Corporate Structure and Business

 

PG&E Corporation, incorporated in California in 1995, is a holding company that conducts its business through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California.  The Utility was incorporated in California in 1905.  PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.

 

The Utility’s revenues are generated mainly through the sale and delivery of electricity and natural gas to customers.  The Utility served approximately 5.2 million electricity distribution customers and approximately 4.4 million natural gas distribution customers at December 31, 2012.  The Utility had approximately $52 billion in assets at December 31, 2012 and generated revenues of approximately $15 billion in 2012.  The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”).  In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

 

Corporate and Other Information

 

The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177.  PG&E Corporation’s telephone number is (415) 267-7000 and the Utility’s telephone number is (415) 973-7000.  PG&E Corporation and the Utility file or furnish various reports with the Securities and Exchange Commission (“SEC”).  These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“1934 Act”), are available free of charge on both PG&E Corporation's website, www.pgecorp.com , and the Utility's website, www.pge.com , as promptly as practicable after they are filed with, or furnished to, the SEC.  The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.

 

This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2012, which is attached to this report as Exhibit 13 (“2012 Annual Report”) and the Joint Proxy Statement relating to the 2013 Annual Meetings of Shareholders.  The 2012 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties.  For a discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the information in the 2012 Annual Report under the headings “Cautionary Language Regarding Forward-Looking Statements” and “Risk Factors” which appear under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”).

 

Operational Improvements

 

The Utility’s electricity and natural gas businesses are each led by a senior executive who reports to the President of the Utility.   During 2012, the Utility continued to build these organizations by adding new leaders with extensive industry expertise and expanding the Utility’s work force where needed to implement the Utility’s enhanced focus on safety and operational excellence.  Significant improvements were made to the Utility’s natural gas operations during 2012 to enhance safety, test and replace pipelines, modernize and upgrade the system, and search and validate records.  Much of this work was carried out under the Utility’s pipeline safety enhancement plan that was approved by the CPUC in late December 2012.  The Utility also continued work to implement the safety recommendations made by the National Transportation Safety Board (“NTSB”) in its 2011 investigative report on the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”).  (For more information, see “Natural Gas Utility Operations” below.)   The Utility also undertook significant projects in 2012 to improve and modernize its electricity operations by repairing, replacing or upgrading equipment to improve reliability and safety.  In addition, the Utility continued the installation of advanced electric and gas meters throughout its service territory and took other steps to lay the foundation for the development of a “smart grid” to enable customers to have better control over their energy usage and costs, to integrate new

sources of energy (such as distributed generation and storage, rooftop solar and other intermittent energy sources), and to enable the continued safe and reliable operation of the grid.  (For more information, see “Electric Utility Operations” below.)

 

Employees 

 

At December 31, 2012, PG&E Corporation and its subsidiaries had 20,593 regular employees, including 20,583 regular employees of the Utility.  Of the Utility’s regular employees, 12,492 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”).  There are two collective bargaining agreements with IBEW.   One IBEW collective bargaining agreement expires on December 31, 2014 and the other IBEW collective bargaining agreement expires on December 31, 2015.  The ESC collective bargaining agreement expires on December 31, 2014.  The SEIU collective bargaining agreement expires on July 31, 2013.

 

Regulatory Environment 

 

Various aspects of the Utility's business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels.  This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility.  These summaries are not an exhaustive description of all the laws, regulations, and regulatory proceedings that affect the Utility.  The energy laws, regulations, and regulatory proceedings may change or be implemented or applied in a way that PG&E Corporation and the Utility do not currently anticipate.

 

PG&E Corporation is a public utility holding company that is subject to the requirements of the Public Utility Holding Company Act of 2005 (“PUHCA”).  Under the PUHCA, public utility holding companies fall principally under the regulatory oversight of the FERC.  PG&E Corporation and its subsidiaries are exempt from all requirements of the PUHCA other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.  These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

 

For discussion of specific pending regulatory proceedings and investigations that are expected to affect the Utility, see the information under the headings within MD&A entitled “Regulatory Matters” and “Natural Gas Matters” in the 2012 Annual Report, which information is incorporated herein by reference.

 

Federal Regulation

 

The Federal Energy Regulatory Commission

 

The FERC regulates the transmission of electricity and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce.  The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations, including the California Independent System Operator Corporation (“CAISO”), and the terms and rates of wholesale electricity sales.  The FERC has authority to impose penalties of up to $1 million per day for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations.  The FERC has jurisdiction over the Utility's electricity transmission annual amount of revenue (“revenue requirements”) and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

 

The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest.  The FERC certified the North American Electric Reliability Corporation (“NERC”) as the nation’s Electric Reliability Organization.  The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval.  The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”).  The Utility must self-certify compliance to the WECC on an annual basis and the compliance program encourages self-reporting of violations.  WECC staff, with participation by the NERC and the FERC, also performs a compliance audit of the Utility every three years.  In addition, the WECC and the NERC may perform

spot checks or other interim audits, reports, or investigations.  The FERC also has authorized the WECC and the NERC to impose penalties up to $1 million per day, per violation.

 

The FERC also has adopted policies and rules to promote investment in energy infrastructure and lower costs for consumers through incentive ratemaking for transmission projects.  In addition, the FERC’s Order No. 1000 establishes electric transmission planning and cost allocation requirements for public utility transmission providers.  Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities.

 

The CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.

 

The Nuclear Regulatory Commission

 

The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”).  NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities.  In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.  For information about NRC matters affecting Diablo Canyon, including the status of the Utility’s relicensing application see the information under the heading within MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2012 Annual Report, which information is incorporated herein by reference.

 

The Pipeline and Hazardous Materials Safety Administration

 

The Utility also is subject to regulations adopted by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation.  The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation's pipeline transportation system and the shipment of hazardous materials.  Through a certification with PHMSA, the CPUC is authorized to enforce the federal pipeline safety standards over intrastate natural gas pipelines, as well as any state pipeline safety requirements that do not conflict with the federal requirements, through penalties and/or injunctive relief.

 

The National Transportation Safety Board

 

The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage.  The NTSB investigated the San Bruno accident and in August 2011 announced that it had determined the probable cause of the San Bruno accident placing the blame primarily on the Utility.  The NTSB report recommended that the Utility take certain actions to improve the safety of its gas transmission system.  The status of the Utility’s implementation of the NTSB’s recommendations is discussed under “Natural Gas Utility Operations” below.

 

State Regulation

The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility's electricity and natural gas distribution operations, electricity generation, and natural gas transportation and storage services.  The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

 

The CPUC also enforces state laws that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution pipeline systems, and for the safe operation of such pipelines and equipment.  The CPUC has adopted many rules and regulations to

implement state laws and policies, such as the laws relating to the development of renewable energy resources, demand response and public purpose programs, and the reduction of greenhouse gas (“GHG”) emissions.  The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.  The CPUC has authority to impose penalties for violating these state and federal laws, orders, or regulations of up to $50,000 per violation, per day.  (See the discussion under the heading within MD&A entitled “Natural Gas Matters” in the 2012 Annual Report for information about the CPUC’s pending enforcement proceedings against the Utility relating to the Utility’s safety recordkeeping for its natural gas transmission system; the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density; and the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct that could have led to or contributed to the San Bruno accident, which discussion is incorporated herein by reference.)  

The CPUC also has adopted complex and detailed rules governing transactions between California's electricity and gas utilities and certain of their affiliates.  The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates.  The CPUC has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.

 

The California Energy Resources Conservation and Development Commission

 

The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“CEC”), is the state's primary energy policy and planning agency.  The CEC is responsible for licensing all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies.  In addition, the CEC is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.

 

The California Air Resources Board

 

The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring GHG and other emission limits.  The CARB also is responsible for adopting and enforcing regulations to meet the California Global Warming Solutions Act of 2006 (“AB 32”), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2013.  In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions.  In November 2012, the CARB held the first auction of GHG emission allowances under this “cap-and-trade” program. (For more information, see “Environmental Matters — Air Quality and Climate Change” below.)

 

Other Regulation

 

The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities.  These permits include discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses.  Some licenses and permits may be revoked or modified by the agency

that granted them if facts develop or events occur that differ significantly from the facts and projections assumed when they were granted.  In addition, discharge permits and other approvals and licenses often have a term that is less than the expected life of the associated facility.  Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.  (For more information, see “Environmental Matters — Water Quality” below.)

 

The Utility has franchise agreements with 292 cities and counties that permit the Utility to install, operate, and maintain the Utility's electric and natural gas facilities in the public streets and roads.  In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties.  In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date.  The Utility has several franchise agreements that have a specified term of years, including an agreement with a large charter city.

 

The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas.  Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.

 

Competition in the Electricity Industry

 

At the federal level, the FERC is charged with developing rules to encourage fair and efficient competitive wholesale electric markets by employing best practices in market rules and reducing barriers to trade between markets and among regions.  (See “Regulatory Environment−Federal Regulation” above for a description of some of these rules.)  The FERC also has 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.  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 electric transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage investment in generation and transmission.

 

At the state level, the California Legislature mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase electricity from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”).  A market framework was established 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 California Power Exchange (“PX”).  As the 2000-2001 California energy crisis unfolded, direct access was suspended.  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 bankruptcy proceeding that was precipitated by the energy crisis, see Note 13: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.)

 

Current California law provides only limited opportunities for customers who receive “bundled” electricity service (i.e., electricity, transmission and distribution services) to choose to purchase electricity directly from an energy service provider other than the three California investor-owned electric utilities. As authorized by California law enacted in October 2009, the CPUC has adopted a plan to reopen direct access on a limited and gradual basis to allow eligible customers of the three California investor-owned electric utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps.  It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access.  Further legislative action is required to exceed these limits.

 

In addition, the Utility’s customers may, under certain circumstances, obtain power from a community choice aggregator (“CCA”) instead of from the Utility.  California law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses after they have registered as

CCAs.  Under these arrangements, the Utility continues to provide distribution, metering, and billing services to the customers of the CCAs and remains the electricity provider of last resort for those customers.  The law provides that a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility.  Under the CPUC’s rules, a surcharge is imposed on retail end-users of the CCA to prevent a shifting of costs to customers who continue to receive electricity from a utility. The law also authorizes the Utility to recover from each CCA any costs of implementing the program that are reasonably attributable to the CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a CCA.  Over 90,000 customers in Marin County are now receiving commodity service from the Marin Energy Authority, a CCA.

 

In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, seek to acquire the Utility’s distribution facilities.  For example South San Joaquin Irrigation District (“SSJID”) has applied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and around the cities of Manteca, Ripon and Escalon.  SSJID has indicated that, if it receives the requested authority, it will seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.

 

It is also possible that technological developments could pose challenges for traditional utilities.  In particular, technology-related cost declines and sustained federal or state subsidies could make the combination of “distributed generation” and storage a viable, cost-effective alternative to the Utility’s bundled electric service.  In addition, the levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits at the full retail rate, are increasing.

 

Although the CPUC has established ratemaking mechanisms that allow the Utility to collect some non-bypassable or fixed charges from those who procure electricity from alternate sources, rates for the Utility’s remaining customers could increase as alternative energy providers (CCAs or local government agencies) and alternative energy sources (self-generation and storage, distributed generation, electric vehicles) become more prevalent.  Increasing rate pressure on remaining customers could, in turn, cause more customers to seek alternative energy providers or sources, further exacerbating the Utility’s rate challenges.

 

Competition in the Natural Gas Industry

 

Under the FERC’s rules, interstate natural gas pipeline companies are required to divide their services into separate gas commodity sales, transportation, and storage services and must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas from these companies.  The Utility’s natural gas pipelines are located within the State of California and are exempt from most of 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 CPUC divides the Utility's natural gas customers into two categories: “core” customers, who are primarily small commercial and residential customers, and “non-core” customers, who are primarily industrial, large commercial, and electric generation customers.  Non-core customers have access to capacity rights for firm service on the Utility’s natural gas pipeline, as well as interruptible (or “as-available”) services.  All services are offered on a nondiscriminatory basis to any creditworthy customer.  This market structure has resulted in a robust wholesale gas commodity market at the Utility’s “Citygate,” which refers to the non-physical interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.  The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998 which largely mimics the regulatory framework required by the FERC for interstate gas pipelines. (See “Ratemaking Mechanisms” below.)

 

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 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 and U.S. Rocky Mountains natural gas delivered to northern California, relative to the total delivered cost of natural gas from the southwestern United States.  In general, when the total cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California 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.

 

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 conduct proceedings to determine the revenue requirements that the Utility is authorized to collect from its customers.  The CPUC determines the Utility’s revenue requirements associated with electricity and natural 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.

 

To develop retail rates, the revenue requirements are allocated among customer classes which are mainly residential, commercial, industrial, and agricultural.  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.

 

The Utility uses balancing accounts to keep track of its authorized revenue requirements, actual customer billings collected through rates, and actual costs incurred to provide electricity and natural gas services.  Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.  For more information regarding the Utility’s balancing accounts, see Note 3: Regulatory Assets, Liabilities and Balancing Accounts, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

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 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 anticipated business and operational costs related to its electricity and natural gas distribution and electricity generation operations and to provide the Utility an opportunity to earn its authorized rate of return.  The CPUC generally conducts a GRC every three years.  Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network.  In November 2012, the Utility filed its 2014 GRC application with the CPUC for rates effective from 2014 through 2016.  For more information see the heading within MD&A entitled “2014 General Rate Case” in the 2012 Annual Report, which information is incorporated herein by reference.  

 

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.

 

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, natural gas transmission, and electricity generation assets.  The authorized capital structure that was in effect through 2012 consisted of 52% equity, 46% long-term debt, and 2% preferred stock.  Since 2008, the Utility’s authorized cost of capital has been subject to an adjustment mechanism that is triggered in a particular year if the 12-month October-through-September average of the applicable Moody's Investors Service utility bond index increases or decreases by more than 100 basis points from the benchmark.  If the adjustment mechanism is triggered, the Utility’s authorized ROE beginning on the next January 1 st would be adjusted by one-half of the increase or decrease.  This mechanism did not trigger a change in the Utility’s authorized rates of return for 2012.

 

In December 2012, the CPUC issued a decision in the cost of capital proceeding that authorizes the Utility to maintain a capital structure consisting of 52% equity, 47% long-term debt, and 1% preferred stock beginning on January 1, 2013. (For more information see the section of MD&A entitled “2013 Cost of Capital Proceeding” in the 2012 Annual Report, which information is incorporated herein by reference.)

 

Rate Recovery of Costs of Electricity Generation Resources

 

Overview

 

California investor-owned electric utilities are required to use the principles of “least-cost dispatch” in managing electric generation resources to meet customer demand for electricity. The utilities are also responsible for procuring electricity required to meet customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electricity contracts.  To accomplish this, each utility must submit a ten-year procurement plan to the CPUC for approval.  Each procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet the 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). The CPUC approved the Utility’s electricity procurement plan in January 2012 covering 2011 through 2020 and approved the Utility’s GHG compliance instrument procurement plan in April 2012.

 

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved electricity procurement plans without further after-the-fact reasonableness review.  To the extent the Utility’s electricity purchases are not in compliance with the CPUC-approved plan, costs associated with those purchases may be disallowed. The Utility recovers its electricity procurement costs through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC.  The ERRA tracks the difference between (1) billed and unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility's authorized procurement plans.  To determine the rates used to collect ERRA revenues, each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, hedging, and generation fuel expense and approves a forecasted revenue requirement.  On December 20, 2012, the CPUC approved the Utility’s forecast of 2013 procurement costs and associated revenue requirement.  Changes in rates to reflect the approved revenue requirement became effective on January 1, 2013.  (The CPUC may adjust a utility’s retail electricity rates at any time when the forecasted aggregate over-collections or under-collections in the ERRA exceed five percent of its prior year electricity procurement revenues.)  The CPUC also performs an annual compliance review to ensure that (1) the Utility prudently administered the contracts that were entered into in accordance with its CPUC-approved procurement plans, (2) utilized the principles of least-cost dispatch in managing its electric generation resources, and (3) prudently operated its own generation facilities.  

 

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 procurement plan, the renewable energy mandate, 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 also recover any above-market costs through either (1) a non-bypassable customer charge or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including direct access customers and CCA customers under certain circumstances.  The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for ten

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 ten years on a case-by-case basis.  If a utility uses the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract.  To use the net capacity allocation method, the CPUC must determine that a resource was needed to meet system or local area reliability needs for the benefit of all distribution customers.  The CPUC can decide whether to require an energy auction for resources subject to the net capacity cost allocation.

 

For renewable generation purchased from third parties under power purchase agreements, the Utility may also recover any above-market costs through the imposition of a non-bypassable charge on customers.

 

Costs of Utility-Owned Generation Resource Projects

 

The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through 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.  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 Utility may recover any above-market costs associated with new utility-owned generation resources in a manner similar to the recovery of above-market costs for non-renewable generation purchases described above.  The recovery of above-market costs is typically addressed in the CPUC order approving a specific utility-owned generation project.

 

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 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 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.  The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.  See the information within MD&A entitled “FERC Transmission Owner Rate Case” in the 2012 Annual Report, which information is incorporated herein by reference.  

 

The Utility's transmission owner tariff includes several 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.  Another component consists of rates that reflect credits and charges from the CAISO for transmission revenues received by the CAISO for providing wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) to third parties using the Utility’s transmission facilities and charges related to the cost of providing service to existing transmission contract customers under specific contracts.  The CAISO also imposes a transmission access charge on the Utility for use of the CAISO-controlled electric transmission grid in serving its customers, which are recovered from the Utility’s retail customers as part of transmission rates.

 

Natural Gas

 

Gas Safety Rulemaking Proceeding

 

The CPUC is conducting a rulemaking proceeding to adopt new safety and reliability regulations for natural gas transmission and distribution pipelines in California and the related ratemaking mechanisms.  As directed by the CPUC, in August 2011, the Utility filed its proposed pipeline safety enhancement plan to replace certain natural gas pipeline segments, install automatic or remote shut-off valves, and take other actions to modernize and upgrade its natural gas transmission system.  On December 20, 2012, the CPUC approved the Utility’s proposed plan but disallowed the Utility’s request for rate recovery of a significant portion of plan-related costs that the Utility forecasted it would incur over the first phase of the plan (2011 through 2014).  See the information under the heading within MD&A entitled “Natural Gas Matters−CPUC Gas Safety Rulemaking Proceeding” in the 2012 Annual Report, which information is incorporated herein by reference.

 

Natural Gas Transmission and Storage Rate Cases

 

The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in a separate rate case called the gas transmission and storage (“GT&S”) rate case.  The CPUC’s decision in the most recent GT&S rate case approved a settlement agreement, known as the Gas Accord V, which set the Utility’s rates and associated revenue requirements for natural gas transmission and storage services from January 1, 2011 through December 31, 2014.  (The Utility expects to file an application to begin the next GT&S rate case in September 2013.)  A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, 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 continues 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 38% of the total backbone capacity on the Utility’s system.  Core customers pay approximately 69% 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 66% to core customers and 34% 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 51% to core customers, 37% to non-core storage service, and 12% 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.

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 recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)

 

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 natural gas 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 commodity 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 Utility retains the remaining amount of savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs.  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.

 

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 beginning November 1, 2010.  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.  (For more information, see Note 10: Derivatives, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference).

 

Interstate and Canadian Natural Gas Transportation

 

The Utility has a number of agreements with interstate and Canadian third-party transportation service providers to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. These 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 transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as electricity procurement costs.  For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements” below.

 

Electric Utility Operations

 

During 2012, the Utility made significant capital investments in its electric transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; to integrate more renewable energy resources; to increase capacity; and add new infrastructure to meet customer demand growth.  The Utility improved the reliability of its system by adding emergency capacity at substations, increasing distribution system automation, upgrading poor performing circuits, performing targeted asset replacement, and improving service restoration processes.  The Utility also has been working to accelerate pole replacement and maintenance of its overhead and underground electric facilities and to increase the use of wireless devices that allow the Utility to monitor the performance of the electric system and respond more quickly to power disruptions.

 

The Utility also substantially completed the installation of an advanced metering infrastructure throughout its service territory in 2012.  As of December 31, 2012, the Utility has installed approximately 8.9 million advanced electric and gas meters.  As permitted by CPUC rules, customers may choose not to have an advanced meter

installed.  The new infrastructure uses SmartMeter TM technology that can measure energy use in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs.  Usage data is collected through a wireless communications network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes.

 

The Utility’s advanced metering infrastructure supports the development of a “smart grid” in California, part of a nationwide effort to improve and modernize the nation’s electric system by combining advanced communications and controls to create a responsive and resilient energy delivery network.  In March 2012, the Utility began incorporating the latest “smart grid” technology in parts of its service territory by installing automated switches that reduce outage duration and the number of customers affected by outages.  When an electrical outage occurs, these switches detect a short circuit, block power flow to the affected area, communicate with a central computer, and then quickly reroute power around the problem to keep as many customers powered as possible. Over the next several years, the Utility plans to undertake various “smart grid” projects and invest in “smart grid” technologies.

 

Electricity Resources

 

The Utility is required to maintain physical generating capacity adequate to meet its customers’ 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 in the most cost-effective way.   The following table shows the percentage of the Utility’s total actual deliveries of electricity to customers in 2012 represented by each major electricity resource.

 

 

                              (1)   Electric utilities are required under federal law to purchase energy and capacity from independent power producers with generation facilities (20 MW or less) that meet the definition of a qualifying facility (“QF”)

                                    under the Public Utility Regulatory Policies Act of 1978.  QFs  primarily include   co-generation facilities that produce combined heat and power and renewable generation facilities.  For more information about the

                                    power purchase agreements that the Utility has entered into with QFs, see “QF Power Purchase Agreements,” below.

 

                              (2) This amount is mainly comprised of net CAISO open market purchases, offset by transmission and distribution related system losses.

 

Diablo Canyon Power Plant.   The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  For the twelve months period ended December 31, 2012, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 90%.  The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025.  For more information on matters affecting Diablo Canyon, see the section of MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2012 Annual Report, which information is incorporated herein by reference.  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 15: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

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 43.6 days.  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

 

 

    Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 109 generating units at 68 powerhouses, including the Helms pumped storage facility.  Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW.  The Helms pumped storage facility consists of three motor/generator units.  During 2011, the Utility began inspections of all three units following reports of a significant failure of a similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue.   The Utility completed inspections and repairs on each of the three units and returned them to service in 2012.

 

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.  The Utility is in the process of renewing hydroelectric licenses associated with capacity of approximately 1,137 MW and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of 5 MW.  Although the original licenses associated with 880 MW of the 1,137 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 3,002 MW of hydroelectric power will expire between 2013 and 2047.

 

Fossil Fuel-fired Generation Facilities. The Utility’s natural gas-fired generation facilities include the Colusa Generating Station, the Gateway Generating Station, and the Humboldt Bay generating station.  In addition, the Utility owns and operates three fuel cell sites in the Bay Area.   On December 20, 2012, the CPUC approved an amended purchase and sale agreement between the Utility and a third-party developer that provides for the construction of a 586-megawatt natural gas-fired facility in Oakley, California  that would be acquired by the Utility no sooner than January 1, 2016. 

 

Photovoltaic Facilities.   In April 2010, the CPUC approved the Utility’s five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities to be owned and operated by the Utility, along with entering into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.  Under the PV program, Utility-owned PV facilities with an aggregate of 100 MW are operational, and an additional 50 MW are under construction and expected to become operational in 2013.  The operational PV facilities include, the Five Points solar station (15 MW), the Westside solar station (15 MW), the Stroud solar station (20 MW), the Huron solar station (20 MW), the Cantua solar station (20 MW), and the Giffen solar station (10 MW).   All of these facilities are located in Fresno County.  The PV facilities under construction are the Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW).  The Gates and West Gates solar stations are located in Fresno County; the Guernsey solar station is located in Kings County.

 

In December 2012, the Utility sought CPUC approval to terminate the PV program early.  If approved, the Utility will not pursue the development of the remaining 100 MW of Utility-owned PV facilities over the remaining two years of the program, but instead will procure this capacity through the CPUC’s Renewable Auction Mechanism (“RAM”) process.  Additionally, the Utility proposed to solicit the remaining 152 MW of capacity to be provided under power purchase agreements through the RAM process rather than through the PV program.

 

Generation Resources from Third Parties

 

QF Power Purchase Agreements.   Under the Public Utility Regulatory Policies Act (“PURPA”) of 1978 electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”).  In June 2011, the FERC approved the California investor-owned utilities’ joint application to terminate their obligation under PURPA to purchase QF energy and capacity from facilities exceeding 20 MW.  QFs primarily include   co-generation facilities that produce combined heat and power and renewable generation facilities.  As of December 31, 2012, the Utility had power purchase agreements with 180 operating QFs for approximately 3,000 MW of capacity.  The majority of this capacity is from cogeneration facilities and the remainder is from renewable generation facilities.  Agreements for approximately 2,700 MW expire at various dates between 2013 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.  No single QF accounted for more than 5% of the Utility’s 2012 electricity deliveries.

 

Irrigation Districts and Water Agencies.   The Utility also has entered into agreements with various irrigation districts and water agencies to purchase hydroelectric power.  These agreements require the Utility to make semi-annual fixed minimum payments as well as variable payments based on the operating and maintenance costs incurred by the irrigation districts and water agencies.  These contracts will expire on various dates between 2013 and 2030.

 

Other Third-Party Power Purchase Agreements .  The Utility has entered into several power purchase agreements for renewable and conventional generation resources, including tolling agreements and resource adequacy agreements.

 

For more information regarding the Utility’s power purchase agreements, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

Renewable Generation Resources

 

Renewable generation resources include bioenergy such as biogas and biomass, small hydroelectric, wind, solar, and geothermal energy.  California’s Renewables Portfolio Standard (“RPS”) program gradually increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from an average of at least 20% of their total retail sales in the years 2011-2013 to 33% of their total retail sales in 2021 and thereafter.  For more information regarding the new RPS program, see the section of MD&A entitled “Environmental Matters – Renewable Energy Resources” in the 2012 Annual Report, which information is  incorporated herein by reference.

 

During 2012, most renewable energy deliveries resulted from third party power purchase agreements and QF agreements.  Additional renewable resources included the Utility’s small hydroelectric and solar facilities and certain irrigation district contracts (small hydroelectric facilities).  (Under California law only small hydroelectric generation resources (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 the 30-MW threshold and do not qualify as RPS-eligible resources.)

 

Total 2012 renewable deliveries are stated in the table below.

 

 

For more information regarding the Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

Electricity Transmission 

 

At December 31, 2012, the Utility owned approximately 18,100 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV.  The Utility also operated 91 electric transmission substations with a capacity of approximately 60,800 MVA.  The Utility’s electric transmission system is interconnected with electric power systems in the WECC, which includes many western states, Alberta and British Columbia, Canada, and parts of Mexico.

 

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 its own 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 by the FERC, 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 under “The Utility’s Regulatory Environment — Federal Regulation” above.

 

During 2012, the Utility upgraded several critical substations and re-conductored some transmission lines to improve maintenance and operating flexibility, reliability and safety, including the installation or replacement of 9 transmission substation banks.  The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system and increase capacity in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, and to improve system reliability.

 

Electricity Distribution

 

The Utility's electricity distribution network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 58 transmission-switching substations, and 601 distribution substations.   The Utility’s distribution network interconnects with  the Utility’s transmission system primarily at transmission switching substations and 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.

 

In 2012, the Utility replaced more than 130,000 feet of underground cable, primarily in San Francisco and Oakland, replaced 98,000 feet of overhead wire, and installed or replaced 39 distribution substation transformer banks to improve reliability and provide capacity to accommodate growing demand.  The Utility plans to continue performing work to improve the reliability and safety of its electricity distribution operations in 2013.

 

               

 

Natural Gas Utility Operations

 

During 2012, the Utility has taken many immediate and longer-term steps to improve the safety and reliability of its natural gas transmission system, including performing extensive pipeline testing and monitoring, and replacing and upgrading equipment.  Much of this work is part of the Utility’s pipeline safety enhancement plan (“PSEP”), approved by the CPUC in December 2012, to meet the new, industry-wide safety standards for gas transmission systems.  (See the information within MD&A under the heading “Natural Gas Matters” in the 2012 Annual Report, which information is incorporated herein by reference.)

 

In 2012, as part of the PSEP pipeline modernization program, the Utility confirmed the strength of 202 miles of transmission pipeline through hydrostatic pressure tests or records verification, installed 46 automated or remote-controlled valves, replaced 40 miles of transmission pipeline, and retrofitted 78 miles of transmission pipeline to accommodate in-line inspection tools.  Since work on the program began in 2011, the Utility has also collected and digitized more than 3.5 million pipeline records, which includes validating the Maximum Allowable Operating Pressure (“MAOP”) for more than 89 percent of its gas transmission system (and 100 percent of the 2,088 miles of the Utility’s transmission pipelines in populated areas).

 

The Utility is also improving operations by utilizing modern tools and technologies.  In 2012, the Utility began demonstrating a new car-mounted natural gas leak detection device, which is much more sensitive than traditional instruments. The Utility also began using an advanced hand-held leak-detection instrument that uses infrared technology to pinpoint methane gas without false alarms from other gases. This technology can detect and grade leaks at the same time.  In addition, the Utility improved its supervisory controls and data acquisition system (“SCADA”) to better detect pipeline leaks and breaks and improved its integrity management program, including incorporating new analysis tools to identify and assess risks to pipeline integrity.

 

For the distribution system, the Utility has implemented a new distribution integrity management program designed to enhance operations and improve the overall safety of the gas distribution system.  In 2012, the Utility replaced 23 miles of Aldyl-A plastic pipeline and identified another 150 miles to be replaced over the next two years. It also updated the geographic information system with information on more than 5,500 miles of Aldyl-A pipeline, including additional pipeline and service attribute information.  The Utility also completed additional distribution leak surveys in 2012, in addition to complying with regular distribution leak survey requirements.

 

Many of these improvement efforts satisfy recommendations made to the Utility by the NTSB and the CPUC in 2010 and 2011.  In the first half of 2012, the Utility was able to officially close out four of the twelve NTSB recommendations. In January 2013, the Utility requested closure on three more recommendations. The Utility continues to make significant progress on the remaining longer-term recommendations, and the NTSB stated in September 2012 that the Utility’s progress was acceptable.

 

In December 2012, the CPUC accepted the gas safety plans submitted by each gas corporation in California, including the Utility, to describe each gas corporation’s programs, plans, and initiatives, to increase the safety and reliability of their natural gas operations.  The plans were submitted in compliance with California Senate Bill 705, enacted in October 2011, which requires each gas corporation subject to CPUC jurisdiction to develop and implement a plan for the safe and reliable operation of its gas pipeline system. The new law required the CPUC to review the plans and accept, modify, or reject each plan by December 31, 2012.  The CPUC has ordered the Utility, as well as the other gas corporations, to submit modifications to their plans by June 2013 and to continually review, revise and update their plans as required by emerging issues, industry practices, and state and federal regulators.

 

Natural Gas System Assets

 

The Utility owns and operates an integrated natural gas transportation, storage, and distribution system that includes most of northern and central California.  At December 31, 2012, the Utility’s natural gas system consisted of approximately 42,400 miles of distribution pipelines, approximately 6,400 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations which receive, store and move natural gas through the Utility’s pipelines.  (The Utility has incurred significant environmental liabilities related to some of its compressor stations. See “Environmental Matters” below.)  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 interconnects with pipeline systems located in the U.S. Southwest and the Rocky Mountains that are owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company).  Line 300 has a receipt capacity of approximately 1.1 Bcf per day.  The Utility’s Line 400/401 interconnects at the California-Oregon border with the pipeline systems owned by Gas Transmission Northwest Corporation (“GTN”) and Ruby Pipeline, LLC.  This line has a receipt capacity at the border of approximately 2.2 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 and has a 25% interest in the new Gill Ranch Storage Field.  These storage fields and the Utility’s Gill Ranch share have a combined firm capacity of approximately 48.7 Bcf.  In addition, three independent storage operators are interconnected to the Utility's northern California transportation system.

 

Natural Gas Services

 

The CPUC divides the Utility’s on-system natural gas customers into two categories for the purpose of determining service reliability: 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 small commercial natural gas customers.  The non-core customer class is comprised of industrial, large commercial, and electric generation natural gas customers.  In 2012, core customers represented more than 99% of the Utility’s total natural gas customers and 36% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 64% of its total natural gas deliveries.   In addition to deliveries discussed above, the Utility delivers gas to off-system customers ( i.e ., outside of the Utility’s service territory) and to third-party natural gas storage customers.

 

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 96% of core customers, representing over 83% of the annual core market demand, receive bundled natural gas service from the Utility.

 

The Utility does not provide procurement service to large non-core customers such as electricity generators, QF co-generators, enhanced oil recovery customers, refiners, and other large non-core customers.  However, some smaller non-core customers are permitted to elect to receive core service, including procurement service, from the Utility if they agree to receive such service for a minimum of five years.  Core service to non-core customers is subject to these restrictions to protect core procurement customers from price increases that could otherwise result if the Utility incurred costs to reinforce its pipeline system and take other measures to provide core service reliability on a short-term basis to serve new load from non-core customers.

 

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, energy efficiency measures, or changes in their consumption levels.  The Utility’s results of operations can be affected, however, 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 the remainder from non-core customers.

 

Natural Gas Supplies

 

The Utility purchases natural gas to serve its core customers directly from producers and marketers in both Canada and the United States.  The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions.  During 2012, the Utility purchased approximately 247,792 MMcf of natural gas (net of the sale of excess supply of gas).  Substantially all this natural gas was purchased under contracts with a term of one year or less.  The Utility’s largest individual supplier

represented approximately 10% of the total natural gas volume the Utility purchased during 2012.

 

Interstate and Canadian Natural Gas Transportation Services Agreements

 

The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands.  The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System.  These companies’ pipeline systems connect at the border to the pipeline system owned by GTN, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon.  The Utility, the largest firm shipper on GTN’s pipeline, has two firm transportation agreements with GTN for these services.  In addition, the Utility has firm transportation agreements with Ruby Pipeline, LLC to transport this gas from the U.S Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border, and firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

 

Natural Gas Deliveries

 

The total volume of natural gas delivered to on-system customers during 2012 was approximately 945 MMDth.  The following table shows the percentage of the Utility’s total 2012 natural gas deliveries represented by each of the Utility’s major customer classes.

 

Residential Customers	20%
Transport-only Customers (non-core)	75%
Commercial Customers	5%

 

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 2012 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 0.3% for the years 2010 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.

 

Public Purpose and Customer Programs

 

California law has historically required the CPUC to authorize certain levels of funding for programs related to energy efficiency, research and development, and renewable energy resources through the collection of an electric public goods charge.  The legislation authorizing the public goods charge expired on January 1, 2012.  The CPUC has ordered the Utility to continue to collect in electric rates the amounts that were previously funded through the public goods charge for energy efficiency and established an energy program investment charge to support ongoing energy efficiency and research and development.  Gas public interest research continues to be funded through the gas public purpose program surcharge.  California law requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed under “Self-Generation Incentive Program and California Solar Initiative,” below.  Additionally, the CPUC has authorized funding for energy savings assistance and demand response programs.  For 2012, the Utility collected authorized revenue requirements of $688 million from electric customers and $169 million from gas customers to fund public purpose and other programs.

Energy Efficiency Programs

 

The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances, other energy-using equipment and energy management products to meet energy savings goals in California.  The CPUC has authorized a total of $823 million to fund the Utility’s 2013 and 2014 energy efficiency programs, including programs administered by the Marin Energy Authority, a CCA, and a regional network of San Francisco Bay area cities and counties.

 

On December 20, 2012, the CPUC approved a new energy efficiency incentive mechanism to reward the Utility and other California energy utilities for the successful implementation of their 2010-2012 energy efficiency programs.  The mechanism provides each utility with an earnings rate composed of a 5% management fee based on qualified program expenditures and an additional performance bonus of up to 1%.  The Utility’s earnings rate for the 2010-2012 energy efficiency program cycle is 5.68%.  The CPUC awarded the Utility $21 million for the successful implementation of the Utility’s 2010 energy efficiency programs.  The CPUC decision also established the process that is expected to apply to incentive claims for program years 2011 and 2012.  After the CPUC completes its audit of the utilities’ 2011 program expenditures, the utilities must file their incentive claims in the third quarter of 2013 for approval by the CPUC in the fourth quarter of 2013.  Similarly, the utilities will file their incentive claims based on the CPUC-audited 2012 program expenditures in the third quarter of 2014 for approval by the CPUC in the fourth quarter of 2014.  

 

It is uncertain what form of incentive ratemaking the CPUC will establish and what amount, if any, the Utility will be authorized to earn for future energy efficiency programs.

 

Demand Response Programs

 

Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use.  In April 2012, the CPUC authorized the Utility to collect $192 million to fund its 2012-2014 demand response programs.  Due to the timing of the decision, the CPUC authorized the Utility to recover both 2012 and 2013 program costs through customer rates collected in 2013.

 

Self-Generation Incentive Program and California Solar Initiative

 

The Utility administers the self-generation incentive program authorized by the CPUC to provide incentives to electricity and gas customers who install certain types of clean or renewable distributed generation and energy storage resources that meet all or a portion of their onsite energy usage.  In December 2011, the CPUC approved continuing annual funding for the self-generation incentive program of $36 million through 2014, with any carryover funds to be administered through 2015.  The Utility also administers the California Solar Initiative in its service territory.  The CPUC has authorized the Utility to collect approximately $1.1 billion from 2007 through 2016 to fund customer incentives for the installation of retail solar energy projects to serve onsite load, as well as to fund research, development, and demonstration activities, and administration expenses.  The current overall objective of this initiative is to install 3,000 MW (through both California investor-owned electric utilities and municipal electric utilities) through 2016.

 

Low-Income Energy Efficiency Programs and California Alternate Rates for Energy

 

The CPUC has authorized the Utility to collect approximately $469 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2012 through 2014.  The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers.  This rate subsidy is paid for by the Utility’s other customers.  During any given year, the extent of the subsidy for customers collectively depends upon the number of customers participating in the program and their actual energy usage.  In 2012, the amount of this subsidy was approximately $851 million.  The CPUC also authorized the Utility to recover approximately $45 million in administrative costs relating to the CARE subsidy through 2014.

 

 

 

Environmental Matters

 

The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public.  These laws and requirements relate to a broad range of activities, including the following:

 

·	the discharge of pollutants into the air, water, and soil;

·	the transportation, handling, storage and disposal of spent nuclear fuel;

·	the identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting, remediation and emergency response in connection with hazardous and radioactive substances;

·	the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and

·	the environmental impacts of land use, including endangered species and habitat protection.

 

The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions.  These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations.  To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify, or replace equipment, acquire permits and/or emission allowances or other emission credits for facility operations and clean-up, or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where the Utility’s wastes may have been disposed.

 

The Utility’s estimated costs to comply with environmental laws and regulations are based on current estimates and assumptions that are subject to change.  In addition, the Utility is likely to incur costs as it develops

and implements strategies to mitigate the impact of its operations on the environment, including climate change and its foreseeable impact on the Utility’s future operations.  The actual amount of costs that the Utility will incur is subject to many factors, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility, the availability of recoveries or contributions from third parties, and the development of market-based strategies to address climate change.  Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review.  Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a special ratemaking mechanism described under “Recovery of Environmental Remediation Costs” below.

 

Air Quality and Climate Change

 

The Utility's electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes.  These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate matter.

 

Federal Regulation .  At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act.  Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted..  In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement.

 

State Regulation.   AB 32 requires the gradual reduction of state-wide GHG emissions to the 1990 level by 2020. The CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce AB 32.  The CARB established a state-wide GHG 1990 emissions baseline of 427 million metric tons of CO2 (or its equivalent) to serve as the 2020 emissions limit for the state of California.  The CARB has approved various regulations to implement AB 32, including a state-wide, comprehensive “cap and trade” program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by the major sources of GHG emissions.

 

The cap and trade program’s first two-year compliance period, which began January 1, 2013, applies to the electricity generation and large industrial sectors.  The next two-year compliance period, from January 1, 2015 through December 31, 2017, will expand to include the natural gas supply and transportation sectors, effectively

covering all the capped sectors until 2020.  Each year the CARB will issue emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHGs emissions allowed for that year.  Emitters can obtain allowances from the CARB at quarterly auctions held by the CARB or from third parties on the secondary market for trading GHG allowances.  The CARB’s first quarterly auction was held on November 14, 2012. Emitters (also known as covered entities) are required to obtain and surrender allowances equal to the amount of their GHGs emissions within a particular compliance period. Emitters may also meet up to 8% of their compliance obligation through the purchase of “offset credits” which represent GHG emissions abatement achieved in sectors that are not subject to the cap.  For more information about the cap-and trade program, see the section of MD&A entitled “Environmental Matters” in the 2012 Annual Report, which information is incorporated herein by reference.

 

Increasing use of renewable energy supplies also is expected to help reduce GHG emissions in California.  In April 2011, the California Governor signed legislation that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy delivered to their customers to at least 33% of the total amount of electricity retail sales by 2020.  (See “Electricity Resources” above.)  In December 2011, the CPUC approved various regulations to implement the new law, including the establishment of renewable energy targets for each compliance period.  (For more information, see “Renewable Generation Resources” above.)

 

Climate Change Mitigation and Adaptation Strategies.   During 2012, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to develop its strategy to plan for the actions that it will need to take to adapt to the likely impacts that climate change will have on the Utility’s future operations.  With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme and frequent hot weather events.  Climate scientists also predict that climate change will result in significant reductions in snowpack in parts of the Sierra Nevada Mountains.  This impact could, in turn, affect the Utility’s hydroelectric generation.  At this time, the Utility does not anticipate that reductions in Sierra Nevada snowpack will have a significant impact on its hydroelectric generation, due in large part to its adaptation strategies. For example, one adaptation strategy the Utility is developing is a combination of operating changes that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes in response to an increased portion of precipitation falling as rain rather than snow, and reduced discretionary reservoir water releases during the late spring and summer.  If the Utility is not successful in fully adapting to projected reductions in snowpack over the coming decades, it may become necessary to replace some of its hydroelectric generation with electricity from other sources, including GHG-emitting natural gas-fired power plants.

 

With respect to natural gas operations, safety-related pipeline hydrotesting, as well as normal pipeline maintenance, releases the GHG methane to the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression. In addition, the Utility continues to replace a substantial portion of its older cast iron and steel gas mains with new pipe, which reduces leakage.

 

The Utility believes its strategies to reduce GHG emissions—such as energy efficiency and demand response programs, infrastructure improvements, and the support of renewable energy development—are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to result from climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.

 

Emissions Data

 

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas.  As a result of the time necessary for a thorough, third-party verification of the Utility’s GHG emissions, emissions data for 2011 are the most recent data available.  Since 2009, the Utility has complied with AB 32’s annual GHG emissions reporting requirements, reporting combustion emissions from its electric generation facilities and natural gas compressor stations to the CARB.  (For information about the sources of electric generation that the Utility delivered to customers in 2012, see “Electric Utility Operations− Electricity  Resources” above.)   Consistent with Utility practice since 2002, the Utility also voluntarily reported its 2011 GHG emissions to The Climate Registry (“TCR”), a non-profit organization that has a reporting and measurement standard applicable to most industry sectors across North America.  Reporting to TCR enables the Utility to publicly report GHG emissions not covered by mandatory reporting requirements.  The Utility’s third-party verified voluntary GHG

inventory for 2011 totaled more than 50 million metric tonnes of CO2-equivalent (“CO2-e”), which includes approximately 33 million metric tonnes CO2-e from customer natural gas use.

 

Beginning with its 2010 emissions, the Utility also reported the GHG emissions from its facilities and operations to the EPA under its mandatory reporting requirements. PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

 

 

(1) Includes nitrous oxide (“N2O”) and methane (“CH4”) emissions from the Utility’s generating stations; does not include de minimis emissions.

(2) Includes compressor stations emitting more than 25,000 metric tonnes of CO2-e annually; does not include de minimis emissions.

(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the exception of gas delivered to other natural gas local distribution companies. This figure does not represent the Utility’s compliance obligation under AB 32, which will be equivalent to the above reported value less the fuel that is delivered to covered entities as calculated by the CARB.

 

 

                                                (1)  Source: Environmental Protection Agency eGRID 2012 Version 1.0, which contains year 2009 information configured to reflect the electric power industry's current structure as of May 10, 2012.  This is the

                                     most up-to-date information available from EPA.

 

                                                 (2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator.  Therefore, there is some unavoidable

                                     uncertainty in the Utility’s total emissions and the Utility’s emission rate  for delivered electricity.

 

 

 

Water Quality

 

Section 316(b) of the federal Clean Water Act requires that cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, reflect the best technology available to minimize adverse environmental impacts.  On April 20, 2011, the EPA published draft regulations that propose specific reductions for impingement (which occurs when larger organisms are caught on water filter screens) and provide a case-by-case site specific assessment to establish compliance requirements for entrainment (which occurs when organisms are drawn through the cooling water system).  The proposed site specific assessment allows for the consideration of a variety of factors including social costs and benefits, energy reliability, land availability, and non-water quality adverse impacts.  The draft regulations were subject to public comment.  In June 2012, the EPA issued a Notice of Data Availability proposing changes to the draft regulations which, if adopted, would provide more flexibility in complying with some of the requirements.  The EPA is required to issue final regulations by July 2013.

 

On May 4, 2010, the California Water Resources Control Board (“California Water Board”) adopted a policy on once-through cooling.  The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%.  However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the California Water Board in developing its policy.  The policy also allows other compliance measures to be taken if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts.  The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of proportion” test.  The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.”  The policy also established a nuclear review committee to evaluate the feasibility and cost of alternative technologies for nuclear plants.  The committee’s consultant, Bechtel, must complete an assessment for the California Water Board’s review by October 2013.  Upon review of the feasibility assessment, if the California Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects.  If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon, may need to procure substitute power, and may incur a material charge.  The Utility would seek to recover such costs in rates.  The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.

 

Hazardous Waste Compliance and Remediation

 

The Utility's facilities are subject to the requirements issued by the EPA under the federal Resource Conservation and Recovery Act (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”), as well as other state hazardous waste laws and other environmental requirements.  CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the

environment.  These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site, and in some cases corporate successors to the operators or arrangers.  Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources, and the costs of required health studies.  In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of hazardous substances and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

 

The Utility has a comprehensive program in place to comply with federal, state, and local laws and regulations related to hazardous materials and hazardous waste compliance, remediation activities, and other environmental requirements.  The Utility assesses and monitors, on an ongoing basis, measures that may be necessary to comply with these laws and regulations and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control (“DTSC”), several California regional water quality control boards, and various other federal, state, and local agencies.

 

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws.  These sites include former manufactured gas plant (“MGP”) sites; current and former power plant sites; former gas gathering and gas storage sites; sites where natural gas compressor stations are located; current and former substations, service centers, and general construction yard sites; and sites currently and formerly used by the Utility for the storage, recycling, or disposal of hazardous substances.  Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

 

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.  For more information about environmental remediation liabilities, see the sections within MD&A entitled “Environmental Matters,” “Critical Accounting Polices,” and Note 15:  Commitments and Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

Generation Facilities

 

Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater.  Although the Utility sold most of its geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws.  The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.  Fossil fuel-fired Units 1 and 2 of the Utility’s Humboldt Bay power plant shut down in September 2010, and are now in the decommissioning process along with the nuclear Unit 3, which was shut down in 1976.  The Utility has entered into a voluntary cleanup agreement with the DTSC and is currently completing a soil and groundwater investigation to determine what soil and groundwater remediation may be necessary.

 

Former Manufactured Gas Plant Sites

 

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired MGP sites.  During their operation, from the mid-1800s through the early 1900s, MGPs produced lampblack and coal tar residues.  The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous.  The Utility has been coordinating with environmental agencies and third-party owners to evaluate and take appropriate action to mitigate any potential environmental concerns at 41 MGP sites that the Utility owned or operated in the past.  Of these sites owned or operated by the Utility, 40 sites have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site.  The Utility spent approximately $51 million in 2012 on these sites.

 

Third-Party Owned Disposal Sites

 

Under environmental laws, such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated clean-up

costs or natural resource damages.  The Utility is currently aware of two such sites where investigation or clean-up activities are currently underway.  At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator.  The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties.  For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and remediation measures.

 

Natural Gas Compressor Stations

 

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices.  The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.  The Utility has incurred significant environmental liabilities associated with these sites.  For more information about the Utility’s remediation and abatement efforts and related liabilities, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.

 

Recovery of Environmental Remediation Costs

 

The CPUC has authorized the Utility to recover most of its environmental remediation costs through various ratemaking mechanisms, subject to exclusions for certain sites, such as the Hinkley natural gas compressor site, and subject to limitations for certain liabilities such as amounts associated with fossil fuel-fired generation facilities formerly owned by the Utility.  For more information, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report which information is incorporated herein by reference.

 

Nuclear Fuel Disposal

 

Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities.  The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay Unit 3.  As a result, the Utility constructed an interim dry cask storage facility to store spent fuel at Diablo Canyon through at least 2024, and a separate facility at Humboldt Bay.  The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel. 

 

On September 5, 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010.  For more information, see Note 15: Commitments and Contingencies−Environmental Remediation Contingencies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.  Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.

Nuclear Decommissioning

 

The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3.  Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates.  Nuclear decommissioning charges collected through rates are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.   (See the discussion of the 2012 Nuclear Decommissioning Cost Triennal Proceeding in Note 2: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in the 2012 Annual Report, which information is incorporated herein by reference.)

 

Endangered Species

Many of the Utility's facilities and operations are located in, or pass through, areas that are designated as critical habitats for federal, or state-listed endangered, threatened, or sensitive species.  The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated at or near the Utility's facilities or operations.  The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with state and federal endangered species acts.  The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.