ࡱ> ` !bjbj E/{ DHHHR<###$vvv8l$ >"̦(b{oqqqqqq$Hh#k"w$eeed#oeoee5"&# @iC@cvd|< RKR R#(C`eU\CCCdCCC $ %!F/rv/$ %Frv$$  SEQ chap \h \R3 PACIFIC GAS AND ELECTRIC COMPANY CHAPTER  SEQ chap \c3 HYDRO OPERATIONS PROGRAM COSTS Introduction Scope and Purpose The purpose of this chapter is to demonstrate that Pacific Gas and Electric Companys (PG&E or the Company) expense and capital expenditure forecasts for its Hydro Operations Program are reasonable and should be adopted by the California Public Utilities Commission (CPUC or Commission). PG&Es hydro system consists of 110generating units at 68powerhouses. These generating units have a combined maximum normal operating capacity of 3,896megawatts (MW) and produce an average of 11,672 gigawatthours (GWh) per year. Commission adoption of PG&Es expense and capital forecasts for operating and maintaining the hydro system is necessary to ensure safe, reliable and lowcost generation from these assets in 2007 and beyond. Summary of Request PG&E requests that the Commission adopt its2007 forecast of capital expenditures of $103.6million to maintain a reliable, lowcost hydro system that produces clean, carbon free, energy to meet Californias needs, while meeting all of the federal, state and local regulatory requirements. PG&E further requests that the Commission adopt its 2007 forecast of $143.9million of hydro operations and maintenance (O&M) expense. PG&E is also providing specific forecasts for 2008 and 2009 to support the generation attrition proposal in Chapter13 of this exhibit. PG&E requests that the Commission reflect in the attrition adjustments for 2008 and 2009 its O&M expense forecast of $150.8million for 2008 and $158.5million for 2009 and its capital forecast of $110.1 million for 2008 and $117.3 million for 2009. Support for Request PG&Es capital and expense forecasts are reasonable and justified because they ensure continued safe, reliable, and environmentally responsible operation of the hydro system. Currently, PG&E: Safely and reliably operates the hydro system in compliance with all state and federal regulations and the Federal Energy Regulatory Commission (FERC) license conditions; Operates and maintains the hydro system to make energy supply available to meet demand, within the constraints of water usage, thereby reducing the overall energy procurement costs charged to customers; Promotes environmental protection, resource stewardship and collaborative relicensing; and Maintains energy and ancillary service capabilities to provide ancillary service products to help meet PG&Es long term needs. Hydro Operations forecast reflects increased 2007-2009 spending associated with the following major business drivers: License conditions associated with new FERC licenses along with new facility safety and environmental regulations; and New regulatory fees imposed on the hydro assets by State and Federal agencies; and Investment in generation efficiency improvements that reduce the costs to PG&Es customers while increasing Californias source of clean, carbon free, energy; and Automation and other improvements to the hydro infrastructure to comply with new, sometimes complex, license requirements at the least cost. Organization of the Remainder of This Chapter The remainder of this chapter is organized as follows: Program Management Process; Estimating Method; Activities and Costs by Subprogram/Major Work Category (MWC); Translation of Program Expenses to FERC Accounts; and Cost Tables. Program Management Process PG&E manages both expense and capital expenditures for its hydro assets through onecentralized program. This program consists of sixsubprograms and uses 16 expense MWCs (regulatory fees are also segregated) and fivecapital MWCs. This section describes the Hydro Operations Program, including background information on the age and condition of the assets and a description of the support organization. PG&E includes this information to assist the Commission and other participants in the General Rate Case (GRC) proceeding in understanding the expansive nature of the hydro system and the need for a centralized program management approach to ensure that PG&E systematically invests in the highest value-work. Overview and History of the Hydroelectric System PG&Es 68hydro powerhouses are located on 16rivers and fourtributaries of the Sierra Nevada, Cascade and Coastal mountain ranges, (see work papers; Figure 3-1). These facilities were built between 1898 and 1986. Most of the dams and powerhouses have been in service for well over 50years, and some of the water collection and transport systems were used for gold mining and consumptive water prior to the development of the hydro system. The hydro system operates under 26FERC licenses, which govern the operation of 105 generating units at 65powerhouses, plus five units at threenonFERC jurisdictional powerhouses with a total generating capacity of 3,896MW. PG&Es authority to divert and store water for power generation is based on 92water right licenses or interim permits, and 160Statements of Water Diversion and Use. Each hydro facility was engineered considering the specific river flows and topography of its site. The system collectively includes the following facilities: 99reservoirs, 76diversions, 174dams, 184miles of canals, 44miles of flumes, 135miles of tunnels, 19miles of pipe, 5miles of natural waterways, and approximately 140,000acres of feeowned land (refer to Chapter 7, Exhibit (PG&E-3) for a discussion of PG&Es land conservation commitment). It also includes switchyards, switching centers that remotely control generation facilities, administrative buildings, fleet, multiple modes of communication, materials and supplies inventories, office equipment, and other miscellaneous instrumentation and monitoring equipment. Organization and Operational Efficiencies When the older hydro facilities were constructed, they required onsite staff to operate and maintain the generating equipment and water systems. Investment in technological advancements automated the hydro system over the past 100years, so that today only 8 of the 68hydro powerhouses are manned during normal operations. Seven of these powerhouses serve as hydro switching centers and the eighth is the Helms Pumped Storage Project. These switching centers and Helms are staffed 24hours a day and have the ability to call for additional hydro personnel as needed. Powerhouse equipment and water system automation over the past decades, including the installation of alarms and controls, have maintained system reliability while reducing the requirement for a number of headquarters, service centers and employee houses. This consolidation has resulted in significant downsizing and cost efficiencies. The current field organization of hydro operations is built around fivewatersheds: Shasta, which includes sixFERC licenses covering 16powerhouses with a combined capacity of 810MW; DeSabla, which includes sixFERC licenses covering 12powerhouses with a combined capacity of 756MW, and threenonjurisdictional powerhouses[] with a combined capacity of 8MW for a total of 764MW; Drum, which includes fourFERC licenses covering 15powerhouses with a combined capacity of 218MW; Motherlode, which includes fourFERC licenses covering eightpowerhouses with a combined capacity of 318MW; and Kings CraneHelms, which includes 7FERC licenses covering 13conventional powerhouses and the Helms Pumped Storage Facility, with a combined capacity of 1,787MW. Service Centers and Reporting Headquarters Hydro Operations O&M personnel are assigned to twelveservice centers and sevenreporting headquarters[] to handle ongoing hydro O&M work. In addition to personnel assigned to the service centers and reporting headquarters, the hydro construction field force is mobile and works throughout the system. Hydro Operations centralized staff is located in SanFrancisco. A series of tables included in the work papers, (Figures 32 through 311), list where O&M personnel who have primary responsibility for responding to work assignments throughout the hydro system are located. There are twotables for each watershed region. The firsttable, titled Personnel Headquarters, identifies the locations in each watershed where personnel providing O&M services normally report to work prior to traveling to a remote hydro facility. Work requirements and, hence, staffing vary in relation to the design features of each project. For example, projects with long water conveyance systems require additional water maintenance and water operations personnel. The secondtable, titled, Job Classifications Reporting to Each Headquarters, lists the number of employees in each O&M job classification at each service center or reporting headquarters. These employees handle the watersheds base workload, including emergency response. The number of employees in the column marked fulltime equivalent (FTE) are as of June 2005. Switching centers generally have fiveto sevenoperators in oneor two classifications.[] Each of the sevenreporting headquarters generally only has one or twooperating personnel assigned to them. Service centers can have up to 35employees in nineclassifications. As shown in these tables, there are only a few hydro employees in each classification at each service center. Hydro Operations centralized organization provides oversight and direction to ensure that critical resources and personnel are shared between watersheds. This includes a mobile construction organization, which handles major maintenance projects throughout the hydro system and a centralized management team that provides the following services and expertise: Business and information systems; Construction and construction management; Engineering, project management and facility safety; Environmental, health and safety; Land management and recreation facilities management; Licensing, compliance and relicensing; Operations; Maintenance; and Water management. LongTerm Plan (LTP) The LTP, along with Hydro Operations condition assessment and work management programs, provides data that allows PG&E to assess the physical condition of the assets, identify the projects and resources needed to maintain the facilities properly, and optimizes work schedules and expenditures to minimize the long-term cost of production from these generating facilities. This information is included in the workpapers to this testimony. Benefits resulting from these efforts include: More efficient utilization of Hydro Operations maintenance, operation, planning, design, licensing, and construction staffs; Early coordination with support departments to obtain needed resources; More efficient utilization of financial resources; and Determination of the proper level of investment to restore and sustain hydro assets. Value and Use of the Hydroelectric System PG&Es hydro plants produce lowcost energy, highvalue ancillary services and peaking capacity to meet customers needs. PG&E has demonstrated its ability to optimize these generation facilities through efficient use of water resources and continuing environmental stewardship. This 2007 General Rate Case forecast identifies the actions and costs required to maintain the systems existing capabilities for the benefit of customers. The California Energy Commission recognizes that Hydroelectricity is an important element of Californias energy portfolio, providing between nine and 30percent 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 states generation system.[] Meeting PG&Es Customers Energy Needs PG&Es hydro system consists of 110 generating units at 68powerhouses with a total generating capacity of 3,896 MW, which represents about 28percent of Californias hydro capacity. PG&Es hydro system includes reservoirs which enable PG&E to store runoff and aquifer flows and then subsequently use the water to generate power when the customers need it most. This shaping of the available generation is performed both seasonally (for example, by storing more water in the spring and releasing water from the reservoirs during high value hot summer days) and daytoday (for example, generating more during hours of peak system demandtypically weekday afternoons and evenings and less at night and on weekends). In general, the highest value of generation is likely to be when PG&Es demand is greatest, and hydro generation can contribute significantly toward reducing the amount of power that has to be purchased during these higherprice hours. CostEffectiveness of Hydroelectricity Hydropower is the most efficient energy resource, with a 90percent conversion rate of transforming hydraulic forces to electricity. Hydro Operations operating costs are low and predictable since there are no fuels to purchase. Once the capital costs are recovered, hydro is the most cost-effective energy source in use today. PG&Es hydro system provides its customers with 3,896MW of normal maximum operating capacity and 11,672GWh of energy in an average precipitation year. The continued availability of this hydro power helps meet the system peak load and plays an essential role in controlling energy prices in California. Maintaining these capabilities can further reduce the cost of obtaining energy or ancillary services to meet PG&E's net open position. Load Shaping and Peaking Value of Hydroelectricity While the primary requirement for electric procurement is to meet customer energy demand, PG&E additionally provides or procures ancillary services required to maintain electric grid stability. The California Independent System Operator (CAISO) requires load serving entities to provide or pay for a proportionate share of the ancillary services needed by the CAISO to maintain electric system reliability. PG&E uses hydro to selfprovide the following ancillary services:[] Regulation Up Generation that is already up and running (synchronized with the power grid) and can be moved via direct electronic commands by the CAISO above the units scheduled output level, to keep system wide energy supply and energy use in balance (Automatic Generation Control (AGC) market); Regulation Down Generation that is already up and running (synchronized with the power grid) and can be moved via direct electronic commands by the CAISO below the units scheduled output level, to keep systemwide energy supply and energy use in balance (AGC market); Spinning Reserves Unloaded online generation that can be dispatched within 10minutes; NonSpinning Reserves Unloaded offline generation that can be dispatched within 10minutes; and Replacement Reserves Generation that can begin contributing to the grid within an hour. PG&E maximizes the availability of these capabilities by operating the majority of the hydro facilities as peaking facilities. This operating strategy helps meet daily changes in system demands and preserves hydro's rapid dispatch and spinning reserve capabilities for use during higher value periods. Hydroelectric generating units typically start up quickly, have high ramprates, and can easily, quickly, and economically vary output in response to changing customer loads and system conditions. In addition, hydro generating units can operate at noload or lowload with much higher efficiency than the alternative fossilfueled peaking plants. Finally, because a large portion of California's nonfossil-fueled electricity resources consist of nondispatchable energy sources such as wind, solar, nuclear and regulatory musttake generation, the CAISO relies on PG&Es hydro resources to satisfy a large portion of its operating reserve requirements. The hydro system provides 90 percent of the ancillary service capabilities required by the CAISO for PG&Es service territory. This means PG&E is usually able to selfprovide the required ancillary service capability and thus eliminate the need to purchase supplemental capabilities from the market. Reliability of Hydroelectricity Hydroelectric generation has one of the highest availability and reliability rates of all generation resources. Customer service reliability is enhanced by the high availability, reliability, and operational flexibility of existing hydro resources. Hydro Operations forebay and afterbay storage capabilities allow this mode of operation while complying with the FERC license streamflow requirements. High availability assures full utilization of the available water resources and therefore reduces the average cost of generation The reliability of the electric grid depends on fast, flexible generation sources to meet peak power demands, maintain level system voltages and quickly restore service after a blackout. Hydroelectricity can be placed on the electric grid faster than any other energy source. Hydropowers ability to go from zero power to maximum output rapidly and predictably makes it exceptionally good at meeting changing loads and providing ancillary electric service that maintain the balance between electric supply and demand. Because hydropower is generated within seconds of when water begins rushing through its turbines, hydropower is particularly adept at providing incremental bursts of power. This is of great value to electric power grid operators, which is why they often rely on hydropowers speed and flexibility to meet fluctuations in electric power demand and to restore service after a blackout. Clean, Carbon Free, Source of Power PG&Es customers benefit from this indigenous, carbon free, resource because it produces no air pollution and hydro power directly offsets the use of nonrenewable fossil fuels. In addition, hydro power is a nonconsumptive use of water resources that is well integrated into water supply, irrigation, flood control, and other multipurpose projects. On September 12, 2002, Governor Gray Davis signed a bill (SB1078) requiring California to generate 20percent of its electricity from renewable[] energy no later than 2017. The new law requires sellers of electricity at retail to increase their use of renewable energy by 1percent per year. Since California already generates about 10percent of its electricity consumption by renewables, the new law will nearly double the state's existing base of wind, geothermal, biomass, small hydro,[] and solar energy resources. While all conventional hydroelectric powerhouses are refueled through annual precipitation, only about 295 MW of PG&Es hydroelectric capacity meet the States small hydro classification and are thus included in the RPS baseline. Natural Resources Stewardship PG&E demonstrated its commitment to environmental stewardship by reaching an agreement in 2003 with the California Public Utilities Commission to establish the Pacific Forest and Watershed Lands Stewardship Council, a California nonprofit foundation, to permanently conserve beneficial uses of its hydro watershed lands. The Council will provide oversight of the development and implementation of a plan that delineates long-term management objectives for PG&Es land holdings of approximately 140,000 acres of hydro watershed lands. These lands will be conserved for a broad range of public benefits, including the protection of the natural habitat for fish, wildlife, and plants, the preservation of open space, outdoor recreation by the general public, sustainable forestry, agricultural uses, and land to be preserved for historic and cultural values. See Chapter 7 of this exhibit for a more detailed discussion of the Pacific Forest and Watershed Lands Stewardship Council. Hydroelectric projects provide a wide range of non-power benefits, including fresh water storage, recreation, flood control, drinking water supply, and irrigation. Hydroelectric projects also provide recreation amenities such as boating areas, fishing sites, picnic grounds, and hiking trails that enhance the quality of life for local communities. PG&E hydro projects deliver water at 54 locations for consumption by 39 different user groups. Reservoirs store about 2million-acre feet of fresh water, which represents 6percent of the states total fresh water storage capacity. PG&E hydro watershed lands provide recreation, including 41 campgrounds, 37 picnic and day use facilities, for an annual number of camp visitors of over 175,000. PG&E also leases watershed lands for recreation home sites, marinas, resorts and parks, boat docks, grazing, fish hatcheries, and tree farms. Estimating Method The Hydro Operations Program develops its forecast by subprogram and MWC. Potential work is identified, categorized, and prioritized in hydros LTP which provides a detailed schedule of work and associated expenditures into the future. Subsequent planning iterations are used to review and refine the scope of work and associated cost estimates as new information is available. The most-current information for the following year (first year of the long-term plan) serves as the basis for hydros annual budget forecast submitted for PG&E management approval. PG&Es management compares the Hydro Operations Program to all other PG&E Programs prior to approving its budget. Even after project-type work is included in the approved annual budget it remains subject to final authorizations following review of moredetailed estimates, schedules, and justifications. Authorization to proceed is also subject to an assessment as to whether higher priority work has materialized. The expense and capital forecast in this GRC request and annual budget does not include a contingency for unidentified work. Yet due to the age and location of these assets, they are subject to unanticipated component failures and storm damage. Major storms disrupt operations and inflict considerable damage on the water conveyance systems and even the powerhouses themselves. The Hydro Operations Program manages these unplanned expenses, whether expense or capital, by assessing what performance efficiencies can be captured or lower priority work can be deferred so that funds are available to proceed with the emergency work. This exercise occurs monthly and assures that the Hydro Operations Program continuously optimizes the investment decisions needed to ensure safe, reliable, and economic operations. This chapter uses four sources of cost data to develop forecasts for 2007, 2008 and 2009. Actual expenditures are used for 2004. Hydro Operations approved budget was used for the 2005 forecast. Hydro Operations recommended budget was used for 2006 and the LTP provided the 2007 through 2009 forecast of expenditures. Forecast Methodology Hydro Operations centralized program management organizes the forecast work by subprogram and MWC. Work identified within each subprogram is compared to ensure similar standards and risk assessment methodologies are used to prioritize work throughout the hydro system. Hydro Operations plannersworking with O&M personnel, engineers, project analysts, and project managersdevelop, review, rank, and submit detailed funding requests to the Hydro Operations Program office for a hydro wide comparison with all other work. The Hydro Operations Program uses managements collective experience and judgment to establish the final assigned priorities and funding request. This recommended Hydro Operations Program budget is then submitted to Generations management to cross prioritize against the proposed fossil and nuclear budget requests. This composite Generation request is then forwarded to the Utility for comparison with all of the non-generation programs prior to approval. Hydro Operations 2005 budget was approved in November 2004. The Hydro Operation Programs annual budget review results in a ranked list of recommended work. The highest-priority work over the recent past and through 2006 has been to maintain these generating assets to operate safely, to protect the environment, to comply with all FERC license conditions, meet other regulatory requirements and to operate reliably. As described in more detail below, the Hydro Operations Program forecast now includes funding for efficiency improvements. PG&Es 2003-2006 investments focused on long term reliable generation from these hydro units. These investments are producing the desired results and therefore Hydro Operations recommends investing in efficiency improvements that provide customers with clean, carbon free, cost effective energy. Safety, environmental and regulatory compliance work will continue to be assigned a higher budget priority. Efficiency improvements will be compared to reliability work so that the highest value work, from a customers perspective, is funded. This economic evaluation considers the consequences of an in-service failure and captures the efficiency associated with scheduling projects to reduce the combined outage duration. Hydro Operations LTP currently indicates minimal spending on efficiency projects until 2006 or later. Most of this work, when it occurs, will be integrated with reliability work to minimize outages. Hydro Operations LTP does not include any capacity additions, although turbine efficiency improvements may yield small increases (i.e., more energy produced with the same water throughput). Hydro Operations 2003 thru 2005 budgets included planning-related process improvements in the business subprogram. In addition to minor expenditures to improve the LTP database itself, Hydro Operations implemented new tools for gathering and analyzing equipment condition assessment data, and also for analyzing and scheduling work (work management). These process improvements promote a systematic collection of data and subsequent analysis so that future investments target the highest-value work. This improves PG&Es ability to assess which investments provide the highest value to customers. Capital Forecast PG&E forecasts an increase in capital expenditures in 20072009 so that the hydro system can continue to provide low cost energy and ancillary services to customers for the long term. Figures 31[] and 32 show the reduced investment in the hydro assets following passage of AssemblyBill(AB) 1890 in 1996 through PG&Es bankruptcy filing in 2002. It then shows the ramp up in expenditures consistent with funding recommended in the 2003 GRC. Figure 31 shows nominal dollars whereas Figure 32 is in constant year 2005 dollars.[] These twofigures show costs by subprogram starting in 1997 following PG&Es conversion to SAP and hydros current accounting structure. The cost data for 1990 through 2000 reflects the year the capital projects were completed or put into service. A number of large multiyear projects approved prior to 1996 were completed and put into service in 1997, which explains the higher total in that year. The figures show capital expenditures for years 2001 through 2009. Testimony in the 2003 GRC anticipated capital expenditures for maintaining the hydro system would return to historic levels by 2005. Cost controls including Hydro Operations use of its condition assessment program focused expenditures on critical components in 2003 and 2004 and deferred non-critical capital expenditures to later years. Hydro Operations forecast increase in capital expenditures from 2006 through 2009 is due to: Requirement to implement new FERC license conditions, as discussed in Section D.3; Reliability/availability projects deferred to later years as a result of implementing Hydro Operations condition assessment program. These projects have been phased into Hydro Operations LTP as discussed in Section D.5. Increased dam safety projects resulting from increased FERC and DSOD focus and revised guidelines , as discussed under Section D.1; and Efficiency improvements and strategic issues as discussed in SectionD.5. Hydro Operations capital forecast consists of specific projects that are individually reviewed to ensure that the highest priority work is identified and funded first through PG&Es budget process. The work papers supporting this chapter provide details on all 2004 through 2009 forecast projects greater than $1,000,000 and summary information on all of the smaller projects included in the forecast. Expense Forecast Hydro Operations expenses include the costs of routine and ongoing expenditures including the cost of personnel who operate and maintain the units. Figures 33[] and 34 show Hydro Operations expenses from 1990 through 2009. Figure 33 shows nominal dollars whereas Figure 34 is in constant year 2005 dollars.[] These twofigures show costs by subprogram starting in 1997 following PG&Es conversion to SAP and the current accounting structure. The Hydro Operation Program has managed a flat expense budget between 1997 and the 2004. This includes reduced expenses following the 1996 passage of AB1890 and further reductions in 2000 and 2001 following passage of ABx1-6[] and then PG&Es Chapter 11 bankruptcy filing. A closer review by subprogram reveals that the increased regulatory compliance subprogram expenses have been offset by reductions in the other subprograms. Hydro Operations expense forecast is built upon its historic base expenditures and specific expense projects as shown in Figure 3-5 for the years 2000 through 2009. Routine base expenditures rise year over year as a result of wage inflation and business drivers that increase the ongoing workload. These routine expenditures decrease as a result of automation and work process improvements that reduce the recurring workload. The chart shows that other than the Regulatory Compliance Subprogram all base costs are being held flat through the GRC forecast period. The specific business drivers that increase the forecast base and project expenditures are: New license compliance activities resulting from new FERC licenses, as discussed in Section D.3; Specific projects resulting from new environmental and safety regulations as discussed in Sections D.1 and D.2; and New regulatory fees imposed by State and Federal agencies, as discussed in Section D.3; and Increased reliability/availability projects identified through condition assessment and phased into the LTP as discussed in Section D.5. Section D: Activities and Costs by SubProgram/MWC provides greater detail including the workpapers where summary information is presented for all 2007 through 2009 expense projects and a one page description is included for all projects exceeding $1.0million dollars. Activities and Costs by Subprogram/Major Work Category The sixsubprograms and 21MWCs, (including the segregated regulatory fees), managed under the Hydro Operations Program are listed in Tables31 and 32 at the end of this chapter and are discussed in the order shown. Each subprogram will be described in its entirety, addressing all of the expense MWCs before describing capital MWCs. Safety and Health Management Subprogram General Safety is a higher priority for Power Generation. Power Generation is committed to create and sustain a work and business environment free of injury, illness, or property damage for the benefit of employees, customers, and the general public. Achieving this value enables us to be the low cost provider through decreased business losses and protect the safety, health and well-being of our employees and the public. Expense (MWC HZ) Safety work was previously combined with environmental work. It is now tracked separately to ensure priority is given to employee and public safety. Base work in the safety subprogram consists of activities such as: Industrial and Office Ergonomics training/evaluations; Illness and injury prevention; Health and wellness training; Regulatory mandated training; Training and recertification for the safety staff; Culture based safety process; Asbestos and lead awareness training; Safety-at-Heights Program; Safe driving training; First responder training HAZWOPER; Preparation of safety tailboards and department safety procedures; Proper use of personal protective equipment; Incident Investigations and communicating lessons learned; Employee injury case management; Safety performance recognition; and Public safety awareness. The base safety work forecast is based on historic expenditures. The safety subprogram also includes funding for specific identified projects that correct potential employee-related safety hazards, such as arc-flash hazard remediation, ground grid studies and remediation, penstock safety condition assessment and remediation, Helms fire hazard reduction, fall protection guidelines and remediation, high voltage protection remediation, and correcting other identified safety hazards. Capital (MWC 13) Safety capital consists of specific facility safety projects essential to keeping the public and employees and the environment safe in and around PG&Es hydro facilities. Figure 3-6 categorizes the capital costs for this subprogram between 2001 and 2009. The forecast increase is driven by the dam safety related projects. Forecast work planned under this subprogram can be further categorized into the following six groups: Fall Protection Work: This consists of safety-at-heights installations on trash racks, powerhouse cranes, penstocks, and ladders to meet federal and state OSHA safety standards. Arc-Flash Hazard Remediation: Employees are exposed to arc-flash risks and in fact there have been serious injuries and in some cases, fatalities in our industry. New regulations requiring employers to provide protection against hazards associated with electrical arc-flash events are either in place or imminent (NFPA70E was issued in 2004 and is expected to be adopted by OSHA in early 2006). Power Generation is taking a proactive role to identify and control these hazards. Arc-flash hazards can be generated during switching operations, grounding activities, or while working on or near exposed energized equipment for all voltages above 50 volts. Arc-flash hazard analysis for 31hydro facilities which will be completed by the end of 2005. This will result in modifications to hydro powerhouse station service switchgear and protection devices, administrative controls and/or personal protective equipment control measures to ensure the safety of our employees. Ohio Brass Insulator Replacement Program: Hydro has undertaken a program to replace certain high voltage insulators manufactured by Ohio Brass Insulator Company. It was determined that these insulators are faulty and have exhibited a high failure rate, which poses an unacceptable safety risk to employees, adjacent equipment and to system reliability. Replacement of these insulators will mitigate a safety risk for employees who have to work around and under the structures where these insulators are installed. The programmatic replacement was started in 2004 and replacement of suspect Ohio Brass insulators at hydro facilities is planned to be complete by 2008. Dam Safety Work: Additional modifications are required because of: (1) changing FERC and DSOD guidelines; (2) findings resulting from FERCs and DSODs regular facility inspections; and (3) the FERC Part 12 independent analysis, under both normal and emergency conditions, required every five years. These modifications could improve the dams stability and operability, or strengthen the low level outlet structures and spill gates. Asignificant project is the Canyon Dam Outlet project. Canyon Dam Outlet tower will be strengthened to conform with DSOD/FERC guidelines. This includes upgrading the gates in the tower. Additional details supporting the forecast are included in the work papers. Additional dam safety work is forecast in the regulatory compliance subprogram. This occurs when modifications are required as a direct result of relicensing. Penstock Safety and Life Extension Program: This includes both relining and replacement of pipeline sections. Work on Hydro Operations 89individual penstocks (260,000 liner feet ranging in age from 20 to105 years old), will begin in 2007 and will continue for at least the next 20 years. A significant project is the Caribou2 penstock realignment project. Engineering and permitting will occur during the forecast period with construction contemplated for the 2010 to 2013 timeframe. This work will mitigate the slow hillside creep of a penstock anchor block. Additional details are included in the work papers. Miscellaneous safety projects such as installing trash rack debrishandling systems, improving personnel access to hydro facilities, and correcting other identified safety hazards. Environmental Subprogram Expense (MWCs AK, ES, CR, AY) Environmental base work consists of environmental permitting and compliance costs associated with the hydro facilities. This work includes solid waste disposal and transportation, water quality protection, environmental support for job planning, environmental incident/emergency response, environmental plans and reports, environmental risk management, and sensitive species protection. Historic expenditures form the basis for the forecast of base work, with adjustments made for new regulatory requirements related to air quality requirements (e.g., diesel engines and anticipated new regulations in the areas of water quality and habitat and species protection). The Environmental subprogram also includes funding for new environmental compliance activities, such as the Valley Elderberry Longhorn Beetle (VELB) permitting and habitat species protection Sensitive species and habitat protection expense costs for specific hydro projects are included in the Regulatory section. Sensitive species and habitat protection costs that are common, such as compliance with a companywide permit for the protection of the Valley elderberry longhorn beetle, are included in the Environmental Subprogram. These costs are higher in the 20042006 time period to fund specific conservation efforts, and will have leveled off in 2007. Costs are anticipated to cover anticipated new species and habitat protection requirements. PCB Retrofit This work is near complete and has systematically reduced the amount and concentration of PCBs in Hydro Operations equipment. The remaining focus is removing PCBs from small equipment when it is maintained. The PCB retrofit program also addresses equipment that may be regulated when it is removed from service and considered waste by the state. Lead Paint Management Program This program ensures that the integrity of coatings on the hydro facilities is intact. Each facility is reviewed, evaluated and addressed as appropriate. 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 potential spill for the powerhouses located in PG&Es watersheds. Each site was evaluated and rated to determine the relative risk of oil spills in general and identified the most at risk bearing systems. The sites were categorized into five families, whereby each family had several common characteristics. The results were compiled into an extremely detailed report and database. Phase 2 developed detailed generic designs for each family of units. The intent of the generic design was to step through the engineering process to ensure that a practical and costeffective solution could be achieved and implemented for each type of cooling system. Generic designs were completed for each family of units in 2005. Phase 3 then took each family generic design and implemented a pilot installation at a specific unit ranking high on the risk assessment list and evaluated the effectiveness of the design approach from an implementation and operation perspective. The intent was to take the pilot installation data and any lessons learned and then select the best remediation solution for each unit, on a careful and deliberate schedule, which accounts for availability of resources and unit outage dates. To date, three of the five generic designs have been converted to specific designs (Pit 6 U1, Pit 7 U2, J.B. Black) and implemented. The final two generic design conversions (Pit 4 and Volta) are expected to be complete by the end of 2005. Critical performance data from each of the pilot installations will be collected over a 6-month period to evaluate the effectiveness of the designs for system-wide installations. Phase 3 should be completed by early 2006. Phase 4, the final phase of the program, will implement the proven solutions on a systemwide prioritized basis to reduce the risk to acceptable levels. This phase will commence in 2006 and run past the GRC forecast period. Two to four units will be retrofitted per year. Most of the remediation will be classified as capital, however its expected that the risk can be abated at some sites through minor expense modifications and/or repairs. Capital Costs for capital projects in the Environmental Subprogram include costs to comply with water quality and air quality regulations, including replacement of Helms sewage treatment plant and AG Wishon governor sump tanks, various oil spill prevention projects, and replacement or retrofit of diesel generators. Regulatory Compliance Subprogram General The regulatory compliance subprogram addresses all of the activities associated with obtaining and then maintaining the regulatory approvals to own and operate PG&Es hydro generating assets and appurtenant facilities, including the associated state and federal fees. Work in the regulatory compliance subprogram includes both expense and capital work. Work that does not result in new capital assets is treated in the expense category, and work that does result in new capital assets is treated in the capital category. In many cases the work is very similar in the expense and capital categories, with only the outcome (a new capital asset or no new capital asset) distinguishing the categories. Expense (MWCs DL, DP and Regulatory Fees) As stated above, this subprogram includes expenditures for regulatory required compliance activities that are not associated with a new capital asset. These expenditures are classified under two MWCs: (1) FERC hydroelectric license compliance activities (DL), and (2)license required recreational facility management activities (DP). Regulatory fees are booked directly against the receiver cost centers To provide context for existing and future business drivers, expense work planned under Regulatory Compliance can be categorized into the following five subcategories, as described in more detail below: (1)complying with the conditions required by recently issued FERC licenses and major license amendments; (2) complying with the conditions required by anticipated new FERC licenses and major license amendments; (3) compliance work related to facility safety; (4) other compliance work associated with standard license articles or inspection findings; and (5) state and federal fees imposed upon the hydro generation assets. Figure 3-7 shows the regulatory compliance subprogram expense costs by MWC from 2000 through 2009. This subprogram is forecast to grow by $14.9million (73percent) between 2003 recorded and 2006 forecast. This is $10million more than forecast in the 2003 GRC. The increase is primarily due to the expansive scope and complexity of the license compliance measures included in the six new licenses received between 2001 and 2003. The regulatory compliance subprogram is forecast to increase an additional $14.6million in 2007. This is primarily due to the forecast increase in license compliance work associated with accepting five new licenses and two major license amendments in 2005 and 2006. There are also some costs associated with new state and federal regulatory fees, as described in more detail below. 1) Complying with the conditions required by recently issued FERC licenses and major license amendments FERC issued PG&E six new licenses and one major license amendment between 2001 and 2005 (HaasKings, Mokelumne, Rock CreekCresta, Pit1, HatCreek and CraneValley new licenses; and Potter Valley license amendment). Prior to this, the last new license was issued in 1993. Relative to licenses previously issued by FERC, the six recently-issued licenses contain more extensive terms and conditions that require an expanded license compliance program to adhere to the new license requirements. Moreover, the recently-issued licenses are each characterized as living documents with extensive provisions for adaptive management and similar measures that allow agencies and non-governmental organizations (NGO) to actively participate in the review and periodic revision of existing management prescriptions. This includes requirements for extensive environmental studies and long-term monitoring of the environmental effects of license-required resource protection, mitigation and enhancement (PM&E) measures. In addition to the adaptive management features of the recently-issued licenses there are requirements for development, maintenance, and operation of improved public recreation facilities owned by a federal land management agency (typically the U.S.Forest Service). Illustrative of the complexity of the new living licenses and the provisions for adaptive management are the approximately 200additional compliance tasks associated with the six new licenses issued since 2001. This includes concomitant requirements for approximately 90 ongoing aquatic, terrestrial, recreation, and cultural resource studies or monitoring efforts, at an annual recurring cost of approximately $4,000,000 to $5,000,000. PG&E has incorporated a number of measures to manage this increasing license complexity, including assignment of focused project management oversight upon receipt of the new license and during the license implementation phase. This oversight provides tight cost controls and periodic adjustments to forecast expenditures for license implementation activities related to monitoring efforts. Most of the expense compliance work is forecast to continue 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 anticipated to be issued in the period 2005 through 2006, (SpringGapStanislaus and Kern Canyon new licenses and Bucks Creek major license amendment in 2005; Poe, UpperNFFeather and Pit 3, 4 and 5 new licenses and Battle Creek major license amendment in 2006), significant new expense compliance expenditures are forecast for the period 2007 through 2009. These new licenses and major amendments are for FERC hydroelectric projects that are generally larger and more complex than the recently-issued licenses and major amendments. However, PG&E continues to capitalize on lessons learned from the preceding relicensing efforts and implementation of the six recently issued licenses. Building upon these lessonslearned, PG&E has entered into agreements with stakeholders in three of the existing relicensing proceedings and both of the major license amendment proceedings which have helped to define and more closely constrain the anticipated scopes of work associated with the new licenses. As a result, these anticipated new licenses are forecast to have requirements for approximately 60 to 90 ongoing aquatic, terrestrial, recreation, and cultural resource studies or monitoring efforts, at an annual recurring cost of approximately $2,200,000 to $3,000,000. As with the recently issued licenses (discussed above), the anticipated new licenses will have extensive adaptive management clauses written into the license conditions. The adaptive management clauses will require periodic reassessment of management prescriptions and provide opportunities for government agencies and NGOs to adjust the PM&E measures, (e.g., altering flow and reservoir storage regimes and monitoring requirements). These anticipated new licenses will also require active compliance management by PG&E and regular interaction with various technical review committees comprised of agency and NGO representatives. The existing and anticipated new licenses also require expense projects such as installation of rip-rap embankment reinforcements; fishery habitat improvements; repair of deteriorating equipment such as valves, weirs and spillways; and dredging. In addition, the anticipated new licenses will require extensive monitoring of stream temperatures, fish and wildlife habitat, and other resource protection, mitigation and enhancement measures. 3) Facility Safety Program This work consists of an ongoing base level of work and substantial additional required work and expenditures resulting from new initiatives and requirements from FERC and the DSOD a) Base work consists of the following activities: FERC Part12 Inspection Reports FERC requires that all 53high and significant hazard dams in the PG&E system be inspected every fiveyears by an independent consultant. There are typically 10 to 12inspections every year. The consultant reviews the accumulated surveillance data, stability analyses, flood data, and seismicity data for each dam and then conducts a physical site inspection. This report, filed with FERC, recommends whether the dam is safe for continued operations. The report may also recommend modifications, subsequent additional field investigations, analysis or increased monitoring activities. Dam Surveillance Data Gathering and Reporting PG&E gathers and analyzes surveillance data such as leakage weir readings, piezometer readings and optical surveys on its dams and reports them on a quarterly basis with the Department of Dam Safety (DSOD) and on a semiannual basis with FERC. Emergency Action Plans As required by the FERC, PG&E has developed and annually updates its emergency action plans. The annual update includes training of watershed and centralized organization personnel, updating emergency contact flow charts, and updating potential failure scenarios and inundation maps as necessary to incorporate results from updated analyses and surveys. Facility Safety Engineering Studies Requested by the FERC and DSOD Regulatory agencies may require additional studies to confirm the safety or stability of various project features as a result of new technical or industry information (e.g.,revised flood or seismicity data). These agencies can request stability analyses, structural analyses of appurtenant structures (e.g.,radial gates), flood and spillway studies. b) Additional required work includes the following: New Part 12D Safety Inspection and Analyses Requirements FERC initiated new Part12D Safety Inspection Guidelines for Dams in 2003 that included new performance monitoring reviews and new failure mode analyses. These requirements apply to all of PG&Es 53 High and Significant hazard potential classification dams that are currently under Part12Drequirements. During 2003-2006, PG&E completed 43separate Part 12D reports including 37 updated to the new guidelines, and is scheduled to complete 16 Part 12D reports during 2007-2009 in conformance with these new guidelines. Update all Dam Break Analyses and Flood Maps FERCs Chapter6 Guidelines requires inundation (i.e.,flood) maps to be included in Emergency Action Plans. The existing inundation maps for all High and Significant hazard potential dams were developed 20 to 25years ago from dam break analyses performed at that time. To meet the new FERC guidelines, the Company will update all of the dam break analyses and revise their associated inundation maps starting in 2006 and ending in 2010. Dam Safety Initiative for Rockfill Dams PG&Es dam leakage monitoring program has recorded increased leakage at PG&Es concrete faced rockfill dams over the past threeyears. PG&E, working in consultation with FERC and DSOD, has completed work at the MainStrawberry dam in 2004 and SaltSprings dam in 2005. The concrete joints and/or the upstream concrete faces have been repaired at these twodams to reduce leakage back to early historic levels. PG&E forecasts that a similar scope of work will be required at all 13 of the Companys rockfill dams, with concrete facing repairs projected to be performed at Relief, Courtright, and Wishon during 2006 to 2009; based on the current and projected downstream leakage levels. Review of Facility/Dam Security Measures and Enhancements As a result of the September11 terrorist attack, FERC has implemented a program to ensure that all hydro licensee dams and facilities are adequately secured. Additional inspection guidelines developed by FERC started in mid2002. Facility security and vulnerability assessments were performed for PG&Es hydro system in 2003. As a result these assessments, the Company expects to develop and implement additional security measures to improve security and comply with the new FERC guidelines during 20042009. New Pending FERC Guidelines on Evaluation of Water Conveyance Systems and Dam Outlet Structures FERC is currently developing guidelines for evaluation of water conveyance systems such as penstocks, canals, flumes, and tunnels. PG&E expects by 2007 that these guidelines will be enacted and the Company will be required to initiate a program to evaluate the safety of these structures. PG&E has proactively initiated a penstock safety program to identify and mitigate risks and hazards and assure the safe long term reliable operation of its penstocks. For this reason, FERC has asked PG&E to help develop appropriate industry-wide guidelines for these structures. Prior to 2003, Geotechnical assessments of all penstocks were performed. Structural assessments and inspections of the penstock pressure boundaries are planned for 2006 to 2008. PG&E is also embarking on a Canal Assessment Program to improve the safe, reliable operation of 184 miles of canals. The program will identify operational risks and hazards along PG&Es canals and develop measures to mitigate unacceptable risks. The program will also develop a tool to document canal conditions and predict future maintenance requirements. This work was started in 2005 and is planned to be complete in 2009. FERC has also taken a keen interest in this activity, as they plan to add some requirements for open channel waterways to their Engineering Guidelines sometime in the next five years. Dam low level outlet rehabilitation projects are foreseen in 2007-2009 based on DSOD/FERC mandated inspections and assessments of various low level outlet features in PG&Es hydro system. Coatings Program for All Gates In conjunction with the radial gate evaluation program implemented in 2003-2006 and the annual FERC and DSOD facilities inspections, the Company has identified that the majority of the gates at dams need new coatings to protect them from corrosion and maintain structural integrity as well as to extend their useful lives. The Gate Coatings Program has identified, evaluated, and prioritized more than 130gates in the hydro system. The coatings work was initiated in 2004, some performed concurrent with the radial gate repairs, and continues through 2007. (13 gates in 2007.) Dam Safety Instrumentation automation PG&E will start to automate its dam safety instrumentation in 2007 to 2009 in an effort to both gather more accurate and timely data and analyze it in a more efficient manner. The data will be merged with hydros condition assessment database and provide automatic trending, alarm, and report generation. In addition, automation of data collection will provide real time data that will provide a more realistic picture of actual conditions within a particular dam during extreme events, such as heavy storms or an earthquake, thereby offering a greater assurance against dam failures and enhanced public safety. PG&E initiated the development of a formal dam inspection program in 2005-2006 to assess and document the current condition and identify any potential safety issues for all low hazard dams not covered by FERC Part 12D or DSOD inspections. This affects 121 dams in PG&Es hydro system. The initial round of assessments will take until 2010 to complete. 4) Other expenses associated with regulations, standard license articles, inspection findings, and required public recreation program a) Additional expense license compliance requirements can materialize in any given year as a result of regulatory inspections: Annual FERC and DSOD inspections focused on project operations and facility safety; Environmental and public use inspections by FERC every 35years; and Additional inspections scheduled in conjunction with major construction projects. b) Further expense requirements related to compliance with new FERC regulations for exhibit drawings issued in 2004 is expected to require substantial re-work of many drawings that are part of existing or newly issued licenses, over the 2005 to 2009 time horizon. c) Public Recreation Program Base work includes managing campgrounds and day use areas; maintaining camp sites, picnic tables, restroom facilities, and other equipment; managing lands and roads at and surrounding recreation facilities; and managing boat ramps, docks and other shoreline recreation features. License conditions may require development of shoreline management plans or specific recreation facility improvements or expansions to accommodate growing demand by the public for water-oriented recreation opportunities. Where these improvements or expansions are required at existing sites owned by a federal land management agency (typically the U.S.Forest Service), the associated construction costs are treated as expense. 5) State and Federal regulatory fees imposed upon the hydro generation assets. These regulatory fees are not captured under a MWC, but are included as a separate cost category in the Regulatory Compliance subprogram. These fees are forecast to significantly increase as described below: a) FERC Fees Pursuant to Section10(e) of the Federal Power Act and Section3401 of the Omnibus Budget Reconciliation Act of 1986, FERC assesses annual charges against licensees and exemptees of jurisdictional hydropower facilities to reimburse the United States for the costs of administration of FERCs hydropower regulatory program [18 CFR11.1]. The annual administrative costs are charged to and allocated among licensees of projects of more than 1.5MW of installed capacity. The allocation is based on the authorized installed capacity of pure pumped storage projects, such as the Helms Pumped Storage Project, and on the authorized installed capacity plus 112.5times the annual energy output in millions of kilowatthours (kWh) for conventional projects, such as the HaasKings River Project. The assessment of annual charges is based on an estimate of the costs of administration of PartI of the Federal Power Act, by FERC and other Federal agencies that are to be incurred during the fiscal year in which the annual charges are assessed. After the end of the fiscal year, the assessment is recalculated based on the costs of administration that were actually incurred during that fiscal year; the actual costs are compared to the estimated costs; and the difference between the actual and estimated costs is carried over as an adjustment to the assessment for the subsequent fiscal year. The FERC and other Federal agency fees have recently increased by about 10percent per year on average as a result of Federal agencies, both cultural and environmental, becoming more involved in the hydro relicensing process. FERC also fixes annual charges for the use, occupancy, and enjoyment of U.S. lands, other than lands adjoining or pertaining to dams or other structures owned by the United States Government, or its other property [18 CFR11.2]. The FERC sets annual charges, subject to adjustments, for the use of government lands based on a schedule of rental fees for linear rights of way established by the Forest Service. Annual charges for transmission line rights of way are equal to the peracre charges established by the Forest Service for linear rights of way. Annual charges for other project lands are equal to twice the charges established by the Forest Service for linear rights of way. Each year FERC updates its fee schedule to reflect changes in land values established by the Forest Service for linear rights of way. These charges have recently increased by 2percent per year on average. Any licensee whose nonfederal project uses a government dam or other structure for electric power generation and whose annual charges are not already specified in final form in the license has to pay the United States an annual charge for the use of that dam or other structure [18 CFR11.3]. Payment of such annual charges is in addition to any reimbursement paid by a licensee for costs incurred by the United States as a direct result of the licensees project development at such government dam. Annual charges for the use of government dams or other structures owned by the United States are 1mill per kWh for the first 40gigawatthours (GWh) of energy a project produces, 1.5mills per kWh for over 40 up to and including 80GWh, and 2mills per kWh for any energy the project produces over 80GWh. The Narrows Project is assessed this type of government dam charge each year. b) DSOD Fees PG&E pays fees, based on dam height, to store water at PG&Es reservoirs. As a result of the State of California budget crisis, DSODs operating budget was eliminated from the States General Fund and converted to fee-based funding approach. Hence, a new fee structure was imposed by DSOD in 2003/2004 to all dam owners to fully cover their annual budget requirements. PG&Es fee increased from $174,240 to $756,750 annually; a 434percent increase that wasnt included in Hydro Operations 2003 GRC forecast. c) USGS Fees PG&E pays fees to the U.S. Geological Survey (USGS) for FERC required water data collection. PG&Es FERC licenses require that PG&E have an ongoing stream gaging program in connection with its many hydro facilities (conduits, canals, flumes, powerhouses, lakes, diversion dams) for each of our licenses. FERC requires that that USGS oversee this program and report any items of noncompliance back to them. The USGS under FERC order requires that PG&E's streamflow gaging compliance meets USGS standards for measurement and record keeping. PG&E at its own discretion with considerable cost savings for our customers has chosen to have eight in-house hydrographers perform streamflow measurements and collect the data ourselves to USGS standards rather than pay for full measurement and data collection service performed solely by the USGS. The annual fees to USGS include data review, field visits to verify compliance with USGS standards, and publication/electronic storage of the data. The annual USGS fees for PG&Es FERC required stream gaging requirements increases an average rate of approximately 3percent or about $8,000/year. Capital (MWC11) Capital work planned under capital Regulatory Compliance can be categorized into the following four sub-categories, as described in more detail below: (1) complying with the conditions required by existing FERC licenses and major license amendments; (2)obtaining new FERC licenses (relicensing) and those major license amendments; (3)complying with conditions anticipated to be required by new FERC licenses and those major license amendments; and (4) other compliance work generally related to facility safety. Figure 3-8 shows the cost of complying with the conditions in the five new FERC Licenses and two new FERC license amendments drives the subprograms costs. Greater detail on the specific projects that make up this forecast can be found in the workpapers. The companys ability to forecast the cost of MWC11 has greatly improved since 2001 when the 2003 GRC was prepared. At that time, the company had just received the first of six new licenses since 1993 and was just beginning to forecast the resulting capital compliance costs. Also, the company had limited information as to when FERC would issue the balance of the pending licenses (several of these licenses had already experienced years of delay waiting for FERC to act). Subsequently, in 2002, FERC implemented an aggressive program to expedite issuance of long-delayed licenses and to avoid future delays, such that license issuance dates can now be more accurately forecast. Additionally, the company used the six new licenses it received between 2001 and 2003 to benchmark and improve its ability to forecast the cost of complying with the capital conditions of future licenses. Three other principal factors have affected actual costs for MWC11 compared to the cost forecast in the 2003 GRC: (1) the time it takes to get permits approved to start compliance work after license issuance; (2) the cessation of relicensing on the Kilarc-Cow Creek project (aonetime event not anticipated at the time of the 2003 GRC); and (3)uncertainty in the scope of Subcategory 4 work (the 2007 GRC forecast subject to this uncertainty). These additional factors are included in the 2007 GRC forecasts. 1) Complying with the conditions required by existing FERC licenses and major license amendments After an eight-year period of no new licenses, extending back to 1993, FERC issued PG&E six new licenses and one major license amendment between 2001 and 2005 (HaasKings, Mokelumne, Rock CreekCresta, Pit1, HatCreek and CraneValley licenses; and Potter Valley license amendment). These recently issued licenses and major license amendment contain terms and conditions with which the company must comply to maintain the license. Relative to licenses previously issued by FERC, they contain terms and conditions that require more extensive capital work to meet the new license requirements. The most costly capital work arising from the recently issued licenses and major license amendments is typically related to implementation of environmental enhancements (often for flow release facility modifications or flow measurement facilities related to increased minimum instream flow requirements) and development of improved public recreation facilities. Formal project management is used to costeffectively plan and perform this work. Most of the work from the six new licenses and onemajor license amendment issued between 2001 and 2005 will have been completed by 2007. 2) Obtaining new FERC licenses and those major license amendments Relicensing of the companys 26 FERC-licensed hydro projects as the current licenses approach their staggered expiration dates represents a significant ongoing capital cost. The minimum fiveyear duration relicensing process includes extensive stakeholder involvement, performance of comprehensive natural resource studies, and balancing of complex societal and environmental issues. Presently, ten projects representing 1,509 MW of the companys 3,896 MW hydro generation portfolio, are in some phase of relicensing (Spring Gap-Stanislaus, Kern Canyon, Poe, Upper North Fork Feather River, Pit 3 4 5, Chili Bar, DeSabla Centerville, McCloud-Pit, and DrumSpaulding), and two more are involved in major license amendments (Bucks Creek and Battle Creek). As many as five of the projects presently in relicensing are anticipated to be issued new licenses in the period 2005 through 2006 (Spring Gap-Stanislaus, Kern Canyon, Poe, Upper North Fork Feather River, and Pit 3 4 5), and both major license amendments are anticipated to be issued in this same period. Through this unprecedented volume of relicensing activity the company has employed collaborative solutions to complex resource issues. Using its collaborative approach to relicensing, the company has been able to preserve the low-cost power generation benefit for customers while substantially improving environmental protections, public recreation opportunity, water quality, and other beneficial uses of the project-affected resources. The company has applied this same approached to the major license amendments. In one ongoing relicensing proceeding (Kilarc-Cow Creek; 5 MW) where a new license was anticipated to result in a higher than market rate cost-of-production, the company entered into an agreement with other stakeholders to discontinue relicensing of the project, and instead, at an equal or lower overall cost to customers, acquire replacement power and either transfer the project or decommission it and restore the affected streams for salmon habitat. Additionally, the company is one of seven hydropower licensees across the nation making use of FERCs new Integrated Licensing Process (ILP), which will further improve the efficiency and reduce the cost of relicensing. The ILP will become the default relicensing process in mid-2005, and is being used on the three newest of the Companys ten ongoing proceedings. During the period 2007 through 2009, at least five hydro projects representing 591 MW will be in some phase of relicensing (Chili Bar, DeSabla-Centerville, McCloud-Pit, Drum-Spaulding, and Merced Falls), with forecast expenditures representing 22 percent of the capital expenditures under this subprogram. It is also anticipated that a major portion of the capital cost of decommissioning Kilarc-Cow Creek Project would be incurred during this period. No other major license amendments are anticipated to start during the 2007-2009 period. 3) Complying with the conditions anticipated to be required by new FERC licenses and those major license amendments When issued, new licenses and major license amendments contain terms and conditions with which the company must comply to maintain the license. This capital work is typically related to implementation of environmental enhancements (often for flow release facility modifications or flow measurement facilities related to increased minimum instream flow requirements), and development of improved public recreation facilities. With up to five new licenses and two major license amendments anticipated to be issued in the period 2005 through 2006 (Spring Gap-Stanislaus, Kern Canyon licenses and Bucks Creek major license amendment in 2005 and Poe, Upper North Fork Feather River, Pit 3 4 5 licenses and Battle Creek major license amendment in 2006) and two new licenses anticipated to be issued in the period 2007 through 2009 (Chili Bar in 2007 and DeSabla Centerville in 2009), significant new capital compliance expenditures are anticipated during the period 2007 through 2009. The company has entered into comprehensive agreements with stakeholders in three of the relicensing proceedings nearing completion and both of the major license amendment proceedings, which help define the anticipated scope of work. These agreements improve PG&Es ability to forecast the cost of this subprogram. 4) Other compliance work that results in new capital assets, generally related to facility safety This category includes miscellaneous regulatory required work, including log booms and boat barriers, erosion control, facility security, and other regulatory mandated enhancements. Most facility safety improvements are included under MWC 13, Safety and Health Management Program, since they address public safety issues. However, those facility safety items that resulted from FERC or DSOD inspections or specific directives are included in this subprogram. Operate Plant Subprogram Expense (MWC AW and EP) Hydro Operations covers work at all hydro facilities. The switching center operators remotely control, via Hydros Supervisory Control and Data Acquisition (SCADA), the majority of PG&Es generating units as well as monitoring and control of PG&Es vast dam and water conveyance system. Many of the older and smaller plants require on-site operator interaction for starting/shutdown of generators as well as for real-time operational changes. Roving operators visit all the plants on a routine basis and check for the vital signs of unit control, electrical, and mechanical equipment and manage any deviations from expected values to keep the units running at their optimum reliability and performance. Typical readings would include: bearing oil levels, generator winding temperatures, and water pressures. Sixty-five of PG&Es medium to large hydro units can be operated semi-automatic or fully automatic. Fully automatic operation allows unit start-up, shut-down and load changes to be made remotely via SCADA, while semi-automatic operation only permits remote unit shut-down and load changes. Seven major powerhousesPit 3, Pit 5, Caribou, Rock Creek, Drum, Wise, and Tiger Creekcurrently have no remote operation capabilities since they function as area switching centers and are therefore staffed 24 hours a day. This combined function results in the current operating staff having to leave their switching center post to manually make unit changes and adjustments to auxiliary systems. Evaluations are underway to automate the remaining seven powerhouses to ensure that PG&E continues to operate in full compliance of the increasing FERC license and CAISO powerhouse operating requirements. The new FERC licenses contain conditions that require complex real time operations. The new requirements of unit ramp rate limits, pulse flow releases, and variable minimum in-stream flows, require precise control and coordination of station facilities within a river shed with little margin for error. These requirements typically cannot be met with existing monitoring and control systems which are beyond their design life and whats technically available. PG&E is pursuing facility automation and integration as the more reliable and cost effective solution over manual operation of the existing facilities with increase staffing. In addition, the CAISO demands for real-time load-following cannot reliably be met with only manual operating capabilities. CAISO is currently proposing to implement new settlement processes which will severely penalize generators for deviations outside a relatively narrow range around imputed schedules (plus or minus three percent of the units capacity, or 5MW, whichever is larger). Avoiding penalties will be a particular challenge during periods of non-steady state schedules, including the prescribed ramp between different output levels in different hours, or changes prompted by the CAISOs automated dispatch system. Aggregation of unit schedules on a watershed is being permitted by the CAISO, and on average will reduce penalties due to random schedule-following errors. However, taking full advantage of schedule aggregation to minimize errors requires the ability to simultaneously control all or most aggregated units on a watershed in real-time, with great precision. The existing plant auxiliary equipment and controls at these sevenpowerhouses are at or near the end of their useful life and in need of replacement. Their replacement will be integrated with the planned 2006-2013 automation to reduce costs and improve watershed control capabilities. Automating the switching center powerhouses when combined with the SCADA replacement projects makes switching center consolidation a real possibility. Two switching centers in the Shasta, DeSabla, and Drum watersheds could be consolidated into one resulting in better control of the watershed operations. The switching center consolidations are forecast for the 2008-2011 timeframe. All capital work resulting from automation and consolidation of the switching centers will be captured under MWC 81, which is part of the Maintain Reliability/Availability subprogram. Operators prepare switch logs for equipment shutdowns and clearance, check the switch logs, and execute switching to actually clear equipment. Other duties include both preparing and following procedures to operate all plant equipment, canal systems, and diversions dams. Additionally, operators are required to respond to operational changes resulting from inclement weather conditions, both during regular work hours and on an after-hour emergency basis. On an ongoing basis, canals must be patrolled and valves/gates operated to respond to changing water flow needs. Operators must manage and document conditions and situations such as in-stream flow releases and contractual water deliveries and be primary responders for emergencies, as well as manage hazardous waste. The hydro operations systems largely shut down automatically when conditions warrant. Alarms may be activated by equipment failure, storm activity, or interruptions to water flow. Operators are the primary trouble shooters for failures in service. They respond to the automatic alarms and recommend a remedy. They act on approved recommendations or ask for assistance. When outages occur, usually several weeks a year, operators assist maintenance crews with work activities. Hydrographers measure and calibrate flow monitoring stations and collect weather data. Hydro Operations has specific operating plans for both winter and summer operations. These plans take into account the unique weather conditions that occur during these seasons, and the local topography in each of Hydro Operations areas, and modify how the plants and water delivery systems are operated to minimize the risk of damage to the hydro facilities and thereby improve availability. By reducing the risk to facilities during times of heavy storms, savings are realized through reduced storm damage to the facilities. During times of excessive heat, stress on electrical system components increases dramatically. By modifying operations during these times, savings are realized through reduced equipment failures. The working conditions are unique. Some locations are assessable only by helicopter or boat. Hydro Operations employees work weekends and holidays and respond to various changing operating conditions and emergencies. They work on sloped grounds to inspect dams, in confined areas, and around heavy plant equipment and chemicals. They work on mountains and difficult terrainsoften in tunnels, small buildings, over rocks and gravel and large pipes, suspended above flumes, on scaffolding, at remote sites, along steep roads, in or near fast moving streams and rivers, in the snow, and around poison oak, snakes, and spiders. They also maneuver on flumes, around water and work around rotating and energized equipment and noise. They use hand tools, electric and power equipment, and computers. Hydro Operations is planning to maintain recent operating practices and staffing levels through 2009. This includes a staffing strategy to manage attrition without temporarily increasing the number of employees. Hydro Operations, like many other programs at PG&E, forecasts a significant increase in employee retirements during 20052009, but believes it can manage attrition without undue operating risk by utilizing the organizations total capabilities. Hydro Operations O&M personnel possess extensive knowledge of site conditions and the unique operating characteristics because of their years of service. Hiring a replacement in advance of the expected retirement would allow the new employee to become knowledgeable about the hydro facilities and complete approved apprentice programs. The hydro organization has a blend of operating and maintenance personnel, Title 200 under the IBEW contract, and construction personnel, Title 300 under the IBEW contract. Hydro Constructions staffing levels increased in 2004 and 2005 as a result of the increased investment in maintenance and reliability projects. Hydro Operations staffing strategy is to hire, train, and develop Title 300 employees to not only handle the increase capital workload, but in anticipation of future T200 vacancies. The goal is for these employees, with construction experience from throughout the system, to have sufficient hydro knowledge and experience to bid into the O&M positions without the need for an overlap or temporary increase in staffing levels. The GRC forecast assumes that this strategy will be successful and therefore the O&M staffing levels and labor cost for this subprogram are flat. Hydro Operation personnel work closely with the Building and Land Services department to manage the hydro lands as describe in Exhibit (PG&E -2), Chapter12, of this application. The Hydro Operation Program currently has approximately 140,000[] of the 240,000 acres managed by Building and Land Services. This includes approximately 65,000 acres of watershed lands surrounding the hydro production facilities that are managed to ensure that there is no development or activity adverse to hydro generation. This is reflected in PG&Es Corporate Policy Manual, Section E-5.10 that states: It is PG&Es 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 companys financial and service objectives. Maintain Reliability, Availability and Improve Efficiency Subprogram General This subprogram includes work associated with maintenance of powerhouse structures, turbine-generator and switchyard equipment, dams, reservoirs, water conveyance systems, roads and bridges, and other facilities. As described in the 2003 GRC, Hydro Operations assessed how best to maintain long term reliability. The two key programs that support Hydro Operations maintenance work came from the work management and condition assessment process improvement projects initiated in 2001 and 2002. Condition Assessment Program This program supports the proposed migration from timebased maintenance to conditionbased maintenance. The basis for the current condition assessment program has been used for years to develop priorities for asset maintenance and replacement. However, much of the current asset management program is timebased, meaning that asset maintenance or replacement is being done based on time durations, with no certainty that it is occurring at the optimum time for each asset. The advantage of a stateoftheart condition assessment program is its ability to use conditionbased assessments to determine when maintenance should be performed or when an asset should be replaced. The optimization of maintenance timing and asset replacement can result in savings over the long run. The condition assessment program system will standardize the collection and trending of performance indicators for key components and facilities. Performance measures or out of spec limits will be established for critical components so that the appropriate corrective action is triggered in the new work management System or long term planning process. Condition assessment summaries will be provided on both a powerhouse and systemwide level for overview evaluations and prospective checks. Hydro Operations is faced with maintaining equipment that in some cases is over 100years old. Condition assessment supports utilizing the right resources, at the right time, on the right work. Hydro Operations has had a basic condition assessment program for years and 43 percent of 2004 projects resulted from some form of condition assessment based upon visual, measured values, fluid/gas sampling, or programmatic assessments. Our current upgrades involve implementing an easily accessible centralized repository for data and establishing uniform out of tolerance criteria to ensure that resources are efficiently allocated to the highest value work. Hydro Operations used the previous condition assessment program to start implementation of a state-of-the-art condition assessment program. This program will ultimately be used for optimization of resources in Hydro Operations long term plan, basing asset maintenance and replacement decisions on the equipments condition, using developed performance measures. In 2004, Hydro Operations started implementation of a cutting edge software program which uses uploaded measured, visual, physical (touch and smell), and calculated data to track equipment condition. Out of tolerance criteria is being established for key equipment as the software program is implemented. This software database will enable Hydro Operations to centralize equipment condition data, store a history of the equipment readings, allow for trending the readings, and generate an alarm when readings vary from pre-determined parameters. In addition, the condition assessment program effort has a plan to review current equipment testing procedures to ensure that testing is performed to industry standards. In the next few years, Hydro Operations will continue to expand the implementation of the condition assessment program to include additional facilities and equipment utilizing the software program, as well as continuing development of out of spec criteria and standardized testing procedures. Work Management Process The work management process improvement project, initiated in 2001, reviewed Hydro Operations historic practices, identified limitations, benchmarked other work management processes, developed and mapped a new work management process and developed an implementation plan. In 2004, a new work management system (WMS), including new processes and tools, was implemented to assist in managing not only the work on hydro equipment and facilities, but also the resources available to perform the work. These new processes have now become ingrained as part of the normal course of business for employees dealing with hydro facilities. The WMS facilitates the management of work to be performed on hydro equipment by allowing each piece of identified work to be assigned to a work center where it is planned, prioritized, and scheduled for completion. Any identified work can be tracked, whether it is periodic routine maintenance tasks, daily trouble reports, minor or major equipment repair work, agency compliance tasks or capital replacement projects. The system tracks the cost of the work and the history of work done against the piece of equipment. The prioritization capability in the WMS allows Hydro Operations to prioritize the work to assure the most critical equipment needs are being addressed by the limited available resources. In addition to these two programs, progress with three additional management processes, started in 2004, continues to ensure projects are completed as planned within budget and on schedule. Improved Project Planning Hydro Operations recognized the significant increase in project work that would take place during the catchup period and the increasing regulatory agency approval and permitting durations, Hydro Operations therefore promoted use of a formalized a multiyear project plan to ensure that projects would be completed as planned. This multi-year project approach is composed of planning and committing to complete the necessary engineering, procurement of material, and obtaining of agency approvals and permits in the first one-to-two years (depending on complexity and lead times) and then completing the construction of the project in the next two-three years. In order to achieve this approach, Hydro Operations plans for projects in both the long-term plan and the annual budgeting process in a manner that commits to completing all phases of a project upfront and then provides the needed resources only in the year needed. By allowing additional time to complete the engineering, procure the material, and obtain agency approvals and permits, Hydro Operations can develop a more dependable plan for use of construction resources and ultimately complete the projects in the most cost-effective manner possible. Strategic Alliances Hydro Operations also developed key strategic alliances with outside engineering firms to efficiently contract out engineering work while ensuring quality and cost competitive services. Hydro Operations is currently in the process of also developing strategic alliances with key major equipment suppliers, such as turbines, large valves, generators, exciters, governors, SCADA, station service switchgear, and switchyard equipment manufacturers. Project Management Hydro Operations continues to enhance its project management capabilities, (organization created in 2003), to manage the larger, more complex projects and outages. Expense (MWCs AI, AX, AZ, BB and BK) The hydro assets require substantial resources to maintain their reliability. The forecast maintains the existing base maintenance practices at historic expenditure levels but also includes a substantial increase for specific new work to catch-up on investments not made during the post AB1890 years. The increase for 2007-2009 is related to projects that maintain unit availability and reliability and implement work determined by programs started in 2003 as well as begins to capture efficiency improvements as this equipment and systems are replaced. Figure 3-9 categorizes this subprograms expenses by MWC. Itshows that costs increase across the board due to age and condition of the hydro facilities, but that the greatest dollar increase is to MWC AX (Maintain Reservoirs, Dams and Waterways). The following testimony provides an expanded description of this work and specific expense projects will also be included in the workpapers. 1. Water storage and conveyance projects This work includes additional reservoir and spill channel maintenance; canal, flume, and tunnel inspections and riskbased condition assessment and repairs; and repairs to tailraces and stop logs. 2. Turbine-generator and associated equipment projects This work includes: (1)assessment and repairs to turbines, including runners, wicket gates or needle valves, bearings, governors, and other turbine components; (2)assessment and repairs of generators, including field poles, bearings, cooler recores, and exciters; (3)assessment and repairs of large valves, including penstock shutoff valves, turbine shutoff valves, and pressure relief valves; and (4)assessment and repairs to miscellaneous electrical systems. 3. Infrastructure projects This work includes increased maintenance for buildings and roofing, roads, bridges identified in the Bridge Mitigation Program, and telecommunication and SCADA facilities. Capital (MWCs 81 and 5) Substantial capital expenditures are needed to maintain generation reliability and availability and begin to capture increased efficiencies. Figure 3-10 categorizes this subprograms work (described below) and shows forecast increases in a number of areas. The forecast is based upon specific identified projects which are listed in the workpapers supporting this chapter including a one-page summary for each project greater than $1 million. Water storage and conveyance projects Water conveyance reliability, including canal, ditches, and tunnel lining; flume replacement; spill gates replacement; geotechnical slide mitigation; and installation of water conveyance monitoring systems. Turbine-generator and associated equipment projects Turbine reliability and efficiency gains, including replacement or upgrades of runners, seal rings, wicket gates, needle valves, and associated turbine components. Powerhouse large valves and mechanical auxiliary system reliability, including replacement of turbine shutoff valves, pressure relief valves, and penstock shutoff valves; governors; and miscellaneous auxiliary oil, water, and air mechanical systems. Generator reliability and upgrades, including stator rewinds, replacement of field coils and poles, and replacement of excitation systems. Supervisory Control and Data Acquisition (SCADA) and telecommunication reliability including replacement of outdated SCADA, analog radio systems, annunciators, and power sources. Electrical Auxiliary Systems reliability, including replacement of medium and low voltage switchgear, motor control centers, transformers, and distribution systems; DC batteries, chargers and distribution systems; emergency backup generator systems; protection systems for generators, high voltage transformers, and high voltage breakers; and plant instrumentation and automation. High Voltage Switchyard reliability, including replacement of high voltage breakers, switches, and step-up transformers. Infrastructure projects This work includes capital replacement of buildings, roofing, HVAC systems, road repaving, bridges identified in the Bridge Mitigation Program, and telecommunication and SCADA facilities. Business Subprogram Expense (MWC AB and BC) Base business subprogram work includes the administrative costs associated with managing the Irrigation District contracts and the reimbursable expenses incurred to perform maintenance on behalf of the Irrigation Districts. The reimbursable maintenance expenses are billed to the Irrigation Districts with the reimbursements recorded as Other Operating Revenue and included in Exhibit (PG&E2), Chapter16. It also includes initiating, managing and implementing business system improvements. The forecast is based on historic expenditures and has decreased from 2005 due to the change in the method used to record the Contract Services section costs. Beginning in 2005, the Contracts section is allocated to the expense and capital orders that they support Translation of Program Expenses to FERC Accounts As discussed in Chapter 4 of Exhibit (PG&E-1) PG&E uses the SAP view of cost information to manage program costs. Thus, for presentation in this GRC, certain SAP dollars must be translated to FERC dollars. This is not an issue for capital costs, where the SAP and FERC view are identical. For O&M expenses, however, the SAP dollars include certain labordriven adders such as employee benefits and payroll taxes that are charged to separate FERC accounts and addressed separately in this rate case. These labordriven adders must be removed from the SAP dollars for O&M expenses to present them by FERC account. Tables33 through 38 show how the SAP expense dollars in the Hydro Operations Program translate to the appropriate FERC accounts. The tables show current year dollars (i.e.,nominal dollars) and restated in base year dollars (i.e.,2004 dollars). Cost Tables PG&Es capital and expense requests for the Hydro Operations Program are summarized in the following tables: Table 31 lists the subprograms and capital MWCs, showing 2004 recorded capital expenditures and 2005 through 2009 forecast capital expenditures by MWC; Table 32 lists the subprograms and expense MWCs, showing 2004 recorded expenses and 2005 through 2009 forecast expenses by MWC; and Tables 33 through 38 display the 2004 recorded expenses and 2005through 2009 forecast expense expenditures by subprogram, MWC, and FERC account. Each subprogram set of tables is in sequence by nominal dollars, nominal dollars by FERC account and 2004 dollars by FERC account. Figure 3-1 Pacific Gas and Electric Company Hydro Capital Nominal ($000)  Figure 3-2 Pacific Gas and Electric Company Hydro Capital (2005 $000)  Figure 3-3 Pacific Gas and Electric Company Hydro Expense Nominal ($000) Figure 3-4 Pacific Gas and Electric Company Hydro Expense (2005 $000)  Figure 3-5 Pacific Gas and Electric Company Hydro Expense Base and Specific Projects Nominal ($000)  Figure 3-6 Pacific Gas and Electric Company Hydro Capital Safety Subprogram (MWC 13) Nominal ($000)  Figure 3-7 Pacific Gas and Electric Company Hydro Expense Regulatory Compliance Subprogram Nominal ($000)  Figure 3-8 Pacific Gas and Electric Company Hydro Capital Regulatory Compliance Subprogram (MWC 11) Nominal ($000)  Figure 3-9 Pacific Gas and Electric Company Hydro Expense Maintain Reliability & Availability Subprogram Nominal ($000)  Figure 3-10 Pacific Gas and Electric Company Maintain Reliability & Availability Subprogram (MWC 81) Nominal ($000)  [] These facilities are outside of FERCs licensing jurisdiction because they are located on nonnavigable waters. [] 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. [] Excluding management classifications. [] 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; 10003-018. [] The definitions are taken from the website of the CAISO: http://oasis1.caiso.com/iso/news/FYIMarkets.html. [] 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. [] 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. [] Figure 32 assumes approximately a 2.5percent per year escalation to aid the reviewer in comparing dollars for this 5year period. [] Figures 3-3 and 3-4 use actual expenditures for 1990 through 2004 and forecast expenses for 2005 through 2009. [] Figure 34 assumes approximately a 2.5percent per year escalation to aid the reviewer in comparing dollars for this 5year period. [] ABx1-6 repealed Public Utilities Code Section 216(h) and modified Sections377 and 330(l)(2) prohibiting PG&E from selling any of its existing generating assets until at least January1, 2006, and requires that those assets be dedicated for the benefit of California ratepayers. [] 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.     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