(PG&E-4)
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 6
UNDERGROUND ASSET MANAGEMENT
1
2
3
4
A. Introduction
1. Scope and Purpose
5
The purpose of this chapter is to demonstrate that Pacific Gas and
6
7
Electric Company’s (PG&E or the Company) expense and capital
8
expenditure forecasts for electric underground asset management activities
9
related to the Company’s primary distribution system are reasonable and
10
should be adopted by the California Public Utilities Commission (CPUC or
11
Commission).
PG&E’s electric underground distribution system consists of
12
13
approximately 24,700 circuit miles of primary distribution cable and
14
associated vaults, enclosures, splices, cable connectors and other
15
equipment. Work within the Underground Asset Management Program
16
primarily consists of replacing cable. Other activities include cable injection,
17
validating underground asset information and replacing cable terminations
18
(splices and elbow connectors).
Commission adoption of the expense and capital expenditures that
19
20
PG&E is forecasting for the Underground Asset Management Program is
21
necessary to ensure safe and reliable operation of the Company’s
22
underground assets.
2. Summary of Dollar Request
23
PG&E requests that the Commission adopt its forecasts for the
24
25
Underground Asset Management Program of: (1) capital expenditures of
26
$25.7 million in 2005, $65.4 million in 2006, $64.2 million in 2007, and
27
$63.7 million in both 2008 and 2009; and (2) a 2007 operations and
maintenance (O&M) expense forecast of $100,000. [1]
28
The capital expenditure forecast for 2007 is $47.8 million more than the
29
recorded 2004 expenditures and $54.7 million more than 2003
30
[1]
These capital and expense costs are stated in current year (or nominal) SAP
dollars, as are all dollars referenced in this chapter unless stated otherwise.
6-1
(PG&E-4)
1
expenditures. The 2007 expense forecast is slightly higher than PG&E’s
2
expenditures in 2004.
3
4
3. Support for Request
PG&E’s capital and expense forecasts for the Underground Asset
5
Management Program are reasonable and fully justified because the
6
Company must:
7
Meet compliance requirements;
8
Replace vertical runs of paper insulated lead covered (PILC) cable within
9
10
11
indoor substations;
Replace aging tie-cable circuits in San Francisco and East Bay Divisions;
and
12
Address the increasing number of underground cable failures.
13
The forecasts are reasonable because the Company:
14
15
16
17
18
19
20
21
Effectively uses centralized program management to ensure high priority
work is completed at reasonable costs;
Continues to remedy safety and compliance-related asset conditions and
address reliability performance; and
Is collecting data that will increase its ability to identify and prioritize future
cable replacement work.
4. Organization of the Remainder of This Chapter
The remainder of this chapter is organized as follows:
22
Program Management Process;
23
Estimating Method;
24
Activities and Costs by Major Work Category (MWC);
25
Translation of Program Expenses to Federal Energy Regulatory
26
27
Commission (FERC) Accounts; and
Cost Tables.
6-2
(PG&E-4)
1
B. Program Management Process
1. Objectives
2
The key objectives of the Underground Asset Management Program are
3
4
to ensure safe facilities, meet regulatory compliance, maintain or replace
5
deteriorated facilities in a cost-effective manner, and provide reliable
6
service. In administering its Underground Asset Management Program,
7
PG&E:
8
Replaces aging and/or deteriorated cables;
9
Replaces cables that do not comply with G.O. 128 due to severe concentric
neutral deterioration;
10
Replaces deteriorated brick and mortar vaults (and associated aging cable)
11
to address employee and public safety concerns;
12
Uses silicon[2] injection for cables without significant concentric neutral
13
deterioration to cost-effectively extend the useful service life; and
14
Validates the age and types of cables in PG&E’s underground primary
15
distribution system.
16
2. Challenges of the Underground System
17
a.
18
Overview of PG&E’s Underground Assets
19
Underground cable consists of conductors covered with insulation.
20
There are approximately 57,500 miles of underground primary cable in
21
22
PG&E’s system, consisting of the following approximate single wire
cable lengths by insulation type:[3]
23

1,540 miles of paper insulated lead covered (PILC);
24

12,000 miles of high molecular weight polyethylene (HMWPE);
25

40,000 miles of cross link polyethylene (XLP); and
26

4,000 miles of ethylene polypropylene rubber (EPR).
[2]
[3]
PG&E uses the term “silicon,” but it is actually a proprietary fluid mixture that
includes silicon and other components.
PG&E used a 1999 evaluation to approximate these values. The values are
miles of cable, not circuit miles. The value on p. 6-1 of this chapter is circuit
miles.
6-3
(PG&E-4)
1
PG&E estimates that the majority of PILC cables are 40 or more
2
years old. While PILC cable is dependable and has a very long service
3
life, it is no longer a standard cable type because of its costly and time-
4
consuming splicing requirements and material composition. The
5
majority of PILC cable in PG&E’s system is located in San Francisco
6
and Oakland. PG&E is currently replacing vertical runs of PILC cables
7
within indoor substations and selected tie-cable circuits in San
8
Francisco and Oakland (see Section D.1.b.(1) Tie Cable Circuits for a
9
description of tie cable circuits). The majority of PG&E’s tie-cable
10
circuits include PILC cable.
As the design of underground cable evolved, and cable insulation
11
12
moved from paper wrapping to plastic compounds, underground
13
distribution systems became more prevalent. Early cable designs and
14
applications (based on specifications used throughout the industry
15
during the late 1960s and early 1970s) exhibit the following
16
characteristics:
17

Certain HMWPE and XLP cables experience high failure rates due
18
to “treeing.” Treeing is an insulation breakdown condition caused
19
primarily by the presence of water, manufacturing impurities, and
20
the applied operating voltage. Treeing weakens the insulation level
21
and leads to cable failures.
22

Early cables were manufactured without an outer protective jacket.
23
Without the jacket, the early cables experience faster deterioration,
24
have a higher chance of concentric neutral deterioration, and are
25
more difficult to remove for replacement.
26

Early cable systems were installed as either direct buried (which
27
means they were laid in a trench and buried) or cable-in-conduit
28
installation (consisting of cable in a flexible conduit that was laid into
29
a trench and buried). Unlike the rigid conduit systems PG&E uses
30
today, it is necessary to either re-trench or use directional boring to
31
replace direct buried cable. PG&E also re-trenches or uses
32
directional boring for many of the cable-in-conduit applications due
6-4
(PG&E-4)
1
to physical restrictions of the flexible conduit, which prohibit simpler
2
replacement by re-pulling cable.
Figure 6-1 illustrates the approximate installation history of plastic
cable in PG&E’s service territory.[4]
3
4
5
6
7
8
FIGURE 6-1
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
PLASTIC CABLE INSTALLATION HISTORY
3500
Plastic Cable Installation History
Local Loop
Cable in Circuit Miles
3000
2500
EPR (Duct)
Mainline
XLP (CIC and Duct)
HMWPE (Duct)
2000
HMWPE (CIC)
1500
HMWPE (DB)
1000
500
0
'62-66
'67-71
'72-76
'77-81
'82-86
'87-91
'92-96
'97-01
Year
From an overall system perspective, underground primary
9
11
distribution failures are not a significant contributor to the Company’s
SAIDI and SAIFI reliability indices.[5] However, underground failures
12
are increasing and, ultimately, system reliability performance will
13
deteriorate as these assets age.
10
[4]
[5]
The majority of cable installed since 2001 is EPR in duct.
SAIDI: System Average Interruption Duration Index. SAIFI: System Average
Interruption Frequency Index. In 2004, underground cable failures
contributed 9.4 minutes to SAIDI and 0.06 customer interruptions to SAIFI.
6-5
(PG&E-4)
Figure 6-2 illustrates the increasing trend of underground cable
1
failures during the last ten years.
2
3
4
5
6
FIGURE 6-2
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
CABLE FAILURES, 1994 TO 2004
600
Sustained Outages
500
400
300
Plastic
Paper and Lead
Linear (Plastic)
200
100
7
20
04
20
03
20
02
20
01
20
00
19
99
19
98
19
97
19
96
19
95
19
94
0
b. KEMA and ABB Analysis of PG&E Underground Assets
8
PG&E expects (and industry experience indicates) that the failure
9
rates of cable systems will increase over time. This belief is validated
10
by separate analyses performed by ABB and KEMA, consultants PG&E
11
hired in 2005 to examine underground system failures and their likely
12
effect on system reliability indices in the future. Both ABB and KEMA
13
conclude that increasing underground failures will negatively affect
14
system reliability in the future.
15
KEMA’s analysis indicates that cable failures will increase by a
16
factor of ten during the next 30 years. They estimate that an increase in
17
failures of this magnitude will cause SAIDI to increase by almost
18
70 percent. KEMA claims that proactive cable replacement has the
19
potential to mitigate the impact of aging cables. Specifically, the KEMA
6-6
(PG&E-4)
1
report states “…that about 400 miles of proactive replacement per year
2
is required over the next 35 years to prevent a noticeable worsening of
reliability indices.”[6] However, KEMA acknowledges that the 400 mile
3
5
per year value can be lower if more complete cable installation data is
available.[7] Accumulating additional information regarding cable
6
installations data is an initiative PG&E is currently pursuing, and the
7
8
Company has included expenses to accelerate this activity in the
Company’s forecast.[8] The workpapers supporting this chapter include
9
a copy of the KEMA report.
4
The analysis conducted by ABB indicates the contribution to SAIFI
10
11
and SAIDI values due to underground cable failures will increase on the
12
order of 30 percent in the next ten years. ABB states that the
13
“…cumulative extent (mile-years) of cable exposure could be held
14
steady by replacement of 321 miles of XLPE cable per year and
15
16 miles of PILC cable per year.” ABB recommends that PG&E
16
continue to improve the Company’s inventory of installed cable. The
17
workpapers supporting this chapter include a copy of the ABB report.
18
19
The proactive cable replacement scenarios that KEMA and ABB
discuss in their reports are significant.[9] However, PG&E’s 2007 GRC
20
expenditure forecast does not reflect their scenarios. This is because
21
PG&E agrees with KEMA and ABB that more complete cable
22
installation data will allow PG&E to better focus future expenditures and
[6]
[7]
[8]
[9]
The annual cost of replacing 400 miles per year is approximately
$211.2 million per year (assuming a replacement cost of $528,000 per mile,
which is $100 per foot).
It is possible that more complete data may indicate that a value more than
400 miles per year is appropriate. The point regarding additional data is that
it provides information that will allow PG&E to better focus cable replacement
expenditures. The alternative is a “shot-gun” approach of replacing more
than what is likely necessary, in order to ensure replacement of a portion of
highly suspect cable.
The expense expenditures are forecasted in MWC GE – Operate Distribution
System - Electric Mapping (see Chapter 14 of this exhibit). See also
Section D.2 MWC GB and the Cable Validation Project of this chapter for
additional information.
PG&E also notes that the consultant reports are reliability-centered and do
not consider cable replacement work due to deteriorated concentric neutrals
or other G.O. 128 compliance issues.
6-7
(PG&E-4)
1
therefore optimize the number of miles of proactive replacement.
2
Consequently, it is premature to forecast expenditures for the level of
3
cable replacement KEMA and ABB describe in their reports.
4
Nevertheless, PG&E recommends that the Commission view the KEMA
5
and ABB reports as support for the Company’s expenditure forecast to
6
address aging underground assets. It is clear from their analyses that
7
proactive spending to replace underground cables will need to increase
8
in the future.
PG&E views its 2007 GRC forecast for the Underground Asset
9
10
Management Program as an interim step that accomplishes the
11
following important objectives:
12

Accelerates the accumulation of cable installation data in order to
13
construct a model that will guide future cable replacement
14
expenditures;
15

Allows the Company time to ramp-up expenditures and refine the
16
processes necessary to efficiently manage a large scale cable
17
replacement program;
18

Forecasts spending for work that is clearly necessary such as
19
replacing aging tie-cables, vertically installed runs of PILC cables
20
and underground facilities with known safety and compliance
21
issues; and
22

Forecasts spending to address underground cables that are
23
negatively affecting reliability.
24
After completing the work to accumulate cable installation data
25
(projected completion in 2010), PG&E will have addressed significant
26
portions of vertically installed runs of PILC and aging tie-cables. In
27
essence, PG&E is addressing one set of assets in the short-term
28
(tie-cables and vertically installed runs of PILC) while collecting data on
29
another set of assets (primarily plastic cable). After accumulating the
30
data, the Company can use that information to develop a targeted
31
replacement plan and begin to transition resources from replacing tie-
32
cables and vertically installed PILC cables to other aging underground
6-8
(PG&E-4)
1
assets, with the idea of performing the amount of work necessary to
2
maintain system reliability indices at a constant level.
c.
3
Comparison to SCE
PG&E’s underground system is not unique with respect to cable
4
5
types, ages, types of construction and failure modes and rates.
6
7
Southern California Edison’s (SCE) 2006 GRC testimony and the
information in this chapter are similar in the following ways: [10]
8

Cable types (pp. 25-26);
9

Failure modes (pp. 26-27);
10

Trends in circuit interruptions due to cable failure (p. 30); and
11

Increased expenditure forecasts to replace cables (p. 31).
Electric utilities in California and across the country are facing an
12
13
increasing need to address aging underground cable systems. In light
14
of the increasing number of failures at PG&E and indications of similar
15
issues with other underground distribution systems throughout the
16
industry, PG&E believes its forecasts for 2005 through 2009 are
17
reasonable. PG&E anticipates it will continue to forecast significant
18
levels of spending in future rate cases to address its aging underground
19
infrastructure.
d. Cable Validation Project
20
22
As the KEMA and ABB reports state, the availability of data is an
important element in better understanding underground assets. [11]
23
PG&E understood this even before hiring KEMA and ABB and initiated
24
the Cable Validation Project in 2003. The Cable Validation Project is
25
collecting important information regarding underground cables and
26
updating the Company’s Centralized Electric Distribution System Assets
27
database (C-EDSA).
21
While C-EDSA contains data on the vast majority of underground
28
cable in PG&E’s system, the data in C-EDSA is most often just the
29
[10]
[11]
Page references are to SCE-3, Volume 3, Part III, Section I.D.9.
KEMA report, PG&E Aging Cable Modeling and Scenario Analysis, dated
July 6, 2005, pp. 30-32. ABB report, Statistical Failure Analysis of
Underground Cables, dated June 16, 2005, pp. 51-52.
6-9
(PG&E-4)
1
cable length, conductor size and relative location in the circuit.
2
Approximately 81 percent of the underground line sections in C-EDSA
3
do not indicate the year of installation or cable type, particularly for
4
pre-1990 installations. Year of installation and cable type are critical
5
pieces of information to effectively manage underground assets and
6
7
create prioritization models. The cable validation project will update
C-EDSA by gathering the following data:[12]
8

Year of installation;
9

Primary conductor insulation type and size;
10

Construction installation type; and
11

Line length.
While the lack of certain data is unfortunate, it is understandable
12
13
when viewed in the context of the creation of C-EDSA. What is known
14
today as C-EDSA began in the late 1960s, well before the development
15
of the asset management concepts PG&E and other utilities use today.
16
Then, as now, it served as a primary distribution connectivity model.
17
The Company uses C-EDSA for a variety of purposes such as
18
distribution load flows, protection studies, franchise tax purposes and
19
outage reporting. Consequently, the focus was on connectivity, not
20
asset management. Indeed, if a cable section failed in the 1980s and
21
was replaced like-for-like, it is very possible that no year-of-installation
22
entry was made in C-EDSA because the connectivity information in the
23
database was unaffected.
PG&E is not unique with respect to the unavailability of certain data
24
25
regarding underground assets. As part of the work it performed for
26
PG&E, KEMA surveyed other large utilities in North America. Of the
27
utilities responding to KEMA’s survey, less than half report having data
28
regarding the age of their underground cables. Even within PG&E, the
29
unavailability of data for asset management purposes is not unique to
30
cable. For example, to better understand its pole assets, PG&E
[12]
PG&E anticipates it will gather most of this data by reviewing existing facility
maps and original construction documentation the Company has at its
operating centers.
6-10
(PG&E-4)
1
conducted a pole inventory program. To better understand and analyze
2
substation equipment, substation personnel have created databases
3
with extensive information.
PG&E plans on completing the Cable Validation Project in 2010.
4
5
The data it collects will allow PG&E to more effectively manage its
6
underground assets. PG&E will be able to better identify, analyze and
7
prioritize underground asset work. See Section D for additional details.
3. Planning and Budgeting Process
8
The Underground Asset Management Program primarily consists of:
9
10
(1) capital investment for cable replacement work; and (2) minor
11
expense-related activities and the Cable Validation Project (a MWC GE
12
expense item). Capital investment in this program includes cable
13
replacement by re-pulling new cable within the existing infrastructure,
14
trenching and installing new distribution facilities, and injecting silicon into
15
the cable to restore its insulation strength. Upgrades of switches,
16
transformers and other equipment can also occur with cable replacement
17
projects.
This program’s expense work includes: (1) replacing splices and elbow
18
19
connectors, testing new underground fault indicators and cable diagnostic
20
technologies and monitoring the gas consumption of low-pressure, gas-filled
21
cable; and (2) validating the age, type and construction of existing
22
underground cables to better identify, analyze and prioritize underground
23
asset work.
24
25
The Underground Asset Management Program does not include
upgrading underground assets to increase capacity.[13] Replacing
26
underground cable to increase capacity is managed in the Electric
27
Distribution Capacity Program (MWC 06) described in Chapter 7 of this
28
exhibit. The Underground Asset Management Program also does not fund
29
the immediate repairing or replacing of assets that fail in the field resulting in
30
customer outages. Those activities are managed by the Emergency
31
Recovery Program described in Chapter 12 of this exhibit. However, the
[13]
Occasionally, a MWC 56 project replaces a cable that is both aged/
deteriorated and overloaded.
6-11
(PG&E-4)
1
program does cover the repair or replacement of underground assets that
2
fail but do not require immediate replacement or repair as part of an
3
emergency outage restoration.
4
a.
Five-Year Plan
5
PG&E determined its forecasts for the Underground Asset
6
Management Program as part of the Company’s five-year planning
7
process. That process entails the following steps:
8

The 18 local planning groups identify work requirements based on
field test results, historical component performance, and ongoing or
9
previously identified projects;
10

11
Local planners create cost estimates using unit costs or costs of
similar projects and engineering judgment;
12
13

The prioritization of projects and expenditures; and
14

The Program Manager works with the Transmission and Distribution
15
(T&D) Finance Team to determine a funding level based on the
16
amount of safety-related work identified, historical spending,
17
reliability performance, system priorities relative to other programs,
18
and professional judgment. PG&E’s program directors and the
19
T&D Finance and Resource Teams revise the plan as needed
20
before submission to the T&D Board and PG&E senior
21
management for approval in the fall (as discussed in Chapter 1,
22
Distribution Operations Policy, of this exhibit).
b. Budgeting Changes in MWC 56 Since the 2003 GRC
23
25
The vast majority of PG&E’s electric distribution system consists of
radial circuits.[14] Underground radial circuits have two basic
26
components: main lines and laterals. The main line, as the phrase
27
indicates, is the portion of the circuit that carries the bulk of the load.
28
Main lines exist to provide power to laterals and to interconnect with
24
[14]
Radial circuits have only one path between each customer and the
distribution substation. A circuit interruption results in a loss of power to the
customers. PG&E’s radial circuits are typically interconnected, but operate
radially by open points (typically switches) at various points on the circuit.
PG&E also have network and tie-cable circuits in San Francisco and
Oakland.
6-12
(PG&E-4)
1
main lines from other radial circuits (via normally open switches).
2
Laterals connect to the main line and carry smaller portions of power
3
from the main line to customers. Underground laterals come in
4
two varieties: radial and looped. An underground radial tap is a spur
5
from the main line that feeds one or more distribution line transformers.
6
An underground radial tap has one source of power from the main line.
7
An underground loop is two (or more) spurs from a main line that tie
8
together. Therefore, an underground loop has at-least two sources of
9
power from the main line.
10
Underground cable failures occur on both main lines and laterals.
11
When a main line failure occurs, PG&E restores service to as many
12
customers as possible by switching, replaces the failed section of cable
13
and completes the service restoration process. There are usually no
14
feasible alternatives when a section of main line fails—the failed section
15
requires immediate replacement. The method for dealing with failures
16
on underground radial taps is the same as main lines. Immediate
17
replacement is necessary because there is only one source of power
18
and customers are without service until the damaged section is
19
repaired.
20
A failure on an underground loop provides more flexibility for service
21
restoration than a main line or radial tap failure. Since a loop has two
22
sources from the main line, it is sometimes possible to restore service
23
without having to immediately replace or repair the failure. Figure 6-3
24
illustrates these loop restoration concepts.
6-13
(PG&E-4)
1
2
3
4
5
FIGURE 6-3
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
CABLE FAILURE IN LOCAL LOOP SYSTEM
Figure 6-3 is a simplified diagram of a local loop system. The local
6
loop system in this diagram serves six transformers. Under normal
7
operating conditions (the top diagram), switch #1 feeds three
8
transformers (Tx 1, Tx 2 and Tx 3) and switch #2 feeds the other three
9
(Tx 4, Tx 5 and Tx 6). There is a normal open switch between these
10
two groupings of transformers (switch #3). In this example an
11
underground cable failure occurs between transformers 2 and 3. To
12
restore service (the bottom diagram), PG&E personnel isolate the cable
13
between transformers 2 and 3. Switch # 3 is closed to restore service to
14
transformer 3. After completing this work, switch #1 is serving two
15
transformers (Tx 1 and Tx 2) and switch # 2 is serving four transformers
16
(Tx 3, Tx 4, Tx 5 and Tx 6).
17
When failures on underground loops occur and the nature of the
18
failure requires immediate replacement/repair, that work is charged to
19
MWC 17 – Emergency Response or BH – Corrective Maintenance.
6-14
(PG&E-4)
1
When a failure on an underground loop occurs and immediate repair is
2
not necessary, as described in the preceding paragraph and illustrated
3
in Figure 6-3, the failed cable is placed on the Equipment Requiring
4
Repair (ERR) list and becomes an “ERR Cable Replacement Project.”
5
Assigning work of this nature to the ERR list allows PG&E to schedule
6
and perform the necessary corrective action during normal business
7
hours.
8
9
Prior to 2005, the expenditures for ERR Cable Replacement work
were charged to MWC 57 – Capital Preventive Maintenance by an
10
Electric Preventive and Corrective Maintenance tag (EPCM tag), and
11
managed by the Company’s Electric Distribution Maintenance Program.
12
As Chapter 2 of this exhibit describes, the maintenance program is
13
predominantly focused on performing a high volume of work at a low
14
cost and consequently a low unit cost on a per tag basis. However,
15
cable replacement work is expensive, especially when compared with
16
typical EPCM tag work which is more frequently overhead in nature and
17
costs much less to address. Consequently, performing primary cable
18
replacement work on EPCM tags was increasing the unit cost for
19
completed EPCM tags in general. The upward pressure ERR cable
20
replacement projects were placing on the unit cost for EPCM tags
21
resulted in the unintended and undesirable behavior of division
22
personnel scheduling cable replacement tags too far out in the future.
23
The capital replacement work of ERR cable sections is identical to
24
the cable replacement work performed under MWC 56. In order to
25
provide a more uniform approach and to better align the investments for
26
underground cable assets, PG&E began charging the ERR cable
27
replacement work to MWC 56 in 2005. Transferring the responsibility of
28
managing this work from the Electric Distribution Maintenance Program
29
to the Underground Asset Management Program allows the application
30
of a more consistent prioritization scheme and will place a greater focus
31
on returning sections of cable to service sooner.
32
See Section D for specific units of work and financial information.
6-15
(PG&E-4)
1
C. Estimating Method
2
PG&E’s capital forecast for proactive cable replacement work is primarily
3
based on project cost estimates. The workpapers supporting this chapter list
4
specific projects the Company plans to construct between 2005 and 2009. The
5
project cost estimates were either based on engineering estimates of the
6
necessary work, unit cost data, costs from similar projects or a combination of
7
these elements. The forecasts for 2007 through 2009 also include expenditures
8
for projects yet to be specified (identified as such in the workpapers). The
9
majority of forecast expenditures for unidentified projects occur in 2008 and
10
2009. PG&E includes these amounts in the forecast because it is reasonable to
11
assume, based on the increasing number of cable failures (see Figure 6-2,
12
earlier in this chapter) and the KEMA and ABB analysis, that a steady stream of
13
expenditures is necessary to address the Company’s aging underground assets.
14
The capital forecast for ERR cable replacement work is based on analysis of
15
pending work, an estimated amount of future work and the application of a unit
16
cost. The expense forecast for 2007 was based on 2004 expenditures.
17
18
19
20
21
See Section D for details regarding the Company’s capital and expense
forecast.
D. Activities and Costs by MWC
Table 6-1 shows the MWCs under the Underground Asset Management
Program.
22
23
24
25
TABLE 6-1
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
MAJOR WORK CATEGORIES
Line
No.
26
27
MWC
1
Capital MWCs
2
Capital-MWC 56
3
Expense MWCs
4
Expense-MWC GB
Title
Cable Replacement
Splice/Connector Replacement
The following section describes the work activities and expenditure forecast
for each MWC.
6-16
(PG&E-4)
1. MWC 56 – Cable Replacement
1
2
Cable replacement is the non-emergency related replacement of
3
primary distribution cables by: (1) pulling new cable through the existing
4
infrastructure; or (2) trenching or boring, and installing new distribution
5
equipment. The work activities include trenching and excavation work,
6
installing new enclosures and conduits, splicing cable, and replacing other
7
distribution equipment such as transformers or switch devices. PG&E also
8
uses injection as a means of rejuvenating cable insulation and is an
9
alternative to replacement.
PG&E’s 2007 GRC forecast consists of projects that replace: (a) tie-
10
11
cable circuits comprised of aging PILC and low pressure gas filled cables;
12
13
(b) vertical runs of PILC cables in indoor substations; (c) cables with severe
concentric neutral deterioration or other G.O. 128 compliance issues; [15]
14
(d) cables with a history of poor reliability due to a high number of failures;
15
and (e) ERR cable replacement work as discussed in Section C.3.b,
16
Budgeting Changes in MWC 56.
17
a.
Recent Expenditure Patterns in MWC 56
PG&E’s MWC 56 capital expenditures have increased steadily from
18
19
2001 to 2004. In 2001, PG&E spent $2.1 million. In 2002, the
20
Company increased spending three-fold, to $6.7 million. MWC 56
21
expenditures in 2003 were $9.5 million, a 40 percent increase over the
22
2002 value and $481,000 over the 2003 GRC test-year forecast of
23
$9.0 million. In 2004, PG&E spent $16.4 million, exceeding 2003
24
expenditures by 73 percent. Figure 6-2 shows this increasing level of
expenditures.[16]
25
[15]
[16]
For example, in downtown Stockton, PG&E is replacing unsafe vaults made
of deteriorating bricks held together with extensively cracked mortar. As part
of this project, PG&E is also replacing approximately 4,000 circuit feet of
cable.
The values in Figure 6-4 are from Table 6-2, excluding estimated past
expenditures for ERR cable replacement work.
6-17
(PG&E-4)
1
2
3
4
FIGURE 6-4
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
MWC 56 CAPITAL EXPENDITURES, 1997-2004
18000
16000
14000
Costs x $1000
12000
10000
Recorded
Linear (Recorded)
8000
6000
4000
2000
0
1997
1998
1999
2000
2001
2002
2003
2004
Year
PG&E’s 2005 capital forecast is $25.7 million, a 56 percent increase
5
over 2004.
6
b. MWC 56 Forecast
7
Table 6-2 shows PG&E’s 2005 through 2009 forecast for MWC 56,
and recorded 2000 through 2004 expenditures. [17] The table presents
8
9
10
capital expenditure data using the following categories:
11

Tie-cable circuits;
12

Vertical runs of PILC cables;
13

Compliance related (e.g., severe concentric neutral deterioration);
14

Reliability related (i.e., high number of failures, both PILC and
plastic insulation); and
15

16
[17]
ERR Cable Replacement.
PG&E did not separately track expenditures for ERR Cable Replacement
work during 2000-2004. The values in Table 6–2 are estimates. The
workpapers explain the estimating methodology.
6-18
1
2
3
4
5
TABLE 6–2
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC DISTRIBUTION UNDERGROUND ASSET MANAGEMENT
MWC 56 HISTORICAL AND FORECAST CAPITAL EXPENDITURES
($000)
Line
No.
1
2
3
4
5
6
MWC
56
56
56
56
56
56
Description
Tie Cable Circuits
Vertical Runs of PILC Cables
Compliance
Reliability – Plastic
Reliability – Lead
ERR Cable Replacement(a)
7
56
Total
_______________
(a)
2000
Actual
2001
Actual
2002
Actual
2003
Actual
2004
Actual
$1,125
$1,448
$1,128
2,449
246
988
$133
1,836
128
1,379
1,987
3,639
4
2,454
1,575
4,630
1,828
3,526
$5,856
2,295
3,937
2,504
1,830
2,768
$4,811
$3,476
$9,209
$13,007
$19,190
2005
Forecast
2006
Forecast
2007
Forecast
2008
Forecast
2009
Forecast
$8,165
4,160
7,341
4,139
1,695
2,000
$28,390
4,785
11,511
11,643
3,671
5,425
$22,930
3,410
11,089
13,875
8,697
4,150
$15,406
2,090
13,370
15,203
13,931
3,725
$10,908
–
13,800
18,042
17,250
3,725
$27,500
$65,425
$64,150
$63,725
$63,725
The values for 2000-2004 are estimates.
6-19
(PG&E-4)
(PG&E-4)
The workpapers supporting this chapter provide a list of projects
1
2
that correspond to the categories in Table 6-2. The list represents
3
PG&E’s best estimate of the specific MWC 56 projects the Company
4
will perform in the coming years. The workpapers also identify the year
5
PG&E anticipates constructing a project. It is important to note that the
6
timing of a specific project can change as a result of the Company
7
identifying another MWC 56 project that is more urgent (e.g., multiple
8
outages in an area with underground facilities that was previously
9
problem free), the scope of a project changing significantly during the
10
estimating or construction process (e.g., a cable replacement project
11
encounters unforeseen asbestos mitigation work, or cables that
12
personnel can not remove and replace due to a collapsed duct ), and
13
the Company’s continuing analyses of underground asset information.
14
Such occurrences will require PG&E to re-prioritize and re-schedule the
15
projects listed in the workpapers.
The following sections briefly describe each of the categories from
16
17
Table 6-2. While the categories are useful in understanding PG&E’s
18
forecast, some projects can easily fall into different categories. For
19
example, a section of line with a deteriorated neutral (a “compliance”
20
project) may also be experiencing multiple failures (a “reliability”
21
project).
22
(1) Tie Cable Circuits
Tie cables are 12 kV circuits that feed other distribution
23
25
substations. The substations they feed serve customers from their
own 4 kV and 12 kV radial circuits. Unlike radial or network[18]
26
circuits, tie-cable circuits do not serve customers directly (i.e., there
27
are no distribution line transformers connected to tie cable circuits).
28
Tie-cable circuits are also different from radial circuits because they
29
are operated in parallel. This means that under normal operating
30
conditions, multiple tie-cables supply the same substation such that
31
the failure of a single tie-cable will not cause an outage to the
24
[18]
Portions of downtown San Francisco and Oakland are served by network
groups. Network circuits provide multiple sources of power to network
groups.
6-20
(PG&E-4)
2
substation it feeds. It is reasonable to think of 12 kV tie cable
circuits as providing the same function as transmission lines.[19]
3
As an example, there are four tie-cables that connect Mission
4
Substation in downtown San Francisco (Mission and Eighth Streets)
5
to Station G which is located several miles away, near Ellis and
6
Broderick Streets. While these tie cables do not directly feed any
7
customers, Station G serves approximately 18,000 customers in the
8
western part of the city.
1
There are 47 tie cable circuits in PG&E’s San Francisco and
9
10
East Bay Divisions. Figure 6-5 is graphical representation of
11
tie-cable circuits and the substations they supply in San Francisco
12
Division.
[19]
While it is correct to think of tie cables as 12 kV transmission lines, PG&E
notes that these lines do not fall under the operational jurisdiction of the
California Independent System Operator and do come under the jurisdiction
of the CPUC for rate making purposes.
6-21
(PG&E-4)
1
2
3
4
5
FIGURE 6-5
PACIFIC GAS AND ELECTRIC COMPANY
UNDERGROUND ASSET MANAGEMENT PROGRAM
SAN FRANCISCO DIVISION TIE CABLE CIRCUITS
PG&E’s tie cables primarily consist of PILC cable. As noted in
6
Section B.2.a., Overview of PG&E’s Underground Assets, PG&E
7
estimates that the majority of PILC cables are 40 or more years old.
8
PG&E’s tie-cable circuits are no exception.
9
While the tie-cable systems have provided highly-reliable
10
service for many years, it is not reasonable to assume that this will
11
continue indefinitely. As KEMA’s analysis indicates, PILC cable
12
failures are increasing. Even though the number of failures is
13
increasing, the current effect of tie-cable failures on SAIFI and
14
SAIDI has been negligible because of the redundancy inherent in
6-22
(PG&E-4)
1
the system. Ultimately though, the number of failures will increase
2
and the redundant nature of the system will be insufficient to
3
preserve current levels of reliability. This concern is best expressed
4
by explaining how specific attributes of tie-cable circuits influence
5
the repair time when failures occur.
Tie cable failures can take several days to repair. First, it is
6
7
necessary to locate the failure. Unlike radial circuits, which have
8
numerous switches to facilitate load transfers and other operating
9
needs, most tie-cable circuits have few, if any, switches because it
10
was not necessary (nor required) to design tie-cable circuits to allow
11
direct load transfers. This means repair crews must go into
12
13
manholes and break-apart the tie-cable to apply fault finding
devices.[20] Second, it usually takes more time to replace or repair
14
PILC cable than it does plastic cable. Whether the crew replaces
15
the failed PILC cable section with plastic cable or installs a new
16
17
section of PILC cable, it can take a day or more to pull the cable
and construct the necessary splices.[21] Factors such as traffic and
18
the difficulty of working in the confined space of a manhole
19
contribute to the amount of time it takes to make repairs.
Failures can also occur when the tie-cable system is abnormally
20
21
configured to facilitate necessary work. This concept is illustrated
22
by an event that occurred on December 17, 2004. The FY-1 tie
23
cable between Larkin Substation and Marina Substation (Station F
24
in Figure 6-5) was de-energized to allow construction personnel to
25
rearrange tie cable circuits as part of a project that is addressing
26
seismic issues at Station I. While personnel were performing their
[20]
[21]
Installing switches might provide some benefit, but is not a complete answer
because the manholes where the switches must be installed are often space
constrained. Another downside to this is the addition of more components
(additional PILC cable, perhaps to plastic-to-lead transition splices and the
switch) that can potentially fail. Because tie-cables do not serve customers
directly, the ideal situation is to install them from substation to substation with
as few devices and splices as possible since each component is a potential
source of future failure.
Splicing PILC cable is a craft that involves the application of molten lead and
other material.
6-23
(PG&E-4)
1
work, the FY-2 cable failed. This resulted in an outage to over
2
13,000 customers. Ultimately, because of the time it takes to repair
3
tie-cable failures, the likelihood of multiple failures resulting in an
4
outage to customers increases as the failure rate of PILC cable
5
increases.
6
Between 2002 and 2004 PG&E spent $8.4 million to replace
7
aging tie-cables. PG&E’s forecast for MWC 56 includes a total of
8
$85.8 million to replace aging tie cables million between 2005 and
9
2009 (see the workpapers supporting this chapter for details).
10
Considering the age of the cables (over 70 years old in some
11
instances), the increasing failure rates, and the number of
12
customers these facilities serve in densely populated urban areas
13
(tens of thousands customers in San Francisco, Oakland and
14
Berkeley), refurbishing the tie-cable systems is a reasonable and
15
necessary first step to address aging underground assets in a
16
significant manner.
17
18
(2) Vertical Runs of PILC Cables
On December 20, 2003, a cable failure inside of Mission
19
Substation in San Francisco caused a fire that led to the interruption
20
of service to over 100,000 customers. PG&E’s investigation of the
21
event found that, over time, the particular application of PILC cable
22
(40 years in a vertical position) caused the cable to lose its
23
insulating capability. This caused the cable to fail and was the
24
initiating event of the fire. Based on laboratory analysis, the cable
25
failed due to degraded insulation in the oil-impregnated paper
26
separating the conductors inside the cable. The degraded
27
insulation led to an electrical arc, which exploded through the
28
copper and lead sheath around the cable.
29
In response to this finding, PG&E is replacing vertically installed
30
runs of PILC cable in other indoor substations. PG&E spent
31
$2.3 million to perform this work in 2004 and estimates it will spend
32
an additional $14.4 million between 2005 and 2008.
6-24
(PG&E-4)
1
2
(3) Compliance
PG&E’s forecast for MWC 56 includes projects that address
3
known compliance and safety issues. Most of the projects in this
4
category address deteriorating concentric neutrals. The
5
deterioration of a concentric neutral is a G.O. 128 violation and
6
possible safety hazard.
7
Another compliance issue is cover. Primary cable with less
8
than 24 inches of cover is also a G.O. 128 violation. Some of the
9
compliance projects PG&E includes in its forecast are for instances
10
where erosion has reduced the minimum amount of necessary
11
cover.
12
In addition to projects relating to meeting G.O. 128
13
requirements, this category also includes an ongoing project in
14
downtown Stockton where PG&E is replacing unsafe vaults made of
15
deteriorated bricks held together with extensively cracked mortar.
16
As part of this project, PG&E is also replacing cable and converting
17
some sections of primary from 4 kV to 12 kV. The deteriorated
18
vaults will be filled with sand after the new infrastructure is
19
constructed.
20
PG&E spent $3.9 million performing compliance related work in
21
2004 and estimates it will spend a total of $57.1 million between
22
2005 and 2009.
23
(4) Reliability
24
This category provides PG&E’s forecast for replacing cable
25
because of age and type (e.g., the HMWPE cable discussed earlier
26
in this chapter or aging PILC cable on radial circuits), multiple
27
failures, or a combination of these factors and other influences such
28
as splice and connector failures. Projects in this category are
29
identified by distribution engineers who are knowledgeable about
30
the performance of underground facilities in their division.
31
This category also includes cable-injection related work. Cable
32
injection involves injecting a fluid between the conductor and the
33
insulation to fill voids created by “treeing” conditions. The injection
34
fluid polymerizes with the water in the insulation and fills the “tree”
6-25
(PG&E-4)
1
condition, restoring its insulating properties. PG&E is not
2
forecasting a significant amount of cable injection because the
3
Company is identifying more work that requires cable replacement.
4
PG&E’s forecast includes two cable injection projects in 2005 for
5
approximately $335,000.
6
PG&E spent $4.3 million performing reliability related work in
7
2004 and estimates it will spend a total of $108.1 million between
8
2005 and 2009
(5) ERR Cable Replacement
9
As described in Section B.3.b “Budgeting Changes in MWC 56
10
11
Since the 2003 GRC,” PG&E is now charging expenditures for ERR
12
cable replacement work in MWC 56. Prior to 2005, these
13
expenditures were charged to either MWC 17 or MWC 57. PG&E
14
anticipates that this change will facilitate a more consistent
15
prioritization scheme and will place a greater focus on returning
16
sections of cable to service sooner.
Prior to 2005, PG&E did not separately track expenditures for
17
18
this cable replacement work. Consequently, it was necessary to
19
estimate historical expenditures for this work. PG&E estimated past
20
expenditures by analyzing Electric Preventive and Corrective
21
Maintenance (EPCM) tags from the years 2000 to 2004. Table 6-2
22
contains the results of this analysis (the workpapers include a
23
detailed description of the analysis and supporting data).
To develop the forecast for 2005 and beyond, PG&E identified
24
26
the number of pending ERR cable replacement tags that will now be
charged to MWC 56.[22] In addition to this pending work, the
27
Company estimates that approximately 60 new ERR cable
28
replacement tags will occur each year. PG&E used this volume of
29
work and a unit cost of $43,000/tag to calculate the forecasted
30
amounts in Table 6-2. The unit cost is based on cost-estimates
31
PG&E prepared for projects the Company plans to construct in
32
2005.
25
[22]
As of June 2005, there are 144 ERR cable replacement projects pending.
6-26
(PG&E-4)
2. MWC GB and the Cable Validation Project
1
This section of testimony describes Underground Asset Management
2
3
program expense activities. It also provides additional details regarding the
4
previously discussed Cable Validation Project (the costs for the Cable
5
Validation Project are captured in MWC GE, which is covered in Chapter 14
6
of this exhibit). Table 6-3, at the end of this section, shows the expense
7
forecast for MWC GB for 2005 through 2007 and the 2000 through 2004
8
actual expenses.
9
a.
MWC GB – Splice/Connector Replacement
MWC GB encompasses the expense activities in the Underground
10
11
Asset Management Program. The work in MWC GB has historically
12
consisted of replacing underground splices and connectors. In 2002
13
through 2004, splice and connector performance did not require the
14
Company to incur significant expenses to proactively replace these
15
components. Consequently, PG&E’s spending in MWC GB was less
16
than $100,000 per year during 2002 to 2004.
17
PG&E’s 2007 GRC forecast for MWC GB is $100,000 per year for
18
2005 through 2007 and is consistent with 2004 actual expenses. This
19
20
forecast will cover expenses to monitor the gas consumption of
low-pressure, gas-filled tie-cables,[23] purchase and test new
21
underground fault indicators, evaluate diagnostic tools that assess cable
22
condition and proactively replace cable terminations such as elbows
23
and splices.
b. Cable Validation Project
24
25
As PG&E explained in Section B.2.d., “Cable Validation Project”
26
earlier in this chapter, the Cable Validation Project updates underground
27
cable information in C-EDSA, the Company’s primary distribution
28
system database. Obtaining and entering data relating to the year of
[23]
As previously described, most of the tie cables in San Francisco and East
Bay Divisions are PILC. However, there are a small number of cables that
are low-pressure, gas-filled. Low-pressure, gas-filled cables use nitrogen as
part of their overall insulation system and represent a sub-category of the
PILC cable family. These cables require a constant feed of nitrogen gas and
PG&E monitors gas consumption at various locations.
6-27
(PG&E-4)
1
installation and cable type (and other pieces of information) are critical
2
for managing underground assets and creating prioritization models.
3
To do this work, division mapping personnel are using circuit maps
4
to systematically compare and validate the data in C-EDSA. They
5
conduct the validation, circuit-by-circuit, until all of the characteristics of
6
the underground primary cable are validated via local maps and job
7
files.
8
9
Through 2004, 18 percent of the system has been validated.
Chapter 14 of this exhibit forecasts an additional $1.4 million (in
10
MWC GE) in 2007 to accelerate this effort. PG&E anticipates the entire
11
Validation Project will cost $6.2 million. Increasing the level of spending
12
will allow PG&E to finish by 2010. PG&E believes this increase is
13
reasonable in light of the trends in underground failures and the
14
conclusions ABB and KEMA reached in their reports. Completing this
15
work sooner will allow the Underground Asset Manager to analyze,
16
identify and prioritize cable replacement projects with greater precision.
6-28
TABLE 6–3
PACIFIC GAS AND ELECTRIC COMPANY
ELECTRIC DISTRIBUTION UNDERGROUND ASSET MANAGEMENT
EXPENSES BY MAJOR WORK CATEGORY
($000)
Line
No.
1
2
MWC
GB
Description
2000
Actual
2001
Actual
2002
Actual
2003
Actual
2004
Actual
2005
Forecast
2006
Forecast
2007
Forecast
UG Expense Activities
$487
$211
$79
$83
$98
$100
$100
$100
Total
$487
$211
$79
$83
$98
$100
$100
$100
1
6-29
(PG&E-4)
(PG&E-4)
1
E. Translation of Program Expenses to FERC Accounts
As discussed in Exhibit (PG&E-1), Chapter 2, PG&E’s program managers
2
3
manage their program costs using the SAP view of cost information, not the
4
FERC account view. Thus, for presentation in this GRC, certain SAP dollars
5
6
must be translated to FERC dollars. This is not an issue for capital costs where
the SAP and FERC views are identical.[24] For O&M expenses, however, the
7
SAP dollars include certain labor-driven adders such as employee benefits and
8
payroll taxes that are charged to separate FERC accounts. These labor-driven
9
adders must be removed from the SAP dollars for O&M expenses to present
them by FERC account.
10
Tables 6-6 and 6-7 show how the SAP expense dollars in the Underground
11
12
Asset Management Program translate to the appropriate FERC accounts.
13
Table 6-6 shows dollars stated in current year dollars (i.e., nominal dollars).
14
Table 6-7 shows dollars stated in base year dollars (i.e., 2004 dollars). The
15
calculations used to deflate the nominal dollars to 2004 dollars (which requires
16
segregating them into their labor and non-labor components) are shown in the
17
workpapers supporting this chapter. The O&M expenses shown by MWC in
18
Table 6-5 are summarized in Exhibit (PG&E-2), Chapter 2 on a base year FERC
19
dollar basis. The capital expenditures shown by MWC in Table 6-4 are
20
summarized in Exhibit (PG&E-2), Chapter 8.
21
F. Cost Tables
The capital and expense requests for the Underground Asset Management
22
23
Program are summarized in the following tables:
24
Table 6-4 lists the capital work by MWC showing the recorded 2004 capital
expenditures and the 2005 through 2009 forecasts;
25
Table 6-5 lists the expense MWC GB, showing 2004 recorded expense and the
26
27
2005 through 2007 forecasted expense in SAP dollars stated in current year
28
dollars;
[24]
Capital costs are typically shown in rate case filings with overheads (i.e., SAP
“adders”) included, such as capitalized employee benefits and payroll taxes.
6-30
(PG&E-4)
1
Table 6-6 displays the translation of the expense MWC GB to appropriate FERC
2
accounts, showing 2004 recorded expense and 2005 through 2007
3
forecasted expense stated in current year dollars; and
4
Table 6-7 displays the translation of the expense MWC GB to appropriate FERC
5
accounts, showing 2004 recorded expense and 2005 through 2007
6
forecasted expense stated in 2004 base year dollars.
6-31