Pacific Gas & Electric (PCG)

Historically, energy utilities operated as regulated monopolies within service territories in which they were essentially the sole suppliers of natural gas and electricity services.  These utilities owned and operated all of the businesses and facilities necessary to generate, transport, and distribute energy.  Services were priced on a combined, or bundled, basis, with rates charged by the energy companies designed to include all the costs of providing these services.  Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital.  The objective of this regulatory policy was to provide universal access to safe and reliable utility services.  Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.

In recent years, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies.  The most significant of these services are the commodity components—the supply of electricity and natural gas.  The driving forces behind these competitive pressures have been customers who believe that they can obtain energy at lower unit prices and competitors who want access to those customers.  Regulators and legislators responded to these forces by providing for more competition in the energy industry.  Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

Competition in the Electricity Industry

Federal.  At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market.  The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and

 

7

---

 

    

among regions.  The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.

Even before the passage of the EPAct, the FERC's policies supported the development of a competitive electricity generation industry.  FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids.  Order 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service.  The FERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets.  On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination; (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections.  These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generation and transmission.  Under the rules and associated tariffs, a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator.  The generator will be reimbursed over a five-year period after the power plant achieves commercial operation.  The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.

State.  At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”).  Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”).  Following the 2000-2001 California energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC.  (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.)

California Assembly Bill 1X authorized the California Department of Water Resources (“DWR”), beginning in February 1, 2001, to purchase electricity and sell that electricity directly to the utilities' retail customers.  Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR’s billing and collection agent.  To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers.  California Senate Bill 695, enacted on October 11, 2009, requires the CPUC to adopt and implement a schedule by April 11, 2010 to reopen direct access on a gradual basis over a period of not less than three years and not more than five years.  The statute imposes an annual limit on the amount of electricity that can be purchased by direct access customers of a particular utility.  The annual limit for each utility is increased each year until it reaches an amount equal to each utility’s historical maximum amount of energy provided by other service providers in that utility’s service territory during any one-year period.  Further legislative action is required to exceed these limits.

Assembly Bill 1890 also provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid.  On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and

 

8

---

 

    

real-time wholesale electricity markets subject to bid caps that increase over time, as part of the implementation of the CAISO’s Market Redesign and Technology Upgrade initiative (“MRTU”).  Market participants, including load-serving entities like the Utility, are permitted to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring congestion revenue rights.  Also, in January 2008, the CPUC staff issued its recommendation to establish a statewide wholesale electric capacity market to replace the current resource adequacy program.  Any changes that the CPUC adopts would be subject to FERC approval.  On October 29, 2009, the CPUC opened a new rulemaking proceeding to continue oversight of the current resource adequacy program, consider program refinements, and establish annual local procurement obligations.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility.  California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators.  Under Assembly Bill 117, the Utility would continue to provide distribution, metering, and billing services to the community choice aggregators' customers and would be those customers' electricity provider of last resort.  Assembly Bill 117 provides that a community choice aggregator can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility.  The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services and allowing a community choice aggregator to start service in phases.  Assembly Bill 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the program not reasonably attributable to a community choice aggregator.

Competition in the Natural Gas Industry

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services.  Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies.  The Utility’s natural gas pipelines are located within the State of California and are exempt from the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.

The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998.  This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines.  The CPUC divides the Utility's natural gas customers into two categories: “core” customers, which are primarily small commercial and residential customers, and “non-core” customers, which are primarily industrial, large commercial, and electric generation customers.  Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services.  All services are offered on a nondiscriminatory basis to any creditworthy customer.  The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.

The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates.  The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights.  Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.  The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods.  In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010. In September 2009, the Utility filed an application with the CPUC to continue a majority of the Gas Accord IV’s terms and conditions for the Utility’s natural gas transportation and storage services from 2011 through 2014.

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural

 

9

---

 

    

gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility's market share of transportation services into southern California decreases.  The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Williams Gas Pipeline Company, LLC, have been jointly pursuing the development of a new 234-mile interstate gas transmission pipeline that would increase natural gas supplies for the West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the proposed Jordan Cove liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon, being developed by Fort Chicago Energy Partners, L.P., as lead investor, would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest, and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 Bcf per day. On December 17, 2009, the FERC issued an order to authorize construction and operation of the LNG terminal and the Pacific Connector Gas Pipeline.

The development and construction of the Pacific Connector Gas Pipeline and the proposed LNG terminal are subject to obtaining all remaining required federal, state and local permits and authorizations, as well as commitments under long-term capacity contracts of sufficient volumes to justify moving forward with construction of the terminal and the pipeline.  Assuming these are obtained and other conditions are timely satisfied, the proposed Pacific Connector Gas Pipeline and LNG terminal could begin commercial operation by late 2014.  However, PG&E Corporation cannot predict whether such conditions will be met and whether the construction of the proposed LNG terminal and associated pipeline will occur.

Ratemaking Mechanisms

Overview

The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (“cost-of-service ratemaking”).  Before setting rates, the CPUC and the FERC determine the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers.  The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage.  The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (“rate base”).  Revenue requirements are primarily determined based on the Utility’s forecast of future costs.  These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.

Regulatory balancing accounts are used to adjust the Utility’s revenue requirements.  Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations.  In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months.  Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors.  Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

 

10

---

 

    

To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy).  Specific rate components are designed to produce the required revenue.  Rate changes become effective prospectively on or after the date of CPUC or FERC decisions.  Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base.  The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.

While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.

Electricity and Natural Gas Distribution and Electricity Generation Operations

General Rate Cases

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations.  The CPUC generally conducts a GRC every three years.  The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year.  Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.  On March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC.  The decision set the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period.  On December 21, 2009, the Utility filed its application for the next GRC to establish revenue requirements for 2011 through 2013.  For more information, see the section of MD&A entitled “Regulatory Matters” in the 2009 Annual Report.

Attrition Rate Adjustments

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.  The CPUC’s decision in the Utility’s 2007 GRC provided for attrition adjustments for 2008, 2009, and 2010.  For more information, see the section of MD&A entitled “Results of Operations” in the 2009 Annual Report.

Cost of Capital Proceedings

The CPUC authorizes the Utility's capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets.  The current authorized capital structure, consisting of 52% equity, 46% long-term debt, and 2% preferred stock, will be maintained through 2012 unless the automatic adjustment mechanism described below is triggered.  The Utility’s current authorized rates of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base are 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.  The CPUC has authorized the Utility to maintain these rates through 2010.

The CPUC’s cost of capital mechanism uses an interest rate index (the 12-month October through September average of the Moody's Investors Service utility bond index) to trigger changes in the authorized cost of

 

11

---

 

    

debt, preferred stock, and equity.  In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark.  In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year.  The Utility may apply for an adjustment to either the cost of capital or the capital structure sooner based on extraordinary circumstances.  The Utility’s next full cost of capital application must be filed by April 20, 2012, so that any resulting changes would become effective on January 1, 2013.

Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility's transmission rates are determined through a negotiated rate settlement.

Baseline Allowance

The CPUC sets and periodically revises a baseline allowance for the Utility's residential gas and electricity customers. A customer's baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increase with usage.

Rate Recovery of Costs of New Electricity Generation Resources

Overview

Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility's own generation facilities and existing electricity contracts (including DWR contracts allocated to the Utility under Assembly Bill 1X).  To accomplish this, each utility must submit a long-term procurement plan covering a 10-year period to the CPUC for approval.  Each long-term procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).  In December 2007, the CPUC approved the utilities’ long-term electricity procurement plans, covering 2007 through 2016, subject to certain required modifications.  California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further after-the-fact reasonableness review.  Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources.  Contracts that are entered into after the RFO process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs.  The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements.  For more information about the Utility’s approved long-term procurement plan covering 2007 through 2016, see “Electric Utility Operations — Electricity Resources — Future Long-Term Generation Resources” below.

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC in accordance with Assembly Bill 57.  The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts.  To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs.  Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the

 

12

---

 

    

CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer.  The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

Costs Incurred Under New Power Purchase Agreements

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements.  The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge on bundled and departing customers only, or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including existing direct access customers and community choice aggregation customers.  (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)

The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less.  Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis.  If a utility elects to use the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract or 10 years, whichever is shorter, starting on the date the new generation unit comes on line.  Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs subject to allocation.  If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.

California Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for recovery of above-market costs from direct access and community choice aggregation customers.  The CPUC has not yet implemented this portion of Senate Bill 695.

Costs of Utility-Owned Generation Resource Projects

The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC.  The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs.  The initial revenue requirement for Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year.  For more information, see the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities” in the 2009 Annual Report.

DWR Electricity and DWR Revenue Requirements>

 

During the 2000-2001 California energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties.  The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities.  The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.”  The rates that these customers pay also include a “bond charge” to pay a share of the DWR’s revenue requirements to recover costs associated with the DWR's $11.3 billion bond offering completed in November 2002.  The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR's revenue requirement and to provide

 

 

13

---

 

    

 

the DWR with funds to make its electricity purchases.  The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.

 

Electricity Transmission 

The Utility's electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues (1) charges under the Utility's transmission owner tariff, and (2) charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998.  These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts.  Other customers pay transmission rates that are established by the FERC in the Utility's transmission owner tariff rate cases.  These FERC-approved rates are included by the CPUC in the Utility's retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.

Transmission Owner Rate Cases

The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”).  The Utility generally files a TO rate case every year, setting rates for a one-year period.  The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.  For more information about the Utility’s TO rate cases, see the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2009 Annual Report.

The Utility's transmission owner tariff includes two rate components.  The primary component consists of base transmission rates intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense, and return on equity.  The Utility derives the majority of the Utility's transmission revenue from base transmission rates.

The other component consists of rates intended to reflect credits and charges from the CAISO.  The CAISO credits the Utility for transmission revenues received by the CAISO.  These revenues include:

·	the proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and

·

revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges, such as firm transmission rights relating to future deliveries of electricity, or in the form of a usage charge to manage congestion relating to real-time delivery of electricity).

These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount that the Utility is entitled to receive from existing transmission contract customers under specific contracts and the amount that the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and protocols.

The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the use of the CAISO-controlled electric transmission grid in serving its customers.  The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provided for a transition over a 10-year period, from 2001 to2010, to a uniform statewide high-voltage transmission rate.  This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff.  The transmission access charge methodology results in a cost shift from transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost

 

14

---

 

    

differential, which is capped at $32 million per year during the 10-year transition period, is recovered in retail transmission rates.

Natural Gas

The Gas Accord

The Utility’s authorized natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010 have been set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV.  On September 18, 2009, the Utility filed an application with the CPUC to establish the Utility’s natural gas transmission and storage revenue requirements from January 1, 2011 through 2014 and to continue a majority of the terms and conditions of the Gas Accord IV.  A decision on the Utility’s application, known as the Gas Accord V, is expected by the end of 2010.  A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges.  The Utility’s ability to recover the remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Backbone Transmission.  The backbone transmission revenue requirement is recovered through a combination of firm two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available one-part rates (consisting only of volumetric usage charges).  The mix of firm and as-available backbone services provided by the Utility continually changes.  As a result, the Utility’s recovery of its backbone transmission costs is subject to volumetric and price risk to the extent that backbone capacity is sold on an as-available basis.  Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity.  Core customers are allocated approximately 36% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

Local Transmission.  The local transmission revenue requirement is allocated approximately 71% to core customers and 29% to non-core customers.  The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.

Storage.  The storage revenue requirement is allocated approximately 71% to core customers, 12% to non-core storage service, and 17% to pipeline load balancing service.  The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.  The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Biennial Cost Allocation Proceeding

Certain of the Utility's natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

 

15

---

 

    

Natural Gas Procurement

The Utility sets the natural gas procurement rate for core customers monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates.  The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (“CPIM”).  Under the CPIM, the Utility's purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas.  Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive in their rates 80% of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million.  While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. The Utility also has received CPUC approval for a long-term gas hedging program through 2011 on behalf of core customers.  The costs of the hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the fact reasonableness review. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report).

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s CPIM.  The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties.  As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program.

Interstate and Canadian Natural Gas Transportation

The Utility's interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines.  United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board.  The Utility's agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility's core natural gas procurement business.  Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins.   For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements.”

Electric Utility Operations

Electricity Resources 

The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service.  The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way.

 

16

---

 

    

The following table shows the percentage of the Utility's total actual deliveries of electricity in 2009 represented by each major electricity resource:

Total 2009 Actual Electricity Delivered 79,585 GWh:

Owned generation:
Nuclear	20.5%
Large Hydroelectric	10.5%
Small Hydroelectric	1.4%
Fossil fuel-fired	3.9%
Total		36.3%
DWR		18.0%
Qualifying Facilities		18.8%
Irrigation Districts		3.7%
Other Power Purchases		23.2%

Owned Generation Facilities 

At December 31, 2009, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type		County Location		Number of Units		Net Operating Capacity (MW)
Nuclear:
Diablo Canyon		San Luis Obispo		2		2,240
Hydroelectric:
Conventional		16 counties in northern and central California		107		2,684
Helms pumped storage		Fresno		3		1,212
Hydroelectric subtotal				110		3,896
Fossil fuel:
Gateway Generating Station(1)		Contra Costa		1		530
Humboldt Bay(2)		Humboldt		2		105
Mobile turbines		Humboldt		2		30
Fossil fuel subtotal				5		665
Total				117		6,801

(1)	The Gateway Generating Station became operational in January 2009.

(2)	The Humboldt Bay facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.  As described below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.

Diablo Canyon Power Plant.  The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity.  For the twelve months period ended December 31, 2009, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 83%.  The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025.  In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years.  The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits.  (See the discussion under the heading “Risk Factors” that appears in the MD&A section of the 2009 Annual Report.)  Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant.  For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters — Nuclear Fuel Disposal” below.

 

17

---

 

    

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel.  The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply.  For more information about these agreements, see Note 16: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.

The following table outlines the Diablo Canyon power plant’s refueling schedule for the next five years.  The Diablo Canyon power plant refueling outages are typically scheduled every 20 months.  The average length of a refueling outage over the last five years has been approximately 51 days.  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

			2010		2011		2012	2013	2014
Unit 1
Refueling			October		-		April	-	February
Duration (days)			40		-		30	-	30
Startup			November		-		May	-	March
Unit 2
Refueling			-		May		-	February	September
Duration (days)			-		30		-	30	35
Startup			-		June		-	March	October

Hydroelectric Generation Facilities.  The Utility’s hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW.  Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW.  The system includes 99 reservoirs, 56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 statements of water diversion and use.  All of the Utility's powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last three years, the FERC renewed three hydroelectric licenses associated with a total of 435 MW of hydroelectric power.  The Utility is in the process of renewing licenses for projects associated with approximately 1,073 MW of hydroelectric power.  Although the original licenses associated with 516 MW of the 1,073 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 2,701 MW of hydroelectric power will expire between 2018 and 2043.

New Generation Facilities.  In addition to the Utility-owned resources shown in the table above, the Utility has been engaged in the development of two generation facilities to be owned and operated by the Utility.  Construction of the Colusa Generating Station, a 657 MW combined cycle generating facility to be located in Colusa County, California, began on October 1, 2008.  Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations by November 2010.  Also, in December 2008, the Utility began construction of a 163 MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life.  Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in September 2010.

DWR Power Purchases 

During 2009, electricity from the DWR contracts allocated to the Utility provided approximately 18.0% of the electricity delivered to the Utility’s customers.  The DWR purchased the electricity under contracts with various generators.  The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent.  The DWR remains legally and financially responsible for its contracts.  The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as these contracts expire or are novated to the Utility.

 

18

---

 

    

Third-Party Power Purchase Agreements

Qualifying Facility Power Purchase Agreements.  As described above under “The Utility’s Regulatory Environment-Federal Energy Regulation,” the Utility is required to purchase energy and capacity from independent power producers that are QFs.  As of December 31, 2009, the Utility had power purchase agreements with 240 QFs for approximately 3,900 MW that are in operation.  Agreements for approximately 3,600 MW expire at various dates between 2010 and 2028.  QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option.  The Utility also has power purchase agreements with approximately 75 inoperative QFs.  The total of approximately 3,900 MW consists of 2,500 MW from cogeneration projects, and 1,400 MW from renewable generation resources, as discussed below.  QF power purchases accounted for 18.8% of the Utility’s 2009 electricity deliveries.  No single QF accounted for more than 5% of the Utility’s 2009 electricity deliveries.

Irrigation Districts and Water Agencies.  The Utility also has entered into contracts with various irrigation districts and water agencies to purchase hydroelectric power.  These agreements are based on debt service requirements (regardless of the amount of power supplied), and include variable payments to the counterparty for operation and maintenance costs.  These contracts will expire on various dates between 2010 and 2031.  In 2009, they accounted for 3.7% of the Utility’s electricity deliveries.

Other Power Purchase Agreements.  The Utility has entered into power purchase agreements, including agreements to purchase renewable energy that were entered into following annual solicitations and separate bilateral negotiations.  In addition, in accordance with the Utility’s CPUC-approved long-term procurement plan, the Utility has entered into power purchase agreements for conventional generation resources.  During 2009, the Utility’s purchases under these agreements accounted for 9.0% of the Utility’s deliveries.  When market prices and forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets.  Electricity purchased in these markets accounted for 14.2% of the Utility’s deliveries in 2009.

For more information regarding the Utility’s power purchase contracts, see Note 16: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.

Renewable Generation Resources

California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from renewable resources equals at least 20% of their total retail sales by the end of 2010.  If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the deficit to be carried forward for up to three years so that future deliveries of renewable power can be used to make up the deficit.

The amount of electricity the Utility delivered from renewable resources during 2009 equaled 14.4 % of the Utility’s total retail electricity sales at December 31, 2009.  Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts.  Additional renewable resources included the Utility’s small hydro and solar facilities and certain irrigation district contracts (small hydro facilities).  (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate.  Most of the Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)

 

19

---

 

    

Total 2009 renewable deliveries are stated in the table below.

Type		GWh				% of Bundled Load
Biopower			3,439				4.3	%
Geothermal			3,412				4.3	%
Wind			2,524				3.2	%
Small Hydroelectric			2,044				2.6	%
Solar			22				0.0	%
Total			11,441				14.4	%

For more information regarding the Utility’s renewable energy contracts, see Note 16: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.

Future Long-Term Generation Resources

In compliance with California’s Clean Energy Action Plan, the Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources.   The Utility’s CPUC-approved long-term electricity procurement plan, covering 2007-2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new generation resources by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources.  Due to the cancellation of two projects selected in its 2004 RFO for new long-term generation resources, the Utility was authorized to increase the new generation resource need to obtain 1,112 to 1,512 MW.  

The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources only through purchase and sale agreements (“PSAs”) ( a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements).  The utilities are prohibited from submitting offers for utility-build generation in their respective RFOs until questions can be resolved about how to compare offers for utility-owned generation with offers from independent power producers.  The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.

For a discussion of the Utility-owned generation projects the Utility has requested that the CPUC approve, see the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities” in the 2009 Annual Report.

 

20

---

 

    

Electricity Transmission 

At December 31, 2009, the Utility owned 18,650 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 57,848 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,213 circuit miles of distribution lines and substations with a capacity of 27,896 MVA.  In 2009, the Utility delivered 85,629 GWh to its customers, including 5,643 GWh delivered to direct access customers.  The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO.  The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO.  The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis.  The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained.  The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid.  The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998.  In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards.  See the discussion of reliability standards above under “The Utility’s Regulatory Environment — Federal Energy Regulation.”

The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO.  (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.)  Potential transmission projects include a high-voltage transmission line to improve regional reliability in the Fresno, California area and ultimately enable access to new renewable generation resources (referred to as the “Central California Clean Energy Transmission Project”).  As previously disclosed, the Utility has been exploring the feasibility of obtaining regulatory approval for a potential investment in a proposed 1,000 mile high-voltage electric transmission project that would run from British Columbia, Canada to Northern California.  The project would provide access to potential new renewable generation resources, improve regional transmission reliability, and provide opportunities for other market participants to use the new facilities.  The supply of and need for new renewable generation have evolved since the Utility began exploring the feasibility of obtaining regulatory approval for the potential investment, as has the interest from potential partners.  In lieu of the 1,000 mile high-voltage transmission line,  the Utility is in continuing discussions with various stakeholders to explore whether, in light of these changing circumstances, a different version of this project or another transmission project in this region should be pursued as part of its overall renewable energy supply strategy.  
  

Electricity Distribution Operations

The Utility's electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California.  The Utility's network consists of 141,213 circuit miles of distribution lines

 

21

---

 

    

(of which approximately 20% are underground and approximately 80% are overhead).  There are 93 transmission substations and 48 transmission-switching stations.  A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another.  The Utility’s network includes 600 distribution substations and 118 low-voltage distribution substations.  The 53 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility's distribution network interconnects to the Utility’s electricity transmission system at 1,116 points.  This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers.  The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment.  Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users.  In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.

2009 Electricity Deliveries.  The following table shows the percentage of the Utility’s total 2009 electricity deliveries represented by each of its major customer classes.

Total 2009 Electricity Delivered: 85,629 GWh

Residential Customers	36%
Commercial Customers	39%
Industrial Customers	17%
Agricultural and Other Customers	8%

Electricity Distribution Operating Statistics

The following table shows certain of the Utility's operating statistics from 2005 to 2009 for electricity sold or delivered, including the classification of sales and revenues by type of service.

 

		2009				2008				2007				2006				2005
Customers (average for the year):
Residential			4,492,359				4,488,884				4,464,483				4,417,638				4,353,458
Commercial			528,786				527,045				521,732				515,297				509,786
Industrial			1,285				1,265				1,261				1,212				1,271
Agricultural			83,581				81,757				80,366				79,006				78,876
Public street and highway lighting			31,227				30,474				29,643				28,799				28,021
Other electric utilities			2				2				2				4				4
Total			5,137,240				5,129,427				5,097,487				5,041,956				4,971,416
Deliveries (in GWh):(1)
Residential			31,234				31,454				30,796				31,014				29,752
Commercial			32,958				34,053				33,986				33,492				32,375
Industrial			14,806				16,148				15,159				15,166				14,932
Agricultural			5,804				5,594				5,402				3,839				3,742
Public street and highway lighting			826				877				833				785				792
Other electric utilities			1				1				3				14				33
Subtotal			85,629				88,127				86,179				84,310				81,626
California Department of Water Resources (DWR)			(13,244	)			(13,344	)			(21,193	)			(19,585	)			(20,476	)
Total non-DWR electricity			72,385				74,783				64,986				64,725				61,150
Revenues (in millions):
Residential		$	4,759			$	4,656			$	4,580			$	4,491			$	3,856
Commercial			4,538				4,413				4,484				4,414				4,114

 

 

22

---

 

 

Industrial			1,392				1,400				1,252				1,293				1,232
Agricultural			770				727				664				483				446
Public street and highway lighting			74				75				78				72				66
Other electric utilities			66				126				85				59				4
Subtotal			11,599				11,397				11,143				10,812				9,718
DWR			(1,987	)			(1,325	)			(2,229	)			(2,119	)			(1,699	)
Miscellaneous			221				336				215				261				235
Regulatory balancing accounts			424				330				352				(202	)			(327	)
Total electricity operating revenues		$	10,257			$	10,738			$	9,481			$	8,752			$	7,927
Other Data:
Average annual residential usage (kWh)			6,953				7,007				6,898				7,020				6,834
Average billed revenues (cents per kWh):
Residential		$	15.24			$	14.80			$	14.87			$	14.48			$	12.96
Commercial			13.77				12.96				13.19				13.18				12.71
Industrial			9.40				8.67				8.26				8.53				8.25
Agricultural			13.27				13.00				12.29				12.58				11.92
Net plant investment per customer		$	4,336			$	3,994			$	3,418			$	3,148			$	2,966

(1)

These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

 

Natural Gas Utility Operations 

The Utility owns and operates an integrated natural gas transportation, storage, and distribution system in California that extends throughout all or a part of 39 of California’s 58 counties and includes most of northern and central California.  In 2009, the Utility served approximately 4.3 million natural gas distribution customers.  The total volume of natural gas throughput during 2009 was approximately 845 Bcf.

As of December 31, 2009, the Utility’s natural gas system consisted of 42,142 miles of distribution pipelines, 6,438 miles of backbone and local transmission pipelines, and three storage facilities.  The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.  The Utility's Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day.  The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border.  This line has a receipt capacity at the border of approximately 2.02 Bcf per day.  Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States.  The Utility also is supplied by natural gas fields in California.

The Utility owns and operates three underground natural gas storage fields connected to the Utility’s transmission and storage system.  These storage fields have a combined firm capacity of approximately 47 Bcf.  In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, is developing an underground natural gas storage facility near Fresno, California.  It is expected that construction of the initial phase, to consist of approximately 20 Bcf of total capacity, will be completed in 2010.  The Utility has a 25% interest in the initial phase of the proposed storage facility.

The CPUC divides the Utility's natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer's annual natural gas usage.  The core customer class is comprised mainly of residential and smaller commercial natural gas customers.  The non-core customer class is comprised of

 

23

---

 

    

industrial, larger commercial, and electric generation natural gas customers.  In 2009, core customers represented more than 99% of the Utility’s total natural gas customers and 38% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 62% of its total natural gas deliveries.

The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory.  Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers.  When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service.  Currently, over 97% of core customers, representing over 96% of core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service through that avenue.  Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility's procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility’s results of operations over the long term are not affected by weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers.  Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2008 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 0.2% for the years 2008 through 2030. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.

2009 Natural Gas Deliveries.  The following table shows the percentage of the Utility's total 2009 natural gas deliveries represented by each of the Utility's major customer classes.

Total 2009 Natural Gas Deliveries: 845 Bcf

Residential Customers	27%
Transport-only Customers (non-core)	62%
Commercial Customers	11%

 

24

---

 

    

Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2005 through 2009 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.

		2009				2008				2007				2006				2005
Customers (average for the year):
Residential			4,046,364				4,043,616				4,030,499				3,989,331				3,929,117
Commercial			223,709				224,617				223,330				220,024				216,749
Industrial			928				926				958				988				962
Other gas utilities			6				6				6				6				6
Total			4,271,007				4,269,165				4,254,793				4,210,349				4,146,834
Gas supply (MMcf):
Purchased from suppliers in:
Canada			190,485				189,608				199,870				202,274				204,884
California (1)			(41,714	)			(53,126	)			(23,065	)			(13,401	)			(18,951	)
Other states			115,543				123,833				101,271				103,658				103,237
Total purchased			264,314				260,315				278,076				292,531				289,170
Net (to storage) from storage			876				560				(1,120	)			4,359				(3,659	)
Total			265,190				260,875				276,956				296,890				285,511
Utility use, losses, etc. (2)			(12,423	)			1,758				(12,760	)			(27,610	)			(14,312	)
Net gas for sales			252,767				262,633				264,196				269,280				271,199
Bundled gas sales (MMcf):
Residential			195,217				198,699				196,903				196,092				194,108
Commercial			57,550				63,934				67,293				73,178				77,056
Industrial			—				—				—				10				35
Other gas utilities			—				—				—				—				—
Total			252,767				262,633				264,196				269,280				271,199
Transportation only (MMcf):			568,715				569,535				605,259				559,270				572,869
Revenues (in millions):
Bundled gas sales:
Residential		$	1,953			$	2,574			$	2,378			$	2,452			$	2,336
Commercial			496				792				766				859				885
Industrial			—				—				—				—				—
Other gas utilities			—				—				—				—				—
Miscellaneous			55				(30	)			87				121				(22	)
Regulatory balancing accounts			289				221				186				40				340
Bundled gas revenues							3,557				3,417				3,472				3,539
Transportation service only revenue			349				333				340				315				237
Operating revenues		$	3,142			$	3,890			$	3,757			$	3,787			$	3,776
Selected Statistics:
Average annual residential usage (Mcf)			48				49				49				49				49
Average billed bundled gas sales revenues per Mcf:
Residential		$	10.00			$	12.95			$	12.07			$	12.50			$	12.04
Commercial			8.62				12.38				11.38				11.73				11.48
Industrial			—				—				—				1.03				0.61
Average billed transportation only revenue per Mcf			0.61				0.59				0.56