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 ofby 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 Public Utilities Commission

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 transmission 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 enforces state laws and regulations that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas and electric facilities. The CPUC can impose penalties of up to $50,000 per day, per violation, for violations that occurred after January 1, 2012.  (The statutory maximum penalty for violations that occurred before January 1, 2012 is $20,000 per violation.)  The CPUC has wide discretion to determine the amount of penalties based on the totality of the circumstances, including such factors as the gravity of the violations; the type of harm caused by the violations and the number of persons affected; and the good faith of the entity charged in attempting to achieve compliance, after notification of a violation. The CPUC also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged. 

As discussed above, in April 2015, the CPUC concluded its three investigative enforcement actions against the Utility by imposing penalties totaling $1.6 billion. (For more information about the Penalty Decision, see Item 1.A. Risk Factors and Note 13 of the Notes to the Consolidated Financial Statements in Item 8. below.) The CPUC is also conducting investigative enforcement proceedings relating to the Utility’s natural gas distribution facilities record-keeping practices and the Utility’s potential violations of the CPUC’s ex parte communication rules.  (See “Enforcement and Litigation Matters” in MD&A for more information.) Further, in August 2015, the CPUC began an investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. (For more information, see “Regulatory Matters” in MD&A.)

The CPUC has adopted separate gas and electric safety enforcement programs that authorize the SED to issue citations and impose fines for violations of certain regulations. Under both the gas and electric programs, the SED is required to impose the maximum statutory penalty of $50,000 for each separate violation and has the discretion to impose daily fines for continuing violations.  During 2016, the CPUC is expected to develop and implement improvements and refinements to the electric and gas safety citation programs, including steps to reconcile the differences between the two programs.

The California State 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, the development of energy storage technologies and facilities, and the development of a state-wide electric vehicle charging infrastructure.  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 also conducts audits and reviews of the Utility’s accounting, performance and compliance with regulatory guidelines.

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 MD&A and Item 1A. Risk Factors.) 

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 CAISO is responsiblethe FERC-approved regional transmission organization for providingthe Utility’s service territory.  The CAISO controls the operation of the electricity transmission system in California and provides open access electricity transmission service on a non-discriminatory basis,basis.  The CAISO also is responsible for 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.  (See “Electricity 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 additional significantsubstantial capital expenditures could be required in the future.  For more information about NRC matters affecting Diablo Canyon, including the status of the Utility’s relicensing application see the information under the heading within“Regulatory Matters – Diablo Canyon” in MD&A entitled “Regulatory Matters−Diablo Canyon Nuclear Power Plant” in the 2013 Annual Report, which information is incorporated herein by reference.

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 meet the AB 32, which requires the gradual reduction ofimplement state law requirements to gradually reduce GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2013.   (For more information, seeCalifornia.  (See “Environmental MattersRegulation — 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.  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.  (For more information, see “Environmental Matters — Water Quality” below.)

Both gas and electric rates vary depending on seasons mostly due to the revenue requirements are allocated among customer classes which are mainly residential, commercial, industrial, and agricultural.  Rate changes become effective prospectively on or afterinfluence of weather.  Gas service rates generally increase during the datewinter months (October through March) to account for the gas peak due to heating while electricity rates increase during summer (June – September) because of CPUC or FERC decisions.  Most rate changes approvedhigher summer costs, driven by air conditioning loads.

During 2015, the CPUC throughout the year are consolidatedcontinued to take effect on the first day of the following year.

From time to time, the CPUC to approve fixed charges to be collected from residential customers. The CPUC has ordered the California investor-owned utilities, includingmay use incentive ratemaking mechanisms that provide the Utility an opportunity to file proposalsearn some additional revenues.  For example, the Utility has earned incentives for changing residential rates that are consistent with the new law.  The current procedural schedule callssuccessful implementation of energy efficiency programs.  (See “Results of Operations” in MD&A.)  These mechanisms can also create financial risk. For a discussion of the re-opened proceeding to review incentive revenues awarded for a final decisionthe 2006-2008 energy efficiency cycle, see “Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards” in Note 13 of the first half of 2014 to approve changesNotes to the Utility’s residential electric rates for summer 2014, and a final decision by year-end 2014 to approve broader changesConsolidated Financial Statements in residential electric rates.

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 anddistribution, natural gas distribution, and Utility owned electricity generation operations and to provide the Utility an opportunity to earn its authorized rate of return.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 rate adjustments”) in revenue requirements for the subsequent years of the GRC period.  Attrition rate adjustments are generally provided for cost increases related to avoid a reduction in earnings due to, among other things, inflation and increases in invested capital.  Intervenorscapital and inflation.  Parties in the Utility's GRC include the CPUC’s ORA and TURN, who generally represent the overall interests of residential customers, as well as a myriad of other intervenors who represent more limitedresidential and other customer interests.

For more information seeabout the heading within MD&A entitledUtility’s current GRC proceeding, see “Regulatory Matters – 2014−2017 General Rate Case” in MD&A.

Natural Gas Transmission and Storage Rate Cases

The CPUC determines the 2013 Annual Report, which information is incorporated herein by reference.  

Electricity Resources

The Utility is required to maintain physical generating capacity adequate to meet its customers’ load,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. way.

The following table shows the percentage of the Utility’s total actual deliveries of electricity to customers in 20132015 represented by each major electricity resource, and further discussed below.

(2) Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 107 generating units at 67 powerhouses, including the Helms pumped storage facility.  Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their powerhouse capacity exceeds 30 MW.  The system includes 98 reservoirs, 73 diversions, 169 dams, 173 miles of canals, 43 miles of flumes, 132 miles of tunnels, 65 miles of pipe (penstocks, siphons and low head pipes), and 4 miles of natural waterways, and approximately 140,000 acres of fee-owned land. The system also includes water rights as specified in 89 permits or licenses and 160 statements of water diversion and use.  The Helms pumped storage facility consists of three motor/generator units.

(3) 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.

Generation Resources from Third Parties

Electricity Transmission 

Electricity Distribution

Electricity Operating Statistics

16

The Utility provides natural gas transportation services to all core“core” customers (i.e., small commercial and non-coreresidential 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 alternate energynon-utility third-party gas procurement service providers.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.

Natural Gas Supplies

Natural Gas Transportation Services Agreements

17

During 2015, the Utility conducted an annual system-wide review of its transmission pipeline class location designations.  The Utility also continued work to install 217 automatic and remote control shut-off valves on its gas transmission system, as specified in the eleventh of twelve safety recommendations made by the NTSB following its investigation of the San Bruno accident.  As of December 31, 2015, the Utility had installed 235 automatic and remote control shut-off valves, and the NTSB closed that recommendation.  The final safety recommendation, considered open and acceptable by the NTSB, involves hydrostatic testing nearly 1,000 miles of the Utility’s gas transmission system. The Utility has completed the majority of this task and currently plans to complete the task for the remaining approximately 100 of pipelines (involving primarily short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines) during 2018. Also, as part of the Utility’s distribution integrity management program, the Utility completed approximately 23,500 sewer inspections during 2015 to identify and correct conflicts between gas and waste water facilities.

Natural Gas Operating Statistics