the annual cost of
undergrounding on Long Island was 2.3 times the average for the rest of New York State.
Taking into account that reliability was 1.73 times better (based on average minutes
interruption to each customer) in 1998, one realizes that LIPA would not gain as much
reliability value per dollar, as would other New York State utilities from a reliability
standpoint.
In the study done jointly by LILCo and the NYPSC in 1993, they found that the average
customer experienced an Interruption due to the overhead distribution system once every
8.6 months compared to once every seven years for a customer affected by a failure of an
4-4
RELIABILITY IMPACTS
CIPUD/RUD2 component. The restoration time was about twice as long for an
underground fault compared to an overhead interruption. From this information it was
concluded that underground was approximately five times more reliable than overhead.
KeySpan does not currently differentiate reliability between its underground and overhead
systems. Due to the current design of the distribution system, overhead failures can cause
interruptions to undergrormd supplied customers and underground failures can cause
interruptions to overhead supplied customers. For this reason, it is very possible for a
customer who has an tmderground service to have poorer reliability than a customer who
has an overhead service. Due to the improvements made in reliability since 1993
(attributable mainly to the use of remote sectionalizing devices and an aggressive circuit
improvement program), the value today is probably closer to three to four times depending
upon the impact and severity of major storms. However, in the event of a catastrophic
storm, one single event could cause as many as 50 to 75 percent of the interruptions seen in
a normal year. Two of the more recent storms that would fit under this category are
Hurricane Bob in 1991, which interrupted service to 477,000 Long Island customers and the
Nor'easter of 1992, which affected 456,000 customers. The worst storm in 1998, the Labor
Day Storm caused sustained interruptions to 16 percent of LIPA's customers and
accounted for approximately 15 percent of the yearly total. Since 1995, there has been only
one event where more than 200,000 customers have been affected.
During storms, due to the extent of damage, the extra equipment needed to clear facilities
and the constraints on manpower, the duration of an outage is also increased. For average
storm activity, the average outage duration can be from three to four times longer than
compared to normal operating conditions. The following graph demonstrates the impact
storm activity has on the reliability of the LIPA T&D system. This graph represents the 4-
year average number of total customer interruptions over the past four years and the
number of interruptions that are caused by storm activity.
2 CIPUD is Commercial, Industrial Parks Underground Distribution and RUD is Residential
Underground Distribution
4-5
RELIABILITY IMPACTS
Customer Interruptions Attributed to
Storms
2 4O0
_c 0
1995 1996 1997 1998
I [] Storm interruptions · Total Outages (95-98 4 year ave.)
Over the last four years, approximately 45 percent of all interruptions' on the LIPA system
were storm related. The following table represents the costs associated with repairing the
electric system on Long Island due to the impact of storms.
$30
$25
$20
$1o
$5
$o
Storm Costn
1992 1993 1994 1995 1996 1997 1998
Once again, the impact of a catastrophic event, such as a hurricane landfall would have
substantial costs associated with it. For example, the costs from damage attributed to
Hurricane Bob in 1991 were approximately $27 million. Since 1992, the costs associated
with repairing the electric system due to storm damage on Long Island were
approximately $119 million or an average of $17 million.
Even if storm costs were assumed to rise annually at 1% from the $17 million average for
the next 30 years, the net present value of these storm costs would represent only three
4-6
RELIABILITY IMPACTS
percent of the 19.7 billion underground conversion costs.
From a reliability standpoint, an evaluation of undergrounding the electric system on Long
Island was performed in 1993, mainly in response to two major storms that occurred in
1991. These two events collectively had caused approximately 750,000 electric customers in
New York State to lose service. In LILCo's 1993 underground study, they concluded that
rates would be impacted by 569 percent over the 25 years it would take to underground the
entire distribution system. They stated that the average service life of underground cables
on the LILCo system was less than 30 years compared to overhead cables whose Lifetime
can exceed 50 years. In general, replacement costs of underground cable and equipment
are three to five times greater than overhead costs. These replacement costs increase to five
to nine times greater if you consider the expected lifetime of each component. In other
words, the underground equipment has to be replaced almost two times for every single
replacement of overhead material and equipment.
Due to these findings, even though reliability benefits would be gained from underground
conversion as a whole, there was no particular area that could be identified as being more
susceptible to storm damage and thus a more effective candidate for underground
conversion.
The results of the LILCo/NYSPSC study demonstrated that there were excessive costs
when compared to the benefit of improving reliability dttring catastrophic storms. The
staff of the Public Service Commission could not recommend systematic undergrounding
for preventing damage from major storms.
In 1991, the Florida Public Service Commission completed a detailed study on the benefits
of underground conversion. One area they examined was the impact of severe weather
and storms and the associated damage and costs that could result. Florida is particularly
susceptible to damage caused by hurricanes. From 1900-1996, Florida had 57 direct hits
from hurricanes that came ashore. Out of these, 24 were considered major hurricanes. In
comparison, New York had nine direct hurricane hits, five of which were considered
major. In other words, Florida would probably sustain a direct hit every 1.7 years while
New York has averaged a direct hit every 10.7 years. Even with the increased vulnerability
and associated negative impacts on storm related costs and reliability related to overhead
construction, the Florida PSC could not justify underground conversion.
There is another factor to consider relating to storms and their impact on the electric
system reliability. Many storms on Long Island such as hurricanes, Nor'easters etc. have
associated coastal flooding problems, especially on low-lying areas on the South Shore.
While underground facilities would be protected from driving wind, rain, and tree
contacts, the effect of standing water, especially salt water, has detrimental effects on the
4-7
RELIABILITY IMPACTS
insulation of associated cable and equipment. While the failure of such equipment may
not happen during the actual storm event, the effects of the storm on a subsequent failure
cannot be discounted. In the Florida PSC 1991 report, Jacksonville Beach estimated that a
category one or two hurricane would result in saltwater intrusion into 90 percent of its
underground system. They stated that "... any category hurricane would be more
devastating to our underground distribution system than overhead distribution in relation
to time for restoration, long-range equipment, cable and cormector failure and associated
costs." 3
In addition, there are other weather-related factors that may impact underground cables.
While lightning strikes are recognized as more of a concern on overhead systems,
underground systems are not totally exempt from lightning induced damage. The State of
Florida, which has the highest incidence rate of thunderstorm activity, estimates that the
expected damage to overhead facilities is 50 percent higher than for underground facilities.
Over the last seven years, on average, lightning is responsible for approximately 7 percent
of customer interruptions on the LIPA distribution system. Assuming the ratio used in the
Florida study, with 1998 LIPA statistics (all other factors remaining constant),
approximately 17,400 fewer interruptions could be expected due to lightning if all
distribution facilities were placed underground. Also, direct buried underground cable is
prone to failures in early spring. After the ground begins to thaw, there is movement and
settling which can cause damage to the cable.
From a reliability standpoint, the LILCo/NYPSC study concluded that the best approach
was to convert entire substations and associated distribution circuits. The only true
reliability benefit gained from underground conversion is if the entire primary mainline
circuit, associated primary branch, secondary and service lines should be converted to
underground. If this is not done, the extensive cost from undergrounding is realized with
little reliability benefit because part of the circuit is still overhead and still will have an
impact on reliability.
If improved reliability is the goal then any undergrounding efforts should be focused on
the distribution system. Due to contingency designs, interruptions on transmission system
don't automatically result in customer interruptions. The majority of the LIPA transmission
grid is a first contingency design. In the event of a loss of a transmission line to a
substation, the other line will supply the load to that substation. In a utility whose
distribution system is mainly radial, as opposed to network design, failures on distribution
lines usually result in interruptions (sustained or momentary) to customers.
~ Florida Public Service Commission, "Report on Cost Effectiveness of Underground Electric
Distribution Facilities", December 1991, Vol. II, p2-11
4-8
RELIABILITY IMPACTS
Underground faults are not found by patrolling the feeder as is done with the overhead.
The process of fault locating is a tedious process on the underground. Various tests must
be done to localize the fault and then digging must be done to actually locate the damage.
On overhead circuits, temporary repairs can be made in an emergency to restore circuits.
Even permanent repairs take significantly less time (days or even weeks) than
underground repair and restoration. Using single contingency design, an entirely
underground transmission system increases the risk associated with losing an entire
substation once an interruption on the other supply occurs.
Another major factor impacting reliability is accidents. Since 1992, an average of 15 percent
of the customer interruptions (major storms excluded) were caused by accidents. KeySpan
currently groups motor vehicle accidents, animal contacts and dig-ins in the accident
category.
20%
18%
16%
14%
12%
10%
Percentage of Customer Interruptions
Caused by Accidents
1992 1993 1994 1995 1996 1997 1998
Motor vehicles striking utility poles are the leading cause of interruptions caused by
accidents. The following chart provides information on the number of vehicle accidents
that caused customer interruptions.
4-9
RELIABILITY IMPACTS
Number of Motor Vehicle Accidents
that Caused Customer Interruptions
1993 1994 1995 1996 1997 1998
Un.derground conversion would reduce the number of motor vehicle acddents and animal
contacts but the number of accidental dig-ins would increase. Accidents over the past 7
years, on average have accounted for 15.5 percent of customer interruptions during non-
major storm conditions. The major components of this category are motor vehicle
accidents (approximately 55 percent), animal contacts (approximately 37 percent) and
accidental dig-ins (8 percent). Motor vehicle accidents and animal contacts are
predominantly overhead related and dig-ins are underground related. Based solely on the
ratio of overhead and underground cable mile exposure, an underground conversion
program would dramatically decrease accidents due to vehicle accidents and animal
contacts but would increase the relevance of accidental dig-in contacts. Overall, the impact
on customer interruptions caused by accidents would be expected to reduce interruptions
caused by accidents to approximately 5.4 percent after full conversion was reached
(assuming all other factors remained constant). Using these assumptions for 1998 would
be expected to result in approximately 78,900 fewer interruptions.
Reliability is also based on operational issues. Faults and damage on overhead systems are
usually quite easy to locate. Local authorities and customers are nsuaily helpful in
assisting the utility in locating a problem on an overhead system. Underground problems
on the other hand are not as visible. Work crews may have to take several steps in order to
isolate the problem. The problem has to be located and isolated before restoration efforts
can begin. Once the problem is found, repairs may require digging or installing temporary
electric lines in the street or on private property in order to restore service. So while the
frequency of interruptions will be less, the length of interruptions will be longer and more
intrusive.
4-10
RELIABILITY IMPACTS
In order to combat these issues, current LIPA design calls for "looped" radial circuits and
sectionalizing devices. The looped system provides two sources of supply to padmount
units. In this way, the secondary source can be switched to serve the load ff the primary
source trips out due to a fault. However, since this design differs from the typical
overhead system, the extra material and equipment bears an added cost compared to a true
"radial" design. Deviation from a "looped" radial design would reduce the cost of
underground conversion but it would negatively impact the operation of the system and
lead to longer outage times for customers in the event of an interruption.
4-11
SECTION 5
SAFETY ISSUES
OVERVIEW
From the perspective of accidental electrical contacts, undergrounding the facilities does
not necessarily mean fewer accidents. As shown in LIPA's history, as more of the system is
constructed as undergrounct the number of accidents on the LIPA system has actually
increased. This trend is not unique to Long Island as it has been found in other states as
well. The cause of these accidents, as originally reported in RMIs' 1998 Construction
Practices Report has been due to the general public digging into the underground circuits.
This has occurred even though Long Island has a locate system that will come out to a site
prior to any digging to locate the underground utilities in the vicinity.
Unlike electrocution accidents, an underground system would significantly reduce
accidents where a vehicle leaves the road and impacts with a utility pole. However,
removing poles as hazards will only eliminate a small percentage of roadside vehicle
acc/dents. In fact, the vast majority of these roadside accidents actually occur when
vehicles collide with trees, not utility poles. In addition, in the majority of roadside
vehicular accidents, there are extenuating circumstances that a utility- company cannot
protect itself from such as the fitness or competence of the driver.
ELECTRICAL CONTACTS
Safety is an issue often raised in a discussion of undergrounding new or existing T&D
facilities. It is often thought that an underground system is inherently safer than an
overhead system. After all, if the wires are below ground, the general public cannot touch
them. This alleviates concern over electrocution. However, as the discussion in Section 4
revealed about the issue of reliability, this section will show that an underground system is
no panacea for safety either.
The following chart that was presented in RMI's 1998 Construction Practices Report
illustrates that the majority of electrocutions on the LIPA system were experienced on the
overhead facilities. In fact, 91 percent of the electrocutions involved a person coming into
contact with the overhead lines.
5-1
SAFETY ISSUES
Lonq Island Power Authority
Composite of Contact Cases
From 1970 Through July, 1998
However, viewing the above chart would mislead the reader into concluding that
converting to underground would result in fewer contact cases. In reality, the high
number of overhead cases actually is a reflection of the fact that the majority of LIPA's
T&D System is currently overhead.
As expected by the sheer volume of overhead facilities (82 percent ) versus underground
(18 percent), there have been significantly more accidents involving the overhead than the
underground facilities. Annually, since 1970, on a per circuit mile basis the accidental
contact rate has been 1.6 contacts/10,000 miles for the overhead facilities and 0.7
contacts/10,000 miles for the underground facilities. However, over the last seven years,
the kontact rate has reversed dramatically to the point where it is 33 percent b. igher for the
underground compared to the overhead facilities. This comparisons shown in Table 5-1
below. Th.Ls points to the fact that placing facilities underground does not automatically
reduce the frequency of accidental contact. It simply changes the nature of the problem.
5-2
SAFETY ISSUES
Table 5-1
Comparison of Contacts with Overhead versus Underground Facilities
Annual Average Annual Average
1970 to July, 1998 1992 to July, 1998
Contacts per 10,000 miles 0.7 0.8
of Underground Facilities
Contacts per 10,000 miles 1.6 0.6
of Overhead Facilities
Accidental electrocutions stemming from contact with energized facilities are not unique to
LIPA's system. The Florida Public Service Commission ("FPSC') conducted a study that
considered converting overhead facilities to underground in 1991. Safety was also an issue
in their study. In 1990, the FPSC found that a total of 16 deaths and 44 injuries had
occurred on electric facilities in Florida. Of these deaths and injuries, four were a result of
the public coming into contact with underground equipment. They also found that one
death occurred in 1991 due to underground facilities. As with LIPA's T&D System, the
Florida T&D System is predominantly overhead, but they still experience accidents on
underground facilities.
Though this report is not intended to be an interpretation of legal cases or current law, a
search was performed to generally determine how contact cases have been treated in legal
proceedings outside of New York. In Michigan, the Michigan State Supreme Court
reviewed a number of cases in 1996. The overriding finding in these cases was the issue of
the ability of the local utility to realistically foresee the potential for contact by the public.
In each case reviewed by the Court, if the contact by the public was not foreseeable by the
utility, then the utility was not held liable for the injuries to the person coming into contact
with the energized facility.
These findings also raised a duty upon the electrical companies to "reasonably inspect and
repair wires and other instrttmentalities in order to discover and remedy hazards and
defects." The court further found that there is no duty to warn someone of a risk of which
that person is aware. Combined, the court found that the duty to inspect and repair does
not arise where it is not foreseeable to the utility that the injured person would not come
into harmful contact with the wires.
Finally, on an international level, Sweden is often sited as having addressed the issue of
undergrounding electrical facilities for numerous safety issues. However, the Swedish
government's policies do not absolutely direct the utilities to underground all energized
lines. In fact, Sweden's national authorities join in recommending the following
5-3
SAFETY ISSUES
precautionary principle: "ff measures generally reducing exposure can be taken at
reasonable expense and with reasonable consequences in alii other respects, an effort
should be made to reduce fields radically deviating from what could be deemed normal in
the environment concerned. Where new electrical installations and buildings are
concerned, efforts should be made already at the planning stage to design and position
them in such a way that exposure is limited...".~
POLE HITS
Another factor to consider when looking at the safety of underground versus overhead
facilities is the number of vehicles making contact with poles each year. Irt discussions
with KeySpan, RMI was told that minimal statistics relating to number of fatalities and
injuries have been maintained that could effectively be used in this report to highlight
actual Long Island experience in this area. The following chart represents the number of
utility pole incidents that have occurred over the past 11 years.
LIPA Utility Pole Incidents
1750 I
1350-Hi~-~ ?
1150 H~~[ _
950
750 ,'"'
The armual average (1988-1998) of accidents on Long Island involving LIPA utility poles
are 1158. As discussed in Section 4, vehicle accidents with utility poles are a cause of
customer interruptions. However, not every pole incident results in sustained customer
interruptions. In fact, In 1998, only one out of every six incidents involved sustained
customer Interruptions. ..
Medical College of W~sconsm, Power Lines and cancer FAQ s, January 1999.
5-4
SAFETY ISSUES
The downward trend seen in the above graph is likely more of a reflection of societal
awareness and law enforcement of factors contributing to off road collisions, such as drunk
driving, rather than any proactive activity to reduce vehicle pole incidents.
Motor vehicle crash statistics as compiled by the National Highway Traffic Safety
Administration (NHTSA) in 1996 and 1997 demonstrate that 3 percent of all motor vehicle
crashes involve collision with "poles/posts". Of all accidents that involve poles and posts,
approximately 66 percent involve property damage only 33 percent result in injuries to
passengers and 1 percent result in fatalities. In 1994 the NHTSA issued a report entitled
"The Economic Cost of Motor Vehicle Crashes". This report outlined the economic cost
components associated with losses due to motor vehicle accidents. The economic costs
include; productivity losses, property damage, medical costs, rehabilitation costs, travel
delays, legal and court costs, emergency service costs and insurance costs/ The report did
not attempt to place a~y value on human life or any human emotional value that a loss
could create. It also did not attempt to place values on pain and suffering that may result
from such an event.
The following information is not intended to be representative of the true costs or number
of injuries/fatalities experienced in the past nor is it meant to be used as a basis for
determining any expected costs or reduction in fatalities or injuries in the future. It is
solely meant to demonstrate the difference in scales between the economic losses
associated with motor vehicle accidents and the cost of overall underground conversion.
Based solely on averages, out of the 1158 yearly accidents: 763 would result in property
damage only, 384 would result in various levels of injuries and 10.5 would result in
fatalities. In 1994 dollars, the unit costs were the following: property damage only was
$1,663 per vehicle, accidents involving injuries, depending on the seriousness of the injury,
ranged from $1,129 to $705,754 per person and fatalities were assessed a value of $831,919
per person. In 1994 dollars the estimated costs associated with the 1158 accidents would be
in the range of $19 million.
In the 1994 NEKA Report, the annualized cost for LILCo for underground conversion was
$1.6 billion per year. The $19 million associated with the economic costs of vehicle
accidents would represent 1.8% of the annual underground conversion cost.
In 1991, the Florida Public Service Commission conducted a study to evaluate the costs and
benefits associated with underground distribution facilities versus overhead ~_ines. One of
the issues considered by the FPSC in theix study was accidents resulting in the general
public coming Into contact with existing poles. The Florida 1T-aC study found that every
year thousands of vehicles hit roadside poles in Florida. The result is a two-percent fatality
rate. If electric distribution facilities were placed underground, according to the FPSC
estimates, approximately 80 percent of these pole accidents could be avoided. However,
5-5
SAFETY ISSUES
even when taking the number of accidents due to pole contacts and electrical contacts, the
FPSC found that a wholesale conversion of existing overhead facilities to underground
would not be in the best interests of Florida's ratepayers.
As mentioned earlier in this report, the review conducted by R_MI is not intended to be a
legal interpretation of court cases and resultant rulings. The intent is only to present
related court cases for informa6'~n purposes. To this c~td, a 1992 court decision in
Mississippi found that when there is no negligence in the placement or maintenance of a
pule by a utility, then the utility cannot be found liable for injuries in an accident where a
car strikes a pole.
Finally, the Insurance Institute for Highway Safety published a report in 1998 called
"Roadside Hazards." This report analyzed the accidents across the country in which
vehicles came into contact with some roadside hazard. The results of this report follow:
About a third of motor vehicle deaths involve vehicles leaving the roadway and hitting
fixed objects such as trees or utility poles alongside the road;
Roadside hazard crashes occur in both urban and rural areas but are mostly a problem
on rural roads. They are most likely to occur on curves and/or downhill road sections;
More than a third involve a vehicle that rolls over and about a third involve occupant
ejection;
1,859 people died in roadside hazard crashes in 1996, down one percent from 1995 and
about eight percent more than in 1975;
The proportion of motor vehicle deaths involving roadside hazards has remained
between 28 and 30 percent since 1979;
Forty-eight percent of drivers killed in roadside hazard crashes in i996 had blood
alcohol concentrations at or above 0.10 percent;
Drivers of 45 percent of the vehicles in fatal roadside hazard crashes in 1996 were men
younger than 35 years of age;
Trees are the most common hazard. Twenty-seven percent of deaths in roadside
hazard crashes in 1996 involved a vehicle s.~.ng a tree;
Utility poles accounted for 9 percent of the deaths in roadside hazard crashes in 1996;
and
5-6
SECTION 6 ECONOMIC ISSUES
Numerous studies have been performed on the state level within New York, by the
individual utilities and by outside consultants. In each case, the findings have consistently
concluded that even though there are benefits inherent to an underground electrical
system, the costs associated with constructing such a system far outweigh the benefits.
Though the studies all provide different rate impact estimates, they all show that for LIPA
to aggressively convert the existing system to underground would result in rate increases
at least double what they are today.
The studies, as do specific project cost estimates, show that even if individual areas are
targeted for conversion, the costs for these smaller areas are not minor. Selecting one area
to underground and not another area, for the sake of safety or reliability, or even aesthetics
would raise many questions from customers elsewhere on Long Island. Questions about
why those that do not benefit by the undergrounding should pay for others to reap
whatever benefits might exist. For this reason, KeySpan In the past has always offered
undergrounding as an option to a customer or a local community, but it was at the
requestor's expense.
In addition to the costs to the utility to underground facilities, there is also the cost to the
customer directly associated with the conversion. These costs have been estimated
consistently at $200 to $1000 per customer for residential customer and significantly more
for businesses served overhead. These costs are only for the electric service conversion and
do not reflect any additional costs for undergrounding the cable television of the phone
service. Plus, there are the indirect costs the customers and communities would incur due
to the congestion associated with the construction and the repairs on roads and yards that
would take time and money to bring back to current conditions.
One possibility was that LIPA could "piggy-back" on public works projects to convert a
portion of the existing overhead system. However, a review of past projects indicates that
this is a good idea in theory, but does not work often in practical application. This is
because most public works projects are small in scope affecting only a few poles at a time.
In addition, the trenches opened for most public works projects would not readily work for
undergrounding the typical overhead facilities - transmission, distribution, phone, and
cable television - necessitating additional trenching, thus not saving any money.
COST TO CONVERT T&D SYSTEM TO UNDERGROUND
Many of the utilities contacted for this study suggested that economics alone was the
driving force behind continuing to construct their T&D facilities over head as opposed to
6-1
ECONOMIC ISSUES
underground. While this was definitely true in the past, now that most utilities are striving
to maintain the lowest possible costs to their ratepayers due to future competition, their
motivation to minimize rates is even greater. RMI's 1998 Construction Practices Study for
LIPA coMim~ed the impact of the economics on LIPA's ratepayers if wholesale conversion
to underground was implemented.
RMI's 1998 CONSTRUCTION PRACTICES STUDY
RMI's 1998 Construction Practices Study discussed the "ovemight" construction costs to
convert the existing overhead facilities to underground. This study estimated the costs for
conversion at approximately $14.7 billion. The construction period was estimated to take at
least 20 to 30 years to complete. However, the actual costs to convert the overhead facilities
would increase significantly beyond the estimated $14.7 billion sinc~ actual costs would
escalate over the extended construction time.
This $14.7 billion estimate would have a profound effect on L1PA's rates. Assuming a
simple 30-year amortization schedule at seven percent per year, LIPA's rates would have to
fund an annual cost to underground of at least $1.2 billion. This annual revenue
requirement would require an increase in electric rates bringing them double what LIPA's
ratepayer's currently pay. This would put LIPA's rates at the highest electric rates in North
America. This is considered a conservative estimate due to the many uncertainties that
would appear over the construction period.
NEW YORK STATE UNDERGROUND STUDIES
A similar study was authorized by the New York Public Service Commission in 1993 found
similar costs to convert LIPA's existing facilities. That study found that it would cost an
estimated $20 billion to convert the T&D System on Long Island to underground. The
report further estimated a rate increase of 569 percent over the 25 years to complete the
conversion. This study was prepared jointly between LILCo and the NYPSC.
The issue of the economics associated with conversion to underground has been addressed
many times since the 1960s by New York State. Each time the issue is raised, and studies
are conducted, they conclude that undergrotmding of the system is not a cost-effective way
to spend ratepayer's money.
Phase II of New York State's proceeding on undergrounding utility facilities (see Section 2
of this report), was an evaluation of the costs and benefits associated with converting
existing overhead facilities to underground. Even though the ALJ recommended closing
the issue on underground conversion, the PSC still believed there were identifiable areas
where underground conversion would make sense.
In 1994, a study was done by NERA that performed a cost benefit analysis associated with
underground conversions. Benefits derived from aesthetics was the major factor driving
6-2
ECONOMIC ISSUES
this study. This study estimated that the cost of converting the overhead distribution lines
to underground in New York State would be approximately $108 bilLion ($97 billion in
conversion costs and another $11.1 billion in costs for customer connection costs). This
represents a cost of $1.07 million per mile for the conversion. The armua]Jzed costs for this
amount (taking O&M reduction into account for underground of $103 million) would be
$8.6 billion or approximately $95,000 per mile. (Note: Annualized costs are based on 30
years at a seven percent real discount rate and all dollars are based on 1993 value)
Table 6-1
Utility Total Conversion $(billions) Annual Cost/Mile
includes customer hookup costs
CHG&E S14.23 $181,703
ConEd $ 9.92 $161,061
LILCo(LIPA) $20.44 $193,524
NYSEG $13.21 $42,964
NIMO $41.76 $92,549
, O&R $2.72 $ 60,360
RG&E $5.65 S 66,562
Under a proposed five-year pilot program, the Commission investigated the concept of
having each utility contribute up to 0.5 percent of their net revenues for a conversion
program. In 1993 dollars, this would have raised approximately $52.3 million per year and
$261.3 n~illlon for five years. Using those 1993 present day dollars (overnight construction),
it would have taken over 1,850 years to convert the entire electric distribution system in
New York State.
For the conversion on Long Island, LILCo estimated that the conversion, in 1993 dollars,
would be $19.7 billion or $2.36 million per mile for the conversion. In addition, there
would be an additional cost of $750 million for customer connection costs. The annual cost
per mile (assuming a $34.2 million annual O&M reduction and a 30-year period at 7
percent) was estimated to be approximately $193,500, which represents a 104 percent
increase compared to the State average. In other words, it would cost twice as much to
convert the electric system on Long Island than the State on average. Using 1993 figures,
under the proposed pilot program, LILCo would have been required to spend $8.92 million
6-3
ECONOMIC ISSUES
on the conversion program. Using 1993 present day dollars (overnight construction), that
would raise the total conversion time for Long Island to over 2,200 years.
NERA performed their cost benefit analysis weighing the costs associated with the
conversion against the aesthetic benefit or value to the consumer. They investigated the
cost benefit analysis for 3 different scenarios:
1. Complete Statewide conversion;
2. Conversion in VSR areas; and
3. Five-year proposed pilot program.
In all three cases, the costs outweighed the benefits in a range from 4.5 times (VSR
program) to 40 times (Statewide conversion). Also, the conflict with other utilities and the
associated costs to underground their facilities for the desired aesthetic effect would
increase the overall cost of a conversion project.
Even though in general the overall annual O&M costs for undergrotmd are lower than
overhead, the life exl~ectancy for overhead facilities is usually 1.5 to 2 times greater. Also as
the underground facilities age, the difference between the associated O&M costs compared
to an overhead facility will decrease. This will lead to higher capital costs to replace the
underground facilities on a shorter cycle than the overhead facilities. Based on previous
surveys done in other areas of the country, the NERA study calculated that the average
benefit per mile, from an aesthetic point of view was $2,260. Using the 1993 circuit miles
and number of customers this resulted in a~. average benefit of $18.70 per customer. If
every customer on Long Island were willing to pay $20 per year today that would raise
approximately $21 million for the conversion process. Assuming the original estimate of
$19.7 billion was still reasonably accurate (minimal inflation assumed) and using present
day values (overnight construction), it would still take over 900 years to convert the system
to underground.
COSTS BASED ON CONVERSIONS OF ACTUAL LONG ISI.~/D FACILITIES
All of the studies discussed above presented generic estimates of what it might cost to
underground all or a portion of the Long Island T&D System. However, in December 1998,
KeySpan was asked to prepare a preliminary estimate associated with converting 5
overhead sections on 2 -138 kV circuits to underground.
The cost of converting 1.3 circuit miles of 138 kV from overhead to underground was
estimated at $6.6 million or approximately $5 million per mile. This estimate did not cover
the cost of permits or additional easements that may be required. In comparison, a project
involving the replacement of 4.8 miles of overhead transmission line and associated static
wire on Eastern Long Island is estimated to cost approximately $900,000 or $~87,,500 per
mile. This demonstrates quite a significant difference when examining the difference in
ECONOMIC ISSUES
magnitude between the underground conversion option and the overhead replace with like
and kind option.
Historically, KeySpan has been asked many times by customers or local communities to
provide estimates for undergrounding a portion of a distribution circuit. In each case,
KeySpan policy has been to provide the requested estimate with the understanding that
any underground conversion costs would be borne by the requestor. In each case, these
requests have not gone beyond the estimating stage. The estimates KeySpan has prepared
have been in the neighborhood of $1.0 to $2.0 million per mile of underground circuit. If
these estimates were to hold up across the entire distribution system, then the costs to
convert the existing overhead distribution system to underground could nm as high as $50
to $100 billion.
COSTS TO CUSTOMERS OF CONVERTING TO UNDERGROUND
There are two levels of costs to the customers associated with converting existing overhead
facilities to undergrotmd construction. The first is the method in which the connection is
completed between the customer and the electrical grid. The second is the cost and
aggravation associated with the underground construction on the customer's premises.
RETROFITTING HOUSES FOR UNDERGROLrND SERVICE FROM EXISTING OVERHEAD
For a homeowner to retrofit his house wiring to accommodate a conversion from overhead
to underground was estimated in the 1998 Construction Practices Report at $500. This cost
will vary depending on the age of the property and other factors and could be as high as
$1,000.
In contacting other electric utilities, RMI found similar cost estimates. NSP in Minnesota
conducted a study on undergrounding overhead facilities and issued a report in January
1999. According to their findings, the cost to the homeowner can range typically from $200
to $1,000 or more in some cases. In fact, they found that some older homes might need
complete rewLring before an inspector would approve the new connection. Such a rewiring
would cost the homeowner an amount significantly in excess of the cost just for the
connection to the electric grid. This would be relevant to certain residential areas on Long
Island where the average homes are 40 to 50 years old.
In the case of LIPA, with over 935,000 residential customers, and assuming approximately
75 percent are served from overhead facilities, the conversion to underground would cost
the consumers on Long Island at least $350,000,000 at $500 per customer.
COSTS TO I:~,IVATE PROPERTY DUE TO CONVERSION TO UNDERGROUND
In addition to the direct costs to the customers for conversion (i.e., conversion of meter pan
and internal wiring), there is also the indirect costs to consider. These costs will vary
6-5
ECONOMIC ISSUES
customer-to-customer. During the due diligence period leading to the LIPA Closing in
May 1998, a field review was conducted of the existing facilities. This review included a
field check of a sampling of the distribution facilities in the field. This field review found
many circumstances were customer's private property and landscaping had grown up
around the existing pole lines. This growth will not pose a problem to LIPA's crews to
operate and maintain the existing facilities. However, if LIPA chooses to convert these
facilities to underground, these customers will incur significant disruption and there will be
a need to repair fences and landscaping. There will be a cost associated with this repair. In
addition, the customers will experience significant disruption of their property as the
service drops are trenched Into their yards to replace the existing overhead service drops.
In each case, the customer and LIPA would need to coordinate this trenching with that of
the phone company and the cable television provider.
COORDINATION WITH PUBLIC WORKS PROJECTS
One area that has bebn investigated as a means of reducing costs associated with
underground conversion is by incorporating the underground work in conjunction with
Public Works Improvements jobs. Due to necessary clearances, electric facilities may
require a separate trench from other utilities such as gas, water and sewer. Each utility or
agency is responsible for the cost associated with their trench or a prorated cost for
common trenches. Depending on the congestion and incremental costs to avoid
interferences, such as added trenching or re-routing of lines, there may be rninimal up front
savings associated with planning to use a "common trench" method. The most significant
benefit would be gained from Public Works improvements that were large in scale and
paralleled existing electric facility layouts.
Transmission facilities, as opposed to distribution facilities, would gain more cost benefit
associated with large-scale public works improvements that involved street digging
because they generally run a straight path between two different substations. On the other
hand, underground conversion of distribution facilities involves routing distribution
circuits to padrnount switchgear and transformers and the installation of various secondary
and service lines. This would involve much more trenching on sidewalks and private
property, and would not be common to the work done in many Public Work
Improvements. Common trenching benefits on the distribution side would be gained more
from common work with telephone and cable.
KeySpan Energy evaluated the 1998 Public Works projects t° determine to what extent an
underground conversion program could be incorporated with such projects. For Local
Town and Village Projects, Nassau County had approximately 32 projects that involved
pole relocations (average of 7 per project). In Suffolk County, there were a large number of
pole relocation projects but each project involved the relocation of one or two poles. This
trend seems to be continuing in 1999. For State and County Projects, the opportunity for
6-6
ECONOMIC ISSUES
removing poles rather than relocating was approximately 400 poles (based on the number
of jobs that involved street openings.)
The following table is an est/mate of the mount of Pubhc Works improvements involving
pole relocations for State and County projects.
Table 6-2
Public Works Projects for 1998
Agency # of prolects # of poles Ave. poles per % of Road
project Openings
NYSDOT 24 420 18 60%
Nassau DPW 4 205 51 80%
Suffolk DPW 3 65 22 80%
More cost benefit for underground conversion is gained if the public works project involves
LIPA having to relocate its facilities, at cost to LIPA, rather than a project where the electric
facilities pose no interference. However, small projects that only call for the relocation of
several iSoles, which may not be adjacent, detract from any cost benefit that may be gained
by doing the project concurrently with the improvement work. Additional duct work,
risers, potheads and switches would have to be installed on any remaining poles that were
not el/minated due to the size of the project in order to make the transition from the new
underground conversion to the existing overhead facilities.
An example of a large-scale project would be the one on Newbridge Road in Bellmore. The
following estimates are based on the re-siting of a 69-kV transmission line. It assumes that
for the underground siting, the electric facilities could be accommodated in the plans and
that only minor additional costs would be realized in providing for necessary clearances.
Conversion - If no other ongoing work was associated with this project, the estimated
cost would be approximately $3 million per mile to convert an existing overhead line to
an underground line;
Conversion - If this work was performed in concurrence with a Public Works
improvement project, the estimated cost would be approximately $1.8 million per mile
to convert an existing overhead line to an underground line; and
Relocation - If an existing overhead circuit was relocated, the estimated cost per mile
would be approximately $450,000 per mile.
In this particular case (transmission only), it is 1.7 times less expensive to do an
underground conversion in conjunction with the Public Works improvement. However,
this choice is still 4 times more expensive than the relocation optSon.
6-7
ECONOMIC ISSUES
There are additional issues to consider when evaluating the compatibility of underground
conversion and PubLic Works Improvements. Currently, the contractor who wins the bid
for a job has domain over work conditions and schedules within the job site under the
State's or county's direction. Currently, /f overhead facilities need to be relocated, this
work is usually done prior to the contractor's excavations in order to avoid conflicts. If the
work was going to be performed simultaneous !y, this may require a utility working on off
shift hours or weekends in order to perform the work and avoid conflicts with the ongoing
PubLic Works Improvements. This would lead to increased costs, in addition, if more
trenches were dug to accommodate all of the new facilities being relocated, road closings
may be needed in place of just lane closings. While not directly leading to higher costs, it
would involve more disruption, and inconveniences to the local cormnunities where the
work is taking place.
Due to space restrictions and clearance requirements, the electric facilities may not be able
to be placed in the most advantageous or economically viable locations. From an
operational standpoint, in order to maximize reLiability and accessibility, it may be
desirable to place the electric lines in separate trenches. This would have to be analyzed on
a case by case basis.
Programs or legislation to include the undergrounding of utility facilities in the scope of
select Public Works improvements would allow for an easier transition and the ability to
minimize the cost exposure to LIPA.
In addition, the more facilities are placed tmderground, the exposure to future cortflicts
increases. Currently, LIPA incurs costs for the relocation of facilities that create interference
with PubLic Works Improvements. The exposure and Liability associated with this would
be higher the more electric facilities are placed underground. Currently, even if relocation
of existing underground facilities is not required, there is a cost incurred by LIPA
associated with the contractor's expenses of supporting and protecting the facilities dm-ing
construction.
This exposure and liability is increased for electric facilities that would be placed in near
proximity to other utilities. In other words, any initial cost savings that may be realized by
siting electric facilities in common trenches may ultimately be offset by increases in
maintenance costs and reLiability concerns. Failures of other utilities and associated
excavation and repair work may cause damage to the electric facilities or require that they
be temporary supported and relocated.
In general, the number of large-scale opportunities for significant undergrotmd conversion
is expected to be minimal. On the large-scale projects that do arise, all factors should be
evaluated to determine the benefits, if any associated with converting the facilities to
underground.
6-8
ECONOMIC ISSUES
ANNUAL O&M EXPENSES
In March 1993, LILCo performed an assessment of the differences in annual operating and
maintenance expenses (O&M) for underground versus overhead facilities. In their
assessment, they considered the additional costs for O&M in the event an existing overhead
line was converted to underground. Therefore, their final estimates reflected an
incremental difference in expenses based on the increased costs for the new underground
facilities and an incremental savings based on the removal of the existing overhead Line.
LILCo's study showed that the new underground line would have incremental annual
O&M expenses of approximately $2,300 per mile based on an estimate of $1,500 per mile
for routine O&M, $500 per mile for emergency service, and $300 per mile for tree trimming.
They further estimated an incremental savings from removing the overhead line of $6,500
per mile, assuming $1,100 for routine O&M, $3,600 for emergency service, and $1,800 for
tree trimming. Based on LILCo's evaluation, the net impact to the ratepayers for this
conversion would be savings of $4,200 per mile per year.
LOST REVENUE DUE TO OUTAGES
When a customer is out of service for any reason a revenue loss results. Therefore,
improved reliability due to an underground facility will result in increased revenue to
LIPA. As discussed in Section 4 of this report, there were approximately 130,000 tree-
related customer outages in 1998. It would be a reasonable expectation that ff the system
were converted to underground, then these tree-related outages would be virtually
eliminated.
The average LIPA customer experienced 59 minutes of outage time in 1998. There was
insufficient data to determine/f a tree-related outage resulted in an average outage time, or
i/due to the nature of the problem, the outage took more or less time to restore service to
the customer. Therefore, for study purposes it is reasonable to assume that ff the tree-
related outages were eliminated through the underground conversion, then LIPA would
save roughly 130,000 non-storm related outages at an average of 59 minutes per outage.
Based on the above assumptions, and just taking into consideration the tree-related
outages, it can be estimated that LIPA's improved revenues due to the undergrounding
would be on the order of about $28,000 per year. This increase in annual revenues would
not begin to come close to funding the estimated $15 to $20 billion necessary to convert the
entire overhead system to underground.
6-9
SECTION 7
FINDINGS
Several utilities, communities, and governmental agendes were contacted or researched for
this report. Each entity addressed the issue of whether or not to underground transmission
and distribution facilities from a different perspective. However, in general the focus of the
evaluations centered on all or a combination of system rellabffity, public safety, aesthetics
and economics. The following summarizes the key information provided in this report:
Numerous studies have been performed on the state level within New York, by the
individual utilities, and by outside consultants. In each case, the findings have
consistently found that even though there are benefits inherent to an underground
electrical system, the costs associated with constructing and operating such a system far
outweigh these benefits.
Local community concerns with aesthetics were often the primary driver behind
decisions to underground new or existing T&D facilities. However in each case, the
local community was also willing to fund the construction through increased rates.
Examples referenced in the report include; Fort Collins, Colorado; WestervRle, Ohio;
Maple Grove, Minnesota; and Richmond, Indiana.
UndergroundIng T&D facilities will not eliminate outages due to weather. An
knprovement In reliability would be expected as outages from trees and vehicular
acc/dents will be minimized. However, based on the experiences of both Long Island
and Florida, outages will still occur on underground systems due to moisture seeping
into the lines. Hurricanes can st/il cause outages as salt-water Intrusion into the
conductors occurs. Salt-water intrusions can severely reduce a conductor's life
expectancy.
Outage durations will be longer on an underground system. This is due to the fi.me
necessary to locate a fault on an underground line. Normally, a fault on an overhead
line is easily identified by visual inspection. However, an underground fault cannot be
readily seen unless the failure was catastrophic in nature. Normally, an underground
failure requires special equipment and trained workmen to locate and the use of
excavation equipment in order to expose and repair the damage.
Undergrounding T&D facilities will not necessarily result in fewer accidental contacts.
Based on LI~A's history, the contact rate for the underground system is 33 percent
higher than for the overhead system over the last seven years. This trend is not unique
to Long Island as it has been found in other states as well.
An underground system would significantly reduce the number of vehicular accidents
with the T&D system. However, removing poles as hazards will only eliminate a small
7-1
FINDINGS
percentage of roadside vehicular accidents. In fact, the vast majority of these roadside
accidents actually occur ',~hen vehicles collide with trees, not utility poles. In 1996 as an
example, out of a total of 1 million accidents with fixed objects, only 20 percent
involved a vehicle hiti:ing a pole of some type. Of the total accidents, less than one
percent resulted in a fatality. In addition, in 'the majority of roadside vehicular
accidents, there are extenuating circumstances that a utility company cannot protect
itself from such as the fitness or competence of the driver.
Table 7-1 lists the general pros and cons noted by the various entities researched for this
report as they investigated the issue of overhead versus underground construction.
Table 7ol
Comparison of Overhead versus Underground Construction
Pros to Underground Construction Cons to Underground Construction
Less susceptible to storm conditions and in Significantly higher cost.
general a reduction in interruption frequency.
Improved aesthetics. Installation is more difficult and
disruptive to the environment.
Reduction in tree trimming costs.
Reduction in costs associated with storm
damage.
Faults are m6re difficult t.o locate, costlier
to repair and result in longer interruption
durations.
Conductor has a shorter life expectancy
(30-40 years for underground compared
to 50-60 years for overhead)
Less exposure of conductors to general public. Increased need for easements on private
property for padmount transformers and
switchgear.
Improvement in power quality (fewer Susceptible to dig-ins, foreign
momentary outages), contaminants such as salt water etc.
Less environmental impact after construction. Greater inconvenience to customers when
repairing faults due to restoration time.
Experience shows that even if only individual areas are targeted for conversion, the
costs for these smaller areas are not minor. Selectively undergrounding one area and
not another, for the sake of safety, reliability, or even aesthetics, would likely raise
7-2
FINDINGS
concerns from the customers that are subsidizing the cost but not receiving the benefit.
For this reason the current LIPA tariff allows tmdergrounding as an option to a
customer or a local community, but it is at that customer's or community's expense.
In addition to the costs to the utility to underground facilities, there is also the cost to
the customer directly associated with the conversion. These costs have been estimated
consistently at $200 to $1000 per residential customer and significantly higher for
commercial customers. Th. ese costs are only for the electric service conversion and do
not reflect any additional costs for uridergrottnding the cable or telephone service. Plus,
there are the indirect costs the customers and communities would incur due to the
congestion associated with the construction and the repairs on roads and yards that
would take time and money to bring back to current conditions.
LIPA could "piggy-back" on public works projects to convert a portion of the existing
overhead system. However, a review of past projects indicates that while this is a good
idea in theory, it does not work often in practical application. Most public works
projects are small in nature and would only affect a few poles. In addition, the trenches
opened for most public works projects would not readily work for undergroundIng the
typical overhead facilities - transmission, distribution, phone, and cable television -
necessitating additional trenching, thus resulting In minimal savIngs.
Currently, LIPA incurs the costs associated with the relocation of their T&D facilities,
when such facilities cause interference with Public Works Improvements. If electric
lines are installed underground, they will be more susceptible to interference with
future Public Works Improvements. The need to relocate underground facilities will
likely add significantly to the cost of future relocations.
There will be a need to site distribution facilities (i.e., padmount transformers,
switchgear) on private property, which will trigger the need for easements at costs,
which could approach several thousand dollars per installation.
7-3
APPENDIX A
LIPA TARIFF
Summary of Requirements for Underground Service - New
Applications
Table A-1
Residential Customers in an Underground Area
LIPA Responsibility Customer Res]~onsibility
Single residences - Provide material, obtain
public right of ways, install up to I00 feet of
underground distribution facilities.
Multiple dwellings-Same as single residences.
The footage allowance is 100 feet times the
average number of dwelling units on each floor.
LIPA will install all underground supply lines
not on private property, line extensions and
laterals up to the property line.
If the distance of the underground supply lines
from LIPA facilities to the meter location is less
than the allotted allowance, LIPA will install the
lateral to the meter location.
Own and maintain pull box or manhole on
property, if required.
Own and maintain the necessary cable between the
pull box and meter location except if footage
allowance is adequate to cover the entire distance
to the approved meter location.
Applicant pays added costs that exceed
allowances.
Table A-2
Residential Customers in an Overhead Area
LIPA Responsibility
If not required by a governmental authority
having jurisdiction or requested by an applicant,
LIPA is under no obligation to provide
underground service.
If underground is requested, a cost allowance is
allocated equal to the costs associated with
overhead construction.
Customer Responsibility
Applicant pays total cost to install underground
facilities minus the allowance allotted for overhead
construction.
Applicants shall provide the material and labor
needed for underground construction
A-1
LIPA TARIFF
Table A-3
Non-Residential Customers in an Underground Area
LIPA Responsibility
If LIPA decides to underground, they will bear
all of the material and installation costs, which
are greater than the amount the Appllcar.]
would have paid if the facilities were, installed
overhead.
LIPA will provide all materials and install
underground facilities equal in cost to the
allowance for overhead construction. This
allowance is 500 feet of single-phase lines and
300 feet of multiple phase lines.
LIPA will inst~ll ail underground supply lines
up to the proper ,ty line.
Customer Responsibility
Th.' applicant will install the service lateral from
the property line to the meter.
Table A-4
Non-Residential Customers in an Overhead Area
LIPA Responsibility
If not required by a governmental authority
having jurisdiction or requested by an applicant,
LIPA is under no obligation to provide
underground service.
If LIPA decides to underground, they will bear
all of the material and installation costs that are
greater than the amount the' Applicant would
have paid if the facilities were installed
overhead.
When a governmental authority requires
underground service, LIPA will incur the costs
equal to the allowance for overhead
construction.
When an applicant requests underground
service, LIPA will incur the costs equal to the
allowance for overhead construction.
Customer Responsibility
The applicant will receive a cost allowance equal to
that for overhead construction.
They will be responsible for providing the
materials and labor for underground construction
to meet the Authority's riser pole unless the
decision to underground was made by the
Authorif]r.
A-2
LIPA TARIFF
Table A-5
Non-Residing Subdivision Applicants in an Underground Area
LIPA Responsibility Customer Responsibility
LIPA will install all underground supply lines
and line extensions up to the property Line. If
the distance of the underground supply lines
from LIPA facilities to the meter location is less
than the allotted allowance, LIPA will install the
lateral to the meter location.
For single residences in a subdivision, LIPA will
install up to 100 feet of underground
distribution facilities, for each residential unit
~lanned, including the supply line, line
extension and lateral.
For multiple dwellings, subject to a Performance
payment, install up to 100 feet of underground
facilities times the average number of dwelling
units on each floor.
Applicant pays added costs that exceed
allowances.
Own and maintain pull box or manhole on
property, if required.
Own and maintain the necessary cable between the
pull box and meter location except if footage
allowance is adequate to cover the entire distance
to the approved meter location.
Table A-6
Non-Residing Subdivision Applicants in an Overhead Area
LIPA Responsibility Customer Responsibility
Unless a governmental authority kaving
jurisdiction or an applicant requests
undergrounding, the Authority may consider
factors such as environmental impacts, the
developers active construction of units, line
lengths to existing overhead systems etc. in
providing or contributing to underground
construction.
AppLicant will pay the total costs to install
underground facilities minus the cost allowance for
overhead facilities.
Applicants will provide the materials and labor
required.
A-3
Appendix B
References
Blincoe, L. 1994. "The Economic Cost of Motor Vehicle Crashes". National Highway
Traffic Safety Administration.
Cape Cod Commission. March 1995. "Final Report on Cape Cod Underground utilities
Workshop".
Department of Energy. 1996. "EA_ 1074- Final Environmental Assessment Mary's Lake
69/115-kV Transmission Line Upgrade and Substation Expansion Projects."
Florida Public Service Commission. December 1991. "Report on Cost- Effectiveness of
Underground Electric Distribution Facilities". Volumes 1-3.
Georgia Transmission Corporation. May 1998. "Batesville 115/12- Kilovolt Substation
and 115 -Kilovolt transmission Line."
Long Island Power Authority. 1998. "Long Island Power Authority Tariff for Electric
Service".
McTague, Janet. March 1998. ' Underground Conversions-Fort Collins' Experience".
National Economic Research Associates Inc. (Harrison, D., Stavins, J., NichoLs, Albert.)
1994. "Benefits and Costs of Undergrotmd Conversion of Overhead Distribution Lines
in New York State".
National Highway Traffic Safety Administration. November 1998. "Traffic Safety Facts
1997".
National Highway Traffic Safety Administration. December 1997. "Traffic Safety Facts
1996".
New York State Depa, t~Lent of Public Service. March 1993. "The Great Nor'easter of '92-
A Report on Utility Performance."
New York State Public Service Commission. March 1993. "A Study to Assess the Cost
Effectiveness of Undergrounding's Potential to Mitigate LILCo Service Interruptions
Caused by Catastrophic Storms".
New York State Public Service Commission. August 1993" Recommended Decision by
Adrmmstrahve Law Judge Frank S. Robins Case 29389 & Case 92-M-0607.
New York State Public Service Commission. September 1993. Opinion No. 93-20-
Opinion, Order and Resolution Adopting Rulemaking Case 92-M-0607
Northern States Power Company. January 1999. "Report on Undergrounding Electric
Distribution Facilities".
B-1
Ontario Hydro. 1998. "Ice Storm '98:A Report on the Electricity Supply Impacts of the
January 1998 Ice Storm in eastern Ontario."
Public Service Commission of Wisconsin. January 999. Final Envrronmental Impact
Statement-Chisago Electric Transmission Line Project."
Resource Management International. December 1998. "Assessment of Transmission &
Distribution Construction Practices and Their Impact on Public Safety".
State of New York Official Compilation of Codes Rules and Regulations. 1995. Title 16.
B-2