(PG&E-3)
1
2
3
4
5
6
PACIFIC GAS AND ELECTRIC COMPANY
CHAPTER 3
HYDRO OPERATIONS PROGRAM COSTS
A. Introduction
1. Scope and Purpose
The purpose of this chapter is to demonstrate that Pacific Gas and
7
Electric Company’s (PG&E or the Company) expense and capital
8
expenditure forecasts for its Hydro Operations Program are reasonable and
9
should be adopted by the California Public Utilities Commission (CPUC or
10
11
Commission).
PG&E’s hydro system consists of 110 generating units at
12
68 powerhouses. These generating units have a combined maximum
13
normal operating capacity of 3,896 megawatts (MW) and produce an
14
average of 11,672 gigawatt-hours (GWh) per year.
15
Commission adoption of PG&E’s expense and capital forecasts for
16
operating and maintaining the hydro system is necessary to ensure safe,
17
reliable and low-cost generation from these assets in 2007 and beyond.
18
19
2. Summary of Request
PG&E requests that the Commission adopt its 2007 forecast of capital
20
expenditures of $103.6 million to maintain a reliable, low-cost hydro system
21
that produces clean, carbon free, energy to meet California’s needs, while
22
meeting all of the federal, state and local regulatory requirements. PG&E
23
further requests that the Commission adopt its 2007 forecast of
24
$143.9 million of hydro operations and maintenance (O&M) expense.
25
PG&E is also providing specific forecasts for 2008 and 2009 to support
26
the generation attrition proposal in Chapter 13 of this exhibit. PG&E
27
requests that the Commission reflect in the attrition adjustments for 2008
28
and 2009 its O&M expense forecast of $150.8 million for 2008 and
29
$158.5 million for 2009 and its capital forecast of $110.1 million for 2008
30
and $117.3 million for 2009.
3-1
(PG&E-3)
1
3. Support for Request
PG&E’s capital and expense forecasts are reasonable and justified
2
3
because they ensure continued safe, reliable, and environmentally
4
responsible operation of the hydro system. Currently, PG&E:
5

Safely and reliably operates the hydro system in compliance with all
6
state and federal regulations and the Federal Energy Regulatory
7
Commission (FERC) license conditions;
8

Operates and maintains the hydro system to make energy supply
available to meet demand, within the constraints of water usage,
9
10
thereby reducing the overall energy procurement costs charged to
11
customers;
12

collaborative relicensing; and
13
14
Promotes environmental protection, resource stewardship and

Maintains energy and ancillary service capabilities to provide ancillary
15
service products to help meet PG&E’s long term needs.
16
Hydro Operations’ forecast reflects increased 2007-2009 spending
17
associated with the following major business drivers:
18

facility safety and environmental regulations; and
19
20

New regulatory fees imposed on the hydro assets by State and Federal
agencies; and
21
22
License conditions associated with new FERC licenses along with new

Investment in generation efficiency improvements that reduce the costs
23
to PG&E’s customers while increasing California’s source of clean,
24
carbon free, energy; and
25

Automation and other improvements to the hydro infrastructure to
26
comply with new, sometimes complex, license requirements at the least
27
cost.
28
4. Organization of the Remainder of This Chapter
The remainder of this chapter is organized as follows:
29
30

Program Management Process;
31

Estimating Method;
3-2
(PG&E-3)
1

Activities and Costs by Subprogram/Major Work Category (MWC);
2

Translation of Program Expenses to FERC Accounts; and
3

Cost Tables.
4
5
B. Program Management Process
PG&E manages both expense and capital expenditures for its hydro assets
6
through one centralized program. This program consists of six subprograms
7
and uses 16 expense MWCs (regulatory fees are also segregated) and
8
five capital MWCs. This section describes the Hydro Operations Program,
9
including background information on the age and condition of the assets and a
10
description of the support organization. PG&E includes this information to assist
11
the Commission and other participants in the General Rate Case (GRC)
12
proceeding in understanding the expansive nature of the hydro system and the
13
need for a centralized program management approach to ensure that PG&E
14
systematically invests in the highest value-work.
15
1. Overview and History of the Hydroelectric System
16
PG&E’s 68 hydro powerhouses are located on 16 rivers and
17
four tributaries of the Sierra Nevada, Cascade and Coastal mountain
18
ranges, (see work papers; Figure 3-1).
19
These facilities were built between 1898 and 1986. Most of the dams
20
and powerhouses have been in service for well over 50 years, and some of
21
the water collection and transport systems were used for gold mining and
22
consumptive water prior to the development of the hydro system.
23
The hydro system operates under 26 FERC licenses, which govern the
24
operation of 105 generating units at 65 powerhouses, plus five units at
25
three non-FERC jurisdictional powerhouses with a total generating capacity
26
of 3,896 MW. PG&E’s authority to divert and store water for power
27
generation is based on 92 water right licenses or interim permits, and
28
160 Statements of Water Diversion and Use.
29
Each hydro facility was engineered considering the specific river flows
30
and topography of its site. The system collectively includes the following
31
facilities: 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals,
32
44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, 5 miles of natural
3-3
(PG&E-3)
1
waterways, and approximately 140,000 acres of fee-owned land (refer to
2
Chapter 7, Exhibit (PG&E-3) for a discussion of PG&E’s land conservation
3
commitment). It also includes switchyards, switching centers that remotely
4
control generation facilities, administrative buildings, fleet, multiple modes of
5
communication, materials and supplies inventories, office equipment, and
6
other miscellaneous instrumentation and monitoring equipment.
2. Organization and Operational Efficiencies
7
When the older hydro facilities were constructed, they required on-site
8
staff to operate and maintain the generating equipment and water systems.
9
10
Investment in technological advancements automated the hydro system
11
over the past 100 years, so that today only 8 of the 68 hydro powerhouses
12
are manned during normal operations. Seven of these powerhouses serve
13
as hydro switching centers and the eighth is the Helms Pumped Storage
14
Project. These switching centers and Helms are staffed 24 hours a day and
15
have the ability to call for additional hydro personnel as needed.
Powerhouse equipment and water system automation over the past
16
17
decades, including the installation of alarms and controls, have maintained
18
system reliability while reducing the requirement for a number of
19
headquarters, service centers and employee houses. This consolidation
20
has resulted in significant downsizing and cost efficiencies.
The current field organization of hydro operations is built around
21
22
five watersheds:
23

Shasta, which includes six FERC licenses covering 16 powerhouses
with a combined capacity of 810 MW;
24

25
DeSabla, which includes six FERC licenses covering 12 powerhouses
27
with a combined capacity of 756 MW, and three non-jurisdictional
powerhouses[1] with a combined capacity of 8 MW for a total of
28
764 MW;
26

29
Drum, which includes four FERC licenses covering 15 powerhouses
with a combined capacity of 218 MW;
30
[1]
These facilities are outside of FERC’s licensing jurisdiction because they are
located on non-navigable waters.
3-4
(PG&E-3)

1
Motherlode, which includes four FERC licenses covering
eight powerhouses with a combined capacity of 318 MW; and
2

3
Kings Crane-Helms, which includes 7 FERC licenses covering
4
13 conventional powerhouses and the Helms Pumped Storage Facility,
5
with a combined capacity of 1,787 MW.
6
3. Service Centers and Reporting Headquarters
8
Hydro Operations’ O&M personnel are assigned to twelve service
centers and seven reporting headquarters[2] to handle ongoing hydro O&M
9
work. In addition to personnel assigned to the service centers and reporting
7
10
headquarters, the hydro construction field force is mobile and works
11
throughout the system. Hydro Operations’ centralized staff is located in
12
San Francisco.
A series of tables included in the work papers, (Figures 3-2 through
13
14
3-11), list where O&M personnel who have primary responsibility for
15
responding to work assignments throughout the hydro system are located.
16
There are two tables for each watershed region. The first table, titled
17
“Personnel Headquarters,” identifies the locations in each watershed where
18
personnel providing O&M services normally report to work prior to traveling
19
to a remote hydro facility. Work requirements and, hence, staffing vary in
20
relation to the design features of each project. For example, projects with
21
long water conveyance systems require additional water maintenance and
22
water operations personnel.
The second table, titled, “Job Classifications Reporting to Each
23
24
Headquarters,” lists the number of employees in each O&M job
25
classification at each service center or reporting headquarters. These
26
employees handle the watershed’s base workload, including emergency
27
response. The number of employees in the column marked full-time
28
equivalent (FTE) are as of June 2005. Switching centers generally have
[2]
Service centers have administrative offices and may include maintenance
facilities and an inventory of tools, equipment, vehicles, material and
supplies. Each service center has facilities and equipment designed to meet
the needs of the assigned powerhouses. A reporting headquarters serves as
a regular point of assembly for hydro operations personnel, but may not
include any additional facilities. Service centers discussed herein do not
include construction service centers.
3-5
(PG&E-3)
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five to seven operators in one or two classifications.[3] Each of the
2
seven reporting headquarters generally only has one or two operating
3
personnel assigned to them. Service centers can have up to 35 employees
4
in nine classifications. As shown in these tables, there are only a few hydro
5
employees in each classification at each service center.
Hydro Operations’ centralized organization provides oversight and
6
7
direction to ensure that critical resources and personnel are shared between
8
watersheds. This includes a mobile construction organization, which
9
handles major maintenance projects throughout the hydro system and a
10
centralized management team that provides the following services and
11
expertise:
12

Business and information systems;
13

Construction and construction management;
14

Engineering, project management and facility safety;
15

Environmental, health and safety;
16

Land management and recreation facilities management;
17

Licensing, compliance and relicensing;
18

Operations;
19

Maintenance; and
20

Water management.
4. Long-Term Plan (LTP)
21
The LTP, along with Hydro Operations’ condition assessment and work
22
23
management programs, provides data that allows PG&E to assess the
24
physical condition of the assets, identify the projects and resources needed
25
to maintain the facilities properly, and optimizes work schedules and
26
expenditures to minimize the long-term cost of production from these
27
generating facilities. This information is included in the workpapers to this
28
testimony. Benefits resulting from these efforts include:
[3]
Excluding management classifications.
3-6
(PG&E-3)

1
More efficient utilization of Hydro Operations’ maintenance, operation,
planning, design, licensing, and construction staffs;
2

3
Early coordination with support departments to obtain needed
resources;
4
5

More efficient utilization of financial resources; and
6

Determination of the proper level of investment to restore and sustain
hydro assets.
7
5. Value and Use of the Hydroelectric System
8
PG&E’s hydro plants produce low-cost energy, high-value ancillary
9
10
services and peaking capacity to meet customers’ needs. PG&E has
11
demonstrated its ability to optimize these generation facilities through
12
efficient use of water resources and continuing environmental stewardship.
13
This 2007 General Rate Case forecast identifies the actions and costs
14
required to maintain the system’s existing capabilities for the benefit of
15
customers.
16
The California Energy Commission recognizes that
17
18
19
20
21
22
23
24
Hydroelectricity is an important element of California’s energy portfolio,
providing between nine and 30 percent of annual state electricity sales
over the last twenty years. In addition to this share of electric
generation, the hydroelectric system provides peaking reserve capacity,
spinning reserve capacity, load following capacity, transmission support,
and extremely low production costs. These attributes have made and
continue to make hydroelectricity a key element of the state’s
generation system.[4]
a.
25
Meeting PG&E’s Customer’s Energy Needs
PG&E’s hydro system consists of 110 generating units at
26
27
68 powerhouses with a total generating capacity of 3,896 MW, which
28
represents about 28 percent of California’s hydro capacity.
PG&E’s hydro system includes reservoirs which enable PG&E to
29
30
store runoff and aquifer flows and then subsequently use the water to
31
generate power when the customers’ need it most. This “shaping” of
[4]
California Hydropower System: Energy and Environment; Appendix D, 2003
Environmental Performance Report; CALIFORNIA ENERGY COMMISSION,
Prepared in Support of the Electricity and Natural Gas Report under the
Integrated Energy Policy Report Proceeding (02-IEP-01); October 2003;
100-03-018.
3-7
(PG&E-3)
1
the available generation is performed both seasonally (for example, by
2
storing more water in the spring and releasing water from the reservoirs
3
during high value hot summer days) and day-to-day (for example,
4
generating more during hours of peak system demand—typically
5
weekday afternoons and evenings and less at night and on weekends).
6
In general, the highest value of generation is likely to be when PG&E’s
7
demand is greatest, and hydro generation can contribute significantly
8
toward reducing the amount of power that has to be purchased during
9
these higher-price hours.
b. Cost-Effectiveness of Hydroelectricity
10
Hydropower is the most efficient energy resource, with a 90 percent
11
12
conversion rate of transforming hydraulic forces to electricity. Hydro
13
Operations’ operating costs are low and predictable since there are no
14
fuels to purchase. Once the capital costs are recovered, hydro is the
15
most cost-effective energy source in use today. PG&E’s hydro system
16
provides its customers with 3,896 MW of normal maximum operating
17
capacity and 11,672 GWh of energy in an average precipitation year.
18
The continued availability of this hydro power helps meet the system
19
peak load and plays an essential role in controlling energy prices in
20
California. Maintaining these capabilities can further reduce the cost of
21
obtaining energy or ancillary services to meet PG&E's net open position.
c.
22
Load Shaping and Peaking Value of Hydroelectricity
While the primary requirement for electric procurement is to meet
23
24
customer energy demand, PG&E additionally provides or procures
25
ancillary services required to maintain electric grid stability.
The California Independent System Operator (CAISO) requires load
26
27
serving entities to provide or pay for a proportionate share of the
28
ancillary services needed by the CAISO to maintain electric system
29
reliability. PG&E uses hydro to self-provide the following ancillary
services:[5]
30
[5]
The definitions are taken from the website of the CAISO:
http://oasis1.caiso.com/iso/news/FYIMarkets.html.
3-8
(PG&E-3)
1

Regulation “Up” – Generation that is already up and running
2
(synchronized with the power grid) and can be moved via direct
3
electronic commands by the CAISO above the unit’s scheduled
4
output level, to keep system wide energy supply and energy use in
5
balance (Automatic Generation Control (AGC) market);
6

Regulation “Down” – Generation that is already up and running
7
(synchronized with the power grid) and can be moved via direct
8
electronic commands by the CAISO below the unit’s scheduled
9
output level, to keep systemwide energy supply and energy use in
balance (AGC market);
10
11

dispatched within 10 minutes;
12
13

Non-Spinning Reserves – Unloaded offline generation that can be
dispatched within 10 minutes; and
14
15
Spinning Reserves – Unloaded online generation that can be

Replacement Reserves – Generation that can begin contributing to
16
the grid within an hour.
17
PG&E maximizes the availability of these capabilities by operating
18
the majority of the hydro facilities as peaking facilities. This operating
19
strategy helps meet daily changes in system demands and preserves
20
hydro's rapid dispatch and spinning reserve capabilities for use during
21
higher value periods. Hydroelectric generating units typically start up
22
quickly, have high ramp-rates, and can easily, quickly, and economically
23
vary output in response to changing customer loads and system
24
conditions. In addition, hydro generating units can operate at no-load or
25
low-load with much higher efficiency than the alternative fossil-fueled
26
peaking plants. Finally, because a large portion of California's
27
non-fossil-fueled electricity resources consist of non-dispatchable
28
energy sources such as wind, solar, nuclear and regulatory “must-take”
29
generation, the CAISO relies on PG&E’s hydro resources to satisfy a
30
large portion of its operating reserve requirements.
31
The hydro system provides 90 percent of the ancillary service
32
capabilities required by the CAISO for PG&E’s service territory. This
3-9
(PG&E-3)
1
means PG&E is usually able to self-provide the required ancillary
2
service capability and thus eliminate the need to purchase supplemental
3
capabilities from the market.
4
d. Reliability of Hydroelectricity
5
Hydroelectric generation has one of the highest availability and
6
reliability rates of all generation resources. Customer service reliability
7
is enhanced by the high availability, reliability, and operational flexibility
8
of existing hydro resources. Hydro Operations’ forebay and afterbay
9
storage capabilities allow this mode of operation while complying with
10
the FERC license streamflow requirements. High availability assures
11
full utilization of the available water resources and therefore reduces the
12
average cost of generation
The reliability of the electric grid depends on fast, flexible generation
13
14
sources to meet peak power demands, maintain level system voltages
15
and quickly restore service after a blackout. Hydroelectricity can be
16
placed on the electric grid faster than any other energy source.
17
Hydropower’s ability to go from zero power to maximum output rapidly
18
and predictably makes it exceptionally good at meeting changing loads
19
and providing ancillary electric service that maintain the balance
20
between electric supply and demand. Because hydropower is
21
generated within seconds of when water begins rushing through its
22
turbines, hydropower is particularly adept at providing incremental
23
bursts of power. This is of great value to electric power grid operators,
24
which is why they often rely on hydropower‘s speed and flexibility to
25
meet fluctuations in electric power demand and to restore service after a
26
blackout.
27
28
e.
Clean, Carbon Free, Source of Power
PG&E’s customers benefit from this indigenous, carbon free,
29
resource because it produces no air pollution and hydro power directly
30
offsets the use of non-renewable fossil fuels. In addition, hydro power
31
is a non-consumptive use of water resources that is well integrated into
32
water supply, irrigation, flood control, and other multi-purpose projects.
33
34
On September 12, 2002, Governor Gray Davis signed a bill
(SB 1078) requiring California to generate 20 percent of its electricity
3-10
(PG&E-3)
1
from renewable[6] energy no later than 2017. The new law requires
2
sellers of electricity at retail to increase their use of renewable energy by
3
1 percent per year. Since California already generates about
4
10 percent of its electricity consumption by renewables, the new law will
5
6
nearly double the state's existing base of wind, geothermal, biomass,
small hydro,[7] and solar energy resources. While all conventional
7
hydroelectric powerhouses are refueled through annual precipitation,
8
only about 295 MW of PG&E’s hydroelectric capacity meet the State’s
9
“small hydro” classification and are thus included in the RPS baseline.
f.
10
Natural Resources Stewardship
PG&E demonstrated it’s commitment to environmental stewardship
11
12
by reaching an agreement in 2003 with the California Public Utilities
13
Commission to establish the Pacific Forest and Watershed Lands
14
Stewardship Council, a California nonprofit foundation, to permanently
15
conserve beneficial uses of its hydro watershed lands. The Council will
16
provide oversight of the development and implementation of a plan that
17
delineates long-term management objectives for PG&E’s land holdings
18
of approximately 140,000 acres of hydro watershed lands. These lands
19
will be conserved for a broad range of public benefits, including the
20
protection of the natural habitat for fish, wildlife, and plants, the
21
preservation of open space, outdoor recreation by the general public,
[6]
[7]
Renewable — A power source other than a conventional power source within
the meaning of Section 2805 of the Public Utilities Code. Section 2805 states:
“‘Conventional power source’ means power derived from nuclear energy or
the operation of a hydropower facility greater than 30 megawatts or the
combustion of fossil fuels, unless cogeneration technology, as defined in
Section 25134 of the Public Resources Code, is employed in the production
of such power.”
Small hydro — A facility employing one or more hydroelectric turbine
generators, the sum capacity of which does not exceed 30 megawatts.
Pursuant to PUC section 399.12, procurement from a small hydro facility as
of January 1, 2003 is eligible only for purposes of establishing the baseline of
an electrical corporation. A new small hydro facility is not eligible for the RPS
if it will require a new or increased appropriation or diversion of water under
Part 2 (commencing with Section 1200) of Division 2 of the Water Code.
Pursuant to PUC section 383.5 (d) (2) (C) (iv) as amended by Public
Resources Code section 25743(b)(3)(D), a new small hydro facility must not
require a new or increased appropriation of water under Part 2 (commencing
with Section 1200) of Division 2 of the Water Code to be eligible for
supplemental energy payments.
3-11
(PG&E-3)
1
sustainable forestry, agricultural uses, and land to be preserved for
2
historic and cultural values. See Chapter 7 of this exhibit for a more
3
detailed discussion of the Pacific Forest and Watershed Lands
4
Stewardship Council.
5
Hydroelectric projects provide a wide range of non-power benefits,
6
including fresh water storage, recreation, flood control, drinking water
7
supply, and irrigation. Hydroelectric projects also provide recreation
8
amenities such as boating areas, fishing sites, picnic grounds, and
9
hiking trails that enhance the quality of life for local communities.
10
PG&E hydro projects deliver water at 54 locations for consumption
11
by 39 different user groups. Reservoirs store about 2 million-acre feet
12
of fresh water, which represents 6 percent of the state’s total fresh water
13
storage capacity. PG&E hydro watershed lands provide recreation,
14
including 41 campgrounds, 37 picnic and day use facilities, for an
15
annual number of camp visitors of over 175,000. PG&E also leases
16
watershed lands for recreation home sites, marinas, resorts and parks,
17
boat docks, grazing, fish hatcheries, and tree farms.
18
C. Estimating Method
19
The Hydro Operations Program develops its forecast by subprogram and
20
MWC. Potential work is identified, categorized, and prioritized in hydro’s LTP
21
which provides a detailed schedule of work and associated expenditures into the
22
future. Subsequent planning iterations are used to review and refine the scope
23
of work and associated cost estimates as new information is available. The
24
most-current information for the following year (first year of the long-term plan)
25
serves as the basis for hydro’s annual budget forecast submitted for PG&E
26
management approval. PG&E’s management compares the Hydro Operations
27
Program to all other PG&E Programs prior to approving its budget.
28
Even after project-type work is included in the approved annual budget it
29
remains subject to final authorizations following review of more detailed
30
estimates, schedules, and justifications. Authorization to proceed is also subject
31
to an assessment as to whether higher priority work has materialized. The
32
expense and capital forecast in this GRC request and annual budget does not
33
include a contingency for unidentified work. Yet due to the age and location of
34
these assets, they are subject to unanticipated component failures and storm
3-12
(PG&E-3)
1
damage. Major storms disrupt operations and inflict considerable damage on
2
the water conveyance systems and even the powerhouses themselves. The
3
Hydro Operations Program manages these unplanned expenses, whether
4
expense or capital, by assessing what performance efficiencies can be captured
5
or lower priority work can be deferred so that funds are available to proceed with
6
the emergency work. This exercise occurs monthly and assures that the Hydro
7
Operations Program continuously optimizes the investment decisions needed to
8
ensure safe, reliable, and economic operations.
9
This chapter uses four sources of cost data to develop forecasts for 2007,
10
2008 and 2009. Actual expenditures are used for 2004. Hydro Operations’
11
approved budget was used for the 2005 forecast. Hydro Operations’
12
recommended budget was used for 2006 and the LTP provided the 2007
13
through 2009 forecast of expenditures.
14
1. Forecast Methodology
15
Hydro Operations’ centralized program management organizes the
16
forecast work by subprogram and MWC. Work identified within each
17
subprogram is compared to ensure similar standards and risk assessment
18
methodologies are used to prioritize work throughout the hydro system.
19
Hydro Operations planners—working with O&M personnel, engineers,
20
project analysts, and project managers—develop, review, rank, and submit
21
detailed funding requests to the Hydro Operations Program office for a
22
hydro wide comparison with all other work. The Hydro Operations Program
23
uses management’s collective experience and judgment to establish the
24
final assigned priorities and funding request. This recommended Hydro
25
Operations Program budget is then submitted to Generation’s management
26
to cross prioritize against the proposed fossil and nuclear budget requests.
27
This composite Generation request is then forwarded to the Utility for
28
comparison with all of the non-generation programs prior to approval. Hydro
29
Operations’ 2005 budget was approved in November 2004.
30
The Hydro Operation Program’s annual budget review results in a
31
ranked list of recommended work. The highest-priority work over the recent
32
past and through 2006 has been to maintain these generating assets to
33
operate safely, to protect the environment, to comply with all FERC license
34
conditions, meet other regulatory requirements and to operate reliably. As
3-13
(PG&E-3)
1
described in more detail below, the Hydro Operations Program forecast now
2
includes funding for efficiency improvements. PG&E’s 2003-2006
3
investments focused on long term reliable generation from these hydro
4
units. These investments are producing the desired results and therefore
5
Hydro Operations recommends investing in efficiency improvements that
6
provide customers with clean, carbon free, cost effective energy.
Safety, environmental and regulatory compliance work will continue to
7
8
be assigned a higher budget priority. Efficiency improvements will be
9
compared to reliability work so that the highest value work, from a
10
customer’s perspective, is funded. This economic evaluation considers the
11
consequences of an in-service failure and captures the efficiency associated
12
with scheduling projects to reduce the combined outage duration.
Hydro Operations’ LTP currently indicates minimal spending on
13
14
efficiency projects until 2006 or later. Most of this work, when it occurs, will
15
be integrated with reliability work to minimize outages. Hydro Operations’
16
LTP does not include any capacity additions, although turbine efficiency
17
improvements may yield small increases (i.e., more energy produced with
18
the same water throughput). Hydro Operations’ 2003 thru 2005 budgets
19
included planning-related process improvements in the business
20
subprogram. In addition to minor expenditures to improve the LTP
21
database itself, Hydro Operations implemented new tools for gathering and
22
analyzing equipment condition assessment data, and also for analyzing and
23
scheduling work (“work management”). These process improvements
24
promote a systematic collection of data and subsequent analysis so that
25
future investments target the highest-value work. This improves PG&E’s
26
ability to assess which investments provide the highest value to customers.
2. Capital Forecast
27
PG&E forecasts an increase in capital expenditures in 2007-2009 so
28
that the hydro system can continue to provide low cost energy and ancillary
services to customers for the long term. Figures 3-1[8] and 3-2 show the
29
30
[8]
Figures 3-1 and 3-2 show capital expenditures for years 1990 through 2009.
Actual expenditures are shown for 1990 through 2004 and forecast capital
expenditures are for 2005 through 2009.
3-14
(PG&E-3)
1
reduced investment in the hydro assets following passage of
2
Assembly Bill (AB) 1890 in 1996 through PG&E’s bankruptcy filing in 2002.
3
It then shows the ramp up in expenditures consistent with funding
4
5
recommended in the 2003 GRC. Figure 3-1 shows nominal dollars whereas
Figure 3-2 is in constant year 2005 dollars.[9] These two figures show costs
6
by subprogram starting in 1997 following PG&E’s conversion to SAP and
7
hydro’s current accounting structure. The cost data for 1990 through 2000
8
reflects the year the capital projects were completed or put into service. A
9
number of large multi-year projects approved prior to 1996 were completed
10
and put into service in 1997, which explains the higher total in that year.
11
The figures show capital expenditures for years 2001 through 2009.
12
Testimony in the 2003 GRC anticipated capital expenditures for maintaining
13
the hydro system would return to historic levels by 2005. Cost controls
14
including Hydro Operation’s use of its condition assessment program
15
focused expenditures on critical components in 2003 and 2004 and deferred
16
non-critical capital expenditures to later years.
Hydro Operation’s forecast increase in capital expenditures from 2006
17
18
through 2009 is due to:
19

Requirement to implement new FERC license conditions, as discussed
in Section D.3;
20

21
Reliability/availability projects deferred to later years as a result of
22
implementing Hydro Operation’s condition assessment program. These
23
projects have been phased into Hydro Operation’s LTP as discussed in
24
Section D.5.

25
Increased dam safety projects resulting from increased FERC and
26
DSOD focus and revised guidelines , as discussed under Section D.1;
27
and

28
Efficiency improvements and strategic issues as discussed in
Section D.5.
29
[9]
Figure 3-2 assumes approximately a 2.5 percent per year escalation to aid
the reviewer in comparing dollars for this 5-year period.
3-15
(PG&E-3)
Hydro Operation’s capital forecast consists of specific projects that are
1
2
individually reviewed to ensure that the highest priority work is identified and
3
funded first through PG&E’s budget process. The work papers supporting
4
this chapter provide details on all 2004 through 2009 forecast projects
5
greater than $1,000,000 and summary information on all of the smaller
6
projects included in the forecast.
3. Expense Forecast
7
8
Hydro Operation’s expenses include the costs of routine and ongoing
9
expenditures including the cost of personnel who operate and maintain the
units. Figures 3-3[10] and 3-4 show Hydro Operation’s expenses from 1990
10
12
through 2009. Figure 3-3 shows nominal dollars whereas Figure 3-4 is in
constant year 2005 dollars.[11] These two figures show costs by
13
subprogram starting in 1997 following PG&E’s conversion to SAP and the
14
current accounting structure.
11
15
The Hydro Operation Program has managed a flat expense budget
16
between 1997 and the 2004. This includes reduced expenses following the
17
18
1996 passage of AB 1890 and further reductions in 2000 and 2001 following
passage of ABx1-6[12] and then PG&E’s Chapter 11 bankruptcy filing. A
19
closer review by subprogram reveals that the increased regulatory
20
compliance subprogram expenses have been offset by reductions in the
21
other subprograms.
22
Hydro Operation’s expense forecast is built upon its historic base
23
expenditures and specific expense projects as shown in Figure 3-5 for the
24
years 2000 through 2009. Routine base expenditures rise year over year as
25
a result of wage inflation and business drivers that increase the ongoing
26
workload. These routine expenditures decrease as a result of automation
27
and work process improvements that reduce the recurring workload. The
[10]
[11]
[12]
Figures 3-3 and 3-4 use actual expenditures for 1990 through 2004 and
forecast expenses for 2005 through 2009.
Figure 3-4 assumes approximately a 2.5 percent per year escalation to aid
the reviewer in comparing dollars for this 5-year period.
ABx1-6 repealed Public Utilities Code Section 216(h) and modified
Sections 377 and 330(l)(2) prohibiting PG&E from selling any of its existing
generating assets until at least January 1, 2006, and requires that those
assets be dedicated for the benefit of California ratepayers.
3-16
(PG&E-3)
1
chart shows that other than the Regulatory Compliance Subprogram all
2
base costs are being held flat through the GRC forecast period.
The specific business drivers that increase the forecast base and
3
4
project expenditures are:
5

discussed in Section D.3;
6
7


New regulatory fees imposed by State and Federal agencies, as
discussed in Section D.3; and
10
11
Specific projects resulting from new environmental and safety
regulations as discussed in Sections D.1 and D.2; and
8
9
New license compliance activities resulting from new FERC licenses, as

Increased reliability/availability projects identified through condition
12
assessment and phased into the LTP as discussed in Section D.5.
13
Section D: Activities and Costs by SubProgram/MWC provides greater
14
detail including the workpapers where summary information is presented
15
for all 2007 through 2009 expense projects and a one page description is
16
included for all projects exceeding $1.0 million dollars.
17
D. Activities and Costs by Subprogram/Major Work Category
18
The six subprograms and 21 MWCs, (including the segregated regulatory
19
fees), managed under the Hydro Operations Program are listed in Tables 3-1
20
and 3-2 at the end of this chapter and are discussed in the order shown. Each
21
subprogram will be described in its entirety, addressing all of the expense
22
MWCs before describing capital MWCs.
23
1. Safety and Health Management Subprogram
24
25
a.
General
Safety is a higher priority for Power Generation. Power Generation
26
is committed to create and sustain a work and business environment
27
free of injury, illness, or property damage for the benefit of employees,
28
customers, and the general public. Achieving this value enables us to
29
be the low cost provider through decreased business losses and protect
30
the safety, health and well-being of our employees and the public.
3-17
(PG&E-3)
1
b. Expense (MWC HZ)
Safety work was previously combined with environmental work. It is
2
3
now tracked separately to ensure priority is given to employee and
4
public safety.
Base work in the safety subprogram consists of activities such as:
5
6

Industrial and Office Ergonomics training/evaluations;
7

Illness and injury prevention;
8

Health and wellness training;
9

Regulatory mandated training;
10

Training and re-certification for the safety staff;
11

Culture based safety process;
12

Asbestos and lead awareness training;
13

Safety-at-Heights Program;
14

Safe driving training;
15

First responder training – HAZWOPER;
16

Preparation of safety tailboards and department safety procedures;
17

Proper use of personal protective equipment;
18

Incident Investigations and communicating lessons learned;
19

Employee injury case management;
20

Safety performance recognition; and
21

Public safety awareness.
22
The base safety work forecast is based on historic expenditures.
23
The safety subprogram also includes funding for specific identified
24
projects that correct potential employee-related safety hazards, such as
25
arc-flash hazard remediation, ground grid studies and remediation,
26
penstock safety condition assessment and remediation, Helms fire
27
hazard reduction, fall protection guidelines and remediation, high
28
voltage protection remediation, and correcting other identified safety
29
hazards.
3-18
(PG&E-3)
1
c.
Capital (MWC 13)
Safety capital consists of specific facility safety projects essential to
2
3
keeping the public and employees and the environment safe in and
4
around PG&E’s hydro facilities. Figure 3-6 categorizes the capital costs
5
for this subprogram between 2001 and 2009. The forecast increase is
6
driven by the dam safety related projects. Forecast work planned under
7
this subprogram can be further categorized into the following six groups:
8

installations on trash racks, powerhouse cranes, penstocks, and
9
ladders to meet federal and state OSHA safety standards.
10
11
Fall Protection Work: This consists of safety-at-heights

Arc-Flash Hazard Remediation: Employees are exposed to arc-
12
flash risks and in fact there have been serious injuries and in some
13
cases, fatalities in our industry. New regulations requiring
14
employers to provide protection against hazards associated with
15
electrical arc-flash events are either in place or imminent
16
(NFPA-70E was issued in 2004 and is expected to be adopted by
17
OSHA in early 2006). Power Generation is taking a pro-active role
18
to identify and control these hazards. Arc-flash hazards can be
19
generated during switching operations, grounding activities, or while
20
working on or near exposed energized equipment for all voltages
21
above 50 volts. Arc-flash hazard analysis for 31 hydro facilities
22
which will be completed by the end of 2005. This will result in
23
modifications to hydro powerhouse station service switchgear and
24
protection devices, administrative controls and/or personal
25
protective equipment control measures to ensure the safety of our
26
employees.
27

Ohio Brass Insulator Replacement Program: Hydro has
28
undertaken a program to replace certain high voltage insulators
29
manufactured by Ohio Brass Insulator Company. It was determined
30
that these insulators are faulty and have exhibited a high failure
31
rate, which poses an unacceptable safety risk to employees,
32
adjacent equipment and to system reliability. Replacement of these
33
insulators will mitigate a safety risk for employees who have to work
3-19
(PG&E-3)
1
around and under the structures where these insulators are
2
installed. The programmatic replacement was started in 2004 and
3
replacement of suspect Ohio Brass insulators at hydro facilities is
4
planned to be complete by 2008.
5

Dam Safety Work: Additional modifications are required because
6
of: (1) changing FERC and DSOD guidelines; (2) findings resulting
7
from FERC’s and DSOD’s regular facility inspections; and (3) the
8
FERC Part 12 independent analysis, under both normal and
9
emergency conditions, required every five years. These
10
modifications could improve the dam’s stability and operability, or
11
strengthen the low level outlet structures and spill gates.
12
A significant project is the Canyon Dam Outlet project. Canyon
13
Dam Outlet tower will be strengthened to conform with DSOD/FERC
14
guidelines. This includes upgrading the gates in the tower.
15
Additional details supporting the forecast are included in the work
16
papers. Additional dam safety work is forecast in the regulatory
17
compliance subprogram. This occurs when modifications are
18
required as a direct result of relicensing.
19

Penstock Safety and Life Extension Program: This includes
20
both relining and replacement of pipeline sections. Work on Hydro
21
Operation’s 89 individual penstocks (260,000 liner feet ranging in
22
age from 20 to105 years old), will begin in 2007 and will continue for
23
at least the next 20 years. A significant project is the Caribou 2
24
penstock realignment project. Engineering and permitting will occur
25
during the forecast period with construction contemplated for the
26
2010 to 2013 timeframe. This work will mitigate the slow hillside
27
creep of a penstock anchor block. Additional details are included in
28
the work papers.
29

Miscellaneous safety projects such as installing trash rack
30
debris-handling systems, improving personnel access to hydro
31
facilities, and correcting other identified safety hazards.
3-20
(PG&E-3)
1
2
3
2. Environmental Subprogram
a.
Expense (MWCs AK, ES, CR, AY)
Environmental base work consists of environmental permitting and
4
compliance costs associated with the hydro facilities. This work
5
includes solid waste disposal and transportation, water quality
6
protection, environmental support for job planning, environmental
7
incident/emergency response, environmental plans and reports,
8
environmental risk management, and sensitive species protection.
9
Historic expenditures form the basis for the forecast of base work,
10
with adjustments made for new regulatory requirements related to air
11
quality requirements (e.g., diesel engines and anticipated new
12
regulations in the areas of water quality and habitat and species
13
protection). The Environmental subprogram also includes funding for
14
new environmental compliance activities, such as the Valley Elderberry
15
Longhorn Beetle (VELB) permitting and habitat species protection
16
Sensitive species and habitat protection expense costs for specific
17
hydro projects are included in the Regulatory section. Sensitive species
18
and habitat protection costs that are common, such as compliance with
19
a companywide permit for the protection of the Valley elderberry
20
longhorn beetle, are included in the Environmental Subprogram. These
21
costs are higher in the 2004–2006 time period to fund specific
22
conservation efforts, and will have leveled off in 2007. Costs are
23
anticipated to cover anticipated new species and habitat protection
24
requirements.
25
26
b. PCB Retrofit
This work is near complete and has systematically reduced the
27
amount and concentration of PCBs in Hydro Operation’s equipment.
28
The remaining focus is removing PCBs from small equipment when it is
29
maintained. The PCB retrofit program also addresses equipment that
30
may be regulated when it is removed from service and considered
31
waste by the state.
3-21
(PG&E-3)
1
c.
Lead Paint Management Program
2
This program ensures that the integrity of coatings on the hydro
3
facilities is intact. Each facility is reviewed, evaluated and addressed as
4
appropriate.
5
6
7
8
9
d. Oil Spill Prevention Program
This program evaluates how to mitigate the potential for oil spills
resulting from leaks in the turbine-generator bearing cooling systems.
The work effort was divided into four phases: Phase 1, which was
completed in 2004, identified the environmental risk associated with a
10
potential spill for the powerhouses located in PG&E’s watersheds. Each
11
site was evaluated and rated to determine the relative risk of oil spills in
12
general and identified the most “at risk” bearing systems. The sites
13
were categorized into five ”families,” whereby each family had several
14
common characteristics. The results were compiled into an extremely
15
detailed report and database.
16
Phase 2 developed detailed generic designs for each family of
17
units. The intent of the generic design was to step through the
18
engineering process to ensure that a practical and cost-effective
19
solution could be achieved and implemented for each type of cooling
20
system. Generic designs were completed for each family of units in
21
2005.
22
Phase 3 then took each family generic design and implemented a
23
“pilot” installation at a specific unit ranking high on the risk assessment
24
list and evaluated the effectiveness of the design approach from an
25
implementation and operation perspective. The intent was to take the
26
pilot installation data and any lessons learned and then select the best
27
remediation solution for each unit, on a careful and deliberate schedule,
28
which accounts for availability of resources and unit outage dates. To
29
date, three of the five generic designs have been converted to specific
30
designs (Pit 6 U1, Pit 7 U2, J.B. Black) and implemented. The final two
31
generic design conversions (Pit 4 and Volta) are expected to be
32
complete by the end of 2005. Critical performance data from each of
33
the pilot installations will be collected over a 6-month period to evaluate
3-22
(PG&E-3)
1
the effectiveness of the designs for system-wide installations. Phase 3
2
should be completed by early 2006.
Phase 4, the final phase of the program, will implement the proven
3
4
solutions on a systemwide prioritized basis to reduce the risk to
5
acceptable levels. This phase will commence in 2006 and run past the
6
GRC forecast period. Two to four units will be retrofitted per year. Most
7
of the remediation will be classified as capital, however it’s expected
8
that the risk can be abated at some sites through minor expense
9
modifications and/or repairs.
10
e.
Capital
Costs for capital projects in the Environmental Subprogram include
11
12
costs to comply with water quality and air quality regulations, including
13
replacement of Helms sewage treatment plant and AG Wishon governor
14
sump tanks, various oil spill prevention projects, and replacement or
15
retrofit of diesel generators.
16
17
18
3. Regulatory Compliance Subprogram
a.
General
The regulatory compliance subprogram addresses all of the
19
activities associated with obtaining and then maintaining the regulatory
20
approvals to own and operate PG&E’s hydro generating assets and
21
appurtenant facilities, including the associated state and federal fees.
22
Work in the regulatory compliance subprogram includes both expense
23
and capital work. Work that does not result in new capital assets is
24
treated in the expense category, and work that does result in new
25
capital assets is treated in the capital category. In many cases the work
26
is very similar in the expense and capital categories, with only the
27
outcome (a new capital asset or no new capital asset) distinguishing the
28
categories.
29
30
b. Expense (MWCs DL, DP and Regulatory Fees)
As stated above, this subprogram includes expenditures for
31
regulatory required compliance activities that are not associated with a
32
new capital asset. These expenditures are classified under two MWCs:
33
(1) FERC hydroelectric license compliance activities (DL), and
3-23
(PG&E-3)
1
(2) license required recreational facility management activities (DP).
2
Regulatory fees are booked directly against the receiver cost centers
3
To provide context for existing and future business drivers, expense
4
work planned under Regulatory Compliance can be categorized into the
5
following five subcategories, as described in more detail below:
6
(1) complying with the conditions required by recently issued FERC
7
licenses and major license amendments; (2) complying with the
8
conditions required by anticipated new FERC licenses and major license
9
amendments; (3) compliance work related to facility safety; (4) other
10
compliance work associated with standard license articles or inspection
11
findings; and (5) state and federal fees imposed upon the hydro
12
generation assets.
13
Figure 3-7 shows the regulatory compliance subprogram expense
14
costs by MWC from 2000 through 2009. This subprogram is forecast to
15
grow by $14.9 million (73 percent) between 2003 recorded and 2006
16
forecast. This is $10 million more than forecast in the 2003 GRC. The
17
increase is primarily due to the expansive scope and complexity of the
18
license compliance measures included in the six new licenses received
19
between 2001 and 2003.
20
The regulatory compliance subprogram is forecast to increase an
21
additional $14.6 million in 2007. This is primarily due to the forecast
22
increase in license compliance work associated with accepting five new
23
licenses and two major license amendments in 2005 and 2006. There
24
are also some costs associated with new state and federal regulatory
25
fees, as described in more detail below.
26
1) Complying with the conditions required by recently issued FERC
27
licenses and major license amendments
28
FERC issued PG&E six new licenses and one major license
29
amendment between 2001 and 2005 (Haas-Kings, Mokelumne,
30
Rock Creek-Cresta, Pit 1, Hat Creek and Crane Valley new
31
licenses; and Potter Valley license amendment). Prior to this, the
32
last new license was issued in 1993. Relative to licenses previously
33
issued by FERC, the six recently-issued licenses contain more
34
extensive terms and conditions that require an expanded license
3-24
(PG&E-3)
1
compliance program to adhere to the new license requirements.
2
Moreover, the recently-issued licenses are each characterized as
3
“living documents” with extensive provisions for adaptive
4
management and similar measures that allow agencies and non-
5
governmental organizations (NGO) to actively participate in the
6
review and periodic revision of existing management prescriptions.
7
This includes requirements for extensive environmental studies and
8
long-term monitoring of the environmental effects of license-
9
required resource protection, mitigation and enhancement (PM&E)
10
measures. In addition to the adaptive management features of the
11
recently-issued licenses there are requirements for development,
12
maintenance, and operation of improved public recreation facilities
13
owned by a federal land management agency (typically the
14
U.S. Forest Service).
15
Illustrative of the complexity of the new “living” licenses and the
16
provisions for adaptive management are the approximately
17
200 additional compliance tasks associated with the six new
18
licenses issued since 2001. This includes concomitant
19
requirements for approximately 90 ongoing aquatic, terrestrial,
20
recreation, and cultural resource studies or monitoring efforts, at an
21
annual recurring cost of approximately $4,000,000 to $5,000,000.
22
PG&E has incorporated a number of measures to manage this
23
increasing license complexity, including assignment of focused
24
project management oversight upon receipt of the new license and
25
during the license implementation phase. This oversight provides
26
tight cost controls and periodic adjustments to forecast expenditures
27
for license implementation activities related to monitoring efforts.
28
Most of the expense compliance work is forecast to continue
29
30
31
32
beyond the 2007 to 2009 GRC.
2) Complying with the conditions required by anticipated new FERC
licenses and major license amendments
With five new licenses and two major license amendments
33
anticipated to be issued in the period 2005 through 2006,
34
(Spring Gap-Stanislaus and Kern Canyon new licenses and Bucks
3-25
(PG&E-3)
1
Creek major license amendment in 2005; Poe, Upper NF Feather
2
and Pit 3, 4 and 5 new licenses and Battle Creek major license
3
amendment in 2006), significant new expense compliance
4
expenditures are forecast for the period 2007 through 2009. These
5
new licenses and major amendments are for FERC hydroelectric
6
projects that are generally larger and more complex than the
7
recently-issued licenses and major amendments. However, PG&E
8
continues to capitalize on lessons learned from the preceding
9
relicensing efforts and implementation of the six recently issued
10
licenses. Building upon these lessons-learned, PG&E has entered
11
into agreements with stakeholders in three of the existing
12
relicensing proceedings and both of the major license amendment
13
proceedings which have helped to define and more closely
14
constrain the anticipated scopes of work associated with the new
15
licenses.
16
As a result, these anticipated new licenses are forecast to have
17
requirements for approximately 60 to 90 ongoing aquatic, terrestrial,
18
recreation, and cultural resource studies or monitoring efforts, at an
19
annual recurring cost of approximately $2,200,000 to $3,000,000.
20
As with the recently issued licenses (discussed above), the
21
anticipated new licenses will have extensive adaptive management
22
clauses written into the license conditions. The adaptive
23
management clauses will require periodic reassessment of
24
management prescriptions and provide opportunities for
25
government agencies and NGOs to adjust the PM&E measures,
26
(e.g., altering flow and reservoir storage regimes and monitoring
27
requirements). These anticipated new licenses will also require
28
active compliance management by PG&E and regular interaction
29
with various technical review committees comprised of agency and
30
NGO representatives.
31
The existing and anticipated new licenses also require expense
32
projects such as installation of rip-rap embankment reinforcements;
33
fishery habitat improvements; repair of deteriorating equipment such
34
as valves, weirs and spillways; and dredging. In addition, the
3-26
(PG&E-3)
1
anticipated new licenses will require extensive monitoring of stream
2
temperatures, fish and wildlife habitat, and other resource
3
protection, mitigation and enhancement measures.
4
3) Facility Safety Program – This work consists of an ongoing base
5
level of work and substantial additional required work and
6
expenditures resulting from new initiatives and requirements from
7
FERC and the DSOD
8
a) Base work consists of the following activities:
9

FERC Part 12 Inspection Reports – FERC requires that all
10
53 high and significant hazard dams in the PG&E system
11
be inspected every five years by an independent consultant.
12
There are typically 10 to 12 inspections every year. The
13
consultant reviews the accumulated surveillance data,
14
stability analyses, flood data, and seismicity data for each
15
dam and then conducts a physical site inspection. This
16
report, filed with FERC, recommends whether the dam is
17
safe for continued operations. The report may also
18
recommend modifications, subsequent additional field
19
investigations, analysis or increased monitoring activities.
20

Dam Surveillance Data Gathering and Reporting – PG&E
21
gathers and analyzes surveillance data such as leakage
22
weir readings, piezometer readings and optical surveys on
23
its dams and reports them on a quarterly basis with the
24
Department of Dam Safety (DSOD) and on a semi-annual
25
basis with FERC.
26

Emergency Action Plans – As required by the FERC, PG&E
27
has developed and annually updates its emergency action
28
plans. The annual update includes training of watershed
29
and centralized organization personnel, updating
30
emergency contact flow charts, and updating potential
31
failure scenarios and inundation maps as necessary to
32
incorporate results from updated analyses and surveys.
3-27
(PG&E-3)
1

Facility Safety Engineering Studies Requested by the FERC
2
and DSOD – Regulatory agencies may require additional
3
studies to confirm the safety or stability of various project
4
features as a result of new technical or industry information
5
(e.g., revised flood or seismicity data). These agencies can
6
request stability analyses, structural analyses of
7
appurtenant structures (e.g., radial gates), flood and
8
spillway studies.
9
10
b) Additional required work includes the following:

New Part 12D Safety Inspection and Analyses
11
Requirements – FERC initiated new Part 12D Safety
12
Inspection Guidelines for Dams in 2003 that included new
13
performance monitoring reviews and new failure mode
14
analyses. These requirements apply to all of PG&E’s 53
15
“High” and “Significant” hazard potential classification dams
16
that are currently under Part 12D requirements. During
17
2003-2006, PG&E completed 43 separate Part 12D reports
18
including 37 updated to the new guidelines, and is
19
scheduled to complete 16 Part 12D reports during 2007-
20
2009 in conformance with these new guidelines.
21

Update all Dam Break Analyses and Flood Maps – FERC’s
22
Chapter 6 Guidelines requires inundation (i.e., flood) maps
23
to be included in Emergency Action Plans. The existing
24
inundation maps for all High and Significant hazard
25
potential dams were developed 20 to 25 years ago from
26
dam break analyses performed at that time. To meet the
27
new FERC guidelines, the Company will update all of the
28
dam break analyses and revise their associated inundation
29
maps starting in 2006 and ending in 2010.
30

Dam Safety Initiative for Rockfill Dams – PG&E’s dam
31
leakage monitoring program has recorded increased
32
leakage at PG&E’s concrete faced rockfill dams over the
33
past three years. PG&E, working in consultation with FERC
3-28
(PG&E-3)
1
and DSOD, has completed work at the Main Strawberry
2
dam in 2004 and Salt Springs dam in 2005. The concrete
3
joints and/or the upstream concrete faces have been
4
repaired at these two dams to reduce leakage back to early
5
historic levels. PG&E forecasts that a similar scope of work
6
will be required at all 13 of the Company’s rockfill dams,
7
with concrete facing repairs projected to be performed at
8
Relief, Courtright, and Wishon during 2006 to 2009; based
9
on the current and projected downstream leakage levels.
10

Review of Facility/Dam Security Measures and
11
Enhancements – As a result of the September 11 terrorist
12
attack, FERC has implemented a program to ensure that all
13
hydro licensee dams and facilities are adequately secured.
14
Additional inspection guidelines developed by FERC started
15
in mid-2002. Facility security and vulnerability assessments
16
were performed for PG&E’s hydro system in 2003. As a
17
result these assessments, the Company expects to develop
18
and implement additional security measures to improve
19
security and comply with the new FERC guidelines during
20
2004-2009.
21

New Pending FERC Guidelines on Evaluation of Water
22
Conveyance Systems and Dam Outlet Structures – FERC is
23
currently developing guidelines for evaluation of water
24
conveyance systems such as penstocks, canals, flumes,
25
and tunnels. PG&E expects by 2007 that these guidelines
26
will be enacted and the Company will be required to initiate
27
a program to evaluate the safety of these structures. PG&E
28
has proactively initiated a penstock safety program to
29
identify and mitigate risks and hazards and assure the safe
30
long term reliable operation of its penstocks. For this
31
reason, FERC has asked PG&E to help develop
32
appropriate industry-wide guidelines for these structures.
33
Prior to 2003, Geotechnical assessments of all penstocks
3-29
(PG&E-3)
1
were performed. Structural assessments and inspections of
2
the penstock pressure boundaries are planned for 2006 to
3
2008.
PG&E is also embarking on a Canal Assessment
4
5
Program to improve the safe, reliable operation of 184 miles
6
of canals. The program will identify operational risks and
7
hazards along PG&E’s canals and develop measures to
8
mitigate unacceptable risks. The program will also develop
9
a tool to document canal conditions and predict future
10
maintenance requirements. This work was started in 2005
11
and is planned to be complete in 2009. FERC has also
12
taken a keen interest in this activity, as they plan to add
13
some requirements for open channel waterways to their
14
Engineering Guidelines sometime in the next five years.
15
Dam low level outlet rehabilitation projects are foreseen
16
in 2007-2009 based on DSOD/FERC mandated inspections
17
and assessments of various low level outlet features in
18
PG&E’s hydro system.
19

Coatings Program for All Gates – In conjunction with the
20
radial gate evaluation program implemented in 2003-2006
21
and the annual FERC and DSOD facilities inspections, the
22
Company has identified that the majority of the gates at
23
dams need new coatings to protect them from corrosion
24
and maintain structural integrity as well as to extend their
25
useful lives. The Gate Coatings Program has identified,
26
evaluated, and prioritized more than 130 gates in the hydro
27
system. The coatings work was initiated in 2004, some
28
performed concurrent with the radial gate repairs, and
29
continues through 2007. (13 gates in 2007.)
30

Dam Safety Instrumentation automation PG&E will start to
31
automate its dam safety instrumentation in 2007 to 2009 in
32
an effort to both gather more accurate and timely data and
33
analyze it in a more efficient manner. The data will be
3-30
(PG&E-3)
1
merged with hydro’s condition assessment database and
2
provide automatic trending, alarm, and report generation.
3
In addition, automation of data collection will provide real
4
time data that will provide a more realistic picture of actual
5
conditions within a particular dam during extreme events,
6
such as heavy storms or an earthquake, thereby offering a
7
greater assurance against dam failures and enhanced
8
public safety.
9

PG&E initiated the development of a formal dam inspection
10
program in 2005-2006 to assess and document the current
11
condition and identify any potential safety issues for all low
12
hazard dams not covered by FERC Part 12D or DSOD
13
inspections. This affects 121 dams in PG&E’s hydro
14
system. The initial round of assessments will take until
15
2010 to complete.
16
4) Other expenses associated with regulations, standard license
17
articles, inspection findings, and required public recreation program
18
a) Additional expense license compliance requirements can
19
materialize in any given year as a result of regulatory
20
inspections:
21

operations and facility safety;
22
23

26
27
Environmental and public use inspections by FERC every
3-5 years; and
24
25
Annual FERC and DSOD inspections focused on project

Additional inspections scheduled in conjunction with major
construction projects.
b) Further expense requirements related to compliance with new
28
FERC regulations for exhibit drawings issued in 2004 is
29
expected to require substantial re-work of many drawings that
30
are part of existing or newly issued licenses, over the 2005 to
31
2009 time horizon.
3-31
(PG&E-3)
1
c) Public Recreation Program – Base work includes managing
2
campgrounds and day use areas; maintaining camp sites,
3
picnic tables, restroom facilities, and other equipment;
4
managing lands and roads at and surrounding recreation
5
facilities; and managing boat ramps, docks and other shoreline
6
recreation features.
7
License conditions may require development of shoreline
8
management plans or specific recreation facility improvements
9
or expansions to accommodate growing demand by the public
10
for water-oriented recreation opportunities. Where these
11
improvements or expansions are required at existing sites
12
owned by a federal land management agency (typically the
13
U.S. Forest Service), the associated construction costs are
14
treated as expense.
15
5) State and Federal regulatory fees imposed upon the hydro
16
generation assets. These regulatory fees are not captured under a
17
MWC, but are included as a separate cost category in the
18
Regulatory Compliance subprogram. These fees are forecast to
19
significantly increase as described below:
20
a) FERC Fees – Pursuant to Section 10(e) of the Federal Power
21
Act and Section 3401 of the Omnibus Budget Reconciliation Act
22
of 1986, FERC assesses annual charges against licensees and
23
exemptees of jurisdictional hydropower facilities to reimburse
24
the United States for the costs of administration of FERC’s
25
hydropower regulatory program [18 CFR11.1]. The annual
26
administrative costs are charged to and allocated among
27
licensees of projects of more than 1.5 MW of installed capacity.
28
The allocation is based on the authorized installed capacity of
29
pure pumped storage projects, such as the Helms Pumped
30
Storage Project, and on the authorized installed capacity plus
31
112.5 times the annual energy output in millions of
32
kilowatt-hours (kWh) for conventional projects, such as the
33
Haas-Kings River Project.
3-32
(PG&E-3)
1
The assessment of annual charges is based on an estimate
2
of the costs of administration of Part I of the Federal Power Act,
3
by FERC and other Federal agencies that are to be incurred
4
during the fiscal year in which the annual charges are assessed.
5
After the end of the fiscal year, the assessment is recalculated
6
based on the costs of administration that were actually incurred
7
during that fiscal year; the actual costs are compared to the
8
estimated costs; and the difference between the actual and
9
estimated costs is carried over as an adjustment to the
10
assessment for the subsequent fiscal year. The FERC and
11
other Federal agency fees have recently increased by about
12
10 percent per year on average as a result of Federal agencies,
13
both cultural and environmental, becoming more involved in the
14
hydro relicensing process.
15
FERC also fixes annual charges for the use, occupancy,
16
and enjoyment of U.S. lands, other than lands adjoining or
17
pertaining to dams or other structures owned by the United
18
States Government, or its other property [18 CFR11.2]. The
19
FERC sets annual charges, subject to adjustments, for the use
20
of government lands based on a schedule of rental fees for
21
linear rights of way established by the Forest Service. Annual
22
charges for transmission line rights of way are equal to the
23
per-acre charges established by the Forest Service for linear
24
rights of way. Annual charges for other project lands are equal
25
to twice the charges established by the Forest Service for linear
26
rights of way. Each year FERC updates its fee schedule to
27
reflect changes in land values established by the Forest Service
28
for linear rights of way. These charges have recently increased
29
by 2 percent per year on average.
30
Any licensee whose non-federal project uses a government
31
dam or other structure for electric power generation and whose
32
annual charges are not already specified in final form in the
33
license has to pay the United States an annual charge for the
34
use of that dam or other structure [18 CFR11.3]. Payment of
3-33
(PG&E-3)
1
such annual charges is in addition to any reimbursement paid
2
by a licensee for costs incurred by the United States as a direct
3
result of the licensee’s project development at such government
4
dam. Annual charges for the use of government dams or other
5
structures owned by the United States are 1 mill per kWh for the
6
first 40 gigawatt-hours (GWh) of energy a project produces,
7
1.5 mills per kWh for over 40 up to and including 80 GWh, and
8
2 mills per kWh for any energy the project produces over
9
80 GWh. The Narrows Project is assessed this type of
10
11
government dam charge each year.
b) DSOD Fees – PG&E pays fees, based on dam height, to store
12
water at PG&E’s reservoirs. As a result of the State of
13
California budget crisis, DSOD‘s operating budget was
14
eliminated from the State’s General Fund and converted to fee-
15
based funding approach. Hence, a new fee structure was
16
imposed by DSOD in 2003/2004 to all dam owners to fully cover
17
their annual budget requirements. PG&E’s fee increased from
18
$174,240 to $756,750 annually; a 434 percent increase that
19
wasn’t included in Hydro Operations’ 2003 GRC forecast.
20
c) USGS Fees – PG&E pays fees to the U.S. Geological Survey
21
(USGS) for FERC required water data collection. PG&E’s
22
FERC licenses require that PG&E have an ongoing stream
23
gaging program in connection with its many hydro facilities
24
(conduits, canals, flumes, powerhouses, lakes, diversion dams)
25
for each of our licenses. FERC requires that that USGS
26
oversee this program and report any items of noncompliance
27
back to them. The USGS under FERC order requires that
28
PG&E's streamflow gaging compliance meets USGS standards
29
for measurement and record keeping. PG&E at its own
30
discretion with considerable cost savings for our customers has
31
chosen to have eight in-house hydrographers perform
32
streamflow measurements and collect the data ourselves to
33
USGS standards rather than pay for full measurement and data
34
collection service performed solely by the USGS. The annual
3-34
(PG&E-3)
1
fees to USGS include data review, field visits to verify
2
compliance with USGS standards, and publication/electronic
3
storage of the data. The annual USGS fees for PG&E’s FERC
4
required stream gaging requirements increases an average rate
5
of approximately 3 percent or about $8,000/year.
6
7
c.
Capital (MWC 11)
Capital work planned under capital Regulatory Compliance can be
8
categorized into the following four sub-categories, as described in more
9
detail below: (1) complying with the conditions required by existing
10
FERC licenses and major license amendments; (2) obtaining new
11
FERC licenses (relicensing) and those major license amendments;
12
(3) complying with conditions anticipated to be required by new FERC
13
licenses and those major license amendments; and (4) other
14
compliance work generally related to facility safety.
15
Figure 3-8 shows the cost of complying with the conditions in the
16
five new FERC Licenses and two new FERC license amendments
17
drives the subprograms costs. Greater detail on the specific projects
18
that make up this forecast can be found in the workpapers.
19
The company’s ability to forecast the cost of MWC 11 has greatly
20
improved since 2001 when the 2003 GRC was prepared. At that time,
21
the company had just received the first of six new licenses since 1993
22
and was just beginning to forecast the resulting capital compliance
23
costs. Also, the company had limited information as to when FERC
24
would issue the balance of the pending licenses (several of these
25
licenses had already experienced years of delay waiting for FERC to
26
act). Subsequently, in 2002, FERC implemented an aggressive
27
program to expedite issuance of long-delayed licenses and to avoid
28
future delays, such that license issuance dates can now be more
29
accurately forecast. Additionally, the company used the six new
30
licenses it received between 2001 and 2003 to benchmark and improve
31
its ability to forecast the cost of complying with the capital conditions of
32
future licenses.
33
34
Three other principal factors have affected actual costs for MWC 11
compared to the cost forecast in the 2003 GRC: (1) the time it takes to
3-35
(PG&E-3)
1
get permits approved to start compliance work after license issuance;
2
(2) the cessation of relicensing on the Kilarc-Cow Creek project
3
(a one-time event not anticipated at the time of the 2003 GRC); and
4
(3) uncertainty in the scope of Subcategory 4 work (the 2007 GRC
5
forecast subject to this uncertainty). These additional factors are
6
included in the 2007 GRC forecasts.
7
1) Complying with the conditions required by existing FERC licenses
8
9
and major license amendments
After an eight-year period of no new licenses, extending back to
10
1993, FERC issued PG&E six new licenses and one major license
11
amendment between 2001 and 2005 (Haas-Kings, Mokelumne,
12
Rock Creek-Cresta, Pit 1, Hat Creek and Crane Valley licenses; and
13
Potter Valley license amendment). These recently issued licenses
14
and major license amendment contain terms and conditions with
15
which the company must comply to maintain the license. Relative
16
to licenses previously issued by FERC, they contain terms and
17
conditions that require more extensive capital work to meet the new
18
license requirements. The most costly capital work arising from the
19
recently issued licenses and major license amendments is typically
20
related to implementation of environmental enhancements (often for
21
flow release facility modifications or flow measurement facilities
22
related to increased minimum instream flow requirements) and
23
development of improved public recreation facilities. Formal project
24
management is used to cost-effectively plan and perform this work.
25
Most of the work from the six new licenses and one major license
26
amendment issued between 2001 and 2005 will have been
27
completed by 2007.
28
29
2) Obtaining new FERC licenses and those major license amendments
Relicensing of the company’s 26 FERC-licensed hydro projects
30
as the current licenses approach their staggered expiration dates
31
represents a significant ongoing capital cost. The minimum
32
five-year duration relicensing process includes extensive
33
stakeholder involvement, performance of comprehensive natural
3-36
(PG&E-3)
1
resource studies, and balancing of complex societal and
2
environmental issues.
3
Presently, ten projects representing 1,509 MW of the
4
company’s 3,896 MW hydro generation portfolio, are in some phase
5
of relicensing (Spring Gap-Stanislaus, Kern Canyon, Poe, Upper
6
North Fork Feather River, Pit 3 4 5, Chili Bar, DeSabla Centerville,
7
McCloud-Pit, and Drum-Spaulding), and two more are involved in
8
major license amendments (Bucks Creek and Battle Creek). As
9
many as five of the projects presently in relicensing are anticipated
10
to be issued new licenses in the period 2005 through 2006 (Spring
11
Gap-Stanislaus, Kern Canyon, Poe, Upper North Fork Feather
12
River, and Pit 3 4 5), and both major license amendments are
13
anticipated to be issued in this same period.
14
Through this unprecedented volume of relicensing activity the
15
company has employed collaborative solutions to complex resource
16
issues. Using its collaborative approach to relicensing, the
17
company has been able to preserve the low-cost power generation
18
benefit for customers while substantially improving environmental
19
protections, public recreation opportunity, water quality, and other
20
beneficial uses of the project-affected resources. The company has
21
applied this same approached to the major license amendments. In
22
one ongoing relicensing proceeding (Kilarc-Cow Creek; 5 MW)
23
where a new license was anticipated to result in a higher than
24
market rate cost-of-production, the company entered into an
25
agreement with other stakeholders to discontinue relicensing of the
26
project, and instead, at an equal or lower overall cost to customers,
27
acquire replacement power and either transfer the project or
28
decommission it and restore the affected streams for salmon
29
habitat. Additionally, the company is one of seven hydropower
30
licensees across the nation making use of FERC’s new Integrated
31
Licensing Process (ILP), which will further improve the efficiency
32
and reduce the cost of relicensing. The ILP will become the default
33
relicensing process in mid-2005, and is being used on the three
34
newest of the Company’s ten ongoing proceedings.
3-37
(PG&E-3)
1
During the period 2007 through 2009, at least five hydro
2
projects representing 591 MW will be in some phase of relicensing
3
(Chili Bar, DeSabla-Centerville, McCloud-Pit, Drum-Spaulding, and
4
Merced Falls), with forecast expenditures representing 22 percent of
5
the capital expenditures under this subprogram. It is also
6
anticipated that a major portion of the capital cost of
7
decommissioning Kilarc-Cow Creek Project would be incurred
8
during this period. No other major license amendments are
9
anticipated to start during the 2007-2009 period.
10
11
3) Complying with the conditions anticipated to be required by new
FERC licenses and those major license amendments
12
When issued, new licenses and major license amendments
13
contain terms and conditions with which the company must comply
14
to maintain the license. This capital work is typically related to
15
implementation of environmental enhancements (often for flow
16
release facility modifications or flow measurement facilities related
17
to increased minimum instream flow requirements), and
18
development of improved public recreation facilities. With up to five
19
new licenses and two major license amendments anticipated to be
20
issued in the period 2005 through 2006 (Spring Gap-Stanislaus,
21
Kern Canyon licenses and Bucks Creek major license amendment
22
in 2005 and Poe, Upper North Fork Feather River, Pit 3 4 5
23
licenses and Battle Creek major license amendment in 2006) and
24
two new licenses anticipated to be issued in the period 2007
25
through 2009 (Chili Bar in 2007 and DeSabla Centerville in 2009),
26
significant new capital compliance expenditures are anticipated
27
during the period 2007 through 2009.
28
The company has entered into comprehensive agreements with
29
stakeholders in three of the relicensing proceedings nearing
30
completion and both of the major license amendment proceedings,
31
which help define the anticipated scope of work. These agreements
32
improve PG&E’s ability to forecast the cost of this subprogram.
33
4) Other compliance work that results in new capital assets, generally
34
related to facility safety
3-38
(PG&E-3)
This category includes miscellaneous regulatory required work,
1
2
including log booms and boat barriers, erosion control, facility
3
security, and other regulatory mandated enhancements. Most
4
facility safety improvements are included under MWC 13, Safety
5
and Health Management Program, since they address public safety
6
issues. However, those facility safety items that resulted from
7
FERC or DSOD inspections or specific directives are included in
8
this subprogram.
9
10
4. Operate Plant Subprogram
a.
Expense (MWC AW and EP)
11
Hydro Operations covers work at all hydro facilities. The switching
12
center operators remotely control, via Hydro’s Supervisory Control and
13
Data Acquisition (SCADA), the majority of PG&E’s generating units as
14
well as monitoring and control of PG&E’s vast dam and water
15
conveyance system. Many of the older and smaller plants require on-
16
site operator interaction for starting/shutdown of generators as well as
17
for real-time operational changes. Roving operators visit all the plants
18
on a routine basis and check for the vital signs of unit control, electrical,
19
and mechanical equipment and manage any deviations from expected
20
values to keep the units running at their optimum reliability and
21
performance. Typical readings would include: bearing oil levels,
22
generator winding temperatures, and water pressures.
23
Sixty-five of PG&E’s medium to large hydro units can be operated
24
semi-automatic or fully automatic. Fully automatic operation allows unit
25
start-up, shut-down and load changes to be made remotely via SCADA,
26
while semi-automatic operation only permits remote unit shut-down and
27
load changes. Seven major powerhouses—Pit 3, Pit 5, Caribou, Rock
28
Creek, Drum, Wise, and Tiger Creek—currently have no remote
29
operation capabilities since they function as area switching centers and
30
are therefore staffed 24 hours a day. This combined function results in
31
the current operating staff having to leave their switching center post to
32
manually make unit changes and adjustments to auxiliary systems.
33
Evaluations are underway to automate the remaining seven
34
powerhouses to ensure that PG&E continues to operate in full
3-39
(PG&E-3)
1
compliance of the increasing FERC license and CAISO powerhouse
2
operating requirements.
3
The new FERC licenses contain conditions that require complex
4
real time operations. The new requirements of unit ramp rate limits,
5
pulse flow releases, and variable minimum in-stream flows, require
6
precise control and coordination of station facilities within a river shed
7
with little margin for error. These requirements typically cannot be met
8
with existing monitoring and control systems which are beyond their
9
design life and what’s technically available. PG&E is pursuing facility
10
automation and integration as the more reliable and cost effective
11
solution over manual operation of the existing facilities with increase
12
staffing.
13
In addition, the CAISO demands for real-time load-following cannot
14
reliably be met with only manual operating capabilities. CAISO is
15
currently proposing to implement new settlement processes which will
16
severely penalize generators for deviations outside a relatively narrow
17
range around imputed schedules (plus or minus three percent of the
18
unit’s capacity, or 5 MW, whichever is larger). Avoiding penalties will be
19
a particular challenge during periods of non-steady state schedules,
20
including the prescribed ramp between different output levels in different
21
hours, or changes prompted by the CAISO’s automated dispatch
22
system. “Aggregation” of unit schedules on a watershed is being
23
permitted by the CAISO, and on average will reduce penalties due to
24
random schedule-following errors. However, taking full advantage of
25
schedule aggregation to minimize errors requires the ability to
26
simultaneously control all or most aggregated units on a watershed in
27
real-time, with great precision.
28
The existing plant auxiliary equipment and controls at these
29
seven powerhouses are at or near the end of their useful life and in
30
need of replacement. Their replacement will be integrated with the
31
planned 2006-2013 automation to reduce costs and improve watershed
32
control capabilities.
33
Automating the switching center powerhouses when combined with
34
the SCADA replacement projects makes switching center consolidation
3-40
(PG&E-3)
1
a real possibility. Two switching centers in the Shasta, DeSabla, and
2
Drum watersheds could be consolidated into one resulting in better
3
control of the watershed operations. The switching center
4
consolidations are forecast for the 2008-2011 timeframe.
5
All capital work resulting from automation and consolidation of the
6
switching centers will be captured under MWC 81, which is part of the
7
Maintain Reliability/Availability subprogram.
8
9
Operators prepare switch logs for equipment shutdowns and
clearance, check the switch logs, and execute switching to actually clear
10
equipment. Other duties include both preparing and following
11
procedures to operate all plant equipment, canal systems, and
12
diversions dams. Additionally, operators are required to respond to
13
operational changes resulting from inclement weather conditions, both
14
during regular work hours and on an after-hour emergency basis. On
15
an ongoing basis, canals must be patrolled and valves/gates operated
16
to respond to changing water flow needs.
17
Operators must manage and document conditions and situations
18
such as in-stream flow releases and contractual water deliveries and be
19
primary responders for emergencies, as well as manage hazardous
20
waste. The hydro operations systems largely shut down automatically
21
when conditions warrant. Alarms may be activated by equipment
22
failure, storm activity, or interruptions to water flow. Operators are the
23
primary trouble shooters for failures in service. They respond to the
24
automatic alarms and recommend a remedy. They act on approved
25
recommendations or ask for assistance. When outages occur, usually
26
several weeks a year, operators assist maintenance crews with work
27
activities. Hydrographers measure and calibrate flow monitoring
28
stations and collect weather data.
29
Hydro Operations has specific operating plans for both winter and
30
summer operations. These plans take into account the unique weather
31
conditions that occur during these seasons, and the local topography in
32
each of Hydro Operation’s areas, and modify how the plants and water
33
delivery systems are operated to minimize the risk of damage to the
34
hydro facilities and thereby improve availability. By reducing the risk to
3-41
(PG&E-3)
1
facilities during times of heavy storms, savings are realized through
2
reduced storm damage to the facilities. During times of excessive heat,
3
stress on electrical system components increases dramatically. By
4
modifying operations during these times, savings are realized through
5
reduced equipment failures.
6
The working conditions are unique. Some locations are assessable
7
only by helicopter or boat. Hydro Operation’s employees work
8
weekends and holidays and respond to various changing operating
9
conditions and emergencies. They work on sloped grounds to inspect
10
dams, in confined areas, and around heavy plant equipment and
11
chemicals. They work on mountains and difficult terrains—often in
12
tunnels, small buildings, over rocks and gravel and large pipes,
13
suspended above flumes, on scaffolding, at remote sites, along steep
14
roads, in or near fast moving streams and rivers, in the snow, and
15
around poison oak, snakes, and spiders. They also maneuver on
16
flumes, around water and work around rotating and energized
17
equipment and noise. They use hand tools, electric and power
18
equipment, and computers.
19
Hydro Operations is planning to maintain recent operating practices
20
and staffing levels through 2009. This includes a staffing strategy to
21
manage attrition without temporarily increasing the number of
22
employees. Hydro Operations, like many other programs at PG&E,
23
forecasts a significant increase in employee retirements during
24
2005-2009, but believes it can manage attrition without undue operating
25
risk by utilizing the organization’s total capabilities. Hydro Operation’s
26
O&M personnel possess extensive knowledge of site conditions and the
27
unique operating characteristics because of their years of service.
28
Hiring a replacement in advance of the expected retirement would allow
29
the new employee to become knowledgeable about the hydro facilities
30
and complete approved apprentice programs.
31
The hydro organization has a blend of operating and maintenance
32
personnel, Title 200 under the IBEW contract, and construction
33
personnel, Title 300 under the IBEW contract. Hydro Construction’s
34
staffing levels increased in 2004 and 2005 as a result of the increased
3-42
(PG&E-3)
1
investment in maintenance and reliability projects. Hydro Operation’s
2
staffing strategy is to hire, train, and develop Title 300 employees to not
3
only handle the increase capital workload, but in anticipation of future
4
T200 vacancies. The goal is for these employees, with construction
5
experience from throughout the system, to have sufficient hydro
6
knowledge and experience to bid into the O&M positions without the
7
need for an overlap or temporary increase in staffing levels. The GRC
8
forecast assumes that this strategy will be successful and therefore the
9
O&M staffing levels and labor cost for this subprogram are flat.
Hydro Operation personnel work closely with the Building and Land
10
11
Services department to manage the hydro lands as describe in Exhibit
12
13
(PG&E -2), Chapter 12, of this application. The Hydro Operation
Program currently has approximately 140,000[13] of the 240,000 acres
14
managed by Building and Land Services. This includes approximately
15
65,000 acres of watershed lands surrounding the hydro production
16
facilities that are managed to ensure that there is no development or
17
activity adverse to hydro generation. This is reflected in PG&E’s
18
Corporate Policy Manual, Section E-5.10 that states:
It is PG&E’s policy to manage company real property in a manner
that supports the safe and reliable operation of company facilities,
provides a positive environment for employees and customers,
helps maintain and enhance environmental quality and biological
diversity, maximizes the efficient use of energy, and promotes
achievement of the company’s financial and service objectives.
19
20
21
22
23
24
5. Maintain Reliability, Availability and Improve Efficiency
25
26
Subprogram
27
a.
General
This subprogram includes work associated with maintenance of
28
29
powerhouse structures, turbine-generator and switchyard equipment,
30
dams, reservoirs, water conveyance systems, roads and bridges, and
31
other facilities. As described in the 2003 GRC, Hydro Operations
32
assessed how best to maintain long term reliability. The two key
[13]
Hydro makes use of approximately 168,000 acres of land. Approximately
26,500 acres are private or government land over which we have easements,
licenses, use permits or other entitlements allowing their use for hydroelectric
production.
3-43
(PG&E-3)
1
programs that support Hydro Operation’s maintenance work came from
2
the work management and condition assessment process improvement
3
projects initiated in 2001 and 2002.
4
(1) Condition Assessment Program
5
This program supports the proposed migration from time-based
6
maintenance to condition-based maintenance. The basis for the
7
current condition assessment program has been used for years to
8
develop priorities for asset maintenance and replacement.
9
However, much of the current asset management program is
10
time-based, meaning that asset maintenance or replacement is
11
being done based on time durations, with no certainty that it is
12
occurring at the optimum time for each asset. The advantage of a
13
state-of-the-art condition assessment program is its ability to use
14
condition-based assessments to determine when maintenance
15
should be performed or when an asset should be replaced. The
16
optimization of maintenance timing and asset replacement can
17
result in savings over the long run. The condition assessment
18
program system will standardize the collection and trending of
19
performance indicators for key components and facilities.
20
Performance measures or “out of spec” limits will be established for
21
critical components so that the appropriate corrective action is
22
triggered in the new work management System or long term
23
planning process. Condition assessment summaries will be
24
provided on both a powerhouse and systemwide level for overview
25
evaluations and prospective checks. Hydro Operations is faced
26
with maintaining equipment that in some cases is over 100 years
27
old. Condition assessment supports utilizing the right resources, at
28
the right time, on the right work.
29
Hydro Operations has had a basic condition assessment
30
program for years and 43 percent of 2004 projects resulted from
31
some form of condition assessment based upon visual, measured
32
values, fluid/gas sampling, or programmatic assessments. Our
33
current upgrades involve implementing an easily accessible
34
centralized repository for data and establishing uniform “out of
3-44
(PG&E-3)
1
tolerance” criteria to ensure that resources are efficiently allocated
2
to the highest value work.
3
Hydro Operations used the previous condition assessment
4
program to start implementation of a state-of-the-art condition
5
assessment program. This program will ultimately be used for
6
optimization of resources in Hydro Operations’ long term plan,
7
basing asset maintenance and replacement decisions on the
8
equipment’s condition, using developed performance measures.
9
In 2004, Hydro Operations started implementation of a cutting
10
edge software program which uses uploaded measured, visual,
11
physical (touch and smell), and calculated data to track equipment
12
condition. Out of tolerance criteria is being established for key
13
equipment as the software program is implemented. This software
14
database will enable Hydro Operations to centralize equipment
15
condition data, store a history of the equipment readings, allow for
16
trending the readings, and generate an alarm when readings vary
17
from pre-determined parameters. In addition, the condition
18
assessment program effort has a plan to review current equipment
19
testing procedures to ensure that testing is performed to industry
20
standards.
21
In the next few years, Hydro Operations will continue to expand
22
the implementation of the condition assessment program to include
23
additional facilities and equipment utilizing the software program, as
24
well as continuing development of “out of spec” criteria and
25
standardized testing procedures.
26
27
(2) Work Management Process
The work management process improvement project, initiated
28
in 2001, reviewed Hydro Operations’ historic practices, identified
29
limitations, benchmarked other work management processes,
30
developed and mapped a new work management process and
31
developed an implementation plan. In 2004, a new work
32
management system (WMS), including new processes and tools,
33
was implemented to assist in managing not only the work on hydro
34
equipment and facilities, but also the resources available to perform
3-45
(PG&E-3)
1
the work. These new processes have now become ingrained as
2
part of the normal course of business for employees dealing with
3
hydro facilities.
4
The WMS facilitates the management of work to be performed
5
on hydro equipment by allowing each piece of identified work to be
6
assigned to a work center where it is planned, prioritized, and
7
scheduled for completion. Any identified work can be tracked,
8
whether it is periodic routine maintenance tasks, daily trouble
9
reports, minor or major equipment repair work, agency compliance
10
tasks or capital replacement projects. The system tracks the cost of
11
the work and the history of work done against the piece of
12
equipment.
13
The prioritization capability in the WMS allows Hydro
14
Operations to prioritize the work to assure the most critical
15
equipment needs are being addressed by the limited available
16
resources.
17
In addition to these two programs, progress with three additional
18
management processes, started in 2004, continues to ensure
19
projects are completed as planned within budget and on schedule.
20
21
(3) Improved Project Planning
Hydro Operations recognized the significant increase in project
22
work that would take place during the catch-up period and the
23
increasing regulatory agency approval and permitting durations,
24
Hydro Operations therefore promoted use of a formalized a
25
multi-year project plan to ensure that projects would be completed
26
as planned. This multi-year project approach is composed of
27
planning and committing to complete the necessary engineering,
28
procurement of material, and obtaining of agency approvals and
29
permits in the first one-to-two years (depending on complexity and
30
lead times) and then completing the construction of the project in
31
the next two-three years. In order to achieve this approach, Hydro
32
Operations plans for projects in both the long-term plan and the
33
annual budgeting process in a manner that commits to completing
34
all phases of a project upfront and then provides the needed
3-46
(PG&E-3)
1
resources only in the year needed. By allowing additional time to
2
complete the engineering, procure the material, and obtain agency
3
approvals and permits, Hydro Operations can develop a more
4
dependable plan for use of construction resources and ultimately
5
complete the projects in the most cost-effective manner possible.
6
(4) Strategic Alliances
7
Hydro Operations also developed key strategic alliances with
8
outside engineering firms to efficiently contract out engineering work
9
while ensuring quality and cost competitive services. Hydro
10
Operations is currently in the process of also developing strategic
11
alliances with key major equipment suppliers, such as turbines,
12
large valves, generators, exciters, governors, SCADA, station
13
service switchgear, and switchyard equipment manufacturers.
14
15
(5) Project Management
Hydro Operations continues to enhance its project management
16
capabilities, (organization created in 2003), to manage the larger,
17
more complex projects and outages.
18
b. Expense (MWCs AI, AX, AZ, BB and BK)
19
The hydro assets require substantial resources to maintain their
20
reliability. The forecast maintains the existing base maintenance
21
practices at historic expenditure levels but also includes a substantial
22
increase for specific new work to catch-up on investments not made
23
during the post AB1890 years. The increase for 2007-2009 is related to
24
projects that maintain unit availability and reliability and implement work
25
determined by programs started in 2003 as well as begins to capture
26
efficiency improvements as this equipment and systems are replaced.
27
Figure 3-9 categorizes this subprogram’s expenses by MWC.
28
It shows that costs increase across the board due to age and condition
29
of the hydro facilities, but that the greatest dollar increase is to MWC AX
30
(Maintain Reservoirs, Dams and Waterways). The following testimony
31
provides an expanded description of this work and specific expense
32
projects will also be included in the workpapers.
33
1. Water storage and conveyance projects – This work includes
34
additional reservoir and spill channel maintenance; canal, flume,
3-47
(PG&E-3)
1
and tunnel inspections and risk-based condition assessment and
2
repairs; and repairs to tailraces and stop logs.
2. Turbine-generator and associated equipment projects – This work
3
4
includes: (1) assessment and repairs to turbines, including runners,
5
wicket gates or needle valves, bearings, governors, and other
6
turbine components; (2) assessment and repairs of generators,
7
including field poles, bearings, cooler re-cores, and exciters;
8
(3) assessment and repairs of large valves, including penstock
9
shutoff valves, turbine shutoff valves, and pressure relief valves;
10
and (4) assessment and repairs to miscellaneous electrical
11
systems.
12
3. Infrastructure projects – This work includes increased maintenance
13
for buildings and roofing, roads, bridges identified in the Bridge
14
Mitigation Program, and telecommunication and SCADA facilities.
15
16
c.
Capital (MWCs 81 and 5)
Substantial capital expenditures are needed to maintain generation
17
reliability and availability and begin to capture increased efficiencies.
18
Figure 3-10 categorizes this subprogram’s work (described below) and
19
shows forecast increases in a number of areas. The forecast is based
20
upon specific identified projects which are listed in the workpapers
21
supporting this chapter including a one-page summary for each project
22
greater than $1 million.
23
(1) Water storage and conveyance projects
24

Water conveyance reliability, including canal, ditches, and
25
tunnel lining; flume replacement; spill gates replacement;
26
geotechnical slide mitigation; and installation of water
27
conveyance monitoring systems.
28
29
(2) Turbine-generator and associated equipment projects

Turbine reliability and efficiency gains, including replacement or
30
upgrades of runners, seal rings, wicket gates, needle valves,
31
and associated turbine components.
32
33

Powerhouse large valves and mechanical auxiliary system
reliability, including replacement of turbine shutoff valves,
3-48
(PG&E-3)
1
pressure relief valves, and penstock shutoff valves; governors;
2
and miscellaneous auxiliary oil, water, and air mechanical
3
systems.

4
Generator reliability and upgrades, including stator rewinds,
5
replacement of field coils and poles, and replacement of
6
excitation systems.

7
Supervisory Control and Data Acquisition (SCADA) and
8
telecommunication reliability including replacement of outdated
9
SCADA, analog radio systems, annunciators, and power
sources.
10

11
Electrical Auxiliary Systems reliability, including replacement of
12
medium and low voltage switchgear, motor control centers,
13
transformers, and distribution systems; DC batteries, chargers
14
and distribution systems; emergency backup generator
15
systems; protection systems for generators, high voltage
16
transformers, and high voltage breakers; and plant
17
instrumentation and automation.

18
High Voltage Switchyard reliability, including replacement of
high voltage breakers, switches, and step-up transformers.
19
(3) Infrastructure projects
20
This work includes capital replacement of buildings, roofing,
21
22
HVAC systems, road repaving, bridges identified in the Bridge
23
Mitigation Program, and telecommunication and SCADA facilities.
24
25
26
6. Business Subprogram
a.
Expense (MWC AB and BC)
Base business subprogram work includes the administrative costs
27
associated with managing the Irrigation District contracts and the
28
reimbursable expenses incurred to perform maintenance on behalf of
29
the Irrigation Districts. The reimbursable maintenance expenses are
30
billed to the Irrigation Districts with the reimbursements recorded as
31
Other Operating Revenue and included in Exhibit (PG&E-2),
32
Chapter 16. It also includes initiating, managing and implementing
3-49
(PG&E-3)
1
business system improvements. The forecast is based on historic
2
expenditures and has decreased from 2005 due to the change in the
3
method used to record the Contract Services section costs. Beginning
4
in 2005, the Contracts section is allocated to the expense and capital
5
orders that they support
6
7
E. Translation of Program Expenses to FERC Accounts
As discussed in Chapter 4 of Exhibit (PG&E-1) PG&E uses the SAP view of
8
cost information to manage program costs. Thus, for presentation in this GRC,
9
certain SAP dollars must be translated to FERC dollars. This is not an issue for
10
capital costs, where the SAP and FERC view are identical. For O&M expenses,
11
however, the SAP dollars include certain labor-driven adders such as employee
12
benefits and payroll taxes that are charged to separate FERC accounts and
13
addressed separately in this rate case. These labor-driven adders must be
14
removed from the SAP dollars for O&M expenses to present them by FERC
15
account.
16
Tables 3-3 through 3-8 show how the SAP expense dollars in the Hydro
17
Operations Program translate to the appropriate FERC accounts. The tables
18
show current year dollars (i.e., nominal dollars) and re-stated in base year
19
dollars (i.e., 2004 dollars).
20
21
F. Cost Tables
PG&E’s capital and expense requests for the Hydro Operations Program
22
are summarized in the following tables:
23
Table 3-1 lists the subprograms and capital MWCs, showing 2004 recorded
24
capital expenditures and 2005 through 2009 forecast capital expenditures
25
by MWC;
26
27
Table 3-2 lists the subprograms and expense MWCs, showing 2004 recorded
expenses and 2005 through 2009 forecast expenses by MWC; and
28
Tables 3-3 through 3-8 display the 2004 recorded expenses and 2005 through
29
2009 forecast expense expenditures by subprogram, MWC, and FERC
30
account. Each subprogram set of tables is in sequence by nominal dollars,
31
nominal dollars by FERC account and 2004 dollars by FERC account.
32
3-50
(PG&E-3)
1
2
3
4
FIGURE 3-1
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO CAPITAL
NOMINAL ($000)
$140,000
$120,000
Reliab./Avail./Prod.
Regulatory
Safety
Environmental
Base
$100,000
$80,000
$60,000
$40,000
$20,000
$0
90-96 1997
1998
1999
2000
2001
3-51
2002
2003
2004
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
FIGURE 3-2
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO CAPITAL
(2005 $000)
$120,000
$100,000
Reliab./Avail./Prod.
Regulatory
Environmental
Safety
Base
$80,000
$60,000
$40,000
$20,000
$0
90-96
1997
1998
1999
2000
2001
5
3-52
2002
2003
2004
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
FIGURE 3-3
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO EXPENSE
NOMINAL ($000)
5
Business
$180,000
Reliability & Availability
Operate
$160,000
Regulatory
Environmental
$140,000
Safety & Health Mgmt.
Base
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
$0
90-96
1997
1998
1999
2000
2001
2002
3-53
2003
2004
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
FIGURE 3-4
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO EXPENSE
(2005 $000)
Business
$160,000
Reliability & Availability
Operate
Regulatory
$140,000
Environmental
Safety & Health Mgmt.
$120,000
Base
$100,000
$80,000
$60,000
$40,000
$20,000
$0
90-96
1997
1998
1999
2000
2001
2002
5
3-54
2003
2004
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
5
FIGURE 3-5
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO EXPENSE
BASE AND SPECIFIC PROJECTS
NOMINAL ($000)
Specific Projects
Base Business
$180,000
Base Safety & Health Mgmt.
Base Environmental
$160,000
Base Regulatroy Compliance
Base Operate Plant
$140,000
Base Maintain Reliab. & Avail.
$120,000
$100,000
$80,000
$60,000
$40,000
$20,000
$0
2000
2001
2002
2003
2004
6
3-55
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
5
FIGURE 3-6
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO CAPITAL
SAFETY SUBPROGRAM (MWC 13)
NOMINAL ($000)
$20,000
Watershed Safety
$18,000
Misc. Safety-Related Projects
Dam-Safety Related Projects
$16,000
Fall Protection
$14,000
$12,000
$10,000
$8,000
$6,000
$4,000
$2,000
$0
2001
2002
2003
2004
6
3-56
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
5
FIGURE 3-7
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO EXPENSE
REGULATORY COMPLIANCE SUBPROGRAM
NOMINAL ($000)
$60,000
MWC DP
MWC DL Specific Projects
Chili Bar license - July '07
MWC DL Base
$50,000
Regulatory Fees
Poe; Pit #3, #4, #5; Upper NF Feather
River licenses - June '06
Potter Valley license amendment - Jan '04
Kern Canyon license Dec '05
$40,000
Crane Valley license - Sept '03
Spring Gap-Stanislaus
license - Sept '05
Pit 1 license - March '03
Moke and RCC licenses - Oct
'01
Hat Creek license - Oct
'02
$30,000
$20,000
Haas-Kings River license - Jan
'01
$10,000
$0
2000
2001
2002
2003
2004
2005
Year
6
3-57
2006
2007
2008
2009
$20,000
2000
2001
$30,000
2002
To Be Issued
Prior Existing
Relicensing
Safety / Other
$40,000
2003
6
3-58
2004
Year
2005
2006
2007
DeSabla Centerville license
Chili Bar license
Upper NF Feather River license
Poe License
Pit #3, #4, #5
Kern Canyon license
Spring Gap-Stanislaus license
Potter Valley license amendment
Pit 1
license
Crane Valley license
Hat Creek license
$50,000
RCC license
1
2
3
4
5
Mokelumne license
Haas-Kings River license
(PG&E-3)
FIGURE 3-8
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO CAPITAL
REGULATORY COMPLIANCE SUBPROGRAM (MWC 11)
NOMINAL ($000)
$60,000
$10,000
$0
2008
2009
(PG&E-3)
1
2
3
4
5
FIGURE 3-9
PACIFIC GAS AND ELECTRIC COMPANY
HYDRO EXPENSE
MAINTAIN RELIABILITY & AVAILABILITY SUBPROGRAM
NOMINAL ($000)
$80,000
Maint Other Equip (BK)
Maint Generators (BB)
$70,000
Maint Roads & Bridges (AZ)
Maint Resv,Dams&Waterways (AX)
Maint Gen Fac-Structure (AI)
$60,000
$50,000
$40,000
$30,000
$20,000
$10,000
$0
2000
2001
2002
2003
2004
6
3-59
2005
2006
2007
2008
2009
(PG&E-3)
1
2
3
4
FIGURE 3-10
PACIFIC GAS AND ELECTRIC COMPANY
MAINTAIN RELIABILITY & AVAILABILITY SUBPROGRAM (MWC 81)
NOMINAL ($000)
$70,000
$60,000
$50,000
$40,000
Miscellaneous Reliability
Road Reliability
Replacement of Batteries
Structural installation/Removal
Water Conveyance Reliability
Modifications at Intakes/Dams
Transformer Replacement
Telecommunication Reliability
Turbine Reliability
Generator reliability
Powerhouse Mechanical and electrical Reliability
General Watershed Reliab/Availability
$30,000
$20,000
$10,000
$0
2001
2002
2003
2004
3-60
2005
2006
2007
2008
2009