Pasadena Water and Power

Integrated Resource Plan

2007

January 31, 2007

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Table of Contents Section 1 - Executive Summary.......................................................................................... 4

Key Findings and Recommendations ............................................................................. 4 Power Requirements ....................................................................................................... 5 Power Supply Resources................................................................................................. 5 Regulatory Issues ............................................................................................................ 5 Local Generation............................................................................................................. 6

Section 2 – Introduction...................................................................................................... 8 Section 3 - Power Requirements....................................................................................... 11

Forecast Methodology and Assumptions...................................................................... 11 Net Electric Load .......................................................................................................... 12 Monthly Load Profile.................................................................................................... 14 Other Considerations .................................................................................................... 16 Resource Adequacy and Local Capacity Requirements ............................................... 17 Future Requirements..................................................................................................... 17

Section 4 – Power Resources............................................................................................ 18 Long Term Contracts .................................................................................................... 19 Generation Ownership .................................................................................................. 22 Energy Efficiency and Demand Side Management ...................................................... 23 Distributed Generation.................................................................................................. 24 Characteristics of Renewable Resources ...................................................................... 25

Section 5 – Transmission Issues ....................................................................................... 28 Master Plan Work ......................................................................................................... 28 Magnolia Transmission Work....................................................................................... 29 Current Transmission Agreements ............................................................................... 30

Section 6 – Environmental Issues ..................................................................................... 33 Local Generation Emissions ......................................................................................... 33 Other Environmental Issues with Local Generation..................................................... 34 Environmental Licensing Issues with Local Generation .............................................. 35 Environmental Constraints on Remote Generation ...................................................... 36

Section 7 – Regulatory Issues ........................................................................................... 38 The California Independent System Operator (CAISO)............................................... 38 Energy Policy Act ......................................................................................................... 38 Greenhouse Gas Legislation ......................................................................................... 40 Other Regulatory Considerations.................................................................................. 40

Section 8 – Market Forecast and Commodity Prices........................................................ 42 Market Forecasts........................................................................................................... 43 Other Factors Impacting Commodity Prices................................................................. 49

Section 9 – Local Generation Considerations................................................................... 51 Fossil Fuel Generation Technology and Local Generation Options............................. 52 Practical Constraints ..................................................................................................... 56 Risk Factor Assessment ................................................................................................ 57

Section 10 – Production Cost Modeling ........................................................................... 58 Portfolio of Resources................................................................................................... 58 Scenarios ....................................................................................................................... 61

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Modeling Process.......................................................................................................... 62 Analysis of Results ....................................................................................................... 62 Summary of Results...................................................................................................... 69

Section 11 - Recommendations ........................................................................................ 70 Local Generation Re-Powering..................................................................................... 70 Renewal Portfolio Standard .......................................................................................... 71 Energy Efficiency ......................................................................................................... 71 Reliance on Coal ........................................................................................................... 71 Financing Issues............................................................................................................ 72

Section 12 – Public Process .............................................................................................. 73 Section 13 – Approval Process ......................................................................................... 74

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Section 1 - Executive Summary

Key Findings and Recommendations Pasadena Water and Power (PWP) continues to focus on delivering reliable, low cost, and environmentally responsible electricity to the Pasadena community. PWP has a stable supply of fixed-rate electrical energy available through a series of long-term power purchases. PWP also remains committed to maintaining local generation to ensure a secure and reliable source within the city. The age of the local generation -- three of the five local units have been in service for more than 40 years -- should be corrected. This resource plan recommends replacing these three units over a five- to seven-year timeframe with newer technology that burns natural gas more efficiently at a lower overall cost and with fewer environmental impacts. The plan also addresses the ongoing efforts to introduce more renewable resources into Pasadena’s energy portfolio. The renewable projects available in the western states have increased tremendously in the last several years, as all power utilities work to fulfill their Renewable Portfolio Standards. These goals within Pasadena that are set by the City Council remain at 10 percent renewable energy (including large hydro) by 2010 and 20 percent renewable energy (including large hydro) by 2017. Joining the global effort to curb greenhouse gas emissions is central to the evolution of the city’s power resource portfolio. At the same time, PWP continues to improve its energy efficiency programs. The programs have centered on public awareness and targeted rebates for improving energy efficiency citywide, among both residential and commercial consumers. While Pasadena does have a reliable power supply for the foreseeable future, efficiency programs are nevertheless cost-effective to reduce peak power. As part of these conservation efforts, the city of Pasadena continues its commitment to the green building movement, in which long-term energy savings are obtained through efficient new construction and restoration of existing infrastructure. These energy efficiency measures are an effective means of reducing the environmental impacts of power production by reducing greenhouse gas emissions. This Integrated Resource Plan also recognizes continuing changes to the energy market and the need for PWP to understand, adopt and manage this change. This requires recognition of the dynamics of the evolving market, as well as preparedness for an aging workforce. This means ensuring that PWP concentrates on doing the right things correctly, and committing valuable human resources to those activities that will best maintain the utility’s infrastructure assets. While the local generation plant requires new technology, it also requires new facilities and the ongoing development of plant personnel. The interaction of resources, efficiency, demand-side response, markets and reliability is complex and challenging.

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Along these same lines, the personnel responsible for the long-term contractual agreements for future power resources, as well as the personnel responsible for the mid-term and short-term marketing of power and natural gas, must continue to be supported in the organization. This will ensure the complex energy portfolio that provides reliable, environmentally responsible and cost-effective electricity to the city is maintained and improved through the coming decades. The California energy market remains a work in progress, with great uncertainty and many divergent viewpoints on its future direction. PWP continues to understand the importance of monitoring and managing this uncertainty and providing a buffer for customers. A municipal utility should not be paternalistic, but it should provide a service; in the current evolution of the California energy market, this service includes managing complexity and uncertainty.

Power Requirements The city of Pasadena’s power requirements are driven by the city’s General Plan, customer habits and the success of PWP’s conservation message. The General Plan calls for growth to serve community needs and to enhance quality of life. This growth has most recently been impacted by the Gold Line, which has generated a series of mixed-use development complexes. While the city’s major institutions, including Caltech, Huntington Hospital and the Rose Bowl, continue to flourish and benefit the community, their growth translates to increased energy use. The impact of this increased consumption is mitigated by energy-efficient building standards, ongoing efficiency improvements in electrical appliances and the continued promotion of conservation by PWP and the state. Despite the success of our community, Pasadena has seen little growth in electricity consumption, and the forecasts for growth indicate a modest increase over the next decade, with a flattening as the city reaches an energy equilibrium.

Power Supply Resources PWP has a respected history of providing long-term solutions for the city’s power needs. The continuous availability of local generation for over 100 years has been instrumental in supporting both the development and quality-of-life goals of the city. Pasadena was an original participant in the Hoover Dam project during the 1930s, and has continued to invest in large projects to build a stable and diversified energy portfolio. Since the adoption of Pasadena’s Renewable Portfolio Standard in 2003, setting new goals for importing “green power,” PWP has augmented its existing hydroelectric resources with investments in wind, geothermal and landfill gas projects.

Regulatory Issues The California power market continues to work to establish a sustainable market infrastructure. The federal government continues to attempt to establish a stable energy market with reduced dependence on foreign oil. In the meantime, natural gas prices, the prime driver of California’s power costs, remain at high levels, with significant volatility.

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This crucial commodity must be utilized as efficiently as possible. The natural gas market is a significant factor in the recommendation to replace Pasadena’s aging generation units with newer and more efficient technology. At the same time, the California Independent System Operator (CAISO), established in 1996, is undertaking a major market redesign and technology upgrade. This initiative is currently slated to become operational in November 2007. This significant change will require continuing improvements to PWP’s information systems, as well as significant training within PWP’s Wholesale Operations Group, which interacts with CAISO on a daily basis. The California State legislature continues to support initiatives to improve the functioning of the energy market and to encourage the implementation of energy efficiency programs and adoption of renewable resources. The adversarial regulatory environment established for investor-owned corporations is not appropriate for publicly owned utilities that are guided by directly elected representatives. This difference between for-profit private corporations and public municipalities continues to be a challenge in developing a comprehensive energy policy. PWP and the city council continue to work with California legislators to develop workable solutions on a variety of energy issues.

Local Generation PWP has been providing the citizens of Pasadena with power since 1907. One hundred years ago, the savings PWP provided over private utility rates was approximately 40 percent. These savings continue today. During the deregulation movement of the late 1990s, many people believed local generation was not required. This was a mistake that was clearly seen in late 2000 and 2001, when the California energy crisis made national and international news. While this crisis has passed, the need to provide local generation continues. PWP depends tremendously on joint projects through entities like the Southern California Public Power Authority (SCPPA), but the ability to produce power locally remains a strong benefit to Pasadena’s citizens, providing reliability and lower overall costs. This Integrated Resource Plan strongly recommends replacing the city’s three generation units (GT-1, GT-2, and B-3) that are over 40 years old. Along with this replacement, we recommend a new facility that supports a centralized operations center, maintenance facilities, engineering support and administrative offices. This effort is expected to take five to seven years to implement, as there are significant technical, logistic and staging issues to address.

Greenhouse Gas Since the commercial operation of the Intermountain Power Project (IPP) in the 1980s, PWP has relied on low cost coal power to supply a majority of the electricity needs of the city. This reliance on coal is becoming a major issue as the impact of greenhouse gases is becoming more widely understood. A coal fired generation unit produce about twice as much carbon dioxide (CO2) as a natural gas fired generation unit. This plan recommends

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a gradual reduction in the coal component of generation and recommends investigating carbon mitigation strategies as well as alternatives to IPP.

Renewable Resources and Energy Efficiency PWP has made significant strides in procuring additional renewable resources and is on target for meeting the goals established by the City Council in 2003. This plan recommends continuing these efforts and increasing the goals for both 2010 and 2017. PWP also recognizes that additional energy efficiency programs must be introduced and a methodology to measure the costs and benefits of these programs must be improved. The energy efficiency programs and demand side management programs introduced to date have been effective but more can be done.

Balance As mentioned throughout this report, PWP must balance many conflicting interests. Customers want low cost and reliable electricity at a stable price with little or preferable no adverse impacts on the environment. PWP hopes this report indicates that these competing goals are carefully considered and the recommendations are an effort to indicate a direction forward. This plan is an effort to articulate that direction, but the ultimate direction will be set by the citizens and business stakeholders in the community through the elected representatives on the City Council. PWP’s priority is to serve the community and implement their vision for the City.

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Section 2 – Introduction As PWP celebrates its centennial, the longevity of our utility is an important reminder of the need for strategic long-term planning. PWP’s customer base has grown from 30,000 in 1910 to 134,000 in the last U.S. Census. The city has evolved from a winter resort for Eastern tourists to a culturally diverse community, connected to Los Angeles through the Pasadena freeway in 1940 and, later, the Gold Line in 2003. The commercial life of the city has also evolved, from the fashionable Lake Avenue shopping district of the late ‘40s and ‘50s to the revitalization of Old Town in the late ‘80s and ‘90s to the makeovers of Lake Avenue and the Paseo Colorado shopping center this millennium. These transitions undoubtedly impact the energy requirements of the city. This Integrated Resource Plan lays out a strategy for addressing impacts anticipated over the next 20 years. As of this writing, PWP serves a population of nearly 160,000 people in Pasadena and unincorporated county areas, who consume an average of 3250 MWh of electricity daily. PWP’s power delivery system covers more than 23 square miles through a system of 11 substations, two receiving stations, 14,000 poles and 440 miles of overhead and underground conductors delivering power to more than 61,000 meters. PWP has undergone tremendous change since the last Strategic Resource Plan was developed in 2001, but many of the conclusions reached in 2001 are still applicable today. This dichotomy of change and constancy is reflective of the overall state of the energy industry in the United States, and particularly here in California. The energy policy of deregulation codified by Assembly Bill 1890 (AB-1890) has been discredited by a historic energy crisis that has resulted in substantial costs to ratepayers and protracted litigation throughout the state. The goal of AB-1890 of lowering rates in California has failed. At the same time, the goal itself – to streamline and improve the energy industry for the benefit of consumers – is still valid and necessary. One of the major findings of the 2001 Resource Plan included:

Local generation will continue to be a vital resource unless significant investments are made in external transmission arrangements, bulk power receiving substations, and cross-town transmission.1

Local generation continues to be a vital resource. Major capital expenditures are planned for the electric distribution system, but no definite plans are made to improve transmission, receiving substations, or cross-town transmission. A critical component of the 2007 Integrated Resource Plan continues to be the improvement of local generation. The 2001 plan directed GT-3 and GT-4 to be built and GT-1 and GT-2 to be retrofitted with new emission controls. These efforts established a reliable peaking solution for PWP, but did not significantly reduce the heat rate efficiency of the megawatts produced by the plant. The average heat rate for local power production during the summer of

1 Pasadena Water and Power Department, Strategic Resource Plan Final Report, September 2001, p.1-1.

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2005 was approximately 12,000 Btu/kwh. This contrasts to the average on-peak heat rate of 10,000 Btu/kwh. As a goal, PWP would like to establish a heat rate of 8,000 Btu/kwh. This could be accomplished in several ways; options are explored thoroughly in the Local Generation section. Since the statewide energy crisis, the state has attempted to build a regulatory system to better manage energy policy. One of the key policies that has evolved is a strong commitment to renewable resources. Senate Bill 1078, passed in September 2002, established a Renewable Portfolio Standard for investor-owned utilities, and required publicly owned utilities to develop a similar standard. The Pasadena City Council adopted a Renewable Portfolio Standard in October 2003 that targeted a 10 percent renewable portfolio by 2010 and 20 percent by 2017. Many of the decisions in this plan depend on effectively meeting this standard. In addition, the California Public Utility Commission (CPUC) and the California Energy Commission (CEC) have published and updated the Energy Action Plan. This Energy Action Plan II (EAP II) states:

Our overarching goal is for California’s energy to be adequate, affordable, technologically advanced, and environmentally-sound.2

A key component of the action plan is the loading order of energy resources. The loading order is the term used to indicate the order in which energy requirements should be met. The loading order is described below:

• Increasing conservation and energy efficiency • Renewable energy resources and distributed generation • Clean (e.g. natural gas) and efficient (combined cycle technology) fossil fuel

generation3

While this loading order is enforced by the CPUC for investor-owned utilities through each utility’s energy procurement plans, PWP has benefited greatly from the strategic guidance provided by the state. Another key component of California energy policy is the Integrated Energy Policy Report, published every two years and updated in the intervening year. In 2002, Senate Bill 1389 (SB-1389) established the need for a comprehensive report to address energy issues faced by the state. The 2005 Integrated Energy Policy Report4 has provided a wealth of information that has guided much of this plan. PWP recognizes the benefits of a coordinated effort amongst all key stakeholders in developing sound energy policy throughout the state.

2 Energy Action Plan II: Implementation Road Map for Energy Policies, State of California Energy Commission/Public Utilities Commission, September 21, 2005, pg. 1. 3 Energy Action Plan, State of California Power Authority/Energy Commission/Public Utilities Commission, May 8, 2003, pg. 4. 4 2005 Integrated Energy Policy Report, California Energy Commission, November 21, 2005.

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A critical factor in the success of energy planning and policy is market structure.5 CAISO continues to develop a market design and technology upgrade that is now scheduled to be operational in November 2007. This critical next step for the CAISO includes efforts to correct market design inefficiencies and improve the technology infrastructure within the CAISO, as well as the technology used to communicate information with market participants. This change is cautiously anticipated by PWP. This resource plan continues to reduce exposure to market dynamics by establishing a flexible and responsive energy resource portfolio with cost-effective energy efficiency and demand-response programs. This resource plan consists of a base case that includes existing and expected resources and requirements over a 20-year period. From this base case, several scenarios were assumed:

1) High Natural Gas Prices with Carbon Tax 2) High Natural Gas Prices with no Carbon Tax 3) Mandated Energy Efficiency Program to Reduce Peak by 10% 4) Aggressive Renewable Portfolio Standard

Many variations of the above scenarios were also evaluated. PWP believes this Integrated Resource Plan lays the foundation for a balanced approach to energy management for the city of Pasadena. We also believe this plan is a solid first step in a more rigorous analysis and planning process that will reach out to all stakeholders in the community to solicit advice. The direction taken from this resource plan will impact the community for years to come, and only through a collaborative process will we arrive at optimal and sustainable solutions.

5 EAP II, pg. 9.

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Section 3 - Power Requirements The PWP electric load forecast establishes the city’s peak demand and annual energy requirements, based on total retail electricity sales to Pasadena customers. This information, combined with contractual energy sales obligations to other utilities, is used for the resource planning process to determine PWP’s service obligation. In addition to meeting the electric demands of our customers, an additional reserve amount is required to allow for contingencies like unplanned outages of generation resources or under-forecasting of load. This reserve requirement has a long-term aspect that is called “resource adequacy” and is generally set at 15 to 17% above forecasted load. There is also a short term aspect, what is expected to be required the next day, and these are referred to as ancillary services and are generally set at 5 to 7% above forecasted load. This smaller reserve requirement for the next day must be available in a short time period (within 10 minutes) whereas the resource adequacy amount can include long start units (taking up to 24 hours to start). These reserve requirements must be factored in when determining the power requirements for a utility.

Forecast Methodology and Assumptions The city’s load forecast is updated periodically based upon historical data and current trends in customer energy consumption. New trends, such as the mixed-use development occurring associated with the Pasadena-Los Angeles Metro Gold Line, are included in the forecast, as well as on-going energy improvements adopted through building standards, improved household appliances and more efficient commercial equipment. Future energy growth is based on a linear regression of historical energy sales over the past five years, and may be adjusted based on qualitative factors and intuitive judgment as appropriate to ensure reasonable results. One such adjustment is to account for the extraordinary conservation made by customers during the energy crisis in 2001 and 2002. While the energy crisis proved that significant conservation can occur, it took very special circumstances and a statewide marketing effort to produce the results achieved during the crisis period. The load forecast was developed based on the following underlying assumptions:

• Moderate growth rates experienced over the past five to ten years will continue in the near future, but slow down in later years to reflect anticipated build-out of the city

• The economy will remain stable during the planning horizon

• Seasonal energy and demand patterns will be similar to those of the past five years

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The load forecast used in the production cost analysis was derived from an initial load based on an average of the years 2003 – 2005, with an annual 1% growth rate over the 20 year study period. This is significantly below the statewide growth rate, as Pasadena is a fairly stable urban area with modest growth from increased housing and commercial density. For long-term planning, this assumption is adequate and will be adjusted each time the Integrated Resource Plan is updated. (Going forward, this will be every two years). Net Electric LoadPWP’s net electric load (NEL) represents the total demand to be served by PWP through a combination of power generated by local plants and energy imported from the statewide grid via the T. M. Goodrich Receiving Station. This demand is the sum of each individual meter on the Pasadena electric system, plus transmission and distribution losses incurred by transmitting the electricity over the system. As the table below indicates, the number of meters installed on the Pasadena system has increased over the last 5 years: 2002 2003 2004 2005 2006 Total Number of Services 58,519 59,601 60,795 61,389 62,250

The NEL fluctuates on an hour-to-hour basis, driven by customer activity throughout the day. On a typical summer day, the NEL will increase as temperature and air conditioning load increase. The NEL bottoms towards the early morning hours, when it is generally 50 percent of the peak load.

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1998 - 2005 Average July Hourly Demand

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50

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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Hour of Day

MW

h Co

nsum

ed

Series1

This hourly fluctuation requires constant adjustments to the power supply schedules. This is an important fact when considering the types of resources needed within Pasadena’s resource portfolio.

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Monthly Load ProfileIn addition to the hourly variation, load requirements vary significantly during the year. Pasadena is a summer-peaking utility, with summer peaks (July through September) about 60 percent higher than winter peaks (November through April).

2005 Peak Monthly Demand

0

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150

200

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300

350

1 2 3 4 5 6 7 8 9 10 11 12

Months of Year

Hour

ly P

eak

MW

h fo

r Mon

th

Series1

This characteristic of the load requirements impacts supply planning and maintenance outage schedules throughout the year. It also indicates the importance of developing demand response programs to reduce the summer peaks. While peak demand varies significantly each month, the total monthly consumption by customers of base load requirements, like refrigerators, is fairly constant over the entire year. Similar to the hourly peaking characteristics described above, the total monthly consumption is heavily weighted across the summer months.

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2001 - 2005 Average Monthly Consumption

0

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40,000

60,000

80,000

100,000

120,000

140,000

1 2 3 4 5 6 7 8 9 10 11 12

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These hourly and seasonal variations in load requirements greatly influence the decisions for power resources. The more flexible the power resource is in managing variability, the more suited it is to matching the load requirement and consequently the more valuable it is to the resource portfolio. The below table lists the hourly peak demand and total load requirement for 2000 – 2005:

Calendar Year Peak Hourly Demand

Total Yearly Demand

2000 275 MW 1,229,522 MWh 2001 245 MW 1,157,704 MWh 2002 270 MW 1,168,125 MWh 2003 281 MW 1,239,998 MWh 2004 277 MW 1,221,407 MWh 2005 292 MW 1,229,673 MWh Average 273 MW 1,207,738 MWh

As the numbers indicate above, besides the period of the California Energy Crisis in 2001 and 2002, the peak load has increased while the yearly demand has been fairly constant.

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Other Considerations Beyond consumer demand for electricity, other trends and events must also be considered in the long-term planning process. One of the major trends over the years is the continuing improvement in building standards. New guidelines reduce energy use through better insulation methods and improved building materials, and by promoting energy efficient commercial machines and household appliances. As for events, the California Energy Crisis and the subsequent campaign to reduce electricity consumption through a statewide marketing campaign have provided a valuable lesson for the future. The combination of high electricity prices, rolling blackouts, news reports and television commercials produced an unprecedented, voluntary reduction in electricity use among customers. PWP continues to encourage energy conservation and reduced peak demand through a number of public benefit programs. These programs include:

• Residential and commercial rebates for energy-saving appliances • Shade-tree promotions • Residential rebates for solar photovoltaic (PV) and efficient cooling systems • Refrigerator recycling program • Compact fluorescent light bulb (CFL) distributions

Two new commercial projects, PWP’s High-Performance Building Program (HPBP) and the Pasadena LEED Certification Program, provide property owners and developers with technical advice and financial incentives for adopting energy-saving measures during major retrofits and new construction. These programs are discussed more thoroughly in the Power Resources section of this report. Other factors for consideration include:

• Increased development of distributed generation by large customers to support combined heat and power requirements (e.g. the California Institute of Technology’s co-generation plant)

• Greater adoption of residential solar panels through legislative initiatives (e.g. Senate Bill 1, the California Solar Initiative)

• Increased energy awareness and conservation through growing concern over greenhouse gases

• Impacts of the Gold Line extension along the Foothill Freeway corridor, and the ongoing development along the route within the city of Pasadena

These factors are generally difficult to forecast accurately, and are subject to significant change in relatively short time periods. After the California Energy Crisis there has been a tremendous effort within the State of California to develop a comprehensive and effective energy policy. One of the reasons Pasadena intends to update this Integrated Resource Plan every two years is the dynamic nature of the California energy market, which brings ongoing developments in state policy.

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Resource Adequacy and Local Capacity Requirements The state legislature passed Assembly Bill 380 (AB380) in February 2005. This bill requires that each publicly owned electric utility “plan for and procure resources that are adequate to meet its planning reserve margin and peak demand and operating reserves, sufficient to provide reliable electric service to its customers.” Planning reserves were established at 15 percent in PWP’s 2001 Integrated Resource Plan. Additionally, the CPUC has established resource adequacy requirements for investor-owned utilities. A component of the requirement is the need to have local resource adequacy, meaning a component of the generation supply must be close to the load that is served. This requirement reduces the dependency on transmission availability and provides a more stable and reliable electrical system. The CAISO is enforcing resource adequacy rules that align with the CPUC rules for investor-owned utilities. These rules echo somewhat existing Western Electricity Coordinating Council guidance on resource adequacy. In line with these rules, PWP reaffirms the findings from its 2001 Integrated Resource Plan that require a 15 percent reserve margin. PWP recommends maintaining 200 MW of local capacity, an amount that exceeds the current CPUC requirement for investor-owned utilities for local capacity.

Future Requirements While PWP monitors load characteristics closely and employs several load forecasting tools, many of the factors in load trends are external and/or difficult to predict. While PWP can encourage conservation and energy efficiency, the adoption rates and impacts are not certain. The various scenarios in the production cost model discussed later in this report are intended to account for as much variation as is possible. These variables and variations impact the resource mix discussed in the next section.

Section 4 – Power Resources PWP has met the city’s load through a combination of long-term remote-generation contracts, long-term transmission contracts to bring power into Pasadena, and local generation. PWP currently has 405 MW of supply resources to meet its loads, including local generation and long-term contracts. These resources, shown below, provide PWP with a 30 percent reserve margin for predicted 2007 peak load of 307 MW.

Resource Type Capacity (MW)

Percent of 2007 Total Production

Contract Expiration

Intermountain Power Project (IPP) Pulverized Coal 102 65% 2027

Hoover Power Plant Large Hydro 20 5% Palo Verde Nuclear 10 5% 2017

Magnolia Power Plant

Natural Gas Combined Cycle 18 8%

BPA Contracts Power Exchange 27 <1% 2009 – 2013

High Winds Wind 2 1% Ormat Geothermal 2 1%

West Covina/Tulare Landfill 9 6% 2017 Broadway and Glenarm Local

Generation

Natural Gas Combustion and Steam Turbines

200 3% Ownership

Azusa (SCE) Small Hydro 15 <1% Ownership 405 94%

Resource considerations over the last several years have been driven primarily by the Renewable Portfolio Standard (RPS) established by the city council in 2003 in response to SB-1078. Since the adoption of the RPS, the geothermal and landfill gas projects listed above have been completed and are now providing energy to Pasadena. An additional landfill gas contract (Ameresco - Chiquita Canyon Landfill) has been signed, but the project is not in operation at this time. With the adoption of the loading order in the State’s Energy Action Plan and the impacts of electric generation on the environment, Pasadena is undertaking new energy efficiency and demand side management programs. PWP has implemented a variety of programs in energy efficiency, conservation and peak shaving, but there are additional areas that are untapped. PWP will undertake studies during 2007 to estimate the potential for savings from further energy efficiency measures and conservation. This data will be provided in a plan to be presented to the city council, recommended for adoption by June 30, 2007 and forwarded to the California Energy Commission to meet state requirements of Assembly Bill 2021 (AB 2021).

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Long Term Contracts PWP meets approximately 90 percent of the city’s energy requirements through long- term contracts. As a municipality currently serving customers, PWP is well situated to contract long-term. There does not appear to be any incentive for customers to request direct access to other energy suppliers; therefore, PWP can enter into long-term arrangements directly with energy suppliers, or through joint action agencies (like SCPPA) to procure energy. These longer term contracts provide a stable market for energy providers; therefore, energy pricing is generally below market rates. Existing long-term contracts include the following:

Intermountain Generating Station (IGS) The Intermountain Generating Station consists of two 900 MW (net) coal-fired steam units, which are located in Utah and operated by the Intermountain Power Service Company (IPSC). PWP has three separate contracts with the Intermountain Power Agency (IPA), which provide an approximate 102 MW entitlement of this facility (subject to Excess Sales Contract fluctuation as discussed below). Over 750GWh of energy are delivered to PWP from the plant each year. The agreements extend through 2027. Details of the three contracts are as follows:

• Original Entitlement (61 MW) -- Pasadena contracted with the IPA to purchase a 3.409 percent (61 MW) entitlement to the plant. The original plan called for four 800 MW units, providing Pasadena with a 109 MW entitlement, but this was later scaled back as load-growth forecasts were moderated throughout the western states. This contract obligates Pasadena to pay its proportional share of the plant costs (including debt and other fixed expenses), regardless of the amount of energy scheduled to Pasadena.

• Layoff Contract (18 MW) -- Pasadena contracted with Utah Power and Light (UP&L), which is now PacifiCorp, and the IPA to purchase a 1 percent (18 MW) entitlement of the plant from UP&L.

• Excess Sales Contract (23 MW) -- The California purchasers (Pasadena, Los Angeles, Burbank, and Glendale) contracted with 27 named Utah participants and the IPA (acting as agent for the sellers) to purchase a 17 percent entitlement of the plant, which was deemed in excess of the sellers’ needs. Pasadena’s share of the excess is 23 MW. This contract also provides for access to the Northern Transmission System, which was built with IPA funds in order to deliver power from the plant to the Utah participants. The term of this contract extends until the IPA bonds are paid off or the sellers’ load requirements meet certain specified conditions. The Utah participants have the unilateral right to recall their original entitlements at any time in the future.

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IPA also has ownership in two mines, the West Ridge and Crandall Canyon mines in Utah. In addition to these facilities, the plant sources coal from other Utah and Wyoming mines. Coal is generally purchased through mid-term (2–5 year) contracts, and the transactions are managed by the Los Angeles Department of Water and Power as the operating agent for IPP.

Hoover Hydro Hoover Power Plant is a large, federal hydro facility built in the 1930’s on the Arizona-Nevada border outside of Boulder City, Nevada. PWP's 20 MW of Hoover entitlement includes an 11 MW renewal of the original contract and 9 MW from plant upgrades. The actual capacity available from Hoover varies, depending on maintenance scheduling and other outages. Under normal hydro conditions, PWP receives about 60 GWh/year of energy deliveries. This energy currently qualifies as a renewable resource under the city council-established Renewable Portfolio Standard.

Palo Verde Nuclear Generating Station (Palo Verde) The Palo Verde Nuclear Generating Station (Palo Verde) in southwest Arizona is comprised of three identical 1270 MW nuclear-fueled steam units. PWP has contracted with SCPPA for a 10 MW entitlement of the 225 MW share funded via SCPPA bond issues.

Magnolia Power Plant (MPP) The Magnolia Power Plant is located in Burbank, California. The 250 MW facility is a combined cycle natural gas-fired plant operated by Burbank Water and Power. The plant began commercial operation in September 2005 and has an expected life span through the period of this resource plan. PWP has contracted through SCPPA for 6.13 percent of the project output, or approximately 15 MW. An additional 3 MW of capacity is available on a limited basis through duct firing.

Bonneville Power Administration (BPA) Purchase/Exchange PWP executed a 20-year contractual arrangement with Bonneville Power Administration (BPA) in December 1987 for up to 12 MW of summer capacity. The agreement has two modes of application: The sale mode takes effect when the Pacific Northwest has surplus energy, and an exchange mode applies during periods when the Pacific Northwest has deficit energy. PWP may schedule on-peak deliveries in two 6 MW blocks, one of which is available only May through September, and the other year-round. Energy deliveries follow an approximate prescribed monthly distribution, as shown below, and are limited to approximately 30 GWh of energy annually. This contract will provide peak capacity through FY 2008.

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec TotalBlock I 1260 1200 1764 2142 2142 2142 2142 2142 2142 1428 1260 1260 21024Block II 0 0 0 0 780 1638 1651 1764 1638 240 0 0 7711

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BPA Exchange In 1994, PWP executed a long-term contract with BPA for an additional 15 MW of firm capacity that is scheduled at PWP’s request on a day-ahead basis. The energy and capacity are provided on an exchange basis with two components: a spring-winter “seasonal” exchange and a summer 24-hour return exchange that behaves as a “pumped-storage” device that is approximately 85 percent efficient (due to transmission losses). Under the terms of the seasonal exchange component, BPA supplies Pasadena a minimum of 3.26 GWh firm energy from May to June, up to 6.0 MW, subject to daily limits of 150 MWh and weekly limits of 750 MWh. Energy is later returned to BPA in off-peak hours from October through March. For the summer component, BPA supplies on-peak capacity and energy from July through September (subject to the same daily and weekly limits as the seasonal component) that must be returned non-firm to BPA within 24 hours. In exchange for the summer capacity entitlement, PWP supplies BPA with an additional 16.5 GWh block of non-firm, off-peak energy during the winter. This contract will provide peak capacity through FY 2013.

High Winds Generation In 2003, PWP executed a 25-year contract with PPM Energy for a 6 MW share of the 146 MW High Winds wind generation facility in Solano County, California. The one third of the energy is scheduled to PWP by PPM Energy on a 24-hour basis. This accounts for the wind only blowing approximately 33% of the time. Once a year, PPM Energy adjusts the scheduled amount to account for differences in actual wind energy generated and the 2 MW energy scheduled. The last five years of the contract are optional by either party. The contract terms are such that PPM Energy is unlikely to continue providing the energy after the initial 20-year term. This energy qualifies as a renewable energy resource.

Ormat Geothermal Energy In 2005, PWP executed a 25-year contract with SCPPA for geothermal energy from two plants (Heber and East Mesa) owned by Ormat Energy. The contract is for 3 MW, 2 MW of which are currently available. The plants are in the Imperial Valley, and energy is delivered through the Imperial Valley Irrigation district’s control area and received by PWP at Southern California Edison’s (SCE) Devers Receiving Station. This energy qualifies as a renewable energy resource.

West Covina and Tulare Landfill Generation In 2006, PWP executed a 10-year contract with Minnesota Methane for 9.5 MW of energy and capacity from two landfills in California: the BKK Landfill in West Covina and the Visalia Landfill in Tulare. These units began scheduling energy to PWP in January 2007, and the energy is delivered into the CAISO grid. This energy qualifies as a renewable energy resource.

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Chiquita Canyon Landfill Generation In 2003, PWP executed a contract for energy from a landfill in Valencia, California. This facility at the Chiquita Canyon Landfill is behind schedule and is not built at this time. PWP executed a revised contract in 2006 for up to 6.7 MW of energy. The plant is expected to be operational at the end of 2007.

Generation Ownership In addition to the above long-term contracts, Pasadena has a 100-year history of providing energy locally through generation resources owned by the city of Pasadena. PWP operates 200 MW of capacity within the city limits, and a small 3 MW hydro facility in the nearby city of Azusa.

Glenarm and Broadway Local Generation The generation facility in Pasadena includes the Glenarm Power Plant (Glenarm) and the Broadway Power Plant (Broadway). The combined facility currently has a capacity of 200 MW. Current local generation consists of the following units:

Unit Name Unit Type In Service Capacity Broadway 3 Steam 1965 65 MW Glenarm 1 Gas Turbine 1975 23 MW Glenarm 2 Gas Turbine 1975 23 MW Glenarm 3 Gas Turbine 2003 45 MW Glenarm 4 Gas Turbine 2003 45 MW

The two newer units, Glenarm 3 (GT-3) and Glenarm 4 (GT-4) are efficient (i.e. they burn natural gas efficiently for each unit of electricity produced), quick start (within 10 minutes), simple cycle units that are generally employed during the summer months. Glenarm 1 (GT-1) and Glenarm 2 (GT-2) are very inefficient units and are only used for standby emergency purposes. The Broadway 3 steam generation unit is a long start (24 hours) unit that is generally used if summer temperatures are forecasted to be high for an extended period of time.

Azusa Hydro PWP also owns a small 3 MW run-of-river hydroelectric generating plant located in the San Gabriel River Basin, built in 1894 and refurbished in 1949. Through an agreement with Southern California Edison (SCE), energy is accumulated and delivered to PWP at PWP’s request at up to 15 MW at a time. Since becoming part of the CAISO-control area, this energy has been scheduled as what is called a Scheduling-Coordinator-to-Scheduling-Coordinator (SC-SC) trade in the SP15 zone, a portion of the statewide grid that encompasses Pasadena and the San Gabriel Valley.

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Energy Efficiency and Demand Side Management Energy efficiency is an increasingly important component of resource planning. Concerns about energy prices and the short- and long-term environmental impacts of fossil-fueled electric generation continue to grow. Lawmakers in California are focusing their attention on decreasing the demand for electric power while increasing the supply of clean, renewable energy resources. Recent legislative actions mandate all electric utilities to integrate cost-effective energy efficiency and conservation measures before securing new generation. PWP has invested significant resources from its Public Benefit Program since FY2000 in energy efficiency measures that are reducing customer usage today and well into the future. Significant opportunities remain in PWP’s service territory for reducing energy consumption and customer costs while improving the local and global environment without sacrificing customer comfort or productivity. Energy conservation benefits our utility (by reducing purchases of expensive peak power), our customers (by reducing utility bills), and society ( by reducing air pollution and global greenhouse gases, and conserving limited fuel supplies). Through the city’s signing of the United Nations Urban Environmental Accords, PWP has committed to reducing peak load by 10 percent by 2013. This will be accomplished with energy efficiency programs as well as targeted demand-side management programs that shift consumption from peak periods to off-peak periods. This shifting of load decreases the need for new generation capacity and decreases the overall cost of energy. The Pasadena City Council passed an ordinance in 1997 directing PWP to create its Public Benefits Charge (PBC) Program to comply with state law AB 1890. Council further directed that PBC funds collected be spent on all four of the eligible AB 1890 categories:

• Low-income customer support programs • Cost-effective conservation and energy efficiency programs • Renewable energy programs • Research, development and demonstration (RD&D) of new technologies

Low-income programs generally refer to assistance in reducing customer costs (rate reductions and no-cost efficiency measures). Conservation programs encourage voluntary reductions of electricity consumption during significant time periods. Efficiency programs reduce energy use without reducing desired output or production. Renewable energy programs may offset the incremental cost of generating or purchasing qualified renewable energy (such as solar, wind, biomass, geothermal, etc.). RD&D programs do not have any cost-effective requirements, but rather help in designing, testing and promoting emerging technologies so that they may become commercially available.

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Council members expressed particular interest at that time in low-income and efficiency programs. PWP began with a small, new staff to renew and enhance existing programs such as Lifeline, Project APPLE and refrigerator recycling. As staffing and expertise grew, PWP was able to create new and popular programs, such as Utility Assistance, low-income refrigerator exchange, Energy Star®, compact fluorescent light (CFL) distributions, Energy Partnering, residential photovoltaic and electric vehicle programs. Staff utilized the CMUA’s “Guidebook to Public Benefit Programs Handbook” as a guide in developing appropriate programs to meet AB 1890. In 2001, PWP staff began working with an energy consultant to develop a cost-effectiveness model for evaluating PWP efficiency programs. Staff reviewed the history and current status of state guidelines for cost-effectiveness procedures. The CEC and CPUC both promote conservation and demand-side management (DSM) programs as alternatives to the construction of new power plants. The governor’s office published a set of new guidelines and standards in 2002, renaming and redefining various types of cost-effectiveness tests. These tests analyze efficiency programs from different perspectives: the ratepayer/customer, the utility and society. PWP integrated the standard utility and societal tests to reflect Pasadena’s community and environmental values. The resulting model has been used each year to prioritize funding for various efficiency projects and programs. This tool also assists in reporting on the results of these programs. In 2006, legislation (AB 2021) required all publicly owned utilities, including PWP, to report their energy efficiency activities to the CEC. PWP worked through the SCPPA Public Benefit Committee and the California Municipal Utility Agency (CMUA) to develop a new reporting tool using standard metrics acceptable to the CEC. This tool, E3, will also assist PWP in planning changes to existing programs, as well as creating new programs. These programs will constitute the plan forward for energy efficiency in Pasadena. This plan will be presented to the city council by the end of the 2007 fiscal year.

Distributed Generation Distributed generation is small generation units or solar panels connected to the distribution system, generally owned and operated by a utility customer. Caltech has the largest distributed generation capacity in Pasadena at 12,000 kw (12 MW), and Pasadena City College has a 120 kw-capacity unit. In addition, PWP’s solar initiative has resulted in 35 residential installations, for a total of 78 kw, and nine commercial installations, for a total of 114 kw. The environmental constraints on fossil fuel-powered distributed generation and the high cost of fossil fuels make it unlikely that many new installations of cogeneration systems will occur in Pasadena in the near to mid-term. Solar installations are expected to continue at a moderate pace or a higher pace if technology improvements reduce costs and improve efficiency. PWP offers a $3.50/watt incentive, up to a maximum of $8,000, to customers who install solar panels.

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Characteristics of Renewable Resources As noted above, the city adopted a RPS that conformed to SB 1078. PWP has had hydro renewable resources from the San Gabriel Canyon (Azusa Hydro) and from the federal government’s Boulder Canyon Project (Hoover Dam) for years. These two resources have recently been augmented with a series of power purchase agreements noted above. PWP continues to evaluate resources to meet the RPS. Each of the renewable sources has operational characteristics and pricing that demand careful consideration in building the portfolio. The major renewable options are discussed below with an indication of PWP’s current opinion on each option.

Wind Wind energy continues to develop at a rapid pace and provides a significant component of the renewable energy provided in the United States in the last 10 years. California has over 2200 MW of wind generation capacity.1 Managing a wind resource is problematic for small utilities like PWP, since the megawatt output of the plant fluctuates unpredictably. The typical utilization rate of a wind resource is 35 percent. This means that a wind farm with 100 MW of capacity is only fully operational for 3 1/2 hours of every 10-hour period. This contrasts with a coal plant like Intermountain that has a utilization factor of approximately 90 percent. In addition, wind generation often peaks at night when load requirements are lower.2 Since the CAISO is a large control area, they are able to manage the intermittency of wind resources and do not penalize wind participants for imbalanced energy. When PWP entered into the wind agreement with PPM Energy, firming of the wind resource was a common practice. This means that PWP receives a steady flow of energy, and PPM Energy manages the intermittency. These types of arrangements are rare and much more expensive than they were several years ago. Another major issue with wind resources is the need to build transmission lines to connect the resource to the load. The two major regions for wind in Southern California are Tehachapi and San Gorgonio. The Tehachapi region in particular has significant development activity, although the transmission paths are still questionable. Transmission development is an ongoing concern throughout the state, as the regulatory process and rights of way continue to present multiple complex issues that have not been resolved. This uncertainty makes investment in wind resources in the area more problematic. In addition, increases in demand for wind energy have resulted in shortages of component parts; therefore, pricing of wind projects has not come down as one would hope with expanded production. Wind prices are currently competitive with natural gas power

1 CAISO Briefing Paper on Wind Generation and Renewables, pg. 2, April 2006. 2 CAISO Briefing Paper on Wind Generation and Renewables, pg. 5, April 2006.

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plants, but with the operational constraints discussed above, wind energy does not have the operational value of a natural gas power plant. Nevertheless, wind power continues to evolve as a viable option. In cooperation with SCPPA, PWP is investigating the possibility of developing additional wind resources. PWP also continues to monitor the scheduling rules within the CAISO for intermittent resources, as favorable scheduling processes are critical to this investment.

Geothermal Similar to wind, there are concentrated areas of geothermal potential, particularly in California’s Napa and Imperial valleys. PWP has entered into an agreement with Ormat for a portion of the Heber geothermal plan in the Imperial Valley. However, similar to the wind situation, transmission is a major issue in connecting the geothermal energy with the load center. In our case, the Imperial Valley is approximately 150 miles southeast of Pasadena. Perhaps more critical than the distance is the complexity of dealing with a second control area, in addition to CAISO. The Imperial Valley is served by the Imperial Irrigation District (IID), which is a separate from CAISO. This subjects PWP to “pancaked” rates, meaning that PWP would have to pay transmission costs to IID as well as the CAISO. Geothermal resources provide a base load profile, meaning the generation pattern is generally constant over an entire 24-hour period. This predictability is good for planning purposes, but PWP has a sufficient supply of off-peak loading and much more need for peak energy.

Small Hydro Small hydro is defined by the California Energy Commission (CEC) as hydro generation with 30 MW in capacity or less. Large hydro (e.g. Hoover Power Plant) is excluded from CPUC renewable portfolio standards set for the for-profit corporations that the CPUC regulates. Smaller hydroelectric generators often are “run-of-river” generators and therefore share with wind resources the problem of intermittency. Water schedules are generally more predictable than wind and, therefore, the associated energy is more valuable, but the energy is not consistent and therefore cannot be considered a reliable source for planning purposes. There is a limited supply of small hydro, and new small hydro developments are not common. Even though small hydro has fewer environmental impacts than large hydro, small hydro does significantly disrupt the eco-system. Siting any new small hydro plant comes with many environmental hurdles. PWP has investigated the feasibility of upgrading the Azusa Power Plant to achieve more efficiency from the plant. All options were found to be uneconomical, and only life extension capital improvement projects are currently slated for the facility.

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Solar No other renewable resource would seem to fit the needs of PWP better than solar energy. As PWP is a summer-peaking utility, solar power would seem to be ideal: PWP’s highest loads are experienced during the highest solar generating period -- summertime. Current solar photovoltaic (PV) panels remain expensive and require a significant capital expenditure. The low power-to-surface area ratio means that a panel of immense dimensions is required to make appreciable levels of power. Further, this means that a large area of land would be required to house said panels. Because of the “footprint” issue, solar generating plants, like wind generating plants, must be located in remote areas and the power brought in through transmission lines, further raising the cost of solar generated energy. High land cost and high capital investment would result in power prices exceeding $0.10/kWh. Other technologies, such as solar water heating, are not suited for wholesale generation of electricity and are currently only utilized at end-user locations. Although the Southwestern United States does enjoy a relatively stable warm-weather climate, it is still too unpredictable to rely upon as a major source of power.

Landfill and Bio-Fuel Landfill technology provides a stable and reliable source of energy. PWP has recently entered into several landfill transactions and at this time is looking to diversify the RPS to include other renewable technologies. Along with other local municipalities, PWP is investigating the feasibility of using city green waste (e.g. lawn clippings) as part of a bio-fuel generation plant.

Section 5 – Transmission Issues As mentioned previously, Pasadena has a single interconnection to the statewide energy transmission grid through the T.M. Goodrich substation on the east side of town. The Goodrich substation is connected to the grid via two transmission lines -- one from the Gould substation northwest of Pasadena and one from Laguna Bell directly south of Pasadena. A transmission agreement with SCE allows PWP to import up to 200 MW (an additional 15MW may be scheduled with SCE associated with Azusa Hydro energy). Local generation has supplied the city with power to meet customer demand and reserve requirements above 215 MW (during the summer peak). The in-town generating units also provide a backup during maintenance or failures of the T.M. Goodrich station or incoming transmission lines. Beginning in 2005, the city council authorized entering into a Transmission Control Agreement (TCA) with the CAISO. This agreement allows PWP to use the entire statewide transmission grid while still retaining rights over PWP’s existing transmission arrangements. The operational control of PWP’s transmission is managed by the CAISO and PWP customers pay a reduced transmission charge under the agreement. The TCA is a multi-party agreement between the CAISO and all Participating Transmission Owners (PTO). The execution of the TCA is filed and approved by the Federal Energy Regulatory Commission (FERC). The net savings from the TCA is approximately $4 million per year over pre-2005 transmission charges.

Master Plan Work PWP’s Electric Distribution System Master Plan identifies the single interconnection at Goodrich substation as a reliability risk. The backup interconnection with LADWP is intended primarily as a Black Start solution (the ability to start-up a blacked-out electrical system) and is only capable of providing approximately 30 MW to Pasadena through two 34.5kv subtransmission lines from LADWP’s St. John substation (RS-A). Transmission alternatives outlined in the Master Plan include the following:

1. Add a fourth transformer at Goodrich 2. Construct a new 230kv receiving station at Glenarm and connect to the CAISO

grid at the Eagle Rock substation 3. Construct a 69kv cross-town link from Glenarm to Goodrich 4. Construct a 230kv cross-town link from Glenarm to Goodrich

The Master Plan focused on the city’s aging subtransmission infrastructure, and the study of the transmission was high-level. The Master Plan recommendation to construct a 230kv transmission system between Glenarm and Goodrich substations addresses some issues, but does not address the single interconnection with the CAISO. Additional transmission planning is required and will be undertaken in the next Integrated Resource Plan scheduled for 2008.

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One of the primary areas of investigation is what additional upgrades, if any, are required on the west side of Pasadena if the power plant were to increase its current generation capacity from 200 MW to 300 MW. This resource plan calls for improving the efficiency of the older Glenarm and Broadway units. As the viability of the Intermountain Power Project and the availability of renewable resources become more defined over the next several years, the increase of local generation capacity may be warranted. No formal studies have been conducted to investigate the impacts and consequences of increasing the capacity at Glenarm/Broadway.

Magnolia Transmission Work As part of the Magnolia Power Project discussed earlier, a transmission service alternatives study was conducted. None of the alternatives proved to be feasible for various reasons. Since commercial operation of the plant began in September 2005, Pasadena has entered into mid-term arrangements to transfer the Magnolia energy over transmission lines to the Pasadena service area. These arrangements have been extended to June 2007. Pasadena will be working on a longer-term solution to this transmission issue. In addition, dynamic scheduling of the plant will be investigated to determine if the Magnolia unit may be bid into the CAISO market for ancillary services. The primary issue with Magnolia transmission is the added costs associated with transmitting over two control areas, LADWP and CAISO. This is referred to as “pancaked” transmission rates, one of the primary issues that encouraged the federal government to develop Regional Transmission Organizations like the CAISO. The LADWP transmission rate is approximately three times higher than the CAISO transmission access charge. This means that Magnolia generation could incur up to four times the transmission charges as generation within the CAISO. LADWP has transacted an energy swap with Pasadena that reduces their import requirements, decreases their transmission losses, and provides for a more reliable control area. This has been done on a periodic basis as mentioned above. Factors that could influence a long-term agreement on transmission include the possibility that LADWP could revisit their Open Access Transmission Tariff (OATT), which has not been substantially updated for approximately 10 years. The Energy Policy Act of 2005 included language to ensure that unregulated transmitting utilities that sell more than 4,000,000 MWh of electricity per year offer transmission service at rates that are comparable to those that the utility charges itself. An investigation of the rate charged by LADWP to others may not align with the transmission charged internally1. This is a difficult issue to identify, as it has to do with LADWP’s internal accounting systems, but the issue being raised in the Energy Policy Act could encourage LADWP to rethink its transmission policy.

1 Energy Policy Act of 2005, Title XII – Electricity, Subtitle C – Transmission Operation Improvements, Section 1231 Open Nondiscriminatory Access, pp. 1124-1125.

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Current Transmission Agreements Since remote resources supply the majority of Pasadena’s energy, a robust transmission network is necessary for system reliability. In addition, PWP’s firm transmission entitlements provide access to major hubs of the wholesale power market at the Nevada-Oregon Border (NOB), Mead/Marketplace, Palo Verde (at Westwing) and Mona in Utah. This transmission network allows Pasadena to obtain low-cost energy supplies and enables bulk sales and exchanges of energy.

Firm Transmission Service Agreements

Transmission Line / Path Owner/Party Capacity Primary Use Sylmar-SP15 SCE/ISO 200 MW ALL Imports Pacific-Northwest DC Intertie * Pasadena 45 MW BPA, NOB Northern Trans. System (NTS) IPA/Utah 89 MW Utah Market Southern Trans. System (STS) SCPPA 113 MW IPP Adelanto-Sylmar LADWP 110 MW IPP Mead-Phoenix SCPPA 33 MW PV, Westwing Mkt. Mead-Adelanto SCPPA 75 MW PV, Marketplace Hoover-Sylmar LADWP 26 MW Hoover Hydro McCullough-Victorville LADWP 26 MW SW Markets Victorville-Sylmar LADWP 26 MW SW Markets * Pasadena owns 69 MW of this line. 24 MW has been sold to the ABC cities, Anaheim, and Riverside.

Sylmar-SP15 PWP has a long-term contractual right to 200 MW of firm capacity from LADWP’s Sylmar Substation to T. M. Goodrich, provided by SCE. This contract, which expires in August 2010, enables PWP to import economy energy and all of its power entitlement from remote resources. CAISO honors PWP’s rights under the existing contract, providing 200 MW of firm import into SP15 at Sylmar. With the CAISO market redesign, scheduled to start on January 31, 2008, these rights will be converted to Congestion Revenue Rights (CRR) that should be comparable to PWP’s existing rights. As part of CAISO’s market redesign and pursuant to the Energy Policy Act of 20052, long-term transmission rights (LTTR) are being determined through a stakeholder process. PWP will need to renew the interconnection agreement with SCE prior to 2010. The process for interconnection is regulated by the Federal Energy Regulatory Commission, and it is a fairly straightforward process. 2 Energy Policy Act of 2005, Title XII – Electricity, Subtitle C – Transmission Operation Improvements, Section 1233 Native Load Service Obligation, pp. 1139-1140.

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Pacific Northwest DC Intertie Spanning 850 miles from Celilo in northern Oregon to Sylmar, California, the Pacific Northwest DC Intertie is a double-pole, +/-500 kV transmission line. This line conveys energy from BPA and other Pacific Northwest utilities at the Oregon border to Sylmar. PWP purchased 69 MW (2.25 percent) of the total 3100 MW capacity of the southern portion (south of the point where the line crosses the border) of the Pacific Northwest DC project.

Northern Transmission System (NTS) The NTS consists of two 50-mile long 345 kV AC transmission lines that connect the Intermountain plant to the Mona Substation in Utah and the Gonder Substation in Nevada. PWP has bidirectional entitlements of 89 MW and 9 MW, respectively, on these transmission lines as a result of the IPP Excess Sales contract with the Utah participants. The term of this contract extends through 2027.

Southern Transmission System (STS) The Southern Transmission System is a double-pole, +/-500 kV DC transmission line spanning 488 miles from the Intermountain plant in central Utah to the Adelanto Substation in Southern California. It is operated and maintained by LADWP under contract with IPA. PWP has a contractual entitlement to 113 MW (5.88 percent) of the total 1920 MW capacity through contracts with SCPPA. The term of this contract extends through 2027 or through the life of IPP, if the IPP contract is renewed with IPA. The California participants are investigating the upgrade of the STS. This would increase the capacity of the transmission line to 2400 MW. The total cost of the upgrade is estimated at $70 million. This decision is also impacted by the renewal of the IPP contract. The STS contract is tied to the IPP participants and, consequently, without participation in the power plant there would not be any rights to the transmission system.

Adelanto-Sylmar This is a continuation of the Southern Transmission System. PWP has a contract with LADWP for 110 MW of bidirectional transmission capacity from either Adelanto or Victorville to Sylmar. The term of this contract extends through 2027 or through the life of IPP if the IPP contract is renewed with IPA.

Mead-Phoenix This 500 kV AC transmission line, which was commissioned on April 15, 1996, provides PWP with access to low-cost energy in the southwest, as well as a permanent path for its Palo Verde entitlement. Through contract with SCPPA, PWP is entitled to receive 33 MW (2.5 percent) of this line’s 1320 MW capacity. The term of this contract extends for the life of the facility, or until all bonds are defeased.

Mead-Adelanto Through contract with SCPPA, PWP is entitled to 70 MW (8.6 percent) of this 500 kVAC transmission line, which was commissioned on April 15, 1996. This arterial

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line provides service to the Marketplace and Mead-500 substations, a major power transmission hub, and is a continuation of the Mead-Phoenix path. The term of this contract extends for the life of the facility, or until all bonds are defeased.

Hoover-Sylmar Transmission Agreements PWP has a 26 MW bidrectional Hoover-to-Sylmar transmission service entitlement provided by LADWP under terms of the original Hoover Transmission Contract, the Hoover Upgrade, and other transmission service arrangements. This includes rights to and from the active trading hub at the Mead 230 substation.

McCullough-Victorville PWP has purchased a 26 MW ownership entitlement from LADWP’s 180-mile, 500 kV AC McCullough-Victorville 2 transmission line. This line provides access to the southwest power market at McCullough.

Victorville-Sylmar PWP presently receives 26 MW of bidrectional transmission service between the Victorville and Sylmar substations, provided by LADWP, as a continuation of the McCullough-Victorville line.

Section 6 – Environmental Issues The power generation industry is subject to some of the most stringent and constantly evolving environmental regulations enacted by the government, in addition to strict public and political scrutiny. While power generation facilities are designed to be long-lived, legislative and regulatory uncertainty pose a challenge; any sites or technology selected for new generation facilities must meet both current and anticipated laws, regulations and goals. Environmental regulations are imposed by the federal Environmental Protection Agency (EPA), states and local agencies, through a cooperative and complex regulatory system. At some times, the states or local agencies take the lead in either introducing new regulations that the EPA has not enacted yet, or adopting requirements more stringent than the EPA’s. As a result, the geographic location of a facility, along with accompanying regulatory requirements for that area, impacts the cost of electric generation and competitiveness in the market place.

Local Generation Emissions Since the Glenarm and Broadway generation facilities are in the Southern California region, the generation units are subject to significant air quality regulations. This is due to the current non-attainment status the Southern California region currently has with federal air quality standards. Pasadena’s local generation units burn natural gas. While natural gas is the cleanest fossil fuel resource (as opposed to coal, gasoline and fuel oil), the units still produce a variety of emissions that are harmful to the environment. While currently unregulated, greenhouse gas emissions are beginning to be scrutinized at various levels; two laws were recently passed to begin to control them. PWP voluntarily tracks greenhouse gas emissions through the California Climate Action Registry (CCAR). A further discussion of greenhouse gases is in the regulatory section of this report. The CPUC has required investor-owned utilities to apply $8-per-ton of carbon dioxide reduction costs in evaluating future long-term utility resource procurement plans. Some industry experts estimate the actual cost of carbon dioxide reduction to be in the $8 to $25 per ton range. A study published by the Electric Power Research Institute (EPRI) estimates costs of about 2-3 cents per kWh, corresponding to $70 to $90 per ton for adding carbon dioxide capture capability to natural gas combined-cycle plants.1 The federal government is providing loan guarantees and tax breaks for integrated gasification combined-cycle demonstration projects.

1 Electric Power Research Institute (EPRI), Retrofit Of CO2 Capture Of Natural Gas Combined-cycle Power Plants, Report 01010169.

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The United States has neither ratified Kyoto protocol, a1997 international agreement to reduce greenhouse gas emissions, nor enacted domestic legislation to regulate carbon or greenhouse gases. In the past, all proposals setting goals for greenhouse gas reductions have been defeated by the U.S. Senate. However, over time, support among Congress for federal greenhouse gas regulatory programs has grown. In the meantime, several states have developed their own greenhouse gas policies, either independently or jointly with other states. When greenhouse gas/carbon dioxide or carbon controls are imposed on utilities, they most likely would take the form of a cap-and-trade program similar to the federal Acid Rain Program for Sulfur Dioxide (SO2) and Nitrogen Oxides (NOx), the SCAQMD Regional Clean Air Incentives Market (RECLAIM), or similar emission trading programs hosted by other agencies. Historically, in cap-and trade programs, existing plants are allocated emission allowances (a cap) at no cost, based on their historical emissions. They can sell or buy such allowances based on their actual emissions. The cap reduces over time. New plants have to procure allowances from the market place before operating permits are issued. Although a cap-and-trade program allows regulated parties to achieve emission reductions in a cost-effective manner, there remain significant concerns about the cost of carbon regulation.

Other Environmental Issues with Local Generation In addition to emission issues there are several other environmental issues associated with local generation. Pasadena’s local plant is required by the regional Water Quality Control Board to maintain a storm water pollution prevention plan, including sampling and reporting. Additionally, the city of Pasadena Planning Department requires an approved Standard Urban Stormwater Mitigation Plan. The Pasadena plant is required to obtain a permit from the County Sanitation Districts of Los Angeles County for waste water discharge from cooling tower blow down, reject water from its water treatment system and other miscellaneous waste water streams. The permit compliance includes monitoring quality and quantity of discharge, and reporting. Aqueous ammonia, used in selective catalytic reduction systems for reducing NOx emissions, requires both federal and state risk management plans to address safe loading, transfer, storage design and operating practices. In addition, hazardous materials and waste management are subject to several local, state and federal regulations and codes. For instance, asbestos and lead maintenance and abatement are subject to California Occupational Safety and Health Organization (CalOSHA), South Coast Air Quality Management District (SCAQMD) and federal regulations. Environmental site assessment is required prior to any major earth-moving activity to determine if there is subsurface contamination, and whether any subsequent remediation is necessary.

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Environmental Licensing Issues with Local Generation Finally, there are a series of ongoing issues that would impact licensing of any new construction at the power plant. These issues include:

• SCAQMD is required to submit its plans for federal EPA approval to meet 8-Hr Ozone levels by June 2007 and small Particulate Matter (PM2.5) standards by April 2008. Attainment is due by 2021 for 8-Hr Ozone and 2010 for PM2.5. The requirements are likely to make governmental review of any proposed new Southern California power plants, as well as emission limits, much more stringent.

• Applicants for any new generation facilities in Southern California are required to

have sufficient emission reduction credits for criteria pollutants, including nitrogen oxides (NOx), sulfur oxides (SOx), carbon monoxide (CO), reactive organic gases (ROG) and particulate matter with aerodynamic diameter of less than or equal to a nominal 10 microns (PM10) prior to permit issuance. Emission reduction credits are scarce and therefore command a very high price. For example, the latest trades for PM10 were priced at greater than $75,000 per pound. PM10 is a major constraint in permitting, due to its short supply and high price. Replacing existing older plants with emission-efficient plants that produce equivalent energy allows for conditional exemption from emission reduction credit requirements. A new generation plant at the Glenarm/Broadway location would be eligible for relief from environmental reduction credits, provided that existing generation capacity is retired subject to SCAQMD approval.

• Prevention of Significant Deterioration (PSD) approval by the EPA is a lengthy

process and may result in operational constraints. This entails a preconstruction review of the new project and approval by the EPA to ensure that the national ambient air quality does not significantly deteriorate while maintaining a margin for future industrial growth.

• New power plants of 50 MW or greater capacity (or repowering an older plant

with an additional 50 MW or more) are subject to California Energy Commission (CEC) licensing. This process is complex and can take 1.5 to 2.5 years.

• The powerful “not in my backyard” argument by local communities has affected

California Environmental Quality Act (CEQA) evaluation and local government decisions, making it nearly impossible to site any new fossil or nuclear power plants at any new locations in Southern California. In recent years, most new plants were installed at existing power plant sites. Therefore, Glenarm/Broadway is the most viable location for any new electric generation plant. In operation for more than a century, the facility has become a fixture for the Pasadena community. Since new generation plants are more energy and emission-efficient than retired units, no major objection is expected from the surrounding

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neighborhood. Requirements to maintain or lower sound from current levels should be expected.

• Environmental justice initiatives can add significant cost to improving community

facilities and, in some cases, prevent the project. This may not come into play during expansion of generation at the Glenarm/Broadway plant. Local residents appear to realize that the plant has benefited Pasadena as a whole for more than a century by providing reliable, cost-effective electricity.

• Potable water use and waste-water discharge are increasingly becoming major

issues for new plants. The California Water Resources Board has in some cases required usage of recycled water and/or zero waste-water discharge.

• The presence of sensitive properties, such as schools, day care facilities, hospitals

and nursing homes, in the neighborhood of any proposed new power plants bring greater regulatory implications. This may translate to considerable mitigation costs or, in some extreme cases, denial of permits. Blair High School is located across Arroyo Boulevard from the Glenarm/Broadway plant, but its presence has not impeded any plant modifications or activities in the past. However, the relatively new presence of Pasadena’s Art Center College of Design on the old Glenarm property and across Glenarm Street may potentially pose a challenge to construction of new generation units in the future.

Environmental Constraints on Remote Generation For new generation outside California, federal environmental laws are the same as applied in California. However, local and state regulations are location specific. Criteria for pollution control technology in other states would be similar to that of California, but the cost of emission reduction credits would be less in other western states. Fuels other than natural gas, such as coal, petro coke and residual oil, could be options, provided PWP maintains a diversified fuel portfolio. Greenhouse gas regulations would increase the relative price of fossil fueled generation, affecting coal generators most significantly. Coal is both the country’s predominant fuel, and its use emits the highest level of carbon per unit of power generated. The CEC is required to establish greenhouse gases emission performance standards applicable to publicly owned utilities by June 30, 2007 for in-state or imported energy. The CEC is expected to follow the CPUC decision due by February 1, 2007 regarding greenhouse gas emission standards as applied to investor-owned utilities. Therefore, PWP should evaluate greenhouse gas emission standards from new generation. In addition to providing high efficiency, integrated gasification combined-cycle plants promise to meet such standards.

Off-Shore Drilling, Liquid Natural Gas and Arctic National Wildlife Refuge Decisions State policies encourage increased supply, reliability, transmission and storage of natural gas, which fuels up to 45 percent of California’s electric generation. California imports 87 percent of its statewide natural gas supply. While offshore drilling expansion would

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increase California’s supply of natural gas, the extent and time frame for such a project is uncertain, as it is environmentally sensitive and greatly affected by political agendas. However, import of liquefied natural gas through ocean vessels seems promising and less controversial. Several companies have recently proposed building offshore liquefied natural gas import facilities in California and Mexico. According to the CEC, the cost of delivered natural gas is expected to be well below market prices that California currently pays at its borders. It is estimated that there is potential for delivering liquefied natural gas to meet about 30 percent of the state’s need. This is expected to lower overall natural gas prices. On December 19, 2005, Congress approved drilling of the Arctic National Wildlife Refuge. This proposal is yet to be approved by the Senate. According to the U.S. Geological Survey, the refuge holds promise for abundant oil and natural gas. As this is an environmentally controversial and politically charged issue, it may take several years before any commercial production takes place. In addition, there is currently no way to deliver natural gas from the refuge to the market. The exact impact of any drilling on oil and natural gas prices is speculative at this time, and several years away.

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Section 7 – Regulatory Issues All aspects of Pasadena’s future power supply, including local generation, transmission, imports and renewable resources, are governed and/or influenced by regulatory issues. A brief explanation of these considerations follows.

The California Independent System Operator (CAISO) CAISO continues to be the Federal Energy Regulatory Commission’s (FERC) only organized market in the western states. FERC is continuing to work with CAISO to develop a workable and efficient market while providing a reliable electric system. CAISO’s Market Redesign and Technology Upgrade (MRTU) initiative was substantially approved by the FERC in September 2006 and the implementation date is currently set for January 31, 2008. There is no indication at this time that either the FERC or the State of California questions the importance of an independent system operator in California. PWP will continue to monitor the MRTU activities, prepare affected employees for the new market redesign, and find solutions for the technology changes required by CAISO. The primary issues that should be resolved by MRTU include:

• Reduce dependency on the real-time market to stabilize costs and enhance reliability

• Eliminate certain opportunities for market manipulation • Update old computer systems • Improve on the efficient operation of the transmission system • Provide more accurate wholesale price signals to help stimulate appropriate

investment in California’s electricity supply These issues are being managed by these primary market design changes:

• Day-ahead energy market (absent from California since the collapse of the Power Exchange)

• Congestion Revenue Rights (transmission allocation based on feasibility of energy flows on the transmission system)

• Locational Marginal Pricing (pricing dictated by forecasted energy flows based on submitted schedules on the electrical system)

Energy Policy Act The Energy Policy Act of 2005 is the first comprehensive federal legislation on energy issues since the Energy Policy Act of 1992. The legislation covers all energy issues. The electricity sector issues that will impact PWP include the following:

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Renewable Energy The Energy Policy Act continues to provide incentives for private developers of renewable energy projects through the use of credits. This has allowed private corporations to propose to public power agencies renewal projects at a reduced cost. A Clean Renewable Energy Bond (CREB) program was also established for public power agencies. The CREB program was oversubscribed and the one project SCPPA submitted was not accepted. The CREB program has recently been extended by Congress and SCPPA will continue to attempt to receive this tax-free financing instrument.

Transmission Corridors The FERC can intervene in transmission projects if the projects are viable but cannot be resolved at the state level. The intention is to accelerate critical transmission projects that support electric reliability or renewable energy projects.

Long Term Transmission Rights (LTTR) Organized markets (like the market being created by CAISO’s MRTU) must provide a mechanism to offer long-term transmission rights to load serving entities (like PWP). These rights should extend for at least ten years and support long-term planning and secure transmission for long-term power purchases.

Liquefied Natural Gas (LNG) Federal intervention is allowed in the siting of liquefied natural gas terminals if a project is delayed by the state. This is a continuing effort to establish a secure supply of natural gas as the country attempts to remove its 50 percent dependence on coal generation.

Repeal of the Public Utility Holding Company Act The Public Utility Holding Company Act has dictated the structure of the U.S. power utility industry since 1935. The repeal of the act will facilitate mergers and acquisitions in the electric and gas utility industry by legalizing mergers and acquisitions that were previously restricted. This includes actions involving companies in different regions, non-contiguous and non-interconnected companies, non-utility ownership and foreign ownership. Theoretically, every utility is now a candidate for acquisition and, therefore, can be targeted by competitors. This may lead to some consolidation in the industry, with resulting effects on market and commodity pricing.

Electric Reliability Organization (ERO) In response to the August 2003 blackout of electricity in the midwest United States, the FERC created an ERO. The ERO will create new mandatory electric reliability standards similar to the current voluntary standards developed by the North American Electric Reliability Council (NERC). These new standards were issued in 2006 and go into effect June 2007.

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Public Utilities Regulatory Policy Act (PURPA) Changes Amendment of the Public Utilities Regulatory Policy Act would also impact PWP. Since 1978, PURPA has fostered competition in generation by requiring electric utilities to purchase power from Qualifying Facilities (QFs) at the utilities’ avoided cost.

Greenhouse Gas Legislation The State of California passed two laws in 2006 that went into effect January 1, 2007. These bills AB-32 and SB-1368 are the first laws to regulate greenhouse gases produced in conjunction with supplying electricity to customers in the state. This legislation is of particular importance to the city of Pasadena, since the utility procures approximately 65 percent of its power requirements from two coal-fired generation units. While all fossil fuel generation produces greenhouse gases, a coal-fired generator produces approximately twice as much greenhouse gas as a comparable natural gas fired generator. The federal government is also considering legislation to limit greenhouse gases. Approximately 50 percent of United States electricity needs are supplied by coal-fired generation. To change this supply mix will require a tremendous change in the electricity sector. These changes may occur, but the timeframe will be over several decades. PWP, in cooperation with other IPP participants, is pursuing greenhouse gas mitigation strategies. A brief discussion of clean coal technology is provided below.

Clean-Coal Technology The Energy Policy Act provides a new credit in the amount of $1.6 billion for investment in clean-coal facilities and integrated gasification combined-cycle plants. The act also provides grants and loan guarantees for some new coal-fired power plants, for the first few successful applicants, providing a strong impetus for the development of clean-coal facilities. The three key drivers for this change were: 1) a growing industry consensus that environmental regulations will tighten and eventually include carbon dioxide controls; 2) coal’s solid position in today’s fuel mix, with a vast supply; and 3) risk of increasing dependence on imported natural gas and associated volatile prices. Advanced technology is required to convert coal into cleaner burning gas, and this comes at higher cost. It is expected that the cost per MW of capacity will be 20 percent higher than a modern, conventional coal-burning plant. At the same time, integrated gasification combined-cycle plants can use cheaper, higher-sulfur coal because the technology gasifies coal.

Other Regulatory Considerations

Resource Adequacy Assembly Bill 380 (AB 380) required the city to adopt a planning reserve margin to have available excess generation for contingencies. The city has already adopted a planning

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reserve margin through the Integrated Resource Plan approved in 2001. PWP submits the following information to the CAISO on an annual basis, as well as with monthly updates:

• Named capacity to indicate a planning reserve of 17 percent for the entire year • Indication of 90 percent compliance for the five summer months a year in

advance • Indication of 100 percent compliance on a month-ahead basis for every month of

the year A component of the Market Redesign and Technology Upgrade project includes revisiting the Resource Adequacy requirements to include a local capacity component. This component is still being considered and will vary from year to year based on the changing configuration (i.e. additions to infrastructure and decommissioning of infrastructure) of the generation system and the transmission grid. Local generation is expected to be a requirement, and PWP is well positioned to meet this requirement.

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Section 8 – Market Forecast and Commodity Prices The electric power market is similar to other commodity markets (e.g. pork bellies, corn, crude oil and natural gas) in having standard products that are bought and sold amongst a group of interested market participants. Electric power does have the unique characteristic of having the actual generation of the product occur at the same time as the consumption. This means that electric power cannot be stored like other commodities; this results in very dynamic real-time fluctuations in power costs that are not seen in other commodity markets. On a forward basis, in future months and years, electric power is traded like other commodity futures, with many of the characteristics of other commodity future markets. Electric power is very seasonal and closely correlated with weather. Electric power is also closely correlated with natural gas prices, particularly in the west and northeast, where natural gas-fired power generation is highly favored over coal-fired power generation. Beyond weather impacts, electric power markets are influenced by long-term supply and demand within a trading region (e.g. the Western States). Generation and transmission planning, as well as population and industry trends, impacts pricing on a forward basis. As mentioned above, the price of the source of fuel required for generation, natural gas in California, greatly impacts the price of power. So the long term availability of natural gas, for example whether or not Liquefied Natural Gas is available on the west coast, will impact forward power prices. Finally the regulatory environment is also important to the forward price of power. A stable regulatory system with clear rules and procedures encourages capital investment since uncertainty is reduced. To the extent there is uncertainty in the regulatory system, there will be a risk adjusted capital investment premium that will have a tendency to reduce investment or increase the cost of investing in the electric power infrastructure. The regulatory rules for environmental impacts also greatly impact future prices of electricity. More stringent rules on emissions generally mean higher costs of electric power. For all of these reasons, PWP utilizes a variety of sources to forecast energy prices. One source is Global Energy Decisions’ fundamental market forecast, developed by an energy consulting and software company and published bi-annually. Global Energy evaluates all of the trends mentioned above and forecasts electric power prices for the next 20 years. In addition to Global Energy, PWP utilizes Platt’s Energy Prices, which are based on actual market transactions for future power. The amount of transactions that occur in years beyond the next three are limited (i.e. the market is not liquid), and therefore these price forecasts are more reliable for the current three-year timeframe. The remainder of this section discusses the current forecasts, as well as drivers that could impact these forecasts.

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Market Forecasts Natural gas, power and coal prices are forecast to remain high over the next few years, but show a trend of decreasing through approximately 2010. After that time, prices for these commodities are expected to gradually increase through the remainder of the 20-year time frame PWP is considering. Based on Platt’s forecast, the prices for power and gas in 2015 are $63.09 per MWh for on-peak power, $39.55 per MWh for off-peak power and $5.284 per MMbtu for natural gas. That is not to say that we will not see price volatility in the short term, resulting from individual events regionally and throughout the world. These events include wars, political unrest, natural disasters, weather patterns, storage levels, snow and precipitation levels, market perception of scarcity, transmission/transportation constraints and many other issues that have a dramatic impact on the spot market. These events generally have less impact on the forward market because, over time, the market will correct itself as a result of supply and demand. The impacts of Hurricane Katrina in 2005 are a good example of this point. Prior to Katrina’s destruction, the market experienced high volatility due to the threat of what might happen. After the hurricane’s destruction was felt, the market responded with a sharp increase in prices due to the damage and reduction in production capacity. Now that the recovery is well on its way, the market is correcting with a decline in prices. The Global Energy forecast and Platt’s forward curves, in addition to other sources, generally agree on a market trend of decreasing prices through 2010, stabilization for some time and gradual increases over the next 20 years. At the same time, there is some disagreement on where the actual prices will end up. The curves show the same patterns, but shift upward or downward based on the source.

Market Pricing Forecast Considerations The impacts of poor price forecasting can impact PWP in many ways. If price forecasts are too high, PWP could buy too much energy/gas at a price that is much higher than the actual market in an effort to hedge against the increase in the cost of power in the future. If the forecasts are too low, PWP could miss out on buying opportunities, waiting around for the forecasted lower cost power. Poor price forecasting could also lead to improper valuation of current and future assets and result in unfavorable decisions. For example, the plant value at a market price of $100 per MWh is very different than at $50 per MWh. If the price forecast is low, this might indicate that existing plants should be retired or sold. If the price forecast is high, this might indicate that PWP should build more generation. In short, any time the actuality is different from the forecasts, the situation could lead to an increase in rates for PWP customers.

Natural Gas Prices To forecast natural gas prices, Global Energy uses three forecasting horizons, outlined in the following table:

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Forecast Phase Period Length Data Source Forecast Technique

Futures Driven First 24 months

NYMEX Henry Hub futures and market differentials

Calculated Henry Hub and Liquid market center differentials

Mean Reversion Next 19 months Global Energy

Linear processes to gradually equate near-term to long-term trend

Long-term Trend

Remaining forecast period (to 2029)

Various Global Energy data sources

Fundamental supply and demand analysis using forecasting model

Natural gas prices are forecast to remain high for the next few years. Based on Global Energy’s fundamental analysis of supply and demand over the 2006-2010 period, prices are expected to decline, reaching a low of $4.54 per MMBtu in 2009 at Henry Hub (a standard trading hub used by the New York Mercantile Exchange – NYMEX) and staying within a range of $4.35 to $4.90 per MMBtu for the remainder of the forecast. From 2009 through 2029, Henry Hub prices gradually rise on average by about 0.40 percent annually in real dollars. Gas prices will continue to react to both regional and continental market forces, such as weather, seasonal hydro flows, nuclear plant availability, oil prices, underground storage levels, pipeline constraints and market perceptions of scarcity. Gas price volatility, owing to the above factors, is expected to remain -- and possibly increase -- as demand from electric generators grows over the coming years. Platt’s forward curves, shown below, yield the same pattern as Global Energy’s forecast, but at a higher level. Based on the actual trading, prices for gas and power show a decline from January 2006 through January 2012. From January 2012 through January 2020, the prices remain somewhat constant and then begin an upward trend through the remainder of the forecast (2026). Some of the factors contributing to the gradual increase in prices over the forecast horizon are: 1) increase in demand/consumption, 2) global competition for a limited resource (e.g. China and India), 3) retirement of cheaper coal and nuclear plants due to state and federal environmental requirements, 4) increasing construction of gas-fired plants, 5) growing dependency on fossil fuels for other purposes such as operating vehicles, 5) increasing governmental requirements for renewable energy, which is traditionally more costly, 6) increasing operating reserve requirements, and 7) the need to increase or upgrade transmission line capacity.

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Coal Prices Coal has been mined across many parts of North America since the mid eighteenth century. Early activity was stimulated by need for heating, cooking and small industrial enterprises. With the industrial revolution, demand for coal increased sharply. In the mid nineteenth century, primary metal smelting -- especially the manufacture of iron and steel -- became a major component of industrialized economies. Coal combustion for electricity generation did not become common until the proliferation of central generation stations in the first two decades of the twentieth century. In 2004, about 52 percent of electricity generation was with coal. Coal prices vary according to the source and quality of the coal and the cost of transportation to the power plant. Most delivered coal prices used to be below $1.50 per MMbtu but are now at higher levels and are forecast to remain so until 2010 before falling in real dollar terms. Thereafter, Global Energy expects coal prices in most basins will rise moderately in line with inflation and gas price escalation, offset by expected mining cost reductions over the remaining portion of the study period. Sources used by Global Energy to derive long-term coal prices include:

• The federal Energy Information Agency (EIA) 2004 Annual Energy Outlook (AEO) Report;

• Federal Energy Regulatory Commission’s (FERC) Form 423 database (1998-2002);

• The EIA’s 2001 Coal Market Module documentation; • Global Energy Intelligence Fuels Database; and • Numerous websites for individual generators, utilities, coal-mining companies,

long-term weather forecasting services, gas and coal trading companies, and rail companies.

Forward Curves Forward curves of power and natural gas are maintained by PWP and used for estimating future costs and valuing transactions. These charts are presented for general reference and are updated on a regular basis.

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Platt's: SoCal Gas 20 Yr Forward Curve

3.000

4.000

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Global Energy Decisions: 20 Yr Forward Curve for Gas SoCal Border

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Platt's: SP15 On Peak Power 20 Yr Forward Curve

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100110120130

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200

9

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Global: SP15 On Peak Power 20 Yr Forecast

30.0040.0050.0060.0070.0080.0090.00

100.00110.00120.00130.00

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Platt's: SP15 Off Peak Power 20 Yr Forward Curve

30405060708090

100110120130

Jan

2007

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200

9

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201

0

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013

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201

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8

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202

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Global: SP15 Off Peak Power 20 Yr Forecast

30405060708090

100110120130

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Global Energy Decisions: Coal Forward Curve Avg Cost Including All Basins

1.40

1.45

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Index

Other Factors Impacting Commodity Prices

Nuclear While the Energy Policy Act of 2005 included incentives for new nuclear power, it remains an open question whether any viable nuclear power project will break ground before the end of the decade, given the extensive application process with federal and state regulators and uncertainties over financing. Without a nuclear power plant having been built in the United States for over 20 years, and given the more competitive business landscape, the cost of constructing a new reactor is a significant uncertainty. For this reason, we do not predict any effects on commodity prices over the next two decades particularly in the western region of the United States.

Renewable Energy The federal renewable purchase mandate is likely to promote establishing a national renewable energy credit market. A Renewable Portfolio Standard would increase the cost of power generation by requiring generators to either generate renewable energy, which is generally more costly than fossil-fueled generation, or to purchase credits from other parties that generate renewable energy. At the same time, as discussed in previous sections, renewable energy faces a number of technological and financial challenges before it becomes a truly viable option. We feel that the economic reality is that the future fuel mix for power generation will not change drastically over the next 20 years.

Liquefied Natural Gas (LNG) Liquefied Natural Gas (LNG) is a process to convert natural gas from its gaseous state to a liquid. This greatly reduces the volume and allows for transportation across international waters. The liquefied natural gas is then deposited at a terminal and

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converted back (by heating) to its gaseous state and injected in the local country’s natural gas pipeline system. Since 1995, U.S. marine liquefied natural gas imports have grown from 18 Bcf to 630 Bcf in 2004. The expected increase in gas consumption for electric generation and growth in other end-use sectors, along with an upward shift in natural gas prices, has fueled a renewed interest in developing liquid natural gas and other non-conventional resources (coal bed methane and frontier gas supply basins). At current market prices, and in Global Energy’s long-term gas price forecast, all of these supply sources are likely to be economic on a full-cycle basis. The Energy Policy Act strengthens the authority of FERC over liquified natural gas. Title 3B grants FERC “The executive authority to approve or deny any application for the siting, construction, expansion or operation of a liquified natural gas terminal” to import or process liquified natural gas. The Energy Policy Act promotes liquified natural gas development, over-riding state and local authority to block it. As of September 2005, 17 proposed liquid natural gas import terminals with a peak send-out capacity of 21.34 Bcf/d have been approved for construction by authorities in Canada, the Unites States and Mexico. In total, 21 new liquid natural gas terminals have been proposed and an additional 19 potential sites have been identified. It is not certain that all will be built, and to the timeline indicated. Moreover, there is nowhere near enough liquefaction capacity to support this growth. The key element limiting liquid natural gas supply to the United States is a worldwide deficit of liquefaction growth specifically dedicated to the U.S. market. By 2011, projections indicate that only about 6 Bcf/d of dedicated liquefaction capacity will be available to the U.S.

Section 9 – Local Generation Considerations Several factors point to a need for improvements to the existing power plant to extend its life. Pasadena continues to have a single transmission interconnection point with an import constraint of 215 MW. During the peak summer months, this 215 MW constraint is exceeded on a daily basis and local generation must be operational. Secondly, there will be new local capacity - resource adequacy (RA) – requirements that are estimated to be approximately 40 percent of peak load, or approximately 120 MW. Thirdly, maintaining local generation provides some independence from high market prices. To the extent the high prices are not directly correlated to natural gas - for example the cause was a transmission constraint - Pasadena’s local generation provides an independent source of power for the city. Finally, local generation provides more reliability to PWP’s customers. Following is a description of PWP’s current generating units: Unit Name Unit Type Fuel In Service Capacity Broadway 3 (B3) Steam Natural Gas 1965 65 MW Glenarm 1 (GT1) Gas Turbine Natural Gas 1975 22 MW Glenarm 2 (GT2) Gas Turbine Natural Gas 1975 22 MW Glenarm 3 (GT3) Gas Turbine Natural Gas 2003 45 MW Glenarm 4 (GT4) Gas Turbine Natural Gas 2003 45 MW While GT-3 and GT-4 were installed in 2003 as part of an $82 million project to re-power the Glenarm Plant, the facility needs additional attention. Over 50 percent (109 MW) of the generation units (GT-1, GT-2 and B-3) are now more than 40 years old and nearing the end of their useful lives, with diminished thermal and operating efficiency, a greater need for frequent maintenance and emissions ratings that are less than optimal. At the same time, advances in generation efficiency have greatly increased over these four decades. For this reason, these older units are used only for reliability purposes and system emergencies. As an example, the B-3 unit is a base load plant with an efficiency rating of 12 (MMBtu/MWh). Newer technology, such as a combined-cycle plant, would have an efficiency rating of approximately 7. This means that for each volume of natural gas burned, there would be a (12 – 7) / 12 = 40 percent savings. If natural gas is priced at $10 per MMBtu, this means the difference between paying $120 per MWh as opposed to $70 per MWh. For a single hour on a summer day, an average amount of energy consumed is 250 MW. If the entire 250 MW were supplied by modern natural gas generation versus units like Broadway 3, this would translate into a savings of 250 MWh * ($120 - $70) = $12,500 for a single hour. It is clear from this example that there are significant benefits to burning natural gas efficiently. At the same time, there are many factors that have interfered in the development of new generating facilities in the State of California. As the California Energy Commission points out in the 2005 Integrated Energy Policy Report, there are “over 7,000 MW of

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permitted power plants that have not moved into construction”1. Independent Power Producers (IPP) have been unable to sign long-term contracts with investor-owned utilities. These utilities do not feel they can sign long-term contracts until direct access is resolved (i.e. eliminated forever). The IPPs cannot receive funding from investment banks until long-term contracts are signed guaranteeing investment recovery. This Catch-22 results in a stalemate in new construction. Without a resolution, and with continuing power demand in California, there will be increased upward pressure on prices that are already at a very high level. This regulatory uncertainty may be resolved, but the timeframe is unknown. In the meantime, Pasadena must continue to ensure reliable and economic generation for its service area. Pasadena has a stable base of customers and a long-term outlook for reliable supply. The competitive market and California regulators are working to correct the current uncertainty. Based on past energy policy in the state, there is good possibility that these issues will not work themselves out in the near or mid-term.

Fossil Fuel Generation Technology and Local Generation Options After thorough consideration of issues described in Section 4, PWP has determined that it is important to maintain at least 230 MW of local generation capacity on the west end of Pasadena. In meeting this goal, we must strive for the most cost-effective, reliable and environmentally friendly option available, ensuring the lowest possible rates, most reliable service for customers and least impact on Pasadena’s environment and quality of life. To determine the most viable options, many practical factors were considered, including system requirements and efficiency rates, available technology, risk factors, environmental issues and financing.

System Requirements and Efficiency Rates The traditional unit of measure for power generating plant efficiency is heat rate, which is defined as the amount of fuel in Btu required for each kilowatt-hour generated. When this heat rate is used to divide the actual 3,413 Btu per KWhr and multiplied by 100, the result will be the efficiency of the plant in percentage. New combined-cycle units have heat rate of about 7,000 Btu/KWhr, while heat rate of gas-fired steam plants varies considerably from about 9,000 to 12,000 Btu/KWhr when run at their rated capacity. In comparison, the city’s 30 MW GT-1 and 30 MW GT-2 simple-cycle gas turbines both have heat rates of 14,000 Btu/KWhr, and the 70 MW B-3 gas-fired steam unit has a heat rate of 13,000 Btu/KWhr. To meet the city’s needs, any new system assets must offer the following characteristics:

• The ability to start up from shutdown conditions and reach full plant output in less than 10 minutes. Preferably these assets would be inputting power into

1 2005 Integrated Energy Policy Report, pg. 32.

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the grid almost immediately after a CAISO signal requests power (what is called a non-spinning reserve);

• The ability to operate at a low minimum plant output reliably, and then modulate between this minimum load and full-rated plant output in a stable manner with repeated cycles over this load range (what is called spinning reserve);

• The ability to modulate from minimum to maximum load with a rapid rate of change, to provide system frequency control on demand surges (up regulation/frequency response);

• The ability to modulate from high plant output to minimum load with a rapid rate of change, to provide system frequency control on sudden demand reductions (down regulation/frequency response);

• The ability to provide voltage support, by being located at the end of transmission systems, in areas of transmission congestion and by having quicker response time than other technologies;

• The ability to start up if the grid fails, synchronize in an islanded mode and then provide power to restore the grid (black start);

While better meeting the city’s need for reliable power, these features would allow PWP to take advantage of revenue to be generated by meeting ancillary service needs, an important consideration in the selection of new generating units.

Available Options Several technological options that meet both city load and ancillary service needs are available for the existing Glenarm/Broadway plant. Following is a discussion of these options. Heat Recovery Steam Generators The simple cycle 47 MW GT-3 and 47 MW GT-4 gas turbines may be upgraded to combined-cycle operation to further improve their efficiency by incorporating either horizontal or vertical heat recovery steam generators. PWP has determined that either GT-3 or GT-4 can be retrofitted with a heat recovery steam generator to gain an additional 12 MW per unit. As an alternative, the 70 MW B-3 unit may be a candidate for a combined-cycle repowering that will lead to substantial increase in generating capacity and efficiency. Combined-cycle power plants using gas turbines have become a very popular power production options. Gas turbines and heat recovery steam generators offer a low initial capital cost - $500,000 per MW installed for natural gas-fired combined-cycle compared to $1.3 million to $1.4 million per MW for a typical fossil fuel boiler project. They also offer relatively short equipment delivery time, short construction times and minimal environmental problems. As in other repowering projects, there is a possibility the existing steam turbine capacity may be matched with commercially available heat recovery steam generators and gas turbines. An article in Gas Turbine World claimed that EPRI has a software program that will provide all of the conceptual design information

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needed at a detailed level sufficient for planning studies, technology selection and configuration decisions. Heat recovery steam generators, along with steam turbines, are essential parts of a combined-cycle system, and their designs have become increasingly complex over the last 10 years. Today’s models typically have three pressure levels with superheat and reheat capabilities; they may be drum, once-through or combined drum/once-through systems. Moreover, numerous variations are available within these basic designs, and many plants that were designed for base load operation are now cycling. It is very common for the heat recovery steam generators to be exposed to fast changing operating conditions, and this is a risk factor. These conditions put extra strain on the unit, affecting life expectancy. The increasing levels of technical and operational complexity have been accompanied by pervasive failures and operating problems, many of which are influenced by cycle chemistry and the thermal transients associated with shutdown and start up. In the event combined-cycle turbines are approved for Pasadena, the anticipated worst case cycling scenario must be clearly considered in the procurement of the heat recovery steam generator. Simple Cycle Gas Turbines Potential gas turbines in the range of 50-100 MW capacity that can replace the less efficient units GT-1, GT-2, and B-3 individually or in combination are:

GE Energy LM6000PC Sprint Alstom GT8C2 Output at terminals

50 MW Output at terminals

56 MW

Efficiency 40.5% Efficiency 33.8% Heat Rate 8,434

Btu/KWhr Heat Rate 10,080

Btu/KWhr Rolls-Royce Trent 60 DLE Pratt & Whitney Twin FT8 Plus

Output at terminals

58 MW Output at terminals

56 MW

Efficiency 40.9% Efficiency 38.6% Heat Rate 8,335

Btu/KWhr Heat Rate 8,840

Btu/KWhr Siemens Power Generation SGT-800 GE Energy LMS100PA, Water Injection

Output at terminals

45 MW Output at terminals

103 MW

Efficiency 37% Efficiency 47.6% Heat Rate 9,222

Btu/Kwhr Heat Rate 7,170

Btu/KWhr With a simple-cycle combustion turbine, the generator can be turned on and off at will, and can be synchronized to the system completely within 10 minutes.

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Combined-Cycle Gas Turbines Assuming GT-1, GT-2, and B-3 will be replaced, the ideal unit size that can be installed at the Broadway site is 100 to 150 MW, not to exceed 180 MW. Assuming participation from other public power agencies, extra capacity may be an estimated 30 MW maximum. Potential combined-cycle units that can replace the less efficient units GT-1, GT-2, and B-3 include:

Model Net Plant Output

Heat Rate, (Btu/kWh)

Net Plant Efficiency

Gas Turbine Power

Steam Turbine Power

Number and Type of Gas turbine

GE LM 6000 PC Sprint 62.4

MW 6,769 50 % 49.9 MW

12.5 MW

1 x LM6000 PC

Rolls-Royce Trent 60 WLE

72.1 MW 6,801 50.2 % 58

MW 14 MW 1 x Trent

Rolls-Royce Trent 60 DLE

64 MW 6,427 53.1 % 50 MW

14 MW 1 x Trent

Siemens CCX100-1

63.9 MW 6,440 53% 44.1

MW 20.5 MW

1 x SGT800

Pratt & Whitney FT8-3 Twin Pac

74.2 MW 6,655 51.3% 54.8

MW 20.6 MW 2 x FT8-3

LMS 100 120 MW 6,320 54% 100

MW 20 MW

1 x LMS 100

With a combined-cycle system, exhaust heat from the combustion turbines is used to heat a steam boiler; this steam is then used to turn a generator. This configuration allows for an additional generator capacity, compared to a simple-cycle system, while increasing the efficiency by lowering the heat rate. The drawback to this option is that the combined-cycle heat recovery steam generator constrains the operation of the unit somewhat. With the combined-cycle configuration, the unit can be turned on and off, but not as easily as a simple-cycle turbine. This requires additional start-up time and fuel, so the turbine is usually left on as much as possible. During off-peak hours, a combined-cycle turbine will generally generate power at a cost higher than that of imported energy purchased during that time of the day. As a result, Pasadena will be tied to using more expensive energy during off-peak hours. One benefit is that, provided the plant’s existing water treatment facility is sufficient to support the needs of the new generating unit(s), a Zero Liquid Discharge system will not be required in the permit.

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Notes: Heat Rates are on gas and based on Lower Heating Value. Ratings are based on ISO conditions of 59 oF and at sea level. Coal-Based Fuel It also may be worth mentioning the latest development on coal-based fuel, even though there is no application for this type of technology at the city’s power plant. The integrated gasification combined-cycle turbine is considered to be the clean-coal technology choice of the future for its superior environmental performance in removing air pollutants (such as carbon monoxide, nitrogen oxides, sulfur dioxides, mercury, particulates, etc.) associated with coal burning. However, it is widely accepted in the industry and government that the capital cost of a coal-based integrated gasification combined-cycle plant is about 10 to 15 percent higher than a comparable sized pulverized coal steam plant that costs about $1,500,000 per MW. To offset the cost disadvantage and accelerate development and commercialization, governments offer substantial financial incentives for utilities and developers. There is nothing made public yet on a proposed integrated gasification combined-cycle plant design, and it is expected that new plants will not be ready before 2010.

Practical Constraints The following space, building and staffing constraints must also be considered with construction of any new generating units.

• Since 1998, the city has held a 10-year lease, with a five-year option to renew, on the 1.4-acre Jacobs Engineering parking lot, located north of the Broadway Plant. At least half of this area must be reacquired for the construction of any new generating unit(s).

• Assuming an additional 185 MW capacity installed on the Broadway site and the

Jacobs parking lot, we have assumed that 0.3 acres will be needed for operations, 0.4 acres will be needed for maintenance and 0.3 acres will be needed for water treating, for a total of one acre. The allowance for a Zero Liquid Discharge system is 0.5 acre, and allowance for unusable space due to the irregular shape of the Broadway site is 25 percent. (This space can be used as a construction and laydown area.)

• There is a possibility that the city of South Pasadena may impose severe

restriction on truck traffic during demolition and construction. Opening of the rail crossing on State Street may not materialize. It is important to begin a dialogue with the city of South Pasadena to minimize traffic and delivery concerns before the city begins any project.

• Existing plant personnel will be displaced by any demolition or major

construction work at the Broadway site.

• Natural gas supply and delivery using existing gas house metering may not be adequate. A detailed study must be conducted by the Southern California Gas

57

Company to evaluate the feasibility of an additional gas supply for the new generating units.

• Staffing dedicated to any new projects must be formed once the 2007 Integrated

Resource Plan is approved. For scheduling purposes, it will take about two years to install a combined -cycle unit from the time of issuing the Notice to Proceed. An Environmental Impact Report must be in placed before any demolition can start at the Broadway Plant.

Risk Factor Assessment

Mode of Operation Risk As discussed previously, the GT-1 and GT-2 gas turbines are of 1974 vintage, and the B-3 gas fired steam plant went into commercial operation in 1967. All three units are paid for, but are inefficient and have few more years of remaining useful life. Operating a new combined-cycle plant with a heat rate of 7,000 Btu/KWhr versus the old B-3 unit would result in a saving of 6,000 Btu/KWhr, or an approximate 46 percent reduction in fuel consumption. The savings will be even more in the case of GT-1 and GT-2. Setting aside the reliability issue, if the existing plant’s future mode of operation will be the same as in the past few years, it may be difficult to recover the capital investment, or it may take a very long time. It would be beneficial to run new units more hours and operate as close as possible to base load operation in order to take advantage of the reduced fuel usage -- especially when price of natural gas fuel is high. If the price of natural gas drops, the units would be required to run even more. When the new unit is subjected to more operating hours at high efficient loads, the loading on GT-3 and/or GT-4 may diminish and consequently cause an increase in heat rate.

Impact of Changing Environmental Policies on Carbon Dioxide Emissions The possibility of new and changing environmental policies is a potential risk inherent in the installation of new power generating units. The costs of new programs to regulate carbon emissions or require the development of renewable energy are potentially high. If carbon dioxide controls are imposed on utilities, they almost certainly would take the form of a cap-and trade-program, which is a market-oriented approach to achieve a specified level of emission reductions at the lowest possible cost. If the emission cap is lowered, the cost to generators will be high due to the need to either reduce emission further or purchase additional allowances from other parties that achieved emission reductions less expensively.

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Section 10 – Production Cost Modeling A product cost model has been developed to determine the cost of serving customers over the 20-year study period. The model is built using existing resources and energy efficiency assumptions to develop what is referred to as the base case scenario. This base case is then adjusted with resource options and energy efficiency assumptions. These options are then applied to a series of price and regulatory scenarios to understand the impacts on overall costs for each portfolio and each scenario. Once these costs are established, a decision can be made on which portfolio of resources best serves the load obligations of the city when electric reliability, price stability, low cost, and minimized negative environmental impacts are considered.

Portfolio of Resources Taking all available information into consideration, PWP engineers developed seven portfolios, or options. For this process, PWP consulted with Global Energy Decisions, a leading provider of integrated software, data and consulting for the energy industry. Working with Global Energy during the summer of 2006, PWP’s engineers completed a thorough modeling process that considered possible options. While some options, such as nuclear power, were easily omitted from consideration, others received more rigorous study. While each portfolio option has a cost, the savings or revenue generated by each portfolio is considered when examining the price and regulatory scenarios. Portfolio 1 – Base Case The base case is to maintain the resource portfolio that PWP currently owns and operates. For local generation this requires extending the expected life of the three oldest existing generating units, GT-1, GT-2 and B-3 (approximately 110MW of generation capacity). Without the life extension, these three units would be decommissioned at some point in the study period. The base case assumes that the Intermountain Power Plant, Hoover Power Plant, Palo Verde Nuclear Generating Station, and Magnolia Power Plant would all be maintained through the study period at their current output. The base case also assumes the Renewable Portfolio Standard (RPS) set by the city council in 2003 would be achieved and that renewable energy, including Hoover, would supply 10 percent of the load by 2010 and 20 percent by 2017. The estimated cost to maintain the existing portfolio is $59.9 million. These costs are primarily associated with capital improvement projects to extend life of the current local generation. These projects would include full renovation and emission control retrofits to keep the three older units operational for an additional 30 years. Portfolio 2 – Simple Cycle This portfolio calls for the installation of two LM6000 simple-cycle combustion turbines at the existing power plant, at an estimated cost $106.5 million. Each unit would produce 45 MW, for a total addition of 90 MW. The equipment is identical to the existing GT-3 and GT-4 units, which would bring greater efficiency from identical parts and maintenance schedules. This maintains a consistent set of peaking units and replaces a large majority of the 110 MW capacity from the older units.

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Portfolio 3 – Combined Cycle Portfolio 3 calls for the installation of two LM6000 combined-cycle combustion turbines, as opposed to simple-cycle turbines. The cost of this installation is estimated to be $131.8 million. This replaces one-for-one the current 110 MW that is at risk of becoming inoperable over time. The LM6000 technology would remain the single standard for the combustion units, and the heat recovery steam generator would be in compliance with the Emission Performance Standard (EPS) set by SB 1368. This would allow the flexibility to operate the natural gas plant as a base load resource if the Intermountain Power Plant were no longer in the portfolio due to a very high carbon tax. The installation of the heat recovery steam generator does increase the overall complexity of the project versus a simple cycle solution. Portfolio 4 – State-of-Art Combined Cycle Portfolio 4 includes the installation of an LMS100 combined-cycle combustion turbine, a model that works with the same type of components as the LM6000 CC unit, but on a larger scale. Total output is estimated to be 130 MW, with a purchase-and-installation cost of $131.4 million. This would introduce new technology at the plant beyond the LM6000 and increase the risk of running one large unit versus two smaller units. In the event of a forced outage, the plant would lose 130 MW of generation compared to 65 MW. (“Forced outages” are unexpected shutdowns of a generating unit or transmission line). To circumvent this potential problem, PWP could build an LMS100 CC plant in conjunction with another entity. Other municipalities in the Southern California area are considering an LMS100 CC installation. An agreement with one or more other entities would reduce the impact of a unit failure, since all entities would share the pool of resources. For example, PWP would enter into a contract with another municipality and two LMS100 CC plants would be developed. Depending on the needs of each utility, zero, one, or both plants would be running at any given time. Each utility would have access to both plants and share the capacity of both plants equally. If an LMS100 generating plant had a forced outage, the other plant would still be available. Rather than suffering the loss of 100 percent of a single plant, PWP would only be at risk of 50 percent of the capacity not being available. This arrangement would offer greater flexibility and benefit both utilities, as the units could be operated as a pool. In addition to minimizing service disruptions and gaining operational efficiencies, this partnership allows for joint inventory, consolidated training and operational knowledge sharing. Portfolio 5 – Internal Combustion (IC) Generation Portfolio 5 involves installing a 128 MW IC Power Plant. Several technology firms are now converting internal combustion engines from ocean liners into generating stations, running on natural gas. These engines have proven to be efficient and reliable, operating

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at a steady level for hours or days on end. For this plan, PWP analyzed equipment from one such company, Wartsila Corp., which proposed a system of eight 16 MW engines for a total output of 128 MW. The plant’s heat rate would be competitive with the plant’s existing combined-cycle combustion turbines (GT-3 and GT-4). Installation costs were estimated to be $111.7 million. The space requirements for this configuration may not work since the Broadway site does not have a standard generation footprint. Space constraints notwithstanding, this option carried many advantages. For one, each engine can be run independently, and can be started and synchronized with the system in less than 10 minutes. This means that the plant could be run with an output range of anywhere from10 MW to 128 MW. Most other types of equipment, as those listed in Portfolios 1 through 4, typically offer a range of operation of 50 to 100 percent. This means that the minimum output for the LMS100 CC would be 65 MW; at this level, the turbine may still be generating more power than is necessary, and is much less efficient, as explained in Portfolio 4. In contrast, the internal combustion plant would offer greater efficiency, cost savings and flexibility. In addition, this configuration would provide better reliability. Because each engine can be run independently, a mechanical breakdown would only result in a loss of 16 MW, or 12 percent of the plant’s capacity. By comparison, a shutdown of the LMS6000 would result in a loss of 65 MW, while a loss of the LMS100 turbine would result in a 130 MW outage. Another benefit is that this option utilizes technology that is tried and true, relying literally on common boat engines. Finally, without large cooling towers, the completed internal combustion plant would be contained in one building resembling a large warehouse or factory, with noise levels said to be lower than a traditional power plant. Portfolio 6 – Green Portfolio 6 calls on Pasadena to adopt a more aggressive stance in procuring renewable resources, or “green power.” As discussed previously, Pasadena currently has a Renewable Portfolio Standard, adopted by the city council, which requires PWP to meet 10 percent of the city’s energy load with renewable resources by the year 2010, and 20 percent by the year 2017. By securing several long-term contracts in recent years with wind, landfill gas-to-energy and geothermal plants throughout California, in addition to hydroelectric power from Azusa and Hoover Dam, PWP is on target to meet the city’s current goals. More than 1,000 customers currently participate in PWP’s green power program, and our utility continues to aggressively promote environmental stewardship through a host of initiatives. Pursuing a more aggressive renewable portfolio takes time, as PWP’s service area is limited and there are few renewable options available within the service area. This means that any new renewable resources will have to be imported into the city from the transmission grid. However, as discussed previously, Pasadena is still limited by an

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import constraint of 215MW at Pasadena’s TM Goodrich receiving station and therefore limited in how much energy it can import. Other drawbacks remain, as discussed previously. Although it would be ideal to rely solely on renewable energy sources, in 2007 they are not reliable enough to guarantee a continued source of power for PWP’s 60,000 customers. For example, while solar energy is considered to be one of the best renewable energy sources available, it is only available during the day, more so in the summer under clear skies. Likewise wind power, by definition, relies on wind, which is a very erratic resource. PWP is fortunate to have entered into a contract for wind power in which the vendor guarantees 2 MW per hour round-the-clock; the vendor stores then distributes the power. However, arrangements like this are rare and very difficult to secure. Other options, including geothermal and wave motion plants, are in development, but all have technical issues that must first be overcome. Quite simply, power generation and storage technology must improve before renewable resources can be relied upon to meet the needs of entire communities. While continuing to procure more renewable resources, and reining in citywide energy use with demand-side management and energy efficiency programs, PWP would nevertheless have to increase generation at its existing power plant to meet basic customer need as well as reserve requirements. Therefore this portfolio assumes that the local generation upgrade of older units is undertaken (using Portfolio 4) but increases the RPS to 15 percent by 2010, while still counting Hoover Power Plant, and then keeping the 20 percent goal by 2017 but excluding Hoover Power Plant. This essentially is similar to raising the 20 percent goal to 25 percent under the city’s current definition of renewable energy.

Scenarios To thoroughly analyze costs, benefits and feasibility, each of the portfolios listed above was subjected to five scenarios. Because all of the generators proposed in this plan are fired by natural gas, these scenarios tested the effects of five different natural gas market conditions on operating costs, including:

1. Fundamental Analysis Gas Forecast: a 20-year marketing forecast provided by Global Energy Decisions;

2. Market Based Gas Forecast: a forecast prepared by PWP engineers based on current gas prices, presenting a more conservative view of the market than the base case scenario;

3. High Gas Market: predicting how a 20 percent increase in natural gas prices would affect operating costs;

4. High Gas with Carbon Tax: a forecast that includes a 20 percent increase in natural gas prices plus a $10 dollar per ton of carbon dioxide (C02) “carbon tax” on all generation. This tax, which has been proposed to help curtail global warming, would particularly impact coal-fired plants like IPP, since a coal fired plant generally emits twice the CO2 as does a natural gas-fired plant.

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5. Spot Market Effects: PWP’s net generation operating costs correspond directly with its ability to sell surplus power on the spot market. For this scenario, we eliminated the benefit of these sales from scenario 2 (Pasadena Case Market) to determine the “true” operating costs of each portfolio.

Modeling Process To determine the best possible options for Pasadena’s power supply future, PWP engineers developed a model that included projected load growth over the next 20 years, anticipated effects of conservation, current generation capacity and long-term contracts. To begin the modeling process, Global Energy Decisions ran “Production Cost Models” for Portfolios 1 through 5, using a proprietary planning and risk modeling tool. Step by step, the software program created models combining PWP’s load projection and current resource mix with ONE of the portfolios under ONE of the scenarios. For example, Model 4A examined PWP’s current load and system plus the LMS100 CC unit (Portfolio 4), run under the Base Case Gas Market scenario (Scenario A). The program then tested each portfolio to see how it performed under various conditions, such as an exceptionally warm or dry year, or other changes in the load projection. The results provided likely projected annual costs for each portfolio under each scenario, for a total of 30 combinations (See Graphs 1 through 5 below). Results were then thoroughly analyzed by the consultant and PWP’s engineers to determine which portfolio was most effective under most conditions.

Analysis of Results Figures 1 through 4 graphically compare the annual cost of each portfolio under each scenario. As can be seen, Portfolio 4, installation of the LMS100 combined-cycle turbine, provides the lowest generation costs for every tested scenario, under all foreseeable market conditions.

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Annual Cost ComparisonAll Portfolios Base Case (GED Gas Forecast)

$30,000

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 1

Ann

ual C

ost (

X)1,

000)

)

As-IsLM6000 Simple CycleLM6000 Combined CycleLMS100 Combined CycleWartsilaAggressive RPS (+LMS CC)

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Annual Cost ComparisonAll Portfolios Normal Gas Market

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 2

Ann

ual C

ost

As-IsLM6000 Simple CycleLM6000 Combined CycleLMS100 Combined CycleWartsilaAggressive RPS (+LMS CC)

Annual Cost ComparisonAll Portfolios High Gas Market

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 3

Ann

ual C

ost

As-IsLM6000 Simple CycleLM6000 Combined CycleLMS100 Combined CycleWartsilaAggressive RPS (+LMS CC)

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Annual Cost Comparison All Portfolios High Gas Market With CO2 Tax

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

$110,000

$120,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 4

Ann

ual C

ost

As-IsLM6000 Simple CycleLM6000 Combined CycleLMS100 Combined CycleWartsilaAggressive RPS (+LMS CC)

It should be noted that all four gas price scenarios include, and rely on, spot market sales of excess energy. In order to examine the effects and benefits of being able to sell excess energy, PWP also performed an analysis of the six portfolios in which spot market sales were eliminated, scenario 5. Figure 5, is the resulting model run that shows that eliminating the benefits of spot-market sales affects all portfolios. For those portfolios with the less efficient units (Portfolio 1, As-Is), the benefits of excess energy sales are minimal and therefore the resultant model had the least effect.

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Annual Cost ComparisonAll Portfolios Normal Gas Market No Sales of Excess Capacity

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 5

Ann

ual C

ost

As-IsLM6000 Simple CycleLM6000 Combined CycleLMS100 Combined CycleWartsilaAggressive RPS (+LMS CC)

For those portfolios with the most efficient units, the loss of sales had a large effect on annual costs. As a result, eliminating spot market sales tightened up the spread in annual cost estimates. However, the LMS100 CC is still less expensive in the long term, by a small margin, than the other five portfolios. In spite of its higher capital cost ($131 million for a new installation vs. a $60 million plant upgrade), installing the LMS100 CC is still favorable to upgrading the current generators. However, in reality there will be excess energy sales; therefore, the cost of service of the LMS100CC portfolio should still be below the cost of the As-Is portfolio. While Figures 1 through 5 effectively justify installing an LMS100 CC unit, the next question is volatility of Portfolio 4 with the LMS100 CC unit. Figure 6 displays the possible spread of costs between the normal case (Scenario 2) and worst case (Scenario 4). By maintaining a budget based on Scenario 2, PWP can weather shortages caused by anomalies in the natural gas market.

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Annual Cost ComparisonAs-Is vs. LMS100CC with vs. without Excess Energy Sales

$35,000

$45,000

$55,000

$65,000

$75,000

$85,000

$95,000

$105,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar YearFigure 6

Ann

ual C

ost (

X 1,

000)

)

LMS100 Combined Cycle w/o Excess Energy Sales

As-Is w/o Excess Energy Sales

As-Is

LMS100 Combined Cycle

Because it is safe to assume that spot market sales will occur, we can look at what the volatility of the market will do to the LMS100CC portfolio. Figure 7 compares the LMS100CC portfolio under the various scenarios. First, ignoring the two extreme scenarios (Scenario 5-no Spot Market Sales and Scenario 4- CO2 tax) for a moment, we can see that the risk due to volatility is relatively small. The differences in costs annually vary by approximately $5 million, or about 5 percent.

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Annual Cost ComparisonLMS100 Combined Cycle Portfolio under Different Scenarios

$35,000

$45,000

$55,000

$65,000

$75,000

$85,000

$95,000

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

Calendar Year Figure 7

Ann

ual C

ost (

X 1,

000)

Base Case (GED Gas Market Forecast)Normal Case (PWP Gas Market Forecast)High Gas Market CaseHigh Gas Market Case +CO2 TaxNormal Case (PWP Gas Market Forecast) w/o Excess Energy Sales

As discussed above, Scenario 5, No Spot Market sales, is not a reasonable scenario and was included only to attempt to isolate the effect of market sales on costs. It was included in this particular figure just for sake of comparison and thoroughness. On the other hand, a carbon tax is a very real possibility in the future. However, the additional cost of the tax would affect all proposed portfolios in a similar manner, since its biggest hit will be on PWP’s IPP entitlement share. This figure is a good reminder that future resource plans will have to include possible coal generation mitigation plans.

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Summary of Results Each of the portfolios is compared to the base case to evaluate the optimal portfolio decision. The chart below summarizes the comparisons to the base case and indicates the net present values (NPV) for the portfolio. This NPV accounts for cost, savings and revenue generated, for the six portfolios under the four reasonable scenarios:

Net Present Value of Each Portfolio by Scenario (in $1,000) Portfolio Fundamental

Price Analysis Market Price Analysis

High Gas Price High Gas Price and Carbon Tax

Base Case 0 0 0 0Simple Cycle -7,453 24,034 36,103 36,301LM6000 CC 26,724 97,042 123,582 128,344LMS100 CC 57,229 142,992 178,664 185,129IC -4,642 31,786 46,766 47,465Green w/LMS100CC

34,677 66,233 81,928

85,352

While the LMS100 Combined Cycle option is the most economical approach to meeting PWP’s resource needs into the future, in order to maintain and promote the City’s commitment to protect the environment, PWP recommends the Green approach that increases the RPS while also improving the local generation efficiency.

Section 11 - Recommendations The recommendations from this analysis include the following:

1. Re-power approximately 110 MW of local generation to replace aging units GT-1, GT-2 and B-3;

2. Increase the RPS goal from 10 percent to 15 percent by 2010 and remove the counting of Hoover Power Plant in 2017 while maintaining the 20 percent goal;

3. Increase funding of energy efficiency and continue to decrease the peak demand and overall consumption of electric power in the city of Pasadena;

4. Continue investigating alternatives to the Intermountain Power Project through divestiture or carbon removal strategies.

Local Generation Re-Powering This resource plan recommends re-powering the 110 MW of generation capacity that is over 40 years old (GT-1, GT-2, and B-3) with natural gas combined cycle technology. The primary advantages of this recommendation include:

1. Maintains local generation to meet resource adequacy and local reliability requirements;

2. Provides a generation resource below market prices for the majority of the year; 3. Provides a base load resource (complies with SB-1368 EPS) if current coal base

load resource becomes uneconomical or undesirable; 4. Decreases plant emissions per unit of power produced; 5. Enables compliance with AB-32; 6. Decreases reliance on external transmission; and 7. Enables other uses for the Glenarm facility.

This is a significant undertaking by PWP and significant planning is required to provide details for the implementation plan. Major activities associated with the execution of this plan include the following:

• Development of new facility to house plant operations, maintenance, and engineering;

• Reconfiguration of B-3 to allow the generating unit to operate independently of the decommissioned units B-1 and B-2 auxiliary equipment and power source;

• Demolition of decommissioned units B-1 and B-2 and removal of hazardous material (asbestos and lead);

• Preparation of site for new construction; • Construction and commercial operation of new generation; and • Decommissioning and demolition of GT-1, GT-2, and B-3.

A series of tasks is required to support these activities. These tasks will be brought to the city council for review and approval over the coming years.

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Renewal Portfolio Standard PWP has had very good success with contracting for renewable resources since the adoption of the RPS in 2003. PWP’s existing contract for wind requires the provider to manage the variability of the wind, and the contracted price is attractive in the current market. The geothermal resource in the Imperial Valley has been providing a steady supply of power to PWP customers. The recent contract for landfill gas-generated energy has increased the renewable portfolio by 80 percent. The landfill gas generation will exceed our Hoover hydroelectric resource, which historically has been the largest contributor to PWP’s renewable portfolio. PWP believes it is realistic to increase the RPS goal by 50 percent from 10 percent to 15 percent renewable supply to meet total customer demand by 2010. By 2017, PWP believes the utility can exclude the Hoover hydroelectric facility from counting towards the RPS and still achieve a 20 percent renewable supply to meet total customer demand.

Energy Efficiency PWP continues to learn how to effectively incorporate energy efficiency and demand side management into its overall integrated planning process. As part of this integration, a newly formed group will be brought together within the utility focused on the environment and natural resources. This group will include the traditional integrated planning group as well as environmental engineers and an energy efficiency engineer. This group will be responsible for all aspects of strategic planning, including energy efficiency and a strategy to manage a carbon constrained power generation environment. This group will also be working closely with the City’s newly forming Environmental Commission. Specifically, PWP will continue to identify and prioritize opportunities for energy efficiency in Pasadena. To name examples, two areas under investigation are an air conditioning cycling program and load shifting for pool pumps, which have the potential for significant citywide energy savings. Even with these efforts, PWP recognizes that there is more to be accomplished in energy efficiency. The above referenced study and report to the city council by June 30, 2007 will provide additional details on future environmental initiatives.

Reliance on Coal Throughout the public process of presenting this draft plan, it was clear that the citizens of Pasadena have a strong desire to reduce the consumption of coal as power generation fuel. PWP shares this strong desire. State legislation has reinforced this concept, and federal legislation over the next several years will likely impose a national standard. PWP recognizes that too much coal is burned to meet the needs of the city. The current 65 percent reliance does not reflect fuel diversity, increases greenhouse gases over a more balanced portfolio, and is at risk of increasing costs through further carbon restrictions or carbon taxes. For all of these reasons, the goal of this plan is to reduce this reliance on coal in a prudent manner through the years.

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PWP is working with the other IPP participants to investigate solutions to the CO2 emissions. There should be no expectation that technology can solve this problem and other options will be investigated such as partial divestiture or renewable energy blending. All of these options will have a consequent cost that PWP will present as an addendum to this report. The costs may include the loss of the associated transmission line (the Southern Transmission System). If a reduction in output from IPP is pursued, additional studies will be required to determine replacement power. One possibility is an increase in local generation. This option will require a further investigation of transmission and distribution impacts associated with increased generation in Pasadena as well as the feasibility of increasing the licensed capacity of local generation.

Financing Issues The primary capital expenditure associated with these recommendations is the re-powering project at the local generation facility. These capital expenditures will be financed through a series of public bonds. The financing environment remains favorable and interest rates remain at relatively low levels. The project indicates a positive net present value and, therefore, there should not be any difficulty in securing financing for the endeavor.

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Section 12 – Public Process This plan was prepared over a one-year period, with significant input from PWP’s Plant Engineering and Operations, Wholesale Operations, Account Managers, and Finance Planning and Analysis teams. To ensure that all stakeholders, including PWP customers, government leaders, PWP employees, environmental groups and the community at large, have the opportunity to thoroughly participate and offer input into Pasadena’s power supply future, this draft has been shared widely both inside the organization and community-wide. The Integrated Resource Plan public presentation was reviewed by the city of Pasadena’s Municipal Services Committee on August 16, 2006. The presentation material was posted for the public prior to the meeting on August 16. The following community outreach program was employed to notify the public of the meeting to present the IRP on November 1, 2006:

• Publication of notice on PWP website - www.PWPweb.com • Newsletter notifications in the October “Conduit” and “Currents” • Flyer distribution throughout public facilities in Pasadena • Newspaper advertisements in the Star News, Pasadena Weekly, and Pasadena

Journal • Press release on October 25, 2006 to announce the meeting

The plan was shared with the public during a community meetings held at the Pasadena Senior Center on November 1, 2006 from 6:30 to 8:30 p.m. In addition to the presentation and a full question and answer period, informational booths were setup, with subject-matter experts addressing PWP’s energy efficiency programs, the renewable program, environmental issues and local generation. All totaled, more than 50 individuals were estimated to have attended the public meetings, representing Pasadena’s residents, businesses and environmental groups. In addition, the Nov. 1 meeting was taped for broadcast this fall on the city’s municipal cable station, 55KPAS, which also streams live on the city’s web site. This written report was posted on the PWP website on January 31, 2007

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Section 13 – Approval Process Due to ongoing questions concerning the implementation of greenhouse gas legislation in California, PWP is continuing to evaluate carbon-constrained options, primarily centered on replacement or carbon mitigation at the IPP facility. This analysis should be complete in March 2007 and the above recommendations - with any additional adjustments pending this carbon mitigation analysis - will be presented to the city’s Municipal Services Committee prior to final consideration by the full city council. This is currently anticipated to occur by June of 2007. None of the above recommendations would be eliminated or reduced based on the further carbon analysis. Therefore, each of the recommendations will begin to be implemented through the normal approval process, guaranteeing many opportunities for public input, employed by the city. The carbon analysis will likely require increased commitments in local re-powering, energy efficiency and renewable power beyond those currently suggested. In the meantime, PWP staff is continuing to solicit feedback on this plan and its recommendations, as well as further input on coal generation and greenhouse gas issues. As mentioned above, an edited version of the original public presentation made on November 1, 2006 is airing on 55KPAS, and ongoing meetings with citizen groups can be arranged with PWP.