ITEM 1. BUSINESS

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, 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 in 1997.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.  At the state level, the Utility is regulated primarily by the CPUC.  At the federal level, the Utility is subject to the jurisdiction of the FERC and the NRC.  PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found in Item 6. Selected Financial Data.

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) 973-1000 and the Utility’s telephone number is (415) 973-7000.

At December 31, 2014, PG&E Corporation and its subsidiaries had 22,581 employees, including 22,569 employees of the Utility.  Of the Utility’s regular employees, 13,649 are covered by collective bargaining agreements with the local chapters of three labor unions:  the International Brotherhood of Electrical Workers (“IBEW”); the Engineers and Scientists of California (“ESC”); and the Service Employees International Union (“SEIU”).  The two agreements with IBEW, and the single agreement with ESC, will expire on December 31, 2015.  The SEIU collective bargaining agreement will expire on July 31, 2015.

This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility.  PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, 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 part of this or any other report that PG&E Corporation and the Utility files with, or furnishes to, the SEC.

This Annual Report on Form 10-K 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 “Item 1A. Risk Factors” and the section entitled “Cautionary Language Regarding Forward-Looking Statements” in Item 7. MD&A.  In particular, PG&E Corporation’s and the Utility’s financial results are expected to be materially affected by the final outcome of the CPUC’s pending investigative enforcement proceedings against the Utility.  These investigations relate to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) 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 pipeline accident that occurred in San Bruno, California on September 9, 2010.  PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have been materially affected by the costs the Utility has incurred related to shareholder funded safety work, the ongoing regulatory investigations, and civil lawsuits that commenced following the San Bruno accident.  In addition, PG&E Corporation’s and the Utility’s financial results could be materially affected by the outcome of the federal criminal prosecution of the Utility and the other enforcement matters discussed in “Enforcement and Litigation Matters” in Item 7. MD&A.

Regulatory Environment 

The Utility's business is 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.  See “Enforcement and Litigation Matters” and “Ratemaking and Other Regulatory Proceedings” in Item 7. MD&A for discussion of specific pending regulatory matters that are expected to materially affect PG&E Corporation and the Utility.

PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC.  PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.

 

The California Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, and the development of energy storage technologies and facilities.  In addition, the CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs. 

The CPUC enforces state laws that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility electric and gas facilities.  The CPUC also has authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.  The CPUC has adopted a gas safety enforcement program and authorized the SED to issue citations and impose fines for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices.  (See “Enforcement and Litigation Matters” in Item 7. MD&A for information about the presiding officer decisions issued in the three CPUC investigative enforcement proceedings pending against the Utility and SED’s enforcement actions taken against the Utility.)  In December 2014, the CPUC also adopted an interim electric safety enforcement program that became effective January 1, 2015.  (On January 7, 2015, the Utility requested that the CPUC reconsider this decision.)  Under both the gas and electric programs, the SED can impose fines up to $50,000 per violation, per day.  The CPUC is expected to review both safety programs during 2015 to determine whether any further changes are needed.

 

In addition, the CPUC conducts audits and reviews of the Utility’s accounting, performance and compliance with regulatory guidelines, as well as investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies.  The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. (For more information, see “Liquidity and Financial Resources” in Item 7. MD&A and Item 1A. Risk Factors.)

The Federal Energy Regulatory Commission and the California Independent System Operator

The FERC has jurisdiction over the Utility's electricity transmission 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 regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations and the terms and rates of wholesale electricity sales.  The FERC also is charged with adopting and enforcing 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. The FERC has authority to impose fines of up to $1 million per day for violation of certain federal statutes and regulations.

The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory.  The CAISO controls the operation of the transmission system in California and provides open access transmission service on a nondiscriminatory basis.  The CAISO also is responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generation capacity, and ensuring that the reliability of the transmission system is maintained.

 

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.  (See “Electric Generation Resources” below.)  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 substantial capital expenditures could be required in the future.

 

Other Regulation

The California Energy Resources Conservation and Development Commission, commonly called the CEC, is the state's primary energy policy and planning agency.  The CEC is responsible for licensing all thermal power plants over 50 MW within California.  The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.

The 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 implement state law requirements to gradually reduce GHG emissions in California to 1990 levels by 2020.  (See “Environmental Regulation — Air Quality and Climate Change” below.)

In addition, 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.  The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.  The Utility has franchise agreements with approximately 300 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.

Ratemaking Mechanisms

The Utility’s rates for electricity and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service including a return on invested capital (“cost-of-service ratemaking”).  Before setting rates, the CPUC and the FERC conduct various proceedings to determine the annual amount that the Utility will be authorized to collect from its customers (“revenue requirements”).  The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (maintenance, administration and general expenses) and capital costs (depreciation, tax, and financing expenses).  In addition, the CPUC authorizes the Utility to collect revenues to recover costs that it is allowed to “pass-through” to customers, including its costs to procure electricity, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.

 

The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings.  The authorized rate of return on all other assets is set in the CPUC’s cost of capital proceeding.  Other than its electric transmission and certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume.  Regulatory balancing accounts, or revenue adjustment mechanisms, ensure that the Utility will fully collect its authorized base revenue requirements.  The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impact Earnings” in Item 7. MD&A) within its authorized base revenue requirements.

To develop retail rates, authorized revenue requirements are allocated among customer classes which are mainly residential, commercial, industrial, and agricultural.  Rate changes become effective prospectively on or after the date of CPUC or FERC decisions.

California AB 327, which became effective on January 1, 2014, repealed prior law that restricted the CPUC’s ability to change residential electric rates and to reduce the level of rate assistance for certain low-income customers.  AB 327 also authorized the CPUC to approve fixed charges to be collected from residential customers.  In 2012, the CPUC opened a rulemaking proceeding to examine residential rate design in California that, consistent with AB 327, allows the CPUC to simplify the rate structure to bring marginal rates closer to reflecting the Utility’s actual costs.  In February 2014, as ordered by the CPUC, the Utility submitted a long-term residential rate reform plan that proposes a fixed customer charge, gradual flattening of the tiered rate structure, and an optional time-of-use rate.  The CPUC is expected to issue a final decision by the summer of 2015.

AB 327 also requires the CPUC to develop a new structure for net energy metering by December 31, 2015, that must be implemented no later than July 1, 2017.  California’s net energy metering program currently allows customers installing renewable distributed generation to receive bill credits for power delivered to the grid at their full retail rate.  Increasing levels of self-generation of electricity by customers, coupled with net metering and retail rates that do not reflect the Utility’s cost structure, has shifted costs to the remaining customers.  AB 327 gives the CPUC new authority to reduce the cost shift associated with renewable distributed generation through residential rate and net energy metering reform.  In July 2014, the CPUC began a rulemaking proceeding to develop a successor to the existing net energy metering program to comply with the requirements of AB 327.  The CPUC is expected to issue a proposed decision in the fall of 2015.

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn additional revenues.  For example, the Utility has earned incentives for the successful implementation of energy efficiency programs.  (See “Results of Operations” in Item 7. MD&A.)

 

Base Revenues

 

General Rate Cases

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, including return on rate base, related to its electricity and natural gas distribution and Utility owned electricity generation operations.  The CPUC generally conducts a GRC every three years.  The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases (known as “attrition adjustments”) in revenue requirements for the subsequent years of the GRC period.  Attrition rate adjustments are generally provided for cost increases related to inflation and increases in invested capital.  Parties in the Utility's GRC include the ORA and TURN, who generally represent the overall interests of residential customers, as well as a myriad of other intervenors who represent residential and other customer interests.

On August 14, 2014, the CPUC issued a decision in the Utility’s 2014 GRC, authorizing the Utility to collect a total 2014 revenue requirement of approximately $7.1 billion to recover anticipated costs associated with electric generation, as well as electric and natural gas distribution (See “Results of Operations” in Item 7. MD&A.) The CPUC also authorized attrition increases of $324 million for 2015 and $371 million for 2016.  

On December 9, 2014, the CPUC issued a decision adopting a risk-based decision-making framework for the CPUC to use in evaluating future major rate cases.  The CPUC ordered the utilities to file an application on May 1, 2015, to initiate a new proceeding called the Safety Model Assessment Proceeding in which the CPUC will review the models the utilities use to assess and prioritize risks.  After this proceeding concludes, each utility would file an application to initiate the first phase of their next GRC.  In this phase, known as the Risk Assessment Mitigation Phase, the CPUC will examine the utility’s assessment of its key risks and its proposed programs for mitigating those risks.   

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 the GT&S rate case.  In December 2013, the Utility filed its 2015 GT&S rate case application (covering 2015 through 2017) requesting the CPUC approve a total annual revenue requirement of $1.29 billion for anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2015.  See “Ratemaking and Other Regulatory Proceedings – 2015 GT&S Rate Case” in Item 7. MD&A for additional information.  

Cost of Capital Proceedings

The CPUC periodically conducts a cost of capital proceeding to authorize the Utility's capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base.  The CPUC has authorized the Utility’s capital structure through 2016, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock.  The CPUC also authorized the Utility to earn a 10.40% ROE effective January 1, 2013, compared to the 11.35% previously authorized.  The Utility’s ROE can be automatically adjusted if the utility bond index changes by certain thresholds on an annual basis.  The index changes to date have not exceeded the threshold so the 2015 ROE has remained at 10.40%.  The Utility’s next cost of capital application is due in April 2016.

Electricity Transmission Owner Rate Cases

The FERC determines the amount of authorized revenue requirement, including rate of return on electric transmission assets, that the Utility may collect in rates in the TO tariff rate case.  The Utility generally files a TO tariff rate case every year.  The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision.  These FERC-approved rates are included by the CPUC in the Utility's retail electric rates and are collected from retail electric customers.  (See “Ratemaking and Other Regulatory Proceedings – FERC Transmission Owner Rate Cases” in Item 7. MD&A.)  The Utility also recovers revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in 1998.  These wholesale customers are charged individualized rates based on the terms of their contracts.

Revenues to Recover Energy Procurement and Other Pass-Through Costs

Electricity Procurement Costs

California investor-owned electric utilities are 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.  The utilities are responsible for scheduling and bidding electric generation resources, including electricity procured from third parties or the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”).  In addition, the utilities are required to obtain CPUC approval of their procurement plans based on long-term demand forecasts.  In January 2012, the CPUC approved the Utility’s procurement plan (covering 2012 through 2020).

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.  Costs associated with electricity purchases may be disallowed if they are not in compliance with the CPUC-approved plan or if the utility failed to follow the principles of least-cost dispatch.  The Utility recovers its electricity procurement costs annually through the energy resource recovery account (“ERRA”).  (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.)  Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG costs, and generation fuel expense and approves a forecasted revenue requirement.  The CPUC may adjust a utility’s retail electricity rates more frequently if the forecasted aggregate over-collections or under-collections in the ERRA exceed five percent of its prior year electricity procurement revenues.  The CPUC performs an annual compliance review of the transactions recorded in the ERRA.

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.  See “Electric Utility Operations – Electricity Resources” below as well as Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for additional information.

Natural Gas Procurement and Transportation Costs

The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs.  The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments through its retail gas rates subject to limits as set forth in its Core Procurement Incentive Mechanism (“CPIM”).  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.  This is accomplished through monthly advice letters that are effective upon filing.  The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electricity rates.

The CPIM protects the Utility against after-the-fact reasonableness reviews of these gas procurement costs.  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.

 

The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers.  These providers 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 agreements are governed by FERC-approved 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 a cost of electricity.

Costs Associated with Public Purpose and Customer Programs

The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers.  These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters.  Additionally, the CPUC has authorized the Utility to provide a discount rate for low-income customers, known as California Alternate Rates for Energy (“CARE”), which is subsidized by the Utility’s other customers.

Nuclear Decommissioning Costs

The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay.  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.

Electric Utility Operations

The Utility generates electricity and provides electricity transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers.  The Utility provides “bundled” services (i.e., electricity, transmission and distribution services) to most customers in its service territory.  Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations.

During 2014, the Utility continued to make improvements to its electric transmission and distribution systems to accommodate the integration of new renewable energy resources, distributed generation resources, and energy storage facilities, and to help create a platform for the development of new Smart Grid technologies.  The Utility plans to continue making similar improvements in 2015.  In December 2014, the CPUC issued a decision that permits the California investor-owned electric utilities to own EV retail charging equipment in their respective service territories to help meet the state’s goal of reducing GHG emissions by promoting cleaner transportation.  On February 9, 2015, the Utility filed an application to request that the CPUC approve the Utility’s proposal to develop, maintain, and operate an EV-charging infrastructure in its service territory.  (For more information about the Utility’s application, see “Ratemaking And Other Regulatory Proceedings” in Item 7. MD&A.)

Electricity Resources

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

The following table shows the percentage of the Utility’s total deliveries of electricity to customers in 2014 represented by each major electricity resource, and further discussed below.

(1) This amount excludes electricity provided to direct access customers and CCAs who procure their own supplies of electricity.

(2) Mainly comprised of net CAISO open market purchases.

(3) Non-renewable sources, including nuclear, large hydroelectric, and fossil fuel-fired are offset by transmission and distribution related system losses.

 

Renewable Energy Resources .  California law requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers to at least 33% of their total annual retail sales.  This program, known as the RPS program, became effective in December 2011, established three multi-year compliance periods that have gradually increasing RPS targets:  2011 through 2013, 2014 through 2016, and 2017 through 2020.  After 2020, the RPS compliance periods will be annual.

Renewable generation resources, for purposes of the RPS program, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy.  During 2014, 27% of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 23.3%.  Approximately 22% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties.  Additional renewable resources were provided by QFs (3.8%), the Utility’s small hydroelectric facilities (0.8%), and the Utility’s solar facilities (0.5%).

The total 2014 renewable deliveries shown above were comprised of the following:

 

Energy Storage.   As required by California law, the CPUC has established initial energy storage procurement targets to be achieved by each load-serving entity, such as the Utility.  The Utility has an 80.5 MW of energy storage target to meet its 2014 energy storage plan.  In December 2014, the Utility held its first competitive request for two types of proposals:  (1) an energy storage agreement with the owner of an energy storage facility that would enable the Utility to offer stored energy into the CAISO market and (2) a purchase and sale agreement under which the counterparty would build a storage facility and transfer the facility to the Utility provided the facility meets certain operational conditions.  Offers are due by February 17, 2015.  The Utility intends to complete negotiations and execute contracts by October 1, 2015 and to submit the executed contracts for CPUC approval by December 1, 2015.

Owned Generation Facilities.   At December 31, 2014, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:

(1) The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  For the year ended December 31, 2014, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 87%.  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.  (See Note 14 to the Consolidated Financial Statements in Item 8.)  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 49.5 days.  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.  The NRC operating licenses for the two operating units at Diablo Canyon include various license conditions related to seismic design and safety.  The current licenses expire in 2024 and 2025.  In November 2009, the Utility filed an application with the NRC to seek the renewal of the licenses, a process which can take several years.  After the March 2011 earthquake in Japan that damaged nuclear facilities, the NRC granted the Utility’s request to delay processing its renewal application until certain advanced seismic studies of the fault zones in the region surrounding Diablo Canyon were completed.  The seismic studies have been completed and in September 2014, the Utility submitted a report to the NRC and the CPUC’s Independent Peer Review Panel that confirmed the seismic safety of the plant.  The Independent Review Panel is providing comments on the report and the Utility expects its review to be completed within the next six to eight months.  (See also “Environmental Matters” and Item 1A. Risk Factors.)

(2) The Utility’s hydroelectric system consists of 107 generating units at 67 powerhouses.  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.

(3) The Utility’s larger operational photovoltaic 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), the Giffen solar station (10 MW), the Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW).  All of these facilities are located in Fresno County, except for the Guernsey solar station, which is located in Kings County.

 

Generation Resources from Third Parties.   The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan.  (See “Ratemaking Mechanisms” above.)  For more information regarding the Utility’s power purchase agreements, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

 

Electricity Transmission 

At December 31, 2014, the Utility owned approximately 18,100 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV.  The Utility also operated 91 electric transmission substations with a capacity of approximately 63,400 MVA.  The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, Alberta and British Columbia, and parts of Mexico.

In November 2013, the Utility, MidAmerican Transmission, LLC, and Citizens Energy Corporation were selected by the CAISO to jointly develop a new 230-kV transmission line to address the growing power demand in Fresno, Madera and Kings counties area.  The 70-mile line will connect the Utility-owned and -operated Gates and Gregg substations.  The new line will help reduce the number and duration of power outages, improve voltage in the area, support economic development, and bolster efforts to integrate clean, renewable energy onto the grid.  The transmission line is expected to commence operations by 2022, and could come online earlier.

Throughout 2014, the Utility upgraded several critical substations and re-conductored a number of transmission lines to improve maintenance and system flexibility, reliability and safety.  The Utility expects to undertake various additional transmission projects over the next several years to upgrade and expand the capacity of its transmission system to accommodate system load growth, secure access to renewable generation resources, replace aging or obsolete equipment and improve system reliability.  The Utility also has taken steps to improve the physical security of its transmission substations and equipment.

Electricity Distribution

The Utility's electricity distribution network consists of approximately 141,700 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 55 transmission switching substations, and 603 distribution substations, with a capacity of approximately 30,200 MVA.  The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.

These distribution substations serve as the central hubs for the Utility’s electric distribution network.  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 facilities to entities, such as municipal and other utilities, that resell the electricity.  In October 2014, the Utility commenced operations at the first of three new electric distribution control centers.  This 24,000-square foot, state-of-the-art facility, located in Fresno, California, will enhance electric reliability and resiliency for the Utility’s customers throughout the Central Valley and will utilize current and future Smart Grid technologies.  Additional facilities in Rocklin and Concord, California, are expected to be completed in 2015 and 2016, respectively.  These control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

In 2014, the Utility replaced approximately 295,000 feet of underground cable, replaced approximately 975,000 feet of overhead wire, and installed or replaced 20 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 2015.

(1) These amounts include electricity provided to direct access customers and CCAs who procure their own supplies of electricity.

(2) This activity is primarily related to a remittance of revenue to the Department of Water Resources (“DWR”) (the Utility acts as a billing and collection agent on behalf of the DWR), partially offset by other miscellaneous revenue items.

(3) These amounts represent revenues authorized to be billed.  The 2014 activity represents an increase to balancing account receivable primarily related to the adoption of the 2014 GRC.

 

Natural Gas Utility Operations 

The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory.  Core customers can purchase natural gas procurement service (i.e. , natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as core transport agents).  When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers.  When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service.  Currently, more than 91% of core customers, representing nearly 80% of the annual core market demand, receive bundled natural gas service from the Utility. 

The Utility does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers.  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 also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.

 

Natural Gas Supplies

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 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 2014, the Utility purchased approximately 269,590 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 17% of the total natural gas volume the Utility purchased during 2014.

Natural Gas System Assets

The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California.  At December 31, 2014, the Utility’s natural gas system consisted of approximately 42,700 miles of distribution pipelines, over 6,400 miles of backbone and local transmission pipelines, and various storage facilities.  The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines.  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 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 Gas Transmission Northwest, LLC, 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 also 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 the U.S. Southwest to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.  The Utility also has a transportation agreement with Kern River Gas Transmission Company to transport gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas system in the area of Daggett, California.  For more information regarding the Utility’s natural gas transportation agreements, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.

The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s transmission system.  The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later withdrawal.  In addition, four independent storage operators are interconnected to the Utility's northern California transmission system.

The Utility also owns and operates a 42,000-square-foot control center in San Ramon, California to monitor and control all aspects of its natural gas system across its service area. 

During 2014, the Utility completed its system-wide replacement of 847 miles of cast iron natural gas distribution pipeline with plastic pipe.  Additionally, the Utility conducted an annual system-wide review of its transmission pipeline class location designations.  As part of its distribution integrity management program, during 2014 the Utility completed inspections of approximately 35,000 sewer laterals.

Since work began on the PSEP and other gas transmission work in 2011, the Utility has validated the maximum allowable operating pressure for all of its transmission pipelines through records verification; accomplished four-year goal of strength testing or records validation of 783 miles of transmission pipeline; replaced 127 miles of transmission pipeline; automated 208 valves; and collected and digitized more than 3.8 million pipeline records.

 

Competition

Competition in the Electricity Industry

California law allows qualifying non-residential customers of investor-owned electric utilities to purchase electricity from energy service providers other than the regulated utilities, (referred to as “direct access”) up to certain annual and overall GWh limits that have been specified for each utility.  

 

The Utility’s customers may, under certain circumstances, obtain power from a CCA instead of from the Utility.  California law permits cities and counties and certain other public agencies to generate and/or purchase electricity for their local residents and businesses after they have registered as CCAs and submitted an Implementation Plan to the CPUC.  Under these arrangements, the Utility continues to provide transmission, 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.  The Utility is able 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.

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, either under a consensual transaction, or via eminent domain.

 

The Utility is also subject to increased competition due to the increasing viability of distributed generation and energy storage.  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.

 

Competition in the Natural Gas Industry

 

The Utility primarily 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 Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Environmental Regulation

The Utility’s operations are subject to extensive 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 remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of carbon monoxide (CO­ 2 ) and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; 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.  (See Item 1A. Risk Factors.)  Generally, the Utility has recovered most of 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 in Note 14: Contingencies—Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in Item 8.

Hazardous Waste Compliance and Remediation

The Utility's facilities are subject to the requirements of the federal Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (CERCLA).  The Utility is also subject to the regulations adopted by the EPA, the federal agency responsible for implementing the federal environmental laws.  The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies.  These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors.  Under CERCLA these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, paying for the harm caused to natural resources, and paying for the costs of required health studies.

The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations.  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.  The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control, several California regional water quality control boards, and various other federal, state, and local agencies.  The Utility has incurred significant environmental remediation liabilities associated with former manufactured gas plant sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances.  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.

For more information about environmental remediation liabilities, see Note 14:  Commitments and Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in Item 8.

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, CO 2 , sulfur dioxide (SO 2 ), mono-nitrogen oxide (NO x ), particulate matter, and other GHG emissions.

In December 2009, the EPA concluded that GHG emissions contribute to climate change and issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare.  In May 2014, the United States released its third National Climate Assessment, which stated that the global climate is changing and that impacts related to climate change are already evident in many sectors and are expected to become increasingly disruptive across the nation throughout this century and beyond.

Federal Regulation .  At the federal level, the 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.

In January 2014, the EPA published draft regulations under section 111(b) of the Clean Air Act to control CO­ 2, the most common GHG, from new fossil fuel-fired power plants.  While these draft regulations as presently written do not apply to the Utility’s power plants, it is possible that the final regulations may affect the design, construction, operation and cost of future fossil fuel-fired power plants.  The EPA is expected to issue final regulations in 2015.

In June 2014, the EPA published draft federal regulations under section 111(d) of the Clean Air Act that are designed to reduce CO 2 emissions from existing fossil fuel-fired power plants on a national basis by as much as 30% by 2030, compared with 2005 levels.  The EPA is expected to issue final regulations in 2015.  As proposed, once the EPA has finalized regulations, states have up to two or three years to submit final plans depending on whether they work alone or in partnership with other states, and up to 15 years for full implementation of all emission reduction measures.  It is uncertain whether and how these federal regulations will ultimately impact California, since existing state regulation currently requires, among other things, the gradual reduction of state-wide GHG emissions to 1990 levels by 2020.  As described below, the Utility expects all costs and revenues associated with the state-wide, comprehensive cap-and-trade program to be passed through to customers.

State Regulation.   California law requires the gradual reduction of state-wide GHG emissions to 1990 levels by 2020.  The CARB has approved various regulations to implement AB 32, including GHG emissions reporting and 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 major GHG emission sources within different sectors of the economy.  The cap–and-trade program’s first compliance period, which began on January 1, 2013, applied to the electricity generation and large industrial sectors.  The next compliance period, which began on January 1, 2015, expanded to include the natural gas and transportation sectors, effectively covering all the economy’s major sectors until 2020.  The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation.   During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year.  Emitters can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges.  Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside of the emitters’ facilities through CARB-qualified offset projects such as reforestation or biomass projects.  The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers.  The California RPS program that requires the utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California.

Climate Change Mitigation and Adaptation Strategies. During 2014, 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 plan for the actions that it will need to take to adapt to the likely impacts of climate change on the Utility’s future operations.  The Utility regularly reviews the most relevant scientific literature on climate change such as sea level rise, temperature changes, rainfall and runoff patterns, and wildfire risk, to help the Utility identify and evaluate climate change-related risks and develop the necessary adaptation strategies.  The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.

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, persistent, and frequent hot weather.  The Utility believes its strategies to reduce GHG emissions—through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage—are effective strategies for adapting to the expected increase in demand for electricity.  The Utility’s vegetation management activities also reduce the risk of wildfire impacts on electric and gas facilities.  Over the long-term, the Utility also faces the risk of higher flooding potential at coastal and low elevation facilities due to sea level rise.

Climate scientists also predict that climate change will result in significant reductions in snowpack in parts of the Sierra Nevada Mountains.  This could, in turn, affect the Utility’s hydroelectric generation.  To plan for this potential change, the Utility is engaging with state and local stakeholders and also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and developing new modeling tools for forecasting runoff.

With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere.  The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting.  In addition, the Utility continues to replace a substantial portion of its older cast iron, steel and plastic distribution pipelines and steel gas transmission mains with new pipe, which reduces leakage.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas.  The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, The Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization.  The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2013 totaled more than 57 million metric tonnes of CO­ 2 -e, two-thirds of which came from natural gas use.  The following table shows the 2013 GHG emissions data the Utility reported to the CARB under AB 32. PG&E Corporation and the Utility publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.

(2) Includes compressor stations emitting more than 25,000 metric tonnes of CO 2 -e annually.

(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, including entities that have their own compliance obligation under AB 32.  The Utility’s compliance obligation under AB 32 (discussed above under “State Regulation”) applies to the combustion of natural gas delivered to customers other than customers that have their own compliance obligation. Excluding the GHG emissions of entities that have their own compliance obligation, the Utility’s GHG emissions for 2013 were approximately 19 million metric tonnes, as calculated by the CARB.

 

                    The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2013 as compared to the national and California averages for electric utilities:

(1) Source: EPA eGRID.

(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 emissions rate.

 

Water Quality

On May 19, 2014, the EPA issued final regulations to implement the requirements of the federal Clean Water Act that require cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts.  The federal regulations provide more flexibility in complying with some of the Clean Water Act’s requirements.  Various industry and environmental groups have challenged the federal regulations in proceedings pending in the U.S. Court of Appeals for the Fourth Circuit.  California’s once-through cooling policy discussed below is considered to be at least as stringent as the new federal regulations.  Therefore, California’s implementation process for the state policy will likely continue without any significant change.

 

At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%.  The California Water Board has appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at Diablo Canyon.  The committee’s consultant submitted its final report to the California Water Board in September 2014 and the board is expected to issue a final decision regarding Diablo Canyon’s compliance with the state policy in 2015.  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 and may incur a material charge.  Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliances measures or to make payments to support various environmental mitigation projects. 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.

The final requirements of the federal and state cooling water policies could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement.  (See “Diablo Canyon Power Plant” in Item 3. Legal Proceedings below.)

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’ customers.  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.  As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until such time as the DOE fulfills its contractual obligation to take possession of the spent fuel.  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. 

In September 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.  The settlement agreement also provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs.  In 2013 and 2014, the Utility was awarded an additional $50 million for costs incurred between 2011 and July 2014.  These proceeds are being refunded to customers through rates.  The settlement agreement, as amended, does not address costs incurred for spent fuel storage beyond 2016 and such costs could be subject to future litigation.  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.