UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

---

FORM 10-K

(Mark One)
	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2015
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _________ to  ___________

 

 

 

77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (415) 973-1000 (Registrant's telephone number, including area code)

77 Beale Street, P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (415) 973-7000 (Registrant's telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class		Name of each exchange on which registered
PG&E Corporation: Common Stock, no par value		New York Stock Exchange
Pacific Gas and Electric Company: First Preferred Stock, cumulative, par value $25 per share:		NYSE Amex Equities
Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%
Nonredeemable: 6%, 5.50%, 5%

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

PG&E Corporation	Yes ☑ No ☐
Pacific Gas and Electric Company	Yes ☑ No ☐

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:

PG&E Corporation	Yes ☐ No  ☑
Pacific Gas and Electric Company	Yes ☐ No  ☑

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

PG&E Corporation	Yes ☑ No ☐
Pacific Gas and Electric Company	Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):

 

PG&E Corporation		Pacific Gas and Electric Company
Large accelerated filer ☑		Large accelerated filer ☐
Accelerated filer ☐		Accelerated filer ☐
Non-accelerated filer ☐		Non-accelerated filer ☑
Smaller reporting company ☐		Smaller reporting company ☐

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

PG&E Corporation	Yes ☐ No ☑
Pacific Gas and Electric Company	Yes ☐ No ☑

 

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2015, the last business day of the most recently completed second fiscal quarter:

 

PG&E Corporation common stock	$23,628 million
Pacific Gas and Electric Company common stock	Wholly owned by PG&E Corporation

 

Common Stock outstanding as of February 12, 2016:

 

PG&E Corporation:	492,830,471 shares
Pacific Gas and Electric Company:	264,374,809 shares (wholly owned by PG&E Corporation)

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:

 

Designated portions of the Joint Proxy Statement relating to the 2016 Annual Meetings of Shareholders

Part III (Items 10, 11, 12, 13 and 14)

Contents

 

UNITS OF MEASUREMENT

GLOSSARY

PART I

ITEM 1. BUSINESS

Regulatory Environment

Ratemaking Mechanisms

Electric Utility Operations

Natural Gas Utility Operations

Competition

Environmental Regulation

ITEM 1A. RISK FACTORS

ITEM 1B. UNRESOLVED STAFF COMMENTS

ITEM 2. PROPERTIES

ITEM 3. LEGAL PROCEEDINGS

ITEM 4. MINE SAFETY DISCLOSURES

EXECUTIVE OFFICERS OF THE REGISTRANTS

PART II

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

ITEM 6. SELECTED FINANCIAL DATA

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

RESULTS OF OPERATIONS

LIQUIDITY AND FINANCIAL RESOURCES

CONTRACTUAL COMMITMENTS

ENFORCEMENT AND LITIGATION MATTERS

REGULATORY MATTERS

LEGISLATIVE AND REGULATORY INITIATIVES

ENVIRONMENTAL MATTERS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

NEW ACCOUNTING PRONOUNCEMENTS

CAUTIONARY LANGUAGE REGARDING FORWARD-LOOKING STATEMENTS

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED STATEMENTS OF CASH FLOWS

CONSOLIDATED STATEMENTS OF EQUITY

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED STATEMENTS OF CASH FLOWS

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 4: DEBT

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

NOTE 6: PREFERRED STOCK

NOTE 7: EARNINGS PER SHARE

NOTE 8: INCOME TAXES

NOTE 9: DERIVATIVES

     

UNITS OF MEASUREMENT

 

GLOSSARY

 

The following terms and abbreviations appearing in the text of this report have the meanings indicated below.

 

2015 Form 10-K	PG&E Corporation's and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2015
AB	Assembly Bill
AFUDC	allowance for funds used during construction
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update
CAISO	California Independent System Operator
CARB	California Air Resources Board
CCA	Community Choice Aggregator
Central Coast Board	Central Coast Regional Water Quality Control Board
CEC	California Energy Resources Conservation and Development Commission
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
DOE	Department of Energy
EPA	Environmental Protection Agency
EPS	earnings per common share
EV	electric vehicle
FERC	Federal Energy Regulatory Commission
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
IRS	Internal Revenue Service
LTIP	long term incentive plan
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Part II, Item 7, of this Form 10-K
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
NTSB	National Transportation Safety Board
ORA	Office of Ratepayer Advocates
PSEP	pipeline safety enhancement plan
QF	Qualifying facility
Regional Board	California Regional Water Quality Control Board, Lahontan Region
REITS	Global real estate investment trust
ROE	return on equity
RPS	renewable portfolio standard
SB	senate bill
SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
TO	transmission owner
TURN	The Utility Reform Network
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
Water Board	California State Water Resources Control Board

PART I

 

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.  PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found below 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, 2015, PG&E Corporation and the Utility had approximately 23,000 regular employees, approximately 20 of which were employees of the PG&E Corporation.  Of the Utility’s regular employees, approximately 13,500 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 SEIU collective bargaining agreement will expire on July 31, 2016. The two agreements with IBEW will expire on December 31, 2016.  The agreement with ESC, originally scheduled to expire on December 31, 2015, automatically renewed for a period of one year pending the negotiation of a new agreement with the union.  In January 2016, the Utility and ESC reached a tentative new agreement, subject to ratification by members of ESC.  If ratified, the new agreement with ESC will be retroactive to January 1, 2016 and will expire on December 31, 2019. 

 

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.

 

In April 2015, the CPUC issued decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping 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 (the “San Bruno accident”).  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) to impose penalties on the Utility 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 Utility also faces criminal charges in the U.S. District Court for the Northern District of California alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act and that the Utility obstructed the NTSB’s investigation into the cause of the San Bruno accident.  The trial currently is scheduled to begin on March 22, 2016.  For more information about the criminal proceeding, see “Enforcement and Litigation Matters” in MD&A, Item 1.A. Risk Factors, and Note 13 of the Notes to the Consolidated Financial Statements in Item 8. below.

 

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 MD&A.

 

Regulatory Environment 

 

The Utility's business is subject to the regulatory jurisdiction of various agencies at the federal, state, and local levels.  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. The Utility is also subject to the requirements of other federal, state and local regulatory agencies with respect to safety, the environment and health. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings affecting 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 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 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 the interconnections of the Utility’s transmission systems with other electric systems and generation facilities, the 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 electricity transmission system in California and provides open access transmission service on a non-discriminatory 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 “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 substantial capital expenditures could be required in the future.  For more information about Diablo Canyon, see “Regulatory Matters – Diablo Canyon” in MD&A and Item 1.A Risk Factors below.)

 

Other Regulation

 

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.  (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 highways.  In exchange for the right to use public streets and highways, 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 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 (e.g., maintenance, administration and general expenses) and capital costs (e.g., 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 (referred to as “Utility Revenues and Costs that did not Impact Earnings” in MD&A), 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 Impacted Earnings” in MD&A) within its authorized base revenue requirements.

 

Both gas and electric rates vary depending on seasons mostly due to the influence of weather.  Gas service rates generally increase during the winter months (October through March) to account for the gas peak due to heating while electricity rates increase during summer (June – September) because of higher summer costs, driven by air conditioning loads.

 

During 2015, the CPUC continued to implement state law requirements to reform residential electric rates to more closely reflect the utilities’ actual costs of service, reduce cross-subsidization among customer rate classes, implement new rules and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use.  (See “Legislative and Regulatory Initiatives” in MD&A for additional information on specific CPUC proceedings.)

 

From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn some additional revenues.  For example, the Utility has earned incentives for the successful 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 the 2006-2008 energy efficiency cycle, see “Rehearing of CPUC Decisions Approving Energy Efficiency Incentive Awards” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8. below.

 

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 distribution, 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 rate adjustments”) in revenue requirements for the subsequent years of the GRC period.  Attrition rate adjustments are generally provided for cost increases related to increases in invested capital and inflation.  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.

 

For more information about the Utility’s current GRC proceeding, see “Regulatory Matters −2017 General Rate Case” in MD&A.

 

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 its 2015 GT&S rate case, the Utility has requested that the CPUC approve a total annual revenue requirement of $1.263 billion for the Utility’s anticipated costs of providing natural gas transmission and storage services for 2015.  The Utility also requested revenue increases of $83 million in 2016 and $142 million in 2017. See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” in 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 2017, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock.  The CPUC also set the authorized ROE at 10.40%.  The CPUC also adopted an adjustment mechanism to allow the Utility’s capital structure and ROE to be adjusted if the utility bond index changes by certain thresholds on an annual basis.  During 2015, the adjustment mechanism was not triggered so the Utility’s authorized ROE will remain at 10.40% for 2016.  On February 12, 2016, a proposed decision was issued, that, if approved by the CPUC, will preclude the Utility from using the mechanism before its next cost of capital application.  As a result, if the proposed decision is approved, the Utility’s capital structure and ROE will not be adjusted for 2017.  The CPUC will review the Utility’s capital structure and ROE for 2018 in the Utility’s next cost of capital proceeding.  The Utility is required to file its 2018 cost of capital application by April 20, 2017.

 

Electricity Transmission Owner Rate Cases

 

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case.  The Utility generally files a TO 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: 1) by the CPUC in the Utility's retail electric rates and are collected from retail electric customers; and 2) by the CAISO in its Transmission Access Charges to wholesale customers.  (See “Regulatory Matters – FERC TO Rate Cases” in MD&A.)  The Utility also recovers a portion of its 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.  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 bundled 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.  The CPUC has approved the Utility’s procurement plan covering 2012 through 2024.

 

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 by the CPUC.  The CPUC may disallow costs associated with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines that the utility failed to follow the principles of least-cost dispatch. 

 

The Utility recovers its electricity procurement costs annually primarily through the energy resource recovery account.  (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 emissions costs, and generation fuel expense, and approves a forecasted revenue requirement.  The CPUC may adjust the Utility’s retail electricity rates more frequently if the forecasted aggregate over-collections or under-collections in the energy resource recovery account exceed 5% of its prior year electricity procurement and utility-owned generation revenues.  The CPUC performs an annual compliance review of the transactions recorded in the energy resource recovery account.

 

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, to meet mandatory renewable energy targets, and to comply with resource adequacy requirements.  For additional information, see “Electric Utility Operations – Electricity Resources” below as well as Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

 

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 that are subject to limits as set forth in its core procurement incentive mechanism, described below.  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 rate changes.  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 core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs.  Under the core procurement incentive mechanism, 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 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.  The FERC approves the United States tariffs that shippers, including the Utility, pay for pipeline service, 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.  Nuclear decommissioning costs are collected in advance through rates and are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.  The Utility files an application with the CPUC every three years requesting approval of the Utility’s updated estimated decommissioning costs and any rate change necessary to fully fund the nuclear decommissioning trusts to the levels needed to decommission the Utility’s nuclear plants.

 

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.

 

As required by California law, on July 1, 2015, the Utility filed its proposed electric distribution resources plan for approval by the CPUC. The Utility’s plan identifies optimal locations on its electric distribution system for deployment of distributed energy resources.  The Utility’s proposal is designed to allow energy technologies to be interconnected with each other and integrated into the larger grid while continuing to provide customers with safe, reliable and affordable electric service.  The Utility envisions a future electric grid, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.  The CPUC also is considering the Utility’s request for approval of the phased deployment of an electric vehicle charging infrastructure in response to the CPUC’s December 2014 decision adopting a policy to expand the California utilities’ role in developing an EV charging infrastructure to support California’s climate goals.  (For more information, see “Legislative and Regulatory Initiatives” in MD&A.)

 

Electricity Resources

 

The Utility is required to maintain 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 2015 represented by each major electricity resource, and further discussed below.

 

Total 2015 Actual Electricity Generated and Procured – 72,113 GWh (1):

 

			Percent of Bundled Retail Sales
Owned Generation Facilities
	Nuclear			22.6	%
	Small Hydroelectric			0.7	%
	Large Hydroelectric			4.6	%
	Fossil fuel-fired			8.9	%
	Solar			0.4	%
	Total						37.2	%
Qualifying Facilities
	Renewable			3.0	%
	Non-Renewable			6.5	%
	Total						9.5	%
Irrigation Districts and Water Agencies
	Small Hydroelectric			0.1	%
	Large Hydroelectric			0.6	%
	Total						0.7	%
Other Third-Party Purchase Agreements
	Renewable			25.3	%
	Large Hydroelectric			0.7	%
	Non-Renewable			9.4	%
	Total						35.4	%
Others, Net (2)							17.2	%
Total (3)							100	%

(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 established a “renewable portfolio standard” (referred to as “RPS”) that requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers.  In October 2015, the California Governor signed SB 350, the Clean Energy and Pollution Reduction Act of 2015 which, effective January 1, 2016, increases the amount of renewable energy that must be delivered by most load-serving entities, including the Utility, to their customers from 33% of their total annual retail sales by the end of the 2017-2020 compliance period to 50% of their total annual retail sales by the end of the 2028- 2030 compliance period and in each compliance period thereafter.  SB 350 establishes increasing interim renewable energy targets for the periods between 2020 and 2030 but also provides compliance flexibility and waiver mechanisms, including increased flexibility to apply excess renewable energy procurement in one compliance period to future compliance periods.  The Utility will incur additional costs to procure renewable energy to meet the new renewable energy targets which the Utility expects will continue to be recoverable from customers as “pass-through” costs. The Utility also may be subject to penalties for failure to meet the higher targets.  The CPUC has stated its intent to propose a decision in late 2016 implementing SB 350’s provisions requiring higher RPS targets and other changes made by the statute to the RPS rules. 

 

Renewable generation resources, for purposes of the RPS requirements, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy.  During 2015, 29.5% of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 23.3%.  Approximately 25% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties.  Additional renewable resources were provided by QFs (3.0%), the Utility’s small hydroelectric facilities (0.7%), and the Utility’s solar facilities (0.4%).

 

The total 2015 renewable deliveries shown above were comprised of the following:

 

Type		GWh		Percent of Bundled Retail Sales
Biopower		3,141		4.4%
Geothermal		3,664		5.0%
Wind		5,451		7.6%
Solar		8,157		11.3%
RPS-Eligible Hydroelectric		878		1.2%
Total		21,291		29.5%

 

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 must hold Requests for Offers (RFOs) to meet biennial targets and procure 580 MW of energy storage which must be operational by the end of 2024.  The Utility’s 2014-2015 energy storage procurement target was 80.5 MW.  The Utility initiated its RFO on December 1, 2014 to obtain at least 74 MW of transmission and distribution connected energy storage, signed contracts for 75 MW, and submitted those contracts for CPUC approval on the CPUC’s December 1, 2015 deadline.  The Utility met its remaining 6.5 MW customer-connected target by funding energy storage under the CPUC-mandated Self Generation Incentive Program. On January 1, 2016, the Utility reported its compliance with its 2014-2015 obligations to the CPUC.  The Utility must file its 2016-2017 plan for procuring 120 MW of energy storage, consisting of 105 MW of transmission and distribution energy storage and 15 MW of customer-connected storage, by March 1, 2016.  A CPUC decision on the Utility’s plan is expected before the December 1, 2016 deadline for the Utility to issue its second energy storage RFO.  The Utility continues to participate in the CPUC proceeding to refine California’s energy storage program, which is considering potentially higher targets and expanded energy storage use cases.

 

Owned Generation Facilities.  At December 31, 2015, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:

 

Generation Type		County Location		Number of Units		Net Operating Capacity (MW)
Nuclear (1):
Diablo Canyon		San Luis Obispo		2		2,240
Hydroelectric (2):
Conventional		16 counties in northern and central California		104		2,684
Helms pumped storage		Fresno		3		1,212
Fossil fuel-fired:
Colusa Generating Station		Colusa		1		657
Gateway Generating Station		Contra Costa		1		580
Humboldt Bay Generating Station		Humboldt		10		163
Fuel Cell:
CSU East Bay Fuel Cell		Alameda		1		1
SF State Fuel Cell		San Francisco		2		2
Photovoltaic (3):		Various		13		152
Total				137		7,691

(1) The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2.  The NRC operating licenses expire in 2024 and 2025, respectively.  (See “Diablo Canyon Nuclear Power Plant” in. MD&A 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 two 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 13 of the Notes to the Consolidated Financial Statements in Item 8.

 

Electricity Transmission 

 

At December 31, 2015, the Utility owned approximately 18,400 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 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 2015, 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 142,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 58 transmission switching substations, and 603 distribution substations, with a capacity of approximately 31,400 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 2015 the Utility commenced operations in a new electric distribution control center facility in Rocklin, California, and expects to complete an additional facility in Concord, California, in 2016.  These control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

 

In 2015, the Utility continued to deploy its Fault Location, Isolation, and Service Restoration circuit technology which involves the rapid operation of smart switches to reduce the duration of customer outages.  Another 83 circuits were outfitted with this equipment, bringing the total deployment to 700 of the Utility’s 3200 distribution circuits.  The Utility also 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 2016.  

 

Electricity Operating Statistics

 

The following table shows certain of the Utility’s operating statistics from 2013 to 2015 for electricity sold or delivered, including the classification of revenues by type of service.  No single customer of the Utility accounted for 10% or more of consolidated revenues for electricity sold in 2015, 2014 and 2013.

 

			2015			2014			2013
Customers (average for the year)			5,311,178			5,276,025			5,243,216
Deliveries (in GWh) (1)			85,860			86,303			86,513
Revenues (in millions):
Residential		$	5,032		$	4,784		$	5,091
Commercial			5,278			5,141			4,905
Industrial			1,555			1,543			1,388
Agricultural			1,233			1,172			1,021
Public street and highway lighting			83			79			75
Other (2)			(84)			(172)			(128)
Subtotal			13,097			12,547			12,352
Regulatory balancing accounts (3)			560			1,109			137
Total operating revenues		$	13,657		$	13,656		$	12,489
Selected Statistics:
Average annual residential usage (kWh)			6,294			6,458			6,752
Average billed revenues per kWh:
Residential		$	0.1719		$	0.1603		$	0.1643
Commercial			0.1640			0.1585			0.1499
Industrial			0.0973			0.0998			0.0928
Agricultural			0.1610			0.1516			0.1454
Net plant investment per customer		$	6,660		$	6,339		$	6,002

(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. 

 

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 2015, the Utility purchased approximately 307,100 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 2015.

 

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, 2015, the Utility’s natural gas system consisted of approximately 42,800 miles of distribution pipelines, over 6,700 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 13 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.

 

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

 

The following table shows the Utility's operating statistics from 2013 through 2015 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service. No single customer of the Utility accounted for 10% or more of consolidated revenues for bundled gas sales in 2015, 2014 and 2013.

 

			2015			2014			2013
Customers (average for the year)			4,415,332			4,394,283			4,378,797
Gas purchased (MMcf)			209,194			202,215			240,414
Average price of natural gas purchased		$	2.11		$	4.09		$	3.29
Bundled gas sales (MMcf):
Residential			144,885			143,514			181,775
Commercial			43,888			42,080			46,668
Total Bundled Gas Sales			188,773			185,594			228,443
Revenues (in millions):
Bundled gas sales:
Residential		$	1,816		$	1,683		$	1,870
Commercial			403			419			395
Other			125			51			44
Bundled gas revenues			2,344			2,153			2,309
Transportation service only revenue			649			662			555
Subtotal			2,993			2,815			2,864
Regulatory balancing accounts			183			617			240
Total operating revenues		$	3,176		$	3,432		$	3,104
Selected Statistics:
Average annual residential usage (Mcf)			35			34			44
Average billed bundled gas sales revenues per Mcf:
Residential		$	12.53		$	11.72		$	10.29
Commercial			9.18			9.96			8.47
Net plant investment per customer		$	2,573		$	2,468		$	2,234

 

Competition

 

Competition in the Electricity Industry

 

California law allows qualifying non-residential electric customers of investor-owned electric utilities to purchase electricity from energy service providers rather than from the utilities up to certain annual and overall GWh limits that have been specified for each utility.  This arrangement is known as “direct access.”  In addition, California law permits cities, counties, and certain other public agencies that have qualified to become a “community choice aggregator” (or “CCA”) to generate and/or purchase electricity for their local residents and businesses.  By law, a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from a utility.

 

The Utility continues to provide transmission, distribution, metering, and billing services to direct access customers, although these customers can choose to obtain metering and billing services from their energy service provider.  The CCA customers continue to obtain transmission, distribution, metering, and billing services from the Utility.  In addition to collecting charges for transmission, distribution, metering, and billing services that it provides, the Utility is able to collect charges to recover the generation-related costs that the Utility incurred on behalf of direct access and CCA customers while they were the Utility’s customers. The Utility remains the electricity provider of last resort for these customers.

 

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, may seek to acquire the Utility’s distribution facilities, either under a consensual transaction or via eminent domain.

 

The Utility is also impacted by 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.

 

The Utility also competes for the opportunity to develop and construct certain types of electric transmission facilities within, or interconnected to, its service territory through a competitive bidding process managed by the CAISO.

 

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 dioxide (CO­2) 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 recovers 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 13: 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.  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 the Comprehensive Environmental Response, Compensation and Liability Act, 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 13 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, CO2, sulfur dioxide (SO2), mono-nitrogen oxide (NOx), 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 U.S. Global Change Research Program (a confederation of the research arms of thirteen federal departments and agencies) 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 August 2015, the EPA published final regulations under section 111(b) of the Clean Air Act to control CO2 emissions from new fossil fuel-fired power plants.  While these regulations do not affect the Utility’s existing power plants, the regulations impose emission limitations on fossil fuel-fired power plants constructed after January 8, 2014 and will affect the design, construction, operation and cost of such power plants. 

 

In August 2015, the EPA also published final regulations under section 111(d) of the Clean Air Act to control CO2 emissions from existing fossil fuel-fired power plants.  These regulations are designed to reduce power plant CO2 emissions on a national basis by as much as 32% by 2030, compared with 2005 levels.  States must submit final plans to comply with these regulations by September 2016, but may request an extension to file such plans until September 2018. 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.  Following publication of the EPA’s regulations, in October 2015 West Virginia and several other states and parties challenged the EPA’s section 111(d) regulations in the United States Court of Appeals for the District of Columbia Circuit and petitioned the Court to stay the regulations pending review of the appeal on the merits.  The D.C. Circuit denied the request for stay but in February 2016, the United States Supreme Court granted a stay of the section 111(d) regulations pending review of the appeal by the D.C. Circuit.  The Supreme Court’s decision may affect the nature, extent and timing of implementation of these regulations.  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’s AB 32, the Global Warming Solutions Act of 2006, provides for the gradual reduction of state-wide GHG emissions to 1990 levels by 2020.  The CARB has approved various regulations to achieve the 2020 target, 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.  During 2016, CARB and the California Legislature are likely to consider proposals to achieve additional GHG reductions beyond the 2020 target established in AB 32.  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 2015, 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 maintains emergency response plans and procedures to address a range of near-term risks, including extreme storms, heat waves and wildfires and uses its risk-assessment process to prioritize infrastructure investments for longer-term risks associated with climate change. 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 is making substantial investments to build a more modern and resilient system that can better withstand extreme weather and related emergencies.  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 and inundation potential at coastal and low elevation facilities due to sea level rise combined with high tides, storm runoff and storm surges.

 

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 is also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and collaborating on research and new modeling tools.

 

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 achieve reductions in methane emissions by implementing improvements in leak detection and repair, upgrades at metering and regulating stations, and maintenance and replacement of other pipeline materials.

 

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 2014 totaled more than 58 million metric tonnes of CO­2 equivalent, nearly two-thirds of which came from customer natural gas use.  The following table shows the 2014 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.

 

Source		Amount (metric tonnes CO2 equivalent)
Fossil Fuel-Fired Plants (1)		2,407,734
Natural Gas Compressor Stations and Storage Facilities (2)		348,155
Distribution Fugitive Natural Gas Emissions		750,223
Customer Natural Gas Use (3)		41,616,935

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

(2) Includes compressor stations and storage facilities emitting more than 25,000 metric tonnes of CO2 equivalent annually.

(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.

 

The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2014 as compared to the national average for electric utilities:

 

		Amount (pounds of CO2 per MWh)
U.S. Average (1)		1,137
Pacific Gas and Electric Company (2)		435

(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.

 

Air Emissions Data for Utility-Owned Generation

 

In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities.  The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36% of the Utility’s delivered electricity in 2014.  PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.

 

		2014		2013
Total NOx Emissions (tons)		141		153
NOx Emissions Rate (pounds/MWh)		0.01		0.01
Total SO2 Emissions (tons)		14		17
SO2 Emissions Rate (pounds/MWh)		0.0010		0.0011

 

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.  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, in 2010 the California Water Board 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%.  As required by the policy the California Water Board 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 not expected to issue a final decision regarding Diablo Canyon’s compliance with the state policy before January 2017.  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 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 2015, the Utility was awarded an additional $21 million for costs incurred between June 1, 2013 and May 31, 2014.  The claim for the period June 1, 2014 through May 31, 2015 is under review by the DOE.  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.

ITEM 1A. RISK FACTORS

 

PG&E Corporation’s and the Utility’s financial results can be affected by many factors, including estimates and assumptions used in the critical accounting policies described in MD&A, that can cause their actual financial results to differ materially from historical results or from anticipated future financial results.  The following discussion of key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility and should be read in conjunction with MD&A and the consolidated financial statements and related notes in Part II, Item 8, “Financial Statements and Supplementary Data” of this Form 10-K.  Any of these factors, in whole or in part, could materially affect PG&E Corporation’s and the Utility’s business, results of operations, financial condition, and stock price.

 

Risks Related to the Outcome of Enforcement Matters, Investigations, and Regulatory Proceedings

 

PG&E Corporation’s and the Utility’s future financial results may be materially affected by the outcome of the federal criminal prosecution of the Utility. 

 

As discussed in MD&A, the Utility is facing federal criminal charges alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act and alleging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident that occurred on September 9, 2010.  The maximum statutory fine for each felony count is $500,000, for potential total fines of $6.5 million.  The federal prosecutor also seeks to impose an alternative fine which could total approximately $562 million, based on allegations that the Utility derived gross gains of approximately $281 million.  The trial currently is scheduled to begin on March 22, 2016.

 

PG&E Corporation and the Utility have not recorded any charges for potential criminal fines in their consolidated financial statements at December 31, 2015.  If the Utility is convicted and a fine is imposed, PG&E Corporation and the Utility will record charges when required in accordance with GAAP.  The Utility also could incur material costs, not recoverable through rates, to implement remedial measures that may be imposed by the court, such as a requirement that the Utility’s natural gas operations be supervised by a third-party monitor. The Utility could also be suspended or debarred from entering into federal procurement and non-procurement contracts and programs.

 

If the Utility incurred material fines or costs following a conviction, PG&E Corporation may need to issue common stock to raise funds to contribute to the Utility to maintain the required equity component of the Utility’s authorized capital structure as the Utility incur charges and costs.  These issuances would be incremental to PG&E Corporation’s current forecast of common stock issuances and could materially dilute PG&E Corporation’s EPS.  The trial and any negative publicity associated with it, as well as the Utility’s conviction and the imposition of a material fine, if incurred, also could affect the Utility’s and PG&E Corporation’s credit ratings or outlooks and make it more difficult for PG&E Corporation and the Utility to access the capital markets.

 

The trial and the Utility’s conviction could harm the Utility’s relationships with regulators, legislators, communities, business partners, or other constituencies and make it more difficult to recruit qualified personnel and senior management.  Further, they could negatively affect the outcome of future ratemaking and regulatory proceedings; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the criminal charges. 

 

In addition, the Utility’s conviction could result in increased regulatory or legislative pressure to require the separation of the Utility’s electric and natural gas businesses, restructure the corporate relationship between PG&E Corporation and the Utility, or undergo some other fundamental corporate restructuring.  As discussed under the heading “Regulatory Matters” in MD&A, the SED will evaluate PG&E Corporation’s and the Utility’s organizational structure in the CPUC’s pending investigation to examine the Utility’s safety culture.

 

PG&E Corporation’s and the Utility’s future financial results may be materially affected by the outcomes of the CPUC’s investigative enforcement proceedings against the Utility, other known enforcement matters, and other ongoing state and federal investigations.  The Utility also could incur material costs and fines in connection with future investigations, citations, audits, or enforcement actions.

 

The Utility could incur material charges, including fines and other penalties, in connection with the CPUC’s investigations of the Utility’s compliance with natural gas distribution record-keeping practices and the Utility’s compliance with the CPUC’s rules regarding ex parte communications.  In addition, there are several other investigations by federal and state law enforcement authorities.  The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014.  The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case discussed above.  Federal and state law enforcement authorities also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel.  If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties or suffer negative consequences described above in the immediately preceding risk factor.  In addition, a negative outcome in any of these investigations or future enforcement actions may negatively affect the outcome of future ratemaking and regulatory proceedings; for example, by enabling parties to challenge the Utility’s request to recover costs that the parties allege are somehow related to the Utility’s violations.

The SED also could impose material fines on the Utility based on the Utility’s self-reports submitted in accordance with the SED’s safety citation program and the Utility’s efforts to identify and remove encroachments from transmission pipeline rights of way.  The Penalty Decision requires the SED to review the Utility’s gas transmission operations (including the Utility’s compliance with the remedies ordered by the Penalty Decision) and to perform annual audits of the Utility’s record-keeping practices for a minimum of ten years. The SED could impose fines on the Utility or require the Utility to incur unrecoverable costs, or both, based on the outcome of these future audits. In addition, although PG&E Corporation and the Utility do not currently face the possibility of fines or penalties in the first phase of the CPUC’s pending investigation into the Utility’s safety culture since it has been categorized as rate setting, it is uncertain how the next phase will be categorized.  (See the discussion under the heading “Regulatory Matters” in MD&A.)

 

The Utility could be subject to additional regulatory or governmental enforcement action in the future with respect to compliance with federal, state or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and resource adequacy requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; and federal electric reliability standards.  The SED could impose fines on the Utility in the future in accordance with its authority under the gas and electric safety citation programs.  The amount of such fines, penalties, or customer refunds could have a material effect on PG&E Corporation’s and the Utility’s financial results.  

 

PG&E Corporation’s and the Utility’s future financial results could be materially affected by the extent to which its natural gas transmission costs exceed authorized revenues as the Utility complies with the Penalty Decision and incurs other natural gas transmission costs that are unrecoverable or that the Utility has not sought to recover. 

 

The Utility’s ability to recover its natural gas transmission and storage costs and earn its authorized ROE could be materially affected by the amount of revenues the CPUC ultimately authorizes the Utility to collect in the 2015 GT&S rate case proceeding and future GT&S rate cases.  (See “Regulatory Matters” in Item 7. MD&A.)  The Utility continues to incur material unrecoverable costs to meet the Penalty Decision’s requirement to fund safety-related projects and programs to be identified by the CPUC in the 2015 GT&S rate case.  Depending on how the CPUC designates pipeline safety-related projects and programs the Utility is required to fund, and how the Utility’s associated costs are counted toward meeting the $850 million maximum disallowance imposed by the Penalty Decision, the ultimate amount of unrecoverable pipeline-related costs the Utility incurs may be higher than current forecasts.  In addition, the Penalty Decision requires the Utility to implement various remedial measures which the CPUC estimated would cost $50 million.  Actual costs to implement the remedies could be higher.

 

In addition, the Utility plans to incur unrecoverable costs to continue performing certain work to complete projects under the PSEP and to identify and remove encroachments from gas transmission pipeline rights-of-way.  Actual costs to perform this work could exceed forecasts.

 

PG&E Corporation’s and the Utility’s financial results primarily depend on the outcomes of  regulatory and ratemaking proceedings and the Utility’s ability to manage its operating expenses and capital expenditures so that it is able to earn its authorized rate of return in a timely manner.

 

As a regulated entity, the Utility’s rates are set by the CPUC or the FERC on a prospective basis and are generally designed to allow the Utility to collect sufficient revenues to recover the costs of providing service, including a return on its capital investments.  PG&E Corporation’s and the Utility’s financial results could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility to safely and reliably serve its customers and earn its authorized ROE.  The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the Utility’s reputation (especially if the Utility is convicted of the federal criminal charges discussed above), the level of opposition by intervening parties; potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services.

 

The Utility also is required to incur costs to comply with legislative and regulatory requirements and initiatives, such as those relating to the development of a state-wide electric vehicle charging infrastructure, the deployment of distributed energy resources, implementation of demand response and customer energy efficiency programs, energy storage and renewable energy targets, and the construction of the California high-speed rail project.  The Utility’s ability to recover costs, including its investments, associated with these and other legislative and regulatory initiatives will, in large part, depend on the final form of legislative or regulatory requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand for the Utility’s electricity and natural gas services. 

 

In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility’s actual costs to safely and reliably serve its customers differ from authorized or forecast costs.  The Utility may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as storms, accidents, catastrophic or other events affecting the Utility’s operations), or compliance with new state laws or policies.  Although the Utility may be allowed to recover some or all of the additional costs, there may be a substantial time lag between when the Utility incurs the costs and when the Utility is authorized to collect revenues to recover such costs.  Alternatively, the CPUC or the FERC may disallow costs that they determine were not reasonably or prudently incurred by the Utility.

 

The Utility’s ability to recover its costs also may be affected by the economy and its impact on the Utility’s customers.  For example, a sustained downturn or sluggishness in the economy could reduce the Utility’s sales to industrial and commercial customers or the level of uncollectible bills could increase.  Although the Utility generally recovers its costs through rates, regardless of sales volume, rate pressures increase when the costs are borne by a smaller sales base. 

 

Changes in commodity prices also may have an adverse effect on the Utility’s ability to timely recover its operating costs and earn its authorized ROE.  Although the Utility generally recovers its electricity and natural gas procurement costs from customers as “pass-through” costs, a significant and sustained rise in commodity prices could create overall rate pressures that make it more difficult for the Utility to recover its costs that are not categorized as “pass-through” costs.  To relieve some of this upward rate pressure, the CPUC could authorize lower revenues than the Utility requested or disallow full cost recovery. 

 

PG&E Corporation’s and the Utility’s financial results depend upon the Utility’s continuing ability to recover “pass-through” costs, including electricity and natural gas procurement costs, from customers  in a timely manner.  The CPUC may disallow procurement costs for a variety of reasons. In addition, the Utility’s ability to recover these costs could be affected by the loss of Utility customers and decreased new customer growth, if the CPUC fails to adjust the Utility’s rates to reflect such events.

 

The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility’s own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market.  The Utility must manage these sources using the commercial and CPUC regulatory principles of “least cost dispatch” and prudent administration of power purchase agreements in compliance with its CPUC-approved long-term procurement plan.  The CPUC could disallow procurement costs incurred by the Utility if the CPUC determines that the Utility did not comply with these principles or if the Utility did not comply with its procurement plan. 

 

Further, the contractual prices for electricity under the Utility’s current or future power purchase agreements could become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to adverse economic conditions or the loss of the Utility’s customers to other retail providers.  In particular, the Utility will incur additional costs to procure renewable energy to meet the higher targets established by California SB 350 that became effective on January 1, 2016.  Despite the CPUC’s current approval of the contracts, the CPUC could disallow contract costs in the future if it determines that the costs are unreasonably above market. 

 

The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by the whether the CAISO wholesale electricity market continues to function effectively.  Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended which could result in excessive market prices.  The CPUC could prohibit the Utility from passing through the higher costs of electricity to customers.  For example, during the 2000 and 2001 energy crisis, the market mechanism flaws in California’s then-newly established wholesale electricity market led to dramatically high market prices for electricity that the Utility was unable to recover through customer rates, ultimately causing the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code.

 

Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreased new customer growth that occurs through municipalization of the Utility’s facilities, an increase in the number of CCAs who provide electricity to their residents, and an increase in the number of consumers who become direct access customers of alternative generation providers.  (See “Competition in the Electricity Industry” in Item 1.)  As the number of bundled customers (i.e., those primarily residential customers who receive electricity and distribution service from the Utility) declines, the rates for remaining customers could increase as the Utility would have a smaller customer base from which to recover certain procurement costs.  Although the Utility is permitted to collect non-bypassable charges for generation-related costs incurred on behalf of former customers, the charges may not be sufficient for the Utility to fully recover these costs.  In addition, the Utility’s ability to collect non-bypassable charges has been, and may continue to be, challenged by certain customer groups.  Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.

 

In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering (“NEM”), which allows self-generating customers to receive bill credits for surplus power at the full retail rate, puts upward rate pressure on remaining customers.  In January 2016, the CPUC adopted new NEM rules and rates.  The new rules and rates are expected to become effective for new NEM customers of the Utility later in 2016.  New NEM customers will be required to pay an interconnection fee, will go on time of use rates, and will be required to pay some non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.  However, the resulting rules will still put upward rate pressure on remaining customers, and remove the cap on the number of NEM customers.  Significantly higher rates for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers. The CPUC states that it intends to revisit these rules in 2019.

 

A confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments.  If the number of the Utility’s customers decreases or grows at a slower rate than anticipated, the Utility’s level of capital investment would likely decline as well, in turn leading to a slower growth in rate base and earnings.  Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could adversely impact PG&E Corporation’s and the Utility’s financial results.

 

The CPUC has begun to implement rate reform to allow residential electric rates to more closely reflect the utilities’ actual costs of providing service and decrease cost-subsidization among customer classes.  Many aspects of rate reform are not yet finalized, including time-of-use rates and whether the utilities can impose a fixed charge on certain customers.  If the Utility is unable to recover a material portion of its procurement costs and/or if the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, the wide deployment of distributed generation, and the development of new electricity generation and energy storage technologies, PG&E Corporation’s and the Utility’s financial results could be materially affected.   

 

Risks Related to Liquidity and Capital Requirements

 

PG&E Corporation’s and the Utility’s financial results will be affected by their ability to continue accessing the capital markets and by the terms of debt and equity financings.

 

PG&E Corporation and the Utility will continue to seek funds in the capital and credit markets to enable the Utility to make capital investments, pay fines that may be imposed in the future, and incur costs to meet the Penalty Decision’s requirement to incur costs of up to $850 million for safety-related projects and programs to be identified by the CPUC in the 2015 GT&S rate case.  PG&E Corporation’s and the Utility’s ability to access the capital and credit markets and the costs and terms of available financing depend primarily on PG&E Corporation’s and the Utility’s credit ratings and outlook.  Their credit ratings and outlook can be affected by many factors, including the outcomes of the on-going criminal prosecution, the pending CPUC investigations, and ratemaking proceedings.  If PG&E Corporation’s or the Utility’s credit ratings were downgraded to below investment grade, their ability to access the capital and credit markets would be negatively affected and could result in higher borrowing costs, fewer financing options, including reduced, or lack of, access to the commercial paper market, additional collateral posting requirements, which in turn could affect liquidity and lead to an increased financing need.  Other factors can affect the availability and terms of debt and equity financing, including changes in the federal or state regulatory environment affecting energy companies generally or PG&E Corporation and the Utility in particular, the overall health of the energy industry, volatility in electricity or natural gas prices, an increase in interest rates by the Federal Reserve Bank, and general economic and financial market conditions.

 

The reputations of PG&E Corporation and the Utility continue to suffer from the negative publicity about matters discussed under “Enforcement and Litigation Matters” in Item 7. MD&A.  The negative publicity and the uncertainty about the outcomes of these matters may undermine investors’ confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment.  As a result, investors may be less willing to buy shares of PG&E Corporation common stock resulting in a lower stock price.  Further, the market price of PG&E Corporation common stock could decline materially after the outcomes are determined.  The amount and timing of future share issuances also could affect the stock price. 

 

If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation and PG&E Corporation could be required to contribute capital to the Utility to enable the Utility to fulfill its obligation to serve.  To maintain PG&E Corporation’s dividend level in these circumstances, PG&E Corporation would be further required to access the capital or credit markets.  PG&E Corporation may need to decrease or discontinue its common stock dividend if it is unable to access the capital or credit markets on reasonable terms.  

 

PG&E Corporation’s ability to meet its debt service and other financial obligations and to pay dividends on its common stock depends on the Utility’s earnings and cash flows.

 

PG&E Corporation is a holding company with no revenue generating operations of its own. The Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation.  Under the CPUC’s rules applicable to utility holding companies, the Utility’s dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company and PG&E Corporation’s Board of Directors give “first priority” to the Utility’s capital requirements, 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.  The CPUC has interpreted this “first priority” obligation to include the requirement that PG&E Corporation “infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve.”  In addition, before the Utility can pay common stock dividends to PG&E Corporation, the Utility must maintain its authorized capital structure with an average 52% equity component. 

 

If the Utility were required to pay a material amount of fines or incur material unrecoverable costs due to a conviction in the on-going criminal prosecution, the pending CPUC investigations, or other enforcement matters, it would require equity contributions from PG&E Corporation to restore its capital structure.  PG&E Corporation common stock issuances used to fund such equity contributions could materially dilute EPS. (See “Liquidity and Financial Resources” in Item 7. MD&A.)  Further, if PG&E Corporation were required to infuse the Utility with significant capital or if the Utility was unable to distribute cash to PG&E Corporation, or both, PG&E Corporation may be unable to pay principal and interest on its outstanding debt, pay its common stock dividend, or meet other obligations.

 

PG&E Corporation’s and the Utility’s ability to pay dividends also could be affected by financial covenants contained in their respective credit agreements that require each company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.

 

Risks Related to Operations and Information Technology

 

The Utility’s electricity and natural gas operations are inherently hazardous and involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial results.  The Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event.

 

The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system.  (See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. Business.)  The Utility’s ability to earn its authorized ROE depends on its ability to efficiently maintain, operate, and protect its facilities, and provide electricity and natural gas services safely and reliably.  The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities.  In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives.  The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from:

 

·	the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines, that can cause explosions, fires, or other catastrophic events;

·	an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that results in the failure of downstream transmission pipelines or distribution assets and uncontained natural gas flow;
·	failure to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;
·	a prolonged statewide electrical black-out that results  in damage to the Utility’s equipment or damage to property owned by customers or other third parties;
·	the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage;
·	the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;
·	the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;
·	the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wild land fire or natural gas explosion), and the failure to respond effectively to a catastrophic event;
·	inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;
·	severe weather events such as storms, tornadoes, floods, drought, earthquakes, tsunamis, wild land and other fires, pandemics, solar events, electromagnetic events, or other natural disasters;
·	operator or other human error;
·	an ineffective records management program that results in the failure to construct, operate and maintain a utility system safely and prudently;
·	construction performed by third parties that damage the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines;
·	the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; flaking lead paint from the Utility's facilities, and leaking or spilled insulating fluid from electrical equipment; and
·	attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.

 

The occurrence of any of these events could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death.  As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, and to compensate third parties.  In particular, the Utility may incur material liability in connection with a wildfire (known as the “Butte fire”) that ignited and spread in Amador and Calaveras counties in Northern California in September 2015 depending on the outcome of the investigations into the cause of the fire. If insurance recoveries are unavailable or insufficient to cover such costs, PG&E Corporation’s and the Utility’s financial condition or results of operations could be materially affected.  The Utility also could incur material fines, penalties or disallowances, as a result of enforcement actions taken by the CPUC or other law enforcement agencies.

 

Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities or the construction or demolition or facilities, the Utility may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders.  The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.  Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject.  An uninsured loss could have a material effect on PG&E Corporation’s and the Utility’s financial results.  Future insurance coverage may not be available at rates and on terms as favorable as the Utility’s current insurance coverage or may not be available at all.

 

The Utility’s operational and information technology systems could fail to function properly or be damaged by third parties (including cyber-attacks and acts of terrorism), severe weather, natural disasters, or other events. Any of these events could disrupt the Utility’s operations and cause the Utility to incur unanticipated losses and expense or liability to third parties.

 

The operation of the Utility’s extensive electricity and natural gas systems relies on evolving and increasingly complex operational and information technology systems and network infrastructures that are interconnected with the systems and network infrastructure owned by third parties.  The Utility’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of tasks and transactions. Despite implementation of security measures, all of the Utility’s technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes.  The failure of the Utility’s operational and information technology systems and networks could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; damage the Utility’s assets or operations or those of third parties; and subject the Utility to claims by customers or third parties, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial results.

 

The Utility’s systems, including its financial information, operational systems, advanced metering, and billing systems, require ongoing maintenance, modification, and updating, which can be costly and increase the risk of errors and malfunction.  The Utility often relies on third-party vendors to maintain, modify, and update its systems and these third-party vendors could cease to exist.  Any disruptions or deficiencies in existing systems, or disruptions, delays or deficiencies in the modification or implementation of new systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively affect the Utility’s ability to maintain effective financial controls, and/or the Utility’s ability to timely file required regulatory reports.  The Utility also could be subject to patent infringement claims arising from the use of third-party technology by the Utility or by a third-party vendor.

 

In addition, the Utility’s information systems contain confidential information, including information about customers and employees.  The theft, damage, or improper disclosure of confidential information can subject the Utility to penalties for violation of applicable privacy laws, subject the Utility to claims from third parties, reduce the value of proprietary information, and harm the Utility’s reputation.

 

The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements change or the plant ceases operations before the licenses expire.

 

The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spent nuclear fuel, and the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act.  If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial results.  In addition, the Utility may be required under federal law to pay up to $255 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)  

 

In addition, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel.  Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power.  Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete.  It is also possible that public pressure could grow leading to adverse changes in legislation, regulations, orders, or their interpretation.  As a result, operations at the Utility’s two nuclear generation units at Diablo Canyon could cease before the licenses expire in 2024 and 2025.  In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge could have a material effect on PG&E Corporation and the Utility’s financial results.

 

The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders.  (See “Regulatory Environment” in Item 1. Business.)  If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial results could be materially affected.  The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until the Utility can comply with new regulations, orders, or decisions.  The Utility may incur a material charge if it ceases operations at Diablo Canyon before the licenses expire in 2024 and 2025.  At December 31, 2015, the Utility’s unrecovered investment in Diablo Canyon was $2.3 billion.

 

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%.  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. 

 

Further, the Utility’s leases of coastal land occupied by the water intake and discharge structures for the nuclear generation units at Diablo Canyon expire in 2018 and 2019.  The Utility has requested that the California State Lands Commission renew the leases until 2024 and 2025 when the NRC licenses expire.  The California State Lands Commission has deferred acting on the application until later in 2016.  It is uncertain what level of environmental review, if any, will be required before the leases can be extended.  If the leases are not extended or if the Utility determines that it cannot comply with any new environmental conditions in a feasible and economic manner, then operations at Diablo Canyon would cease and the Utility could incur a material charge for the remaining amount of its unrecovered investment. 

 

The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives.  (See Note 2: Summary of Significant Accounting Policies – Asset Retirement Obligations of the Notes to the Consolidated Financial Statement in Item 8.)  The CPUC authorizes the Utility to recover its estimated costs to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.  If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial results could be materially affected.

 

Risks Related to Environmental Factors

 

The Utility’s operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation’s and the Utility’s financial results.

 

The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife.  The Utility incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations.  The Utility has been in the past, and may be in the future, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws.  Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 for more information.)  

 

Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations.  Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions. 

 

The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms.  One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.

 

Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance.  (See “Environmental Regulation” in Item 1.) The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial results.  Their financial results also can be materially affected by changes in estimated costs and by the extent to which actual remediation costs differ from recorded liabilities.

 

The Utility’s future operations may be affected by climate change that may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. 

 

The Utility has been studying the potential effects of climate change (increased temperatures, changing precipitation patterns, rising sea levels) on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most significant.  Scientists project that climate change will increase electricity demand due to more extreme, persistent and hot weather.  Increasing temperatures and changing levels of precipitation in the Utility’s service territory would reduce snowpack in the Sierra Mountains.  If the levels of snowpack were reduced, the Utility’s hydroelectric generation would decrease and the Utility would need to acquire additional generation from other sources at a greater cost.  If the Utility increases its reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits.  In addition, increasing temperatures and lower levels of precipitation could increase the occurrence of wildfires in the Utility’s service territory causing damage to the Utility’s facilities or the facilities of third parties on which the Utility relies to provide service, damage to third parties for loss of property, personal injury, or loss of life. In addition, flooding caused by rising sea levels could damage the Utility’s facilities, including hydroelectric assets such as dams and canals, and the electric transmission and distribution assets.  The Utility could incur substantial costs to repair or replace facilities, restore service, compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase. 

 

Events or conditions caused by climate change could have a greater impact on the Utility’s operations than the Utility’s studies suggest and could result in lower revenues or increased expenses, or both.  If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected.

 

Other Risk Factors

 

The Utility may be required to incur substantial costs in order to obtain or renew licenses and permits needed to operate the Utility’s business and the Utility may be subject to fines and penalties for failure to comply or obtain license renewal.

 

The Utility must comply with the terms of various governmental permits, authorizations, and licenses, including those issued by the FERC for the continued operation of the Utility’s hydroelectric generation facilities, and those issued by environmental and other federal, state and local governmental agencies. Many of the Utility’s capital investment projects, and some maintenance activities, often require the Utility to obtain land use, construction, environmental, or other governmental permits.  These permits, authorizations, and licenses may be difficult to obtain on a timely basis, causing work delays.  Further, existing permits and licenses could be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued.  In addition, the Utility often seeks periodic renewal of a license or permit, such as a waste discharge permit or a FERC operating license for a hydroelectric generation facility.  If a license or permit is not renewed for a particular facility and the Utility is required to cease operations at that facility, the Utility could incur an impairment charge or other costs.  Before renewing a permit or license, the issuing agency may impose additional requirements that may increase the Utility’s compliance costs.  In particular, in connection with a license renewal for one or more of the Utility’s hydroelectric generation facilities or assets, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility.  In addition, local governments may attempt to assert jurisdiction over various utility operations by requiring permits or other approvals that the Utility has not been previously required to obtain. 

 

The Utility may incur penalties and sanctions for failure to comply with the terms and conditions of licenses and permits which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.  If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, licenses, ordinances, or other requirements, or if the Utility cannot recover the increase in associated compliance and other costs in a timely manner, PG&E Corporation’s and the Utility’s financial results could be materially affected. 

 

Poor investment performance or other factors could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension plan, other postretirement benefits plans, and nuclear decommissioning trusts.

 

PG&E Corporation and the Utility provide defined benefit pension plans and other postretirement benefits for eligible employees and retirees.  The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities.  The performance of the debt and equity markets affects the value of plan assets and trust assets.  A decline in the market value may increase the funding requirements for these plans and trusts. The cost of providing pension and other postretirement benefits is also affected by other factors, including interest rates used to measure the required minimum funding levels, the rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, future government regulation, and prior contributions to the plans.  Similarly, funding requirements for the nuclear decommissioning trusts are affected by the rates of return on trust assets, changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements as well as changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment.  (See Note 2: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in Item 8.) If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans or if actual nuclear decommissioning costs exceed the amount of nuclear decommissioning trust funds and the Utility is unable to recover the contributions or additional costs in rates, PG&E Corporation’s and the Utility’s financial results could be materially affected.

 

The Utility’s success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees.  PG&E Corporation’s and the Utility’s results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.

 

The Utility’s workforce is aging and many employees are or will become eligible to retire within the next few years.  Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may be faced with a shortage of experienced and qualified personnel.  The majority of the Utility’s employees are covered by collective bargaining agreements with three unions.  Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements with the unions or if tentative new agreements are not ratified by their members.  In addition, some of the remaining non-represented Utility employees could join one of these unions in the future. 

 

PG&E Corporation and the Utility also may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the ongoing enforcement proceedings.  Any such occurrences could negatively impact PG&E Corporation’s and the Utility’s financial condition and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2. PROPERTIES

 

The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, which are described in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.”  The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities.  In total, the Utility occupies 11.1 million square feet of real property, including 8.9 million square feet owned by the Utility.  The Utility's corporate headquarters comprises approximately 1.7 million square feet located in several Utility-owned buildings in San Francisco, California.

 

PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California.  This lease will expire in 2022.

 

The Utility currently owns approximately 168,000 acres of land, including approximately 140,000 acres of watershed lands.  In 2002 the Utility agreed to implement its “Land Conservation Commitment” (“LCC”) to permanently preserve the six “beneficial public values” on all the watershed lands through conservation easements or equivalent protections, as well as to make approximately 70,000 acres of the watershed lands available for donation to qualified organizations.  The six “beneficial public values” being preserved by the LCC include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values.  The Utility’s goal is to implement all the transactions needed to implement the LCC by the end of 2018, subject to securing all required regulatory approvals.

 

ITEM 3. LEGAL PROCEEDINGS

 

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business.  For more information regarding material lawsuits and proceedings, see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 and in Item 7. MD&A.

 

Penalty Decision Related to the CPUC’s Investigative Enforcement Proceedings Related to Natural Gas Transmission

 

On April 9, 2015, the CPUC approved final decisions in the three investigations that had been brought against the Utility relating to (1) the Utility’s safety record-keeping 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, record-keeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.  In August 2015, the Utility paid the $300 million fine. At December 31, 2015, the Consolidated Balance Sheets include $400 million in current liabilities – other for the one-time bill credit that will be provided to the Utility’s natural gas customers in 2016.  On January 14, 2016, the CPUC issued final decisions to close these investigative proceedings.

 

The Penalty Decision requires that at least $689 million of the $850 million disallowance be allocated to capital expenditures, and that the Utility be precluded from including these capital costs in rate base.  The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case.  If the $850 million is not exhausted by designated safety-related projects and programs in the 2015 GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify safety-related projects and programs that will be subject to the disallowance. It is uncertain how much of the Utility’s costs to perform the safety-related projects and programs the CPUC will identify as counting toward the $850 million shareholder-funded obligation. If the Utility’s actual costs exceed costs that the CPUC counts towards the $850 million maximum, the Utility would record additional charges if such costs are not otherwise authorized by the CPUC.  As a result, the total shareholder-funded obligation could exceed $850 million.  For more information, see “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

 

Federal Criminal Indictment

 

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that superseded the original indictment that was returned on April 1, 2014.  The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record-keeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident.  On December 23, 2015, the court presiding over the federal criminal proceeding dismissed 15 of the Pipeline Safety Act counts, leaving 13 remaining counts.  The maximum statutory fine for each felony count is $500,000 for total potential fines of $6.5 million.  On December 8, 2015, the court also issued an order granting, in part, the Utility’s request to dismiss the government’s allegations seeking an alternative fine under the Alternative Fines Act.  (The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”)  The court dismissed the government’s allegations regarding the amount of losses, but concluded that it required additional information about how the government would prove its allegations about the amount of the gross gain prior to deciding whether to dismiss those allegations. (Based on the superseding indictment’s allegation that the Utility derived gross gains of approximately $281 million, the potential maximum alternative fine would be approximately $562 million.)   After considering the additional information submitted by the government, on February 2, 2016, the court issued an order holding that if the government’s allegations about the Utility’s gross gains are considered, they would be considered in a second trial phase that would take place after the trial on the criminal charges. The trial on the criminal charges currently is scheduled to begin March 22, 2016.

 

The Utility entered a plea of not guilty.  The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Consolidated Financial Statements as such amounts are not considered to be probable.

 

Litigation Related to the San Bruno Accident and Natural Gas Spending

 

As of December 31, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

 

Four of the complaints were consolidated as the San Bruno Fire Derivative Cases and are pending in the Superior Court of California, County of San Mateo.  On August 28, 2015, the Superior Court overruled the demurrers filed by PG&E Corporation, the Utility and the individual director and officer defendants seeking to dismiss the San Bruno Fire Derivative Cases, based upon the plaintiffs’ failure to demand action by the Boards of PG&E Corporation and the Utility prior to filing the complaint.  After the ruling, and pursuant to co-petitions for writ of mandate previously filed by PG&E Corporation, the Utility, and the individual defendants, on September 3, 2015, the California Court of Appeal issued an order staying the San Bruno Fire Derivative Cases pending the court’s final determination whether to stay the matter altogether until the resolution of federal criminal proceedings against the Utility.  On September 30, 2015, PG&E Corporation, the Utility, and the individual defendants filed an additional petition for writ of mandate asking the Court of Appeal to review the lower court’s August 28 decision overruling their demurrers.  On October 22, 2015, the Court of Appeal issued a ruling declining to review the August 28 decision.  On December 8, 2015, the Court of Appeal issued a writ of mandate to the Superior Court, ordering the Superior Court to stay all proceedings in the San Bruno Fire Derivative Cases “pending conclusion of the federal criminal proceedings” against the Utility.  The other two derivative actions are entitled Tellardin v. PG&E Corp. et. al., pending in the Superior Court of California, San Mateo County, and Iron Workers Mid-South Pension Fund v. Johns, et. al., pending in the United States District Court for the Northern District of California.  PG&E Corporation, and the other defendants have not answered or otherwise responded to the complaints in these actions.  In the Tellardin action, the defendants must answer or respond to the complaint 30 days after the stay in the San Bruno Fire Derivative Cases is lifted.  In the Iron Workers action, the court has not established a deadline by which the defendants must answer or respond.  Case management conferences have been scheduled in both actions (March 21, 2016 in the Tellardin action and June 3, 2016 in the Iron Workers action), after which PG&E Corporation will have more information about any further proceedings in these actions. 

 

Investigation of the Butte Fire

 

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  The California Department of Forestry and Fire Protection (“Cal Fire”) is investigating the source of the Butte Fire to determine whether a tree contacted a power line operated by the Utility and was the cause of the fire.  Cal Fire has reported that as a result of the fire there were two deaths and 965 structures, including 571 houses, were damaged or destroyed. Cal Fire’s investigation is expected to conclude in 2016.  

 

Approximately 27 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in both the County of Calaveras and the County of San Francisco, involving more than 600 individual plaintiffs and their insurance companies. Plaintiffs and the Utility filed petitions with the California Judicial Council to coordinate these cases.  The petitions were assigned to the Calaveras Superior Court for a recommendation to the Judicial Council.  On January 21, 2016, the Calaveras Superior Court issued an order recommending to the Judicial Council that the cases be coordinated in the Superior Court of California, Sacramento County, for all purposes including trial.  Among other factors, the Court found that coordination requires a court with a significant number of judges and complex litigation support personnel, neither of which are present in Calaveras County.  For additional information, see “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

 

Other Enforcement Matters

 

The Utility also could be required to pay fines, or incur other unrecoverable costs, associated with the CPUC’s pending investigations of the Utility’s natural gas distribution facilities record-keeping practices and the Utility’s potential violations of the CPUC’s ex parte communication rules.  In addition, fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of noncompliance with natural gas safety regulations, investigations that were commenced after a pipeline explosion in Carmel, California on March 3, 2014, and other enforcement matters. See “Enforcement and Litigation Matters” in Note 13: Contingencies and Commitments of the Notes to the Consolidated Financial Statements in Item 8.

 

Diablo Canyon Power Plant

 

The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected.  The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species.  In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.

 

In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act.  As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources.  On March 21, 2003, the Central Coast Board voted to accept the settlement agreement.  On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office.  A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's permit.

 

At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely.  Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff.  In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures.  If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million.  The Utility would seek to recover these costs through rates charged to customers.

 

The final requirements of the federal and state cooling water policies (discussed above in Item 1. Business under “Environmental Regulation – Water Quality”) could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement.  PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.  

 

Venting Incidents in San Benito County

 

As part of its regular maintenance and inspection practices for its natural gas transmission system, the Utility performs in-line inspections of pipelines using devices called “pigs” that travel through the pipeline to inspect and clean the walls of the pipe.  When in-line inspections are performed, natural gas in the pipeline is released or vented at the pipeline station where the device is removed.  In February 2014, the Utility conducted an in-line inspection of a natural gas transmission pipeline that traverses San Benito County and vented the natural gas at the Utility’s transmission station located in Hollister, which is next to an elementary school.  The Utility vented the natural gas during school hours on three occasions that month.  After being informed of the venting by the local air district, the San Benito County District Attorney notified the Utility in December 2014 that it was contemplating bringing legal action against the Utility for violation of Health and Safety Code section 41700, which prohibits discharges of air contaminants that cause a public nuisance.  The Utility has been in settlement discussions with the district attorney’s office since that time.  On October 28, 2015, the district attorney informed the Utility that it would seek civil penalties in excess of $100,000 but is willing to continue to explore settlement options with the Utility.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable. 

EXECUTIVE OFFICERS OF THE REGISTRANTS

 

The following individuals serve as executive officers (1) of PG&E Corporation and/or the Utility, as of February 18, 2016.  Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

 

Name		Age		Positions Held Over Last Five Years		Time in Position
Anthony F. Earley, Jr.		66		Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation		September 13, 2011 to present
				Executive Chairman of the Board, DTE Energy Company		October 1, 2010 to September 12, 2011
Nickolas Stavropoulos		57		President, Gas		September 15, 2015 to present
				President, Gas Operations		August 17, 2015 to September 15, 2015
				Executive Vice President, Gas Operations		June 13, 2011 to August 16, 2015
				Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid		August 2007 to March 31, 2011
Geisha J. Williams		54		President, Electric		September 15, 2015 to present
				President, Electric Operations		August 17, 2015 to September 15, 2015
				Executive Vice President, Electric Operations		June 1, 2011 to August 16, 2015
				Senior Vice President, Energy Delivery		December 1, 2007 to May 31, 2011
Jason P. Wells		38		Senior Vice President and Chief Financial Officer, PG&E Corporation		January 1, 2016 to present
				Vice President, Business Finance		August 1, 2013 to December 31, 2015
				Vice President, Finance		October 1, 2011 to July 31, 2013
				Senior Director and Assistant Controller		November 1, 2008 to September 30, 2011
Dinyar B. Mistry		54		Vice President, Chief Financial Officer, and Controller		October 1, 2011 to present
				Vice President and Controller, PG&E Corporation		March 8, 2010 to present
				Vice President and Controller		March 8, 2010 to September 30, 2011
John R. Simon		51		Executive Vice President, Corporate Services and Human Resources, PG&E Corporation		August 17, 2015 to present
				Senior Vice President, Human Resources		April 16, 2007 to August 16, 2015
				Senior Vice President, Human Resources, PG&E Corporation		April 16, 2007 to August 16, 2015
Karen A. Austin		54		Senior Vice President and Chief Information Officer		June 1, 2011 to present
				President, Consumer Electronics, Sears Holdings		February 2009 to May 2011
Desmond A. Bell		53		Senior Vice President, Safety and Shared Services		January 1, 2012 to present
				Senior Vice President, Shared Services and Chief Procurement Officer		October 1, 2008 to December 31, 2011

Helen A. Burt		59		Senior Vice President, External Affairs and Public Policy, PG&E Corporation		September 30, 2015 to present
				Senior Vice President, Corporate Affairs		September 18, 2014 to September 30, 2015
				Senior Vice President, Corporate Affairs, PG&E Corporation		September 18, 2014 to September 30, 2015
				Senior Vice President and Chief Customer Officer		February 27, 2006 to September 17, 2014
Loraine M. Giammona		48		Senior Vice President and Chief Customer Officer		September 18, 2014 to present
				Vice President, Customer Service		January 23, 2012 to September 17, 2014
				Regional Vice President, Customer Care, Comcast Cable		November 2002 to January 2012
Edward D. Halpin		54		Senior Vice President, Power Generation and Chief Nuclear Officer		September 8, 2015 to present
				Senior Vice President and Chief Nuclear Officer		April 2, 2012 to September 8, 2015
				President, Chief Executive Officer and Chief Nuclear Officer, South Texas Project Nuclear Operating Company		December 2009 to March 2012
Kent M. Harvey		57		Senior Vice President, Finance, PG&E Corporation		January 1, 2016 to present
				Senior Vice President and Chief Financial Officer, PG&E Corporation		August 1, 2009 to December 31, 2015
				Senior Vice President, Financial Services		August 1, 2009 to August 17, 2015
Julie M. Kane		57		Senior Vice President and Chief Ethics and Compliance Officer		May 18, 2015 to present
				Vice President, General Counsel and Compliance Officer, North America and Corporate Functions, and Compliance Officer, North America, Avon Products, Inc.		September 30, 2013 to March 31, 2015
				Vice President, Ethics and Compliance, Novartis Corporation		January 1, 2010 to August 31, 2013
Gregory K. Kiraly		51		Senior Vice President, Electric Transmission and Distribution		September 8, 2015 to present
				Senior Vice President, Electric Distribution Operations		September 18, 2012 to September 8, 2015
				Vice President, Electric Distribution Operations		October 1, 2011 to September 17, 2012
				Vice President, SmartMeter Operations		August 23, 2010 to September 30, 2011
Steven E. Malnight		43		Senior Vice President, Regulatory Affairs		September 18, 2014 to present
				Vice President, Customer Energy Solutions		May 15, 2011 to September 17, 2014
				Vice President, Integrated Demand Side Management		July 1, 2010 to May 14, 2011

Hyun Park		54		Senior Vice President and General Counsel, PG&E Corporation		November 13, 2006 to present
Jesus Soto, Jr.		48		Senior Vice President, Gas Operations		September 8, 2015 to present
				Senior Vice President, Engineering, Construction and Operations		September 16, 2013 to September 8, 2015
				Senior Vice President, Gas Transmission Operations		May 29, 2012 to September 15, 2013
				Vice President, Operations Services, El Paso Pipeline Group		May 2007 to May 2012
Fong Wan		54		Senior Vice President, Energy Policy and Procurement		September 8, 2015 to present
				Senior Vice President, Energy Procurement		October 1, 2008 to September 8, 2015

 

(1) Mr. Earley, Mr. Stavropoulos, Ms. Williams, Mr. Simon, Ms. Burt, Ms. Kane, Mr. Park, and Mr. Wells are executive officers of both PG&E Corporation and the Utility.  Mr. Harvey is an executive officer of PG&E Corporation only.  All other listed officers are executive officers of the Utility only.

PART II

 

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

As of February 12, 2016, there were 59,317 holders of record of PG&E Corporation common stock.  PG&E Corporation common stock is listed on the New York Stock Exchange.  The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth in the table entitled “Quarterly Consolidated Financial Data (Unaudited)” which appears after the Notes to the Consolidated Financial Statements in Item 8. Shares of common stock of the Utility are wholly owned by PG&E Corporation.  Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility for the two most recent fiscal years and information about the restrictions upon the payment of dividends on their common stock Utility appears in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 of the Notes to the Consolidated Financial Statements in Item 8 and in “Liquidity and Financial Resources – Dividends” in Item 7 below.

 

Sales of Unregistered Equity Securities

 

 

Issuer Purchases of Equity Securities

 

During the quarter ended December 31, 2015, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.  Also, during the quarter ended December 31, 2015, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 6. SELECTED FINANCIAL DATA

 

(in millions, except per share amounts)	2015		2014			2013			2012			2011
PG&E Corporation
For the Year
Operating revenues	$	16,833	$	17,090		$	15,598		$	15,040		$	14,956
Operating income		1,508		2,450			1,762			1,693			1,942
Net income		888		1,450			828			830			858
Net earnings per common share, basic (1)		1.81		3.07			1.83			1.92			2.10
Net earnings per common share, diluted		1.79		3.06			1.83			1.92			2.10
Dividends declared per common share (2)		1.82		1.82			1.82			1.82			1.82
At Year-End
Common stock price per share	$	53.19	$	53.24		$	40.28		$	40.18		$	41.22
Total assets		63,339		60,127			55,605			52,449			49,750
Long-term debt (excluding current portion)		16,030		15,050			12,717			12,517			11,766
Capital lease obligations (excluding current
portion) (3)		49		69			90			113			212
Pacific Gas and Electric Company
For the Year
Operating revenues	$	16,833	$	17,088		$	15,593		$	15,035		$	14,951
Operating income		1,511		2,452			1,790			1,695			1,944
Income available for common stock		848		1,419			852			797			831
At Year-End
Total assets		63,140		59,865			55,049			51,923			49,242
Long-term debt (excluding current portion)		15,680		14,700			12,717			12,167			11,417
Capital lease obligations (excluding current
portion) (3)		49		69			90			113			212

(1) See “Summary of Changes in Net Income and Earnings per Share” in Item 7. MD&A.

(2) Information about the frequency and amount of dividends and restrictions on the payment of dividends is set forth in “Liquidity and Financial Resources – Dividends” in MD&A in Item 7 and in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 in Item 8.

(3) The capital lease obligations amounts are included in noncurrent liabilities – other in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.