10-K 1 form10k.htm FORM 10-K

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, 2017

 

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________ to  ___________

 

Commission

File Number

 

Exact Name of Registrant

as Specified In Its Charter

 

State or Other Jurisdiction of

Incorporation or Organization

 

IRS Employer

Identification Number

1-12609

 

PG&E CORPORATION

 

California

 

94-3234914

1-2348

 

PACIFIC GAS AND ELECTRIC COMPANY

 

California

 

94-0742640

 

 

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 MKT LLC

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).

 

PG&E Corporation

Yes ☑ No ☐

Pacific Gas and Electric Company

Yes ☑ No ☐

 

 

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:

PG&E Corporation

Pacific Gas and Electric Company

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” 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 ☐

Emerging growth company ☐

 

Emerging growth company ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

 

                     PG&E Corporation

                     Pacific Gas and Electric 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, 2017, the last business day of the most recently completed second fiscal quarter:

 

                 PG&E Corporation common stock     

                     $33,956 million

                 Pacific Gas and Electric Company common stock

                     Wholly owned by PG&E Corporation

 

Common Stock outstanding as of February 1, 2018:

 

 

                PG&E Corporation:

514,969,045 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 2018 Annual Meetings of Shareholders
Part III (Items 10, 11, 12, 13 and 14)

2

 
 

Contents

 

UNITS OF MEASUREMENT

GLOSSARY

PART I

ITEM 1. BUSINESS

Regulatory and Enforcement 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 Shareholder 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

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

3


NOTE 9: DERIVATIVES

NOTE 10: FAIR VALUE MEASUREMENTS

NOTE 11: EMPLOYEE BENEFIT PLANS

NOTE 12: RELATED PARTY AGREEMENTS AND TRANSACTIONS

NOTE 13: CONTINGENCIES AND COMMITMENTS

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

ITEM 9A. Controls and Procedures

ITEM 9B. Other Information

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

ITEM 11. Executive Compensation

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

ITEM 13. Certain Relationships and Related Transactions, and Director Independence

ITEM 14. Principal Accountant Fees and Services

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

EXHIBIT INDEX

ITEM 16. Form 10-k summary

SIGNATURES

UNITS OF MEASUREMENT

 

1 Kilowatt-Hour (kWh)

=

One kilowatt continuously for one hour

1 Megawatt (MW)

=

One thousand kilowatts

1 Megawatt-Hour (MWh)

=

One megawatt continuously for one hour

1 Gigawatt-Hour (GWh)

=

One gigawatt continuously for one hour

1 Kilovolt (kV)

=

One thousand volts

1 MVA

=

One megavolt ampere

1 Mcf

=

One thousand cubic feet

1 MMcf

=

One million cubic feet

 


GLOSSARY

 

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

 

2017 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, 2017

AB

Assembly Bill

AFUDC

allowance for funds used during construction

ARO

asset retirement obligation

ASU

accounting standard update issued by the FASB (see below)

CAISO

California Independent System Operator

California Water Board

California State Water Resources Control Board

Cal Fire

California Department of Forestry and Fire Protection

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

CEMA

Catastrophic Event Memorandum Account

CO2

carbon dioxide

CPUC

California Public Utilities Commission

CRRs

congestion revenue rights

DER

distributed energy resources

DIDF

Distribution Investment Deferral Framework

Diablo Canyon

Diablo Canyon nuclear power plant

DOE

U.S. Department of Energy

DOGGR

Division of Oil, Gas and Geothermal Resources

DOI

U.S. Department of the Interior

DRP

electric distribution resources plan

DTSC

Department of Toxic Substances Control

EDA

equity distribution agreement

EMANI

European Mutual Association for Nuclear Insurance

EPA

Environmental Protection Agency

EPS

earnings per common share

EV

electric vehicle

FASB

Financial Accounting Standards Board

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

HSM

hazardous substance memorandum account

IOUs

investor-owned utility(ies)

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

NAV

net asset value

NDCTP

Nuclear Decommissioning Cost Triennial Proceeding

NEIL

Nuclear Electric Insurance Limited

NEM

net energy metering

NRC

Nuclear Regulatory Commission

NTSB

National Transportation Safety Board

OES

State of California Office of Emergency Services

OII

order instituting investigation

 


OIR

order instituting rulemaking

ORA

Office of Ratepayer Advocates

PCIA

Power Charge Indifference Adjustment

PD

proposed decision

PFM

petition for modification

PHMSA

Pipeline and Hazardous Materials Safety Administration

PSEP

pipeline safety enhancement plan

QF

qualifying facility

RAMP

Risk Assessment Mitigation Phase

REITS

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

Tax Act

Tax Cuts and Jobs Act of 2017

TE

transportation electrification

TO

transmission owner

TURN

The Utility Reform Network

Utility

Pacific Gas and Electric Company

VIE(s)

variable interest entity(ies)

WEMA

Wildfire Expense Memorandum Account

Westinghouse

Westinghouse Electric Company, LLC

 


                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        

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, 2017, PG&E Corporation and the Utility had approximately 23,000 regular employees, approximately 20 of which were employees of PG&E Corporation.  Of the Utility’s regular employees, approximately 15,000 are covered by collective bargaining agreements with the local chapters of three labor unions:  the International Brotherhood of Electrical Workers; the Engineers and Scientists of California; and the Service Employees International Union.  The collective bargaining agreements currently in effect 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.  Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency.  It is possible that these regulatory filings or information included therein could be deemed to be material information.  The information contained on this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC.  PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.  PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab, in order to publicly disseminate such information. 

 

This 2017 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 “Forward-Looking Statements” in Item 7. MD&A.

 

Regulatory and Enforcement 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, including 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 is a regulatory agency that regulates privately owned public utilities in California.  The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility's electric and natural gas distribution operations, electric 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 electric 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. 

 

The CPUC has delegated authority to the SED to issue citations and impose penalties for violations identified through audits, investigations, or self-reports.  Under the current gas and electric citation programs adopted by the CPUC in September 2016, the SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.  The SED has the discretion to either address each violation in a distinct citation or to include multiple violations in a single citation regardless of whether the violations occurred in the same incident or are of a similar nature. Penalty payments for citations issued pursuant to the gas and electric safety citation programs are the responsibility of shareholders of an issuer and must not be recovered in rates or otherwise directly or indirectly charged to customers. 

 

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 establishment of energy storage procurement targets, 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 Item 7. MD&A and Item 1A. Risk Factors.) 

 

The Federal Energy Regulatory Commission and the California Independent System Operator

 

The FERC has jurisdiction over the Utility's electric 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 system 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 electric 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 violations 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 electric 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 generating 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 Nuclear Power Plant” in Item 7. MD&A and Item 1A. Risk Factors below.)

 

Third-party monitor

 

On April 12, 2017, the Utility retained a third-party monitor at the Utility’s expense as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction, which sentenced the Utility to, among other things, a five-year corporate probation period and oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years.  The goal of the monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations and maintains effective ethics, compliance, and safety related incentive programs on a Utility-wide basis.  (For additional information see Item 1A. Risk Factors.)

 

Other Regulators

 

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 and for adopting building and appliance energy efficiency requirements.

 

The CARB is the state agency responsible for setting and monitoring GHG and other emission limits.  The CARB is also 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.  (For additional information see Item 1A. Risk Factors.)

 

 


Ratemaking Mechanisms

 

The Utility’s rates for electric and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service and 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 the Utility is allowed to “pass-through” to customers (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Item 7. 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.  Similarly, the authorized rate of return on all other Utility 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, are designed to allow the Utility to fully collect its authorized base revenue requirements.  As a result, the Utility’s base revenues are not impacted by fluctuations in sales resulting from rate changes or usage.  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 Item 7. MD&A) within its authorized base revenue requirements.

 

Due to the seasonal nature of the Utility’s business and rate design, customer electric bills are generally higher during summer months (May – October) because of higher demand, driven by air conditioning loads.  Customer bills related to gas service generally increase during the winter months (November – March) to account for the gas peak due to heating.

 

During 2017, 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 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 “Regulatory Matters” in Item 7. MD&A for more 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 “Regulatory Matters – 2015 – 2016 Energy Efficiency Incentives Awards” in Item 7. MD&A.)

 

Base Revenues

 

General Rate Cases

 

The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, including return on rate base, related to its electric distribution, natural gas distribution, and Utility-owned electric generation operations.  The CPUC generally conducts a GRC every three or four 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 in revenue requirements for the subsequent years of the GRC period (known as “attrition years”).  Attrition year 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 other business, community, customer, environmental, and union interests.  The Utility plans to file the 2020 GRC in the third quarter of 2018.  In December 2014, the CPUC established two new procedures concerning safety-related activities, the Safety Model Assessment Proceeding and the RAMP, preceding a utility’s GRC. The purpose of the Safety Model Assessment Proceeding is to undertake a comprehensive analysis of each utility’s risk-based decision making approach.  The RAMP submittal includes a utility’s prioritization of the risks it is facing, and a prioritization of risk mitigation alternatives, as well as a risk mitigation plan.  The Utility filed its first RAMP submittal with the CPUC on November 30, 2017.

 

(For more information about the Utility’s GRC, see “Regulatory Matters −2017 General Rate Case” and Regulatory Matters −2020 General Rate Case” in Item 7. 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.  The CPUC generally conducts a GT&S rate case every three or four years.  Similar to the GRC, the CPUC approves the annual revenue requirements for the first year (or “test year”) of the GT&S rate case period and typically determines annual increases in revenue requirements for attrition years of the GT&S rate case period.  Parties in the Utility's GT&S rate case include the ORA and TURN, who generally represent the overall interests of residential customers, as well as other intervenors who represent other business, community, customer, environmental, and union interests.  The Utility filed the 2019 GT&S rate case application on November 17, 2017.  (For more information, see “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” and “Regulatory Matters – 2019 Gas Transmission and Storage Rate Case” in Item 7. MD&A.)     

 

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 2019, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock.  The CPUC also set the authorized ROE through 2017 at 10.40% and 10.25% beginning on January 1, 2018 and reset the cost of debt to 4.89%.  The CPUC 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.

 

(For more information, see “Regulatory Matters – CPUC Cost of Capital” in Item 7. MD&A.)

 

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 has historically filed 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 by the CPUC in the Utility's retail electric rates and by the CAISO in its Transmission Access Charges to wholesale customers.  (For more information, see “Regulatory Matters –Transmission Owner Rate Cases” in Item 7. 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 electrical capacity required to meet bundled customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electric contracts.  The utilities are responsible for scheduling and bidding electric generation resources, including certain electricity procured from third parties into 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 bundled customer procurement plans based on long-term demand forecasts.  In October 2015, the CPUC approved the Utility’s most recent bundled customer procurement plan.  It was revised since its initial approval and will remain in effect as revised until superseded by a subsequent CPUC-approved plan.

 

California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved bundled customer procurement plans without further after-the-fact reasonableness review by the CPUCThe 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.  Additionally, the CPUC may disallow the cost of replacement power procured due to unplanned outages at Utility-owned generation facilities.

 

 


The Utility recovers its electric 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 electric rates more frequently if the forecasted aggregate over-collections or under-collections in the energy resource recovery account exceed 5% of its prior year electric 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 more 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, Storage, and Transportation Costs

 

The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electric rates.

 

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 for its core gas portfolio, through its retail gas rates, 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 core procurement incentive mechanism protects the Utility against after-the-fact reasonableness reviews of its gas procurement costs for its core gas portfolio.  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 these 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 National Energy Board, a Canadian regulatory agency.  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.

 

On January 11, 2018, the CPUC approved the retirement of Diablo Canyon’s two nuclear power reactor units by 2024 and 2025.  (For more information, see “Regulatory Matters” in Item 7. MD&A.)

 

Electric Utility Operations

 

The Utility generates electricity and provides electric 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.

 

The Utility has continued to invest in its vision for a future electric grid which will allow customers to choose new, advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service.  In 2017, the Utility continued to work on the foundation for its program to deploy up to 7,500 charging stations. (For more information, see “Regulatory Matters” in Item 7. 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 electric 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 2017 represented by each major electric resource, and further discussed below.

 

 


Total 2017 Actual Electricity Generated and Procured – 61,397 GWh (1):

 

  

 

Percent of Bundled Retail Sales

 

Owned Generation Facilities

           

Nuclear

   

27.4

%

     

Large Hydroelectric

   

15.1

%

     

Fossil fuel-fired

   

8.7

%

     

Small Hydroelectric

   

1.7

%

     

Solar

   

0.5

%

     

Total

           

53.4

%

 

               

Qualifying Facilities

               

Non-Renewable

   

3.9

%

       

Renewable

   

1.9

%

       

Total

           

5.8

%

Other Third-Party Purchase Agreements

               

Renewable

   

29.0

%

       

Non-Renewable

   

7.3

%

       

Large Hydroelectric

   

3.3

%

       

Total

           

39.6

%

Others, Net (2)

           

1.2

%

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 an 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 into law. SB 350 became effective January 1, 2016, and 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 three-year compliance period thereafter, unless changed by legislative action.  SB 350 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 is required to open a new rulemaking proceeding to adopt regulations to implement the higher renewable targets.  

 

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 2017, 33.1% of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 27%.  Approximately 29% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties.  Additional renewable resources were provided by QFs (1.9%), the Utility’s small hydroelectric facilities (1.7%), and the Utility’s solar facilities (0.5%).

 

 


The total 2017 renewable deliveries shown above were comprised of the following:

 

Type

 

GWh

   

Percent of Bundled Retail Sales

 

Solar

   

8,294

     

13.5

%

Wind

   

5,047

     

8.2

%

Geothermal

   

2,796

     

4.6

%

Biopower

   

2,217

     

3.6

%

RPS-Eligible Hydroelectric

   

1,943

     

3.2

%

Total

   

20,297

     

33.1

%

 

Energy Storage

 

As required by California law, the CPUC has opened a proceeding to establish a multi-year energy storage procurement framework, including energy storage procurement targets to be achieved by each load-serving entity under the CPUC jurisdiction, including the Utility.  Under the adopted energy storage procurement framework, the Utility is required to procure 580 MW of qualifying storage capacity by 2020, with all energy storage projects required to be operational by the end of 2024.

 

The CPUC also adopted biennial interim storage targets for the Utility, beginning in 2014 and ending in 2020.  Under the adopted framework, the Utility is required to conduct biennial competitive request for offer to help meet its interim storage targets. 

 

The Utility’s 2017 energy storage target is 120 MW, plus an additional amount to replace failed and rejected agreements for a total of approximately 160 MW.  On November 30, 2016, the Utility issued its 2016 request for offer. On December 1, 2017, the Utility submitted contracts for 165 MW of energy storage projects for CPUC review.  One of the projects is a 20 MW distribution deferral project that would be Utility-owned.

 

The Utility currently owns or operates three battery storage facilities, each less than 10 MW.

 

 


Owned Generation Facilities

 

At December 31, 2017, 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

 

103

 

2,680

  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

 

 

 

136

 

7,687

 

 

 

 

 

 

 

(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.  On January 11, 2018, the CPUC approved the Utility’s application to retire Unit 1 by 2024 and Unit 2 by 2025. (See “Diablo Canyon Nuclear Power Plant” in. Item 7. MD&A and Item 1A. Risk Factors.)

(2) The Utility’s hydroelectric system consists of 106 generating units at 66 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 large photovoltaic facilities are Cantua solar station (20 MW), Five Points solar station (15 MW), Gates solar station (20 MW), Giffen solar station (10 MW), Guernsey solar station (20 MW), Huron solar station (20 MW ), Stroud solar station (20 MW), West Gates solar station (10 MW), and Westside solar station (15 MW).  All of these facilities are located in Fresno County, except for 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, 2017, the Utility owned approximately 19,200 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV.  The Utility also operated 92 electric transmission substations with a capacity of approximately 64,700 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.

 

Decisions about expansions and maintenance of the transmission system can be influenced by decisions of our regulators. For example, 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 the Fresno, Madera and Kings counties area.  However, the 2022 in-service date for the 70-mile line was subsequently postponed by the CAISO, and the CAISO has placed the project on hold.  The Utility has stopped all work on the project pending a decision from the CAISO that could defer or cancel the project.  A decision by the CAISO is expected by March 2018.  In addition, as a part of the CAISO's 2016-2017 planning efforts, the CAISO found that a number of lower-voltage transmission projects were no longer required and recommended cancelling or requiring further review in the 2017-2018 planning cycle.

 

 


Throughout 2017, the Utility upgraded several 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 secure access to renewable generation resources and 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 electric distribution network consists of approximately 107,200 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 59 transmission switching substations, and 605 distribution substations, with a capacity of approximately 31,800 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.  The Utility operates electric distribution control center facilities in Concord, Rocklin, and Fresno, California; these control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.

 

In 2017, the Utility continued to deploy its fault location, isolation, and service restoration circuit technology that involves the rapid operation of smart switches to reduce the duration of customer outages.  Another 92 circuits were outfitted with this equipment, bringing the total deployment to 882 of the Utility’s 3,200 distribution circuits.  The Utility plans to continue performing work to improve the reliability and safety of its electric distribution operations in 2018.

 

 


Electricity Operating Statistics

 

The following table shows certain of the Utility’s operating statistics from 2015 to 2017 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 2017, 2016 and 2015.

 

 

 

2017

   

2016

   

2015

Customers (average for the year)

   

5,384,525

     

5,349,691

     

5,311,178

Deliveries (in GWh) (1) 

   

82,226

     

83,017

     

85,860

Revenues (in millions):

                     

   Residential

 

$

5,693

   

$

5,409

   

$

5,032

   Commercial

   

5,431

     

5,396

     

5,278

   Industrial

   

1,603

     

1,525

     

1,555

   Agricultural

   

1,069

     

1,226

     

1,233

   Public street and highway lighting

   

79

     

80

     

83

   Other (2)

   

(294)

 

   

(68)

 

   

(84)

      Subtotal

   

13,581

     

13,568

     

13,097

Regulatory balancing accounts (3)

   

(344)

 

   

297

     

560

Total operating revenues

 

$

13,237

   

$

13,865

   

$

13,657

Selected Statistics:

                     

Average annual residential usage (kWh)

   

6,231

     

6,115

     

6,294

Average billed revenues per kWh:

                     

   Residential

 

$

0.1936

   

$

0.1887

   

$

0.1719

   Commercial

   

0.1716

     

0.1716

     

0.1640

   Industrial

   

0.1055

     

0.0990

     

0.0973

   Agricultural

   

0.2041

     

0.1814

     

0.1610

Net plant investment per customer

 

$

7,486

   

$

7,195

   

$

6,660

 

                     

(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 provisions for rate refunds and unbilled electric revenue, 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 95% of core customers, representing approximately 80% of the annual core market demand, receive bundled natural gas service from the Utility.

 

The Utility generally does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers, unless the customer is a natural gas-fired generation facility that the Utility has a power purchase agreement with that includes its generation fuel expense.  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 can also receive natural gas from 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 varied generally based on market conditions.  During 2017, the Utility purchased approximately 291,100 MMcf of natural gas (net of the sale of excess supply of gas).  Substantially all of this natural gas was purchased under contracts with a term of one year or less.  The Utility’s largest individual supplier represented approximately 14% of the total natural gas volume the Utility purchased during 2017.

 

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, 2017, the Utility’s natural gas system consisted of approximately 42,800 miles of distribution pipelines, over 6,400 miles of backbone and local transmission pipelines, and various storage facilities.  The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines.  The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.

 

The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. interconnecting downstream with TransCanada Foothills Pipe Lines Ltd., B.C. System.  The Foothills system interconnects 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 natural 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.  Similarly, the Utility has firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport natural gas from supply points in the Southwestern United States 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.  Changes to gas storage safety requirements by DOGGR have led the Utility to develop and propose in its 2019 GT&S rate case application a natural gas storage strategy which includes the discontinuation (through closure or sale) of operations at two gas storage fields.  (For more information, see “Regulatory Matters” in Item 7. MD&A.)

 

In 2017, the Utility continued upgrading transmission pipeline to allow for the use of in-line inspection tools and continued its work on the final NTSB recommendation from its San Bruno investigation to hydrostatically test all high consequence pipeline mileage.  The Utility currently plans to complete this NTSB recommendation by 2022 for remaining short pipeline segments that include tie-in pieces, fittings or smaller diameter off-takes from the larger transmission pipelines.

 

Natural Gas Operating Statistics

 

The following table shows the Utility's operating statistics from 2015 through 2017 (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 2017, 2016 and 2015.

 

 

 

2017

   

2016

   

2015

Customers (average for the year)

   

4,467,657

     

4,442,379

     

4,415,332

Gas purchased (MMcf)

   

234,181

     

208,260

     

209,194

Average price of natural gas purchased

 

$

2.30

   

$

1.83

   

$

2.11

Bundled gas sales (MMcf):

                     

  Residential

   

160,969

     

149,483

     

144,885

  Commercial

   

50,329

     

46,507

     

43,888

Total Bundled Gas Sales

   

211,298

     

195,990

     

188,773

Revenues (in millions):

                     

Bundled gas sales:

                     

  Residential

 

$

2,298

   

$

1,968

   

$

1,816

  Commercial

   

541

     

439

     

403

  Other

   

(25)

 

   

149

     

125

Bundled gas revenues

   

2,814

     

2,556

     

2,344

Transportation service only revenue

   

976

     

800

     

649

      Subtotal

   

3,790

     

3,356

     

2,993

  Regulatory balancing accounts

   

221

     

446

     

183

Total operating revenues

 

$

4,011

   

$

3,802

   

$

3,176

Selected Statistics:

                     

Average annual residential usage (Mcf)

   

38

     

36

     

35

Average billed bundled gas sales revenues per Mcf:

                     

  Residential

 

$

14.27

   

$

13.10

   

$

12.53

  Commercial

   

11.36

     

9.45

     

9.18

Net plant investment per customer

 

$

3,093

   

$

2,808

   

$

2,573

 

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 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 and businesses that do not affirmatively elect to continue to receive electricity generated or procured by 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 intended 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.  

 

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 (“NEM”), which allows self-generating customers to receive bill credits at the full retail rate, are increasing.  These factors result in a shift of cost responsibility for grid and related services to other customers of the Utility.  For example, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer 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.  New rules and rates became effective for new NEM customers of the Utility in December 2016.  New NEM customers are required to pay an interconnection fee, comply with time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.  Significantly higher bills for remaining customers may result in a decline of the number of such customers as they may seek alternative energy providers.  The CPUC has indicated that it intends to revisit these rules in 2019.

 

Further, 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, generally through eminent domain.  These same entities may, and sometimes do, construct duplicate distribution facilities to serve existing or new Utility customers.

 

The effect of such types of retail competition generally is to reduce the amount of electricity purchased by customers from the Utility.

 

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.  The FERC's transmission planning requirements rules, effective in 2011, removed the incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities and mandated regional and interregional transmission planning.  In 2014, the FERC approved the CAISO's process for regional planning and competitive solicitations and the CAISO's interregional planning process.

 

(For risks in connection with increasing competition, see Item 1A. Risk Factors.)

 

Competition in the Natural Gas Industry

 

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services.  The 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 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 ratemaking mechanism described in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

 

 


Hazardous Waste Compliance and Remediation

 

The Utility's facilities are subject to various regulations adopted by the U.S.  Environmental Protection Agency, including the 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 other federal agencies responsible for implementing 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, monitoring and paying for the harm caused to natural resources, and paying for the costs of 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 DTSC, 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 electric generation plants, natural gas pipeline operations, vehicle 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.

 

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.

 

The federal administration of President Donald Trump has led to significant uncertainty with regard to what further actions may occur regarding climate change at the federal level.  Upon taking office, President Trump issued an executive order to freeze all regulations issued in the 60 days preceding his inauguration and directed the EPA and the White House to remove climate change-related materials and web pages.  In October 2017, the EPA issued a notice of proposed rulemaking to formally repeal the Clean Power Plan regulations.  The Trump administration is expected to take further action to substantially limit climate related regulatory and funding activities.  In light of the policy reversal at the federal level, the State of California has indicated that it intends to continue and enhance its leadership on climate change nationally and globally.

 

 


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 electric 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.  SB 32 (2016) requires that CARB ensure a 40% reduction in greenhouse gases by 2030 compared to 1990 levels.  In 2017, AB 398 extended the cap-and-trade program to 2030.  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 Resilience Strategies

 

During 2017, the Utility continued its programs 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 increase its resilience in light of the likely impacts of climate change on the Utility’s operations.  The Utility regularly reviews the most relevant scientific literature on climate change such as rising sea levels, major storm events, increasing temperatures and heatwaves, wildfires, drought and land subsidence, to help the Utility identify and evaluate climate change-related risks and develop the necessary resilience strategies.  The Utility maintains emergency response plans and procedures to address a range of near-term risks, including wildfires, extreme storms, and  heat waves 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.

 

The Utility is working to better understand the current and future impacts of climate change.  In 2017, the Utility filed its first RAMP submittal with the CPUC, which examined Utility safety risks. The Climate Resilience RAMP model indicated potential additional Utility safety consequences due to climate change, including in the near term.  The Utility is conducting foundational work to help anticipate and plan for evolving conditions in terms of weather and climate-change related events.  This work will guide efforts to design a Utility-wide climate change risk integration strategy.  This strategy will inform resource planning and investment, operational decisions, and potential additional programs to identify and pursue mitigations that will incorporate the resilience and safety of the Utility’s assets, infrastructure, operations, employees, and customers.

 

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 changes 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. 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.  As the state continues to face increased risk of wildfire, the Utility’s vegetation management activities will continue to play an important role to help reduce the risk of wildfire and its impact on electric and gas facilities.

 

Climate scientists predict that climate change will result in varying temperatures and levels of precipitation in the Utility’s service territory.  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 2016, the most recent data available, totaled more than 50 million metric tonnes of CO­2 equivalent, three-quarters of which came from customer natural gas use.  The following table shows the 2016 GHG emissions data the Utility reported to the CARB under AB 32. PG&E Corporation and the Utility also publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.

 

Source

 

Amount (metric tonnes CO2)

Fossil Fuel-Fired Plants (1)

 

2,261,032

Natural Gas Compressor Stations and Storage Facilities (2)

 

295,851

Distribution Fugitive Natural Gas Emissions

 

605,690

Customer Natural Gas Use  (3)

 

38,697,656

 

 

 

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

(2) Includes emissions from compressor stations and storage facilities that are reportable to CARB.

(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.

 

The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2016 as compared to the national average for electric utilities:

 

 

 

Amount (pounds of CO2 per MWh)

U.S. Average (1)

 

1,123

Pacific Gas and Electric Company (2)

 

294

 

 

 

(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 one-half of the Utility’s delivered electricity in 2016.  PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.

 

 

 

2016

 

2015

Total NOx Emissions (tons)                                                                                                              

 

141

 

160

NOx Emissions Rate (pounds/MWh)                                                                                             

 

0.01

 

0.01

Total SO2

 

13

 

17

SO2

 

0.001

 

0.001

 

 


Water Quality

 

In 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 Second 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%.  The policy also provided for an alternative compliance approach for nuclear plants if certain criteria were met.  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.  The report addressed feasibility, costs and timeframes to install alternative technologies at Diablo Canyon, such as cooling towers.

 

On June 20, 2016, the Utility entered into a joint proposal with certain parties to retire Diablo Canyon’s two nuclear power reactor units at the expiration of their current operating licenses in 2024 and 2025.  As a result of the planned retirement, the California Water Board will no longer need to address alternative compliance measures for Diablo Canyon.  As required under the policy, the Utility paid an annual interim mitigation fee beginning in 2017, which it will continue to pay until operations cease in 2025. 

 

Additionally, the Utility expects that its decision to retire Diablo Canyon will affect the terms of a final settlement agreement between the Utility, the Central Coast Board and the California Attorney General’s Office regarding the thermal component of the plant’s once-through cooling discharge.  (For more information, see “Diablo Canyon Nuclear 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 (“DOJ”) 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.  Through 2017, the Utility has been awarded an additional $114 million through these annual submissions, including $15 million for costs incurred between June 1, 2015 and May 31, 2016.  The claim for the period June 1, 2016 through May 31, 2017, totaled approximately $29 million and is currently under review by the DOE.  These proceeds are being refunded to customers through rates.  A new settlement agreement, for costs through 2019 was executed in March 2017.  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, financial condition, results of operations, liquidity, cash flows, and stock price.

 

Risks Related to Wildfires

 

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the Northern California wildfires. PG&E Corporation and the Utility also expect to be the subject of additional lawsuits and could be the subject of additional investigations, citations, fines or enforcement actions.

 

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the multiple wildfires that spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City, beginning on October 8, 2017 (the “Northern California wildfires”).  According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures.  Subsequently, the number of fatalities increased to 44.

 

The Utility incurred $219 million in costs for service restoration and repair to the Utility’s facilities (including $97 million in capital expenditures) through December 31, 2017 in connection with these fires.  While the Utility believes that such costs are recoverable through CEMA, its CEMA requests are subject to CPUC approval.  The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs.

 

The fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities.  The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the ways that they progressed.  The CPUC’s SED also is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire impacted areas.  According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response.  Various other entities, including fire departments, may also be investigating certain of the fires.  (For example, on February 3, 2018, it was reported that investigators with the Santa Rosa Fire Department had completed their investigation of two small fires that reportedly destroyed two homes and damaged one outbuilding and had concluded that the Utility’s facilities, along with high wind and other factors, contributed to those fires.)  It is uncertain when the investigations will be complete and whether Cal Fire will release any preliminary findings before its investigation is complete. 

 

As of January 31, 2018, the Utility had submitted 22 electric incident reports to the CPUC associated with the Northern California wildfires where Cal Fire has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000.  The information contained in these reports is factual and preliminary, and does not reflect a determination of the causes of the fires.  The investigations into the fires are ongoing.

 

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility.  (See “The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially negatively affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows” below.)  In addition to such claims for property damage, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility.  Further, the Utility could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action and determined that the Utility failed to comply with applicable laws and regulations.


 

 

Given the preliminary stages of investigations and the uncertainty as to the causes of the fires, PG&E Corporation and the Utility do not believe a loss is probable at this time.  However, it is reasonably possible that facts could emerge through the course of the various investigations that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in an accrued liability in the future, the amount of which could be material.   PG&E Corporation and the Utility currently are unable to reasonably estimate the amount of losses (or range of amounts) that they could incur, given the preliminary stages of the investigations and the uncertainty regarding the extent and magnitude of potential damages.  On January 31, 2018, the California Department of Insurance issued a press release announcing an update on property losses in connection with the October and December wildfires in California, stating that, as of such date, “insurers have received nearly 45,000 insurance claims totaling more than $11.79 billion in losses,” of which approximately $10 billion relates to statewide claims from the October 2017 wildfires.  The remaining amount relates to claims from the Southern California December 2017 wildfires.  According to the California Department of Insurance, as of the date of the press release, more than 21,000 homes, 3,200 businesses, and more than 6,100 vehicles, watercraft, farm vehicles, and other equipment were damaged or destroyed by the October 2017 wildfires.  PG&E Corporation and the Utility have not independently verified these estimates.  The California Department of Insurance did not state in its press release whether it intends to provide updated estimates of losses in the future.

 

If the Utility’s facilities are determined to be the cause of one or more of the Northern California wildfires, PG&E Corporation and the Utility could be liable for the related property losses and other damages.  The California Department of Insurance January 31, 2018 press release reflects insured property losses only.  The press release does not account for uninsured losses, interest, attorneys’ fees, fire suppression costs, evacuation costs, medical expenses, personal injury and wrongful death damages or other costs.  If the Utility were to be found liable for certain or all of such other costs and expenses, the amount of PG&E Corporation’s and the Utility’s liability could be higher than the approximately $10 billion estimated in respect of the wildfires that occurred in October 2017, depending on the extent of the damage in connection with such fire or fires.  As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

 

PG&E Corporation and the Utility also are the subject of a still increasing number of lawsuits that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties’ Superior Courts, several of which seek to be certified as class actions.  The lawsuits allege, among other things, negligence, inverse condemnation, trespass, and private nuisance.  They principally assert that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the fires.  The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages.  In addition, two derivative lawsuits for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively. PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires.  The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved.  The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $800 million.  If the Utility were to be found liable for one or more fires, the Utility’s insurance could be insufficient to cover that liability, depending on the extent of the damage in connection with such fire or fires.

 

In addition, it could take a number of years before the Utility’s final liability is known and the Utility could apply for cost recovery.  The Utility may be unable to recover costs in excess of insurance through regulatory mechanisms and, even if such recovery is possible, it could take a number of years to resolve and a number of years thereafter to collect.  Further, SB 819, introduced in the California Senate in January 2018, if it becomes law, would prohibit utilities from recovering costs in excess of insurance resulting from damages caused by such utilities’ facilities, if the CPUC determines that the utility did not reasonably construct, maintain, manage, control, or operate the facilities.  PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.  (See “If the Utility is unable to recover all or a significant portion of its excess costs in connection with the Northern California wildfires and the Butte fire through ratemaking mechanisms, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected” below.)

 

Losses in connection with the wildfires would likely require PG&E Corporation and the Utility to seek financing, which may not be available on terms acceptable to PG&E Corporation or the Utility, or at all, when required.  (See “Risks Related to Liquidity and Capital Requirements” below.)

 

 

 

As of December 31, 2017, neither PG&E Corporation nor the Utility has accrued a liability with respect to the Northern California wildfires. If PG&E Corporation and the Utility were to determine that it is both probable that a loss has occurred and the amount of loss can be reasonably estimated, a liability would be recorded consistent with applicable accounting principles and as described in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.  As noted above, to the extent that such determination is made and a liability is accrued with respect to the Northern California wildfires, the amount of such liability accrual may be substantial. To the extent not offset by insurance recoveries determined to be similarly probable and estimable, the liability would reduce the balance sheet equity of PG&E Corporation and the Utility, which could adversely impact the Utility’s ability to maintain its CPUC-authorized capital structure of 52% equity and 48% debt and preferred stock, and which could also adversely impact PG&E Corporation’s and the Utility’s credit ratings and their ability to declare and pay dividends, efficiently raise capital, comply with financial covenants, and meet financial obligations.  (See “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” below.)

 

Uncertainties relating to and market perception of these matters and the disclosure of findings regarding these matters over time, also could continue or increase volatility in the market for PG&E Corporation’s common stock and other securities, and for the securities of the Utility, and materially affect the price of such securities.

 

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by the ultimate amount of third-party liability that the Utility incurs in connection with the Butte fire.

 

In September 2015, a wildfire (known as the “Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California.  On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the wildfire.  According to Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concluded that the wildfire was caused when a gray pine tree contacted the Utility’s electric line which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

 

In connection with the Butte fire, complaints have been filed against the Utility, currently involving approximately 3,770 individual plaintiffs representing approximately 2,030 households and their insurance companies.  Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also seek punitive damages.  The number of individual complaints and plaintiffs may still increase in the future, because the statute of limitations for property damages in connection with the Butte fire has not yet expired.  (The statute of limitations for personal injury in connection with the Butte fire has expired.)  The Utility continues mediating and settling cases.

 

In addition, on April 13, 2017, Cal Fire filed a complaint seeking to recover $87 million for its costs incurred in connection with the Butte fire, and in May 2017, the OES indicated that it intends to bring a claim against the Utility that the OES estimated in the approximate amount of $190 million.  Also, in June 2017, the County of Calaveras indicated that it intends to bring a claim against the Utility that it estimates in the approximate amount of $85 million. 

 

In connection with this matter, the Utility may be liable for property damages, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.  In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility were found to have been negligent.  While the Utility believes it was not negligent, there can be no assurance that a court or jury would agree with the Utility. 

 

The Utility currently believes that it is probable that it will incur a loss of at least $1.1 billion, increased from the $750 million previously estimated as of December 31, 2016 in connection with the Butte fire.  While this amount includes the Utility’s assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any significant portion of the estimated claims from the OES and the County of Calaveras.  The Utility still does not have sufficient information to reasonably estimate the probable loss it may have for these additional claims.  A change in management’s estimates or assumptions could result in an adjustment that could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.  (See Note 13 to the Consolidated Financial Statements in Item 8.)

 

If the Utility is unable to recover all or a significant portion of its excess costs in connection with the Northern California wildfires and the Butte Fire through ratemaking mechanisms, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

 

Through December 31, 2017, the amounts accrued in connection with claims relating to the Butte fire have exceeded the Utility’s liability insurance coverage.  While the Utility filed an application with the CPUC requesting approval to establish a WEMA to track wildfire expenses and to preserve the opportunity for the Utility to request recovery of wildfire costs that have not otherwise been recovered through insurance or other mechanisms, the Utility cannot predict the outcome of this proceeding.  (See “Regulatory Matters – Application to Establish a Wildfire Expense Memorandum Account” in Item 7. MD&A.)


 

In addition, there can be no assurance that the Utility will be allowed to recover costs recorded in WEMA, if approved, in the future. While the CPUC previously approved WEMA tracking accounts for San Diego Gas & Electric Company in 2010, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to the CPUC’s prudent manager standard.  That determination is being challenged by San Diego Gas & Electric as well as by the Utility and Southern California Edison. 

 

Additionally, SB 819 introduced in the California Senate in January 2018, if it becomes law, would prohibit utilities’ recovery of costs in excess of insurance resulting from damages caused by such utilities’ facilities, if the CPUC determines that the Utility did not reasonably construct, maintain, manage, control, or operate the facilities.

 

PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover all or a significant portion of costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

 

The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

 

California law includes a doctrine of inverse condemnation that is routinely invoked in California for wildfire damages. Inverse condemnation imposes strict liability (including liability for attorneys’ fees) for damages as a result of the design, construction and maintenance of utility facilities, including utilities’ electric transmission lines.  Courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefitted from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers.  Plaintiffs have asserted the doctrine of inverse condemnation in lawsuits related to the Northern California and Butte fires, and it is possible that plaintiffs could be successful in convincing courts to apply this doctrine in these or other litigations. For example, on June 22, 2017, the Superior Court for the County of Sacramento found that the doctrine of inverse condemnation applies to the Utility with respect to the Butte fire.  Although the Utility has filed a renewed motion for a legal determination of inverse condemnation liability, there can be no assurance that the Utility will be successful in its arguments that the doctrine of inverse condemnation does not apply in the Butte fire or other litigation against PG&E Corporation or the Utility.

 

Furthermore, a court could determine that the doctrine of inverse condemnation applies even in the absence of an open CPUC proceeding for cost recovery, or before a potential cost recovery decision is issued by the CPUC.  Although the imposition of liability is premised on the assumption that utilities have the ability to automatically recover these costs from their customers, there can be no guarantee that the CPUC would authorize cost recovery whether or not a previous court decision imposes liability on a utility under the doctrine of inverse condemnation.  In December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to the CPUC’s prudent manager standard. That determination is being challenged by San Diego Gas & Electric as well as by the Utility and Southern California Edison.

 

If PG&E Corporation or the Utility were to be found liable for damage under the doctrine of inverse condemnation, but is unable to secure a cost recovery decision from the CPUC to pay for such costs through increases in rates, the financial condition, results of operations, liquidity and cash flows of PG&E Corporation and the Utility would be materially affected by potential losses resulting from the impact of the Northern California wildfires.  (See “PG&E Corporation and the Utility also expect to be the subject of additional lawsuits and could be the subject of additional investigations, citations, fines or enforcement actions” and “PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected by the ultimate amount of third-party liability that the Utility incurs in connection with the Butte fire” above.)

 

 

30

 


 

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

 

The Utility is subject to extensive regulations and the risk of enforcement proceedings in connection with such regulations, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could 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 and requests for informationThe Utility could incur material costs and fines in connection with compliance with penalties from closed investigations or enforcement actions or in connection with future investigations, citations, audits, or enforcement actions.

 

The Utility is subject to extensive regulations, including federal, state and local energy, environmental and other laws and regulations, and the risk of enforcement proceedings in connection with such regulations.  The Utility could incur material charges, including fines and other penalties, in connection with the ex parte OII, safety culture OII, and the CPUC’s SED investigations, including the SED’s investigations of the Yuba City incident, which arose from a residential structure fire in Yuba City, California, in January 2017, that resulted in the collapse of a house and injuries to two persons inside the house, or other current and future investigations.  The SED could launch investigations at any time on any issue it deems appropriate.

 

The SED has discretion whether to issue a penalty for each violation, but if it assesses a penalty for a violation, it is required to impose the maximum statutory penalty of $50,000, with an administrative limit of $8 million per citation issued.  The SED may, at its discretion, impose penalties on a daily basis, or on less than a daily basis, for violations that continued for more than one day.  The SED also 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 SED also is required to consider the appropriateness of the amount of the penalty to the size of the entity charged.  Historically, the SED has exercised broad discretion in determining whether violations are continuing and the amount of penalties to be imposed.  While it is uncertain how the CPUC will calculate the number of violations or the penalty for any violations, such fines or penalties could be significant and materially affect PG&E Corporation’s and the Utility’s liquidity and results of operations.  (See Note 13 to the Consolidated Financial Statements in Item 8.)

 

The Utility also is a target of a number of investigations.  In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility also is unable to predict the outcome of, or costs and expenses associate with, pending investigations, including whether any charges will be brought against the Utility.

 

If these investigations result in enforcement action against the Utility, the Utility could incur additional fines or penalties and, in the event of a judgment against the Utility, suffer further ongoing negative consequences.  For example, on April 9, 2015, the CPUC issued a decision in its investigative enforcement proceedings against the Utility to impose total penalties of $1.6 billion on the Utility after determining that the Utility had committed numerous violations of laws and regulations related to its natural gas transmission operations (the “San Bruno Penalty Decision”).  The San Bruno Penalty Decision requires the SED to review the Utility’s gas transmission operations (including the Utility’s compliance with the remedies ordered by the San Bruno 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.  Furthermore, a negative outcome in any of these investigations, or future enforcement actions, could negatively affect the outcome of future ratemaking and regulatory proceedings to which the Utility may be subject; 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.  (See also “PG&E Corporation’s and the Utility’s future financial results could be materially affected by the conviction of the Utility in the federal criminal proceeding and by the debarment proceeding” below.)

 

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; compliance with CPUC general orders or other applicable CPUC decisions or regulations; federal electric reliability standards; and environmental compliance.  For example, despite the Utility’s system-wide survey of its transmission pipelines, carried out in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way, the SED could impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. CPUC staff could also impose penalties 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 condition, results of operations, liquidity, and cash flows.  

 


PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the event of non-compliance with the terms of probation and by the outcome of the debarment proceeding.

 

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.  On January 26, 2017, the court issued a judgment of conviction against the Utility.  The court sentenced the Utility to a five-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

 

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period.  As part of the probation, the Utility has retained a third-party monitor at the Utility’s expense.  The goal of the monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

 

The Utility could incur material costs and additional penalties, not recoverable through rates, in the event of non-compliance with the terms of its probation and in connection with the monitorship (including but not limited to costs resulting from recommendations of the monitor).

 

Since 2015, the Utility has also been the subject of a DOI inquiry into whether the Utility should be suspended or debarred from entering into federal procurement and non-procurement contracts and programs, citing the San Bruno explosion, and indicating, as the basis for the inquiry, alleged poor record-keeping, poor identification and evaluation of threats to gas lines and obstruction of the NTSB’s investigation.  On December 21, 2016, the Utility and the DOI entered into an interim administrative agreement that reflects the DOI’s determination that the Utility remains eligible to contract with federal government agencies while the DOI determines whether any further action is necessary to protect the federal government’s business interests.  If the DOI determines that the Utility’s compliance and ethics program is not generally effective in preventing and detecting criminal conduct, the Utility may be required to enter into an amended administrative agreement and implement remedial and other measures, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by one or more independent third-party monitor(s).

 

The Utility’s conviction and the outcome of probation and the debarment proceeding 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 argue that the Utility should not be allowed to recover costs that the parties allege are somehow related to the criminal charges on which the Utility was found guilty.  They could also result in increased regulatory or legislative scrutiny with respect to various aspects of how the Utility’s business is conducted or organized.  (See “Enforcement and Litigation Matters in Item 7. MD&A.) 

 

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 reasonable 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 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. Further, the increasing amount of Reliability Must Run (RMR) electric generation in the CAISO could increase the Utility’s costs of procuring capacity needed for reliable service to its customers.



 

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, fires, accidents, or 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 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, underground gas storage, 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 a lower customer demand for the Utility’s electricity and natural gas services. 

 

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 terms of such contracts, including price, do not meet the CPUC reasonableness standard. 

 

The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by 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 decreasing bundled load 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 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 above market 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 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.  New rules and rates became effective for new NEM customers of the Utility in December 2016.  New NEM customers are required to pay an interconnection fee, comply with time of use rates, and are required to pay certain non-bypassable charges to help fund some of the costs of low income, energy efficiency, and other programs that other customers pay.  Remaining customers may incur significantly higher bills due to an increase in customers seeking alternative energy providers.  The CPUC has indicated 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 authorized capital investment could decline as well, 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 materially affect PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows.

 

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 cross-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. 

 

Further, 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. 

 

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 condition, results of operations, liquidity, and cash flows could be materially affected

 

Risks Related to Liquidity and Capital Requirements

 

The outcome or market perception of the investigations and litigation in connection with the Northern California wildfires, and the outcome or market perception of other litigation and enforcement matters, could reduce or eliminate PG&E Corporation’s and the Utility’s access to the capital markets and other sources of financing, which could have a material adverse effect on PG&E Corporation and the Utility.

 

PG&E Corporation’s and the Utility’s liquidity is dependent on many factors, including access to the capital markets and availability under their revolving credit facilities and commercial paper programsPG&E Corporation’s and the Utility’s ability to access the capital markets, the ability to borrow under their loan financing arrangements, including their revolving credit facilities, and the terms and rates of future financings, as well as the credit ratings of PG&E Corporation and the Utility and their respective debt facilities, could be materially affected by the outcome or market perception of the matters discussed in this 2017 Form 10-K under “Northern California Wildfires” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.  Liabilities that could be incurred as a result of the Northern California wildfires could adversely affect their ability to comply with the covenants in their financing arrangements, which could adversely affect the ability to borrow under the applicable facility or program.

 

Access by PG&E Corporation to the equity capital markets is also critical to maintaining the Utility’s CPUC-authorized capital structure. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure.  In the fiscal year ended December 31, 2017, PG&E Corporation issued $416 million in common stock and made equity contributions of $455 million to the Utility. PG&E Corporation forecasts it will need a material amount of equity in future years, including to support the Utility’s capital expenditures.  PG&E Corporation may also seek to issue additional equity to fund unrecoverable operating expenses and to pay claims, losses, fines and penalties that may be required by the outcome of enforcement matters and litigation, including in connection with the Northern California wildfires, and the outcome of the related CPUC and Cal Fire investigations.

 

If either PG&E Corporation or the Utility is unable to access the capital markets or to borrow under their respective loan financing arrangements or commercial paper programs, PG&E Corporation and the Utility’s financial condition, results of operations, liquidity, and cash flows, could be materially affected.


 

 

PG&E Corporation’s and the Utility’s ability to meet their debt service and other financial obligations and their ability to pay dividends depend on the Utility’s earnings and cash flows. In addition, in December 2017, the Boards of Directors suspended dividends on PG&E Corporation’s common stock and the Utility’s preferred stock, as a result of which the price of PG&E Corporation’s common stock and the ability of PG&E Corporation and the Utility to raise equity capital could be adversely affected.

 

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 the Utility’s obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, unless suspended, 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 must 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 in connection with the Northern California wildfires, the Butte fire, the pending CPUC investigations, the terms of probation or monitorship, or other liabilities or enforcement matters, it would require incremental 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 earnings per share. (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 were 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.

 

In December 2017, the Boards of Directors of PG&E Corporation and the Utility suspended dividends on common stock of PG&E Corporation and preferred stock of the Utility due to uncertainty related to the causes and potential liabilities associated with the Northern California wildfires.  The suspension of dividends could continue to materially affect the price of PG&E Corporation’s common stock and adversely affect the ability of PG&E Corporation to raise additional equity capital.  There can be no assurances as to when, if at all, the Board of Directors of PG&E Corporation and the Utility will determine to re-instate quarterly cash dividends on PG&E Corporation’s common stock or the Utility’s preferred stock.

 

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, and to pay fines that may be imposed in the future, as well as costs related to rights-of-way and legal and regulatory costs.  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 pending or anticipated litigation, the pending Cal Fire and CPUC investigations and CPUC ratemaking proceedings, and by the December 20, 2017 decision of the Boards of Directors of PG&E Corporation and the Utility to suspend dividends, as well as the perceived impact of all such matters on PG&E Corporation’s and the Utility’s financial condition, whether or not such perception is accurate.  On December 21, 2017, Moody's Investor Services and on December 22, 2017, Standard & Poor’s Global Ratings, each placed all of the ratings of PG&E Corporation and the Utility under review for downgrade, and Standard & Poor’s Global Ratings additionally lowered its ratings on the Utility’s preferred stock.  If PG&E Corporation’s or the Utility’s credit ratings were to be downgraded or the ratings on the Utility’s preferred stock are further downgraded, in particular 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 and 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, 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 3. Legal Proceedings and Note 13 of the Notes to the Consolidated Financial Statements in Item 8The negative publicity and the uncertainty about the outcomes of these matters may undermine confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment, which could adversely impact PG&E Corporation’s stock price.  Further, the market price of PG&E Corporation common stock could decline materially depending on the outcome of these matters.  The amount and timing of future share issuances also could affect the stock price.

 

 

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 condition, results of operations, liquidity, and cash flows. 

 

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, and the CPUC approved retirement of Diablo Canyon by 2024 and 2025.  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;

 

  • the 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);

 

  • 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;

 

  • 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 damages 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-based 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.  

 

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 condition, results of operations, liquidity, and cash flows. 

 

The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events, or may not be available at a reasonable cost, or available at all.

 

The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from the Utility’s ordinary operations. PG&E Corporation, the Utility or its contractors and customers may experience coverage reductions and/or increased wildfire insurance costs in future years.  No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage.  Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates.  A loss which is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

 

As a result of the potential application of a strict liability standard under the doctrine of inverse condemnation, recent losses recorded by insurance companies, the risk of increase of wildfires including as a result of the ongoing drought, the Northern California wildfires, and the Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at comparable cost and terms as the Utility’s current insurance coverage, or at all.  In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.

 

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.  If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

 

The electric power industry is undergoing significant change driven by technological advancements and a decarbonized economy, which could materially impact the Utility’s operations, financial condition, and results of operations.

 

The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy.  California's environmental policy objectives are accelerating the pace and scope of the industry change.  The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policymakers notwithstanding a recent change in the federal approach to such matters.  California utilities are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies.  This growth will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid's capacity, and interconnect DERs.

 

In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and state infrastructure modernization (e.g. rail and water projects).

 

 

 

To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs; consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator.  The CPUC has also recently opened proceedings regarding the creation of a shared database or statewide census of utility poles and conduits in California and increased access by communications providers to utility rights-of-way.  This proceeding could require utilities to invest significant resources into inspecting poles and conduits, limit available capacity in existing rights-of-way, or impose other requirements on utilities facilities.  The Utility is unable to predict the outcome of these proceedings. 

 

In addition, the CPUC has held discussions on potential changes to California’s electricity market.  On May 19, 2017, California energy companies, along with other stakeholders, discussed customer choice and the future of the state’s electricity industry at a CPUC “en banc” meeting.  Specifically, the goal of the “en banc” was to frame a discussion on the trends that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future.  While the CPUC had indicated its intent to open a proceeding related to customer choice, the Utility is unable to predict whether that remains the CPUC’s intent or the timing of any such proceeding.

 

The industry change, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric industry, could materially affect the Utility’s operations, financial condition, and results of operations.

 

A cyber incident, cyber security breach, severe natural event or physical attack on the Utility’s operational networks and information technology systems could have a material effect on its business, financial condition, results of operations, liquidity, and cash flows.

 

The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events—such as severe weather or seismic events—and by malicious events, such as cyber and physical attacks.  Private and public entities, such as the North American Electric Reliability Corporation, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency.  The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems.  Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties. 

 

The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers.  These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures.  Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.

 

The Utility and its third party vendors have been subject to, and will likely continue to be subject to attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations.  None of these attempts or breaches has individually or in the aggregate resulted in a security incident with a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations.  Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent the unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations.  Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.

 

The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents.  However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

 


 

 

The operation and decommissioning of the Utility’s nuclear generation facilities 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 condition, results of operations, liquidity, and cash flows.  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.)  

 

On January 11, 2018, the CPUC approved the retirement of Diablo Canyon units by 2024 and 2025.  However, 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 their respective 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 condition, results of operations, liquidity, and cash flows.

 

In addition, in order to retain highly skilled personnel necessary to safely operate Diablo Canyon during the remaining years of operations, the Utility will incur costs in connection with (i) an employee retention program to ensure adequate staffing levels at Diablo Canyon, and (ii) an employee retraining and development program, to facilitate redeployment of a portion of Diablo Canyon personnel to the decommissioning project and elsewhere in the company.  In its January 11, 2018 decision, the CPUC authorized rate recovery up to $211.3 million (compared with the $352.1 million requested by the Utility) for an employee retention program, but there can be no assurance that the Utility will be successful in retaining highly skilled personnel under such program.

 

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’s two nuclear generation units before their respective licenses expire in 2024 and 2025.  At December 31, 2017, the Utility’s unrecovered investment in Diablo Canyon was $1.7 billion.

 

On June 28, 2016 the California State Lands Commission approved an extension of the Utility’s leases of coastal land occupied by the water intake and discharge structures for the nuclear generation units at Diablo Canyon, to run concurrently with Diablo Canyon’s current operating licenses.  The Utility will be required to obtain an additional lease extension from the State Lands Commission to cover the period of time necessary to decommission the facility.  The State Lands Commission and California Coastal Commission will evaluate appropriate environmental mitigation and development conditions associated with the decommissioning project, the costs of which could be substantial.

 

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 condition, results of operations, liquidity, and cash flows could be materially affected.

 

 


 

The Utility purchases its nuclear fuel assemblies from a sole source, Westinghouse.  If Westinghouse experiences business disruptions as a result of Chapter 11 proceedings or its pending acquisition by Brookfield, the Utility could experience disruptions in nuclear fuel supply, and delays in connection with its Diablo Canyon outages and refuelings.

 

The Utility purchases its nuclear fuel assemblies for Diablo Canyon from a sole source, Westinghouse.  The Utility also stores nuclear fuel inventory at the Westinghouse fuel fabrication facility. In addition, Westinghouse provides the Utility with Diablo Canyon outage support services, nuclear fuel analysis, original equipment manufacturer engineering and parts support.  On March 29, 2017, Westinghouse filed for Chapter 11 protection in the United States Bankruptcy Court, Southern District of New York.  On January 4, 2018, Westinghouse announced that it has agreed to be acquired by Brookfield Business Partners L.P. Westinghouse also indicated that its acquisition by Brookfield is expected to close in the third quarter of 2018, subject to Bankruptcy Court approval and customary closing conditions including, among others, regulatory approvals.  In the event that Westinghouse experiences business disruptions in its nuclear fuel business as a result of bankruptcy proceedings, its pending acquisition by Brookfield, or otherwise, the Utility could experience issues with its nuclear fuel supply and delays in connection with Diablo Canyon refueling outages. 

 

Diablo Canyon’s Unit 2 refueling outage will occur in the first quarter of 2018 and the required fuel for that outage has been delivered.  The next Unit 1 refueling outage is expected to occur in the first quarter of 2019 and the fuel for that outage has not yet been fabricated.  If Westinghouse were to fail to deliver nuclear fuel or provide outage support to the Utility, the Utility’s operation of Diablo Canyon would be adversely affected.  PG&E Corporation and the Utility also could experience additional costs, including decreased electricity market revenues, in the event that one or both Diablo Canyon units are unable to operate.  There can be no assurance that any such additional costs would be recoverable in the rates the Utility is permitted to recover from its customers.  Furthermore, the Utility currently is not able to estimate the nature or amount of additional costs and expenses that it might incur in connection with the uncertainties surrounding Westinghouse but such costs and expenses could be material.

 

For certain critical technologies, products and services, the Utility relies on a limited number of suppliers and, in some cases, sole suppliers.  In the event these suppliers are unable to perform, the Utility could experience delays and disruptions in its operations while it transitions to alternative plans or suppliers.

 

The Utility relies on a limited number of sole source suppliers for certain of its technologies, products and services.  Although the Utility has long-term agreements with such suppliers, if the suppliers are unable to deliver these technologies, products or services, the Utility could experience delays and disruptions while it implements alternative plans and makes arrangements with acceptable substitute suppliers.  As a result, the Utility’s business, financial condition, and results of operations could be significantly affected.  As an example, the Utility relies on Silver Spring Networks, Inc. and Aclara Technologies LLC as suppliers of proprietary SmartMeter™ devices and software, and of managed services, utilized in its advanced metering system that collects electric and natural gas usage data from customers.  If these suppliers encounter performance difficulties or are unable to supply these devices or maintain and update their software, or provide other services to maintain these systems, the Utility’s metering, billing, and electric network operations could be impacted and disrupted.

 

Risks Related to Environmental Factors

 

Severe weather conditions, extended drought and shifting climate patterns could materially affect PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows.

 

Extreme weather, extended drought and shifting climate patterns have intensified the challenges associated with wildfire management in California. Environmental extremes, such as drought conditions followed by periods of wet weather, can drive additional vegetation growth (which then fuel any fires) and influence both the likelihood and severity of extraordinary wildfire events.  In California, over the past five years, inconsistent and extreme precipitation, coupled with more hot summer days, have increased the wildfire risk and made wildfire outbreaks increasingly difficult to manage.  In particular, the risk posed by wildfires has increased in the Utility’s service area (the Utility has approximately 82,000 distribution overhead circuit miles and 18,000 transmission overhead circuit miles) as a result of an extended period of drought, bark beetle infestations in the California forest and wildfire fuel increases due to record rainfall following the drought, among other environmental factors. Other contributing factors include local land use policies and historical forestry management practices.  The combined effects of extreme weather and climate change also impact this risk.

 

Severe weather events, including wildfires and other fires, storms, tornadoes, floods, drought, earthquakes, tsunamis, pandemics, solar events, electromagnetic events, or other natural disasters such as wildfires, could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs to PG&E Corporation and the Utility.  Any such event could have a material effect on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows.  If the Utility is unable to recover its wildfire costs, due to the reasons described in the risk factors related to the Northern California fires, Butte fire, the doctrine of inverse condemnation, and insurance limitations above, or for other reasons, its financial condition, results of operations, liquidity, and cash flows could be materially affected.

 


 

Further, 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.  As a result, the Utility’s hydroelectric generation could change and the Utility would need to consider managing or acquiring additional generation.  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, flooding caused by rising sea levels could damage the Utility’s facilities, including generation and electric transmission and distribution assets.  The Utility could incur substantial costs to repair or replace facilities, restore service, or 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, liquidity, and cash flows could be materially affected.

 

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, and 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.  (For more information, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

 

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. and Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)  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.

 

State climate policy requires reductions in greenhouse gases of 40% by 2030 and 80% by 2050.  Various proposals for addressing these reductions have the potential to reduce natural gas usage and increase natural gas costs. The future recovery of the increased costs associated with compliance is uncertain.

 

The CARB is the state’s primary regulator for GHG emission reduction programs.  Natural gas providers have been subject to compliance with CARB’s Cap-and-Trade Program since 2015, and natural gas end-use customers have an increasing exposure to carbon costs under the Program through 2030 when the full cost will be reflected in customer bills.  CARB’s Scoping Plan also proposes various methods of reducing GHG emissions from natural gas.  These include more aggressive energy efficiency programs to reduce natural gas end use, increased renewable portfolio standards generation in the electric sector reducing noncore gas load, and replacement of natural gas appliances with electric appliances, leading to further reduced demand.  These natural gas load reductions may be partially offset by CARB’s proposals to deploy natural gas to replace wood fuel in home heating and diesel in transportation applications.  CARB also proposes a displacement of some conventional natural gas with above-market renewable natural gas.  The combination of reduced load and increased costs could result in higher natural gas customer bills and a potential mandate to deliver renewable natural gas could lead to cost recovery risk.

 


 

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 condition, results of operations, liquidity, and cash flows 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 condition, results of operations, liquidity, and cash flows 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.

 

The Utility’s business activities are concentrated in one region, as a result of which, its future performance may be affected by events and factors unique to California.

 

The Utility’s business activities are concentrated in Northern California.  As a result, the Utility’s future performance may be affected by events and economic factors unique to California or by regional regulation or legislation, for example the doctrine of inverse condemnation.  (See “The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation and the Utility are subject, could significantly expand the potential liabilities from such litigation and materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows” above.)

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 million square feet of real property, including 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 160,000 acres of land, including approximately 132,000 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 2022, 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.

 

Order Instituting an Investigation into the Utility’s Safety Culture

 

On August 27, 2015, the CPUC began a formal 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.  The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents.  The CPUC authorized the SED to engage a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s assessment. 

 

On May 8, 2017, the CPUC President released the consultant’s report, accompanied by a scoping memo and ruling.  The scoping memo establishes a second phase in this OII in which the CPUC will evaluate the safety recommendations of the consultant that may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part.  This phase of the proceeding will also consider all necessary measures, including, but not limited to, a potential reduction of the Utility’s return on equity until any recommendations adopted by the CPUC are implemented.  On November 17, 2017, the CPUC issued a phase two scoping memo and procedural schedule. The scoping memo directed the Utility and other parties to file testimony addressing a number of issues including adoption of the safety recommendations from the consultant, the Utility’s implementation process for the safety recommendations of the consultant, the Utility’s Board of Director’s actions and initiatives related to safety culture and the consultant’s recommendations, the Utility’s corrective action program, and the Utility’s response to certain specified safety incidents that occurred in 2013 through 2015.  The Utility’s testimony was submitted to the CPUC on January 8, 2018 and stated that the Utility agrees with all of the recommendations of the consultant and supports their adoption by the CPUC.  Other parties’ responsive testimony is due February 16, 2018, and the Utility’s rebuttal is due February 23, 2018.  On January 29, 2018, the CPUC modified the procedural schedule to allow more time for parties to better identify areas of agreement to reduce the number of issues that may require hearings.

 

PG&E Corporation and the Utility are unable to predict the outcome of this proceeding, including whether additional fines, penalties, or other ratemaking tools will ultimately be adopted by the CPUC, and whether the CPUC will require that a portion of return on equity for the Utility be dependent on making safety progress as the CPUC may define in this proceeding.

 

Diablo Canyon Nuclear 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 was that the Central Coast Board renew Diablo Canyon's permit.

 

However, 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 to develop additional information on possible mitigation measures for Central Coast Board staff.  In 2005, the Central Coast Board reviewed the scientists' draft report recommending several such mitigation measures, but no action was taken. 

 

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%.  The policy also provided for an alternative compliance approach for nuclear plants if certain criteria were met.  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.  The report addressed feasibility, costs and timeframes to install alternative technologies at Diablo Canyon, such as cooling towers.

 

On January 11, 2018, the CPUC approved the retirement of Diablo Canyon Unit 1 by 2024 and Unit 2 by 2025.  As a result of the planned retirement, the California Water Board will no longer need to address alternative compliance measures for Diablo Canyon.  As required under the policy, the Utility paid an annual interim mitigation fee beginning in 2017, which it will continue to pay until operations cease in 2025.  Additionally, the Utility expects that its decision to retire Diablo Canyon will affect the terms of a final settlement agreement between the Utility and the Central Coast Board regarding the thermal component of the plant’s once-through cooling discharge. 

 

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.   

 

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 9, 2018.  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

 

 

 

 

 

 

 

Geisha J. Williams

 

56

 

Chief Executive Officer and President, PG&E Corporation

 

March 1, 2017 to present

 


 

 

 

 

President, Electric

 

September 15, 2015 to February 28, 2017

 

 

 

 

President, Electric Operations

 

August 17, 2015 to September 15, 2015

 

 

 

 

Executive Vice President, Electric Operations

 

June 1, 2011 to August 16, 2015

 

 

 

 

 

 

 

Nickolas Stavropoulos 

 

59

 

President and Chief Operating Officer

 

March 1, 2017 to present

 

 

 

 

President, Gas

 

September 15, 2015 to February 28, 2017

 

 

 

 

President, Gas Operations

 

August 17, 2015 to September 15, 2015

 

 

 

 

Executive Vice President, Gas Operations

 

June 13, 2011 to August 16, 2015

 

 

 

 

 

 

 

Jason P. Wells

 

40

 

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

 

 

 

 

 

 

 

John R. Simon

 

53

 

Executive Vice President and General Counsel, PG&E Corporation

 

March 1, 2017 to present

 

 

 

 

Executive Vice President, Corporate Services and Human Resources, PG&E Corporation

 

August 17, 2015 to February 28, 2017

 

 

 

 

Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company 

 

April 16, 2007 to August 16, 2015

 

 

 

 

 

 

 

Karen A. Austin

 

56

 

Senior Vice President and Chief Information Officer

 

June 1, 2011 to present

 

 

 

 

 

 

 

Loraine M. Giammona

 

50

 

Senior Vice President and Chief Customer Officer

 

September 18, 2014 to present

 

 

 

 

Vice President, Customer Service

 

January 23, 2012 to September 17, 2014

 

 

 

 

 

 

 

Patrick M. Hogan

 

54

 

Senior Vice President, Electric Operations

 

February 1, 2017 to present

 

 

 

 

Senior Vice President, Electric Transmission and Distribution

 

March 1, 2016 to January 31, 2017

 

 

 

 

Vice President, Electric Strategy and Asset Management

 

September 8, 2015 to February 29, 2016

 

 

 

 

Vice President, Electric Operations, Asset Management

 

November 18, 2013 to September 7, 2015

 

 

 

 

Senior Vice President, Transmission and Distribution Engineering and Design, BC Hydro

 

October 2011 to November 2013

 

 

 

 

 

 

 

Julie M. Kane

 

59

 

Senior Vice President, Chief Ethics and Compliance Officer, and Deputy General Counsel, PG&E Corporation and Pacific Gas and Electric Company

 

March 21, 2017 to present

 

 

 

 

Senior Vice President and Chief Ethics and Compliance Officer, PG&E Corporation and Pacific Gas and Electric Company

 

May 18, 2015 to March 20, 2017

 


 

 

 

 

Vice President, General Counsel 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, 2015

 

 

 

 

 

 

 

Steven E. Malnight

 

45

 

Senior Vice President, Strategy and Policy, PG&E Corporation and Pacific Gas and Electric Company

 

March 1, 2017 to present

 

 

 

 

Senior Vice President, Regulatory Affairs

 

September 18, 2014 to February 28, 2017

 

 

 

 

Vice President, Customer Energy Solutions

 

May 15, 2011 to September 17, 2014

 

 

 

 

 

 

 

Dinyar B. Mistry

 

56

 

Senior Vice President, Human Resources and Chief Diversity Officer, PG&E Corporation and Pacific Gas and Electric Company

 

February 1, 2017 to present

 

 

 

 

Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company

 

June 1, 2016 to January 31, 2017

 

 

 

 

Senior Vice President, Human Resources, Chief Financial Officer, and Controller

 

March 1, 2016 to May 31, 2016

 

 

 

 

Senior Vice President, Human Resources and Controller, PG&E Corporation

 

March 1, 2016 to May 31, 2016

 

 

 

 

Vice President, Chief Financial Officer, and Controller

 

October 1, 2011 to February 28, 2016

 

 

 

 

Vice President and Controller, PG&E Corporation

 

March 8, 2010 to February 28, 2016

 

 

 

 

 

 

 

Jesus Soto, Jr.

 

50

 

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

 

 

 

 

 

 

 

Fong Wan

 

56

 

Senior Vice President, Energy Policy and Procurement, Pacific Gas and Electric Company

 

September 8, 2015 to present

 

 

 

 

Senior Vice President, Energy Procurement

 

October 1, 2008 to September 8, 2015

 

 

 

 

 

 

 

David S. Thomason

 

42

 

Vice President, Chief Financial Officer, and Controller, Pacific Gas and Electric Company

 

 

June 1, 2016 to present

 

 

 

 

Vice President and Controller, PG&E Corporation

 

June 1, 2016 to present

 

 

 

 

Senior Director, Financial Forecasting and Analysis

 

March 2, 2015 to May 31, 2016

 

 

 

 

Senior Director, Corporate Accounting

 

March 2, 2014 to March 1, 2015

 

 

 

 

Senior Director, Financial Forecasting and Analysis

 

September 1, 2012 to March 1, 2014

 

 

 

 

 

 

 

 

(1) Ms. Williams, Mr. Stavropoulos, Mr. Wells, Mr. Simon, Ms. Kane, Mr. Malnight and Mr. Mistry are executive officers of both PG&E Corporation and the Utility.  All other listed officers are executive officers of the Utility only.

 


PART II

 

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

 

As of February 1, 2018, there were 53,878 holders of record of PG&E Corporation common stock.  PG&E Corporation common stock is listed on the New York Stock Exchange and is traded under the symbol “PCG”.  The high and low closing 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 appears in “Liquidity and Financial Resources Dividends” in Item 7. MD&A and in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and in Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

 

Sales of Unregistered Equity Securities

 

PG&E Corporation made equity contributions to the Utility totaling $50 million during the quarter ended December 31, 2017PG&E Corporation did not make any sales of unregistered equity securities during 2017 in reliance on an exemption from registration under the Securities Act of 1933, as amended. 

 

Issuer Purchases of Equity Securities

 

During the quarter ended December 31, 2017, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding.  PG&E Corporation does not have any preferred stock outstanding.  Also, during the quarter ended December 31, 2017, 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)

2017

 

2016

 

2015

 

2014

 

2013

PG&E Corporation

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$

17,135 

 

$

17,666 

 

$

16,833 

 

$

17,090 

 

$

15,598 

Operating income

 

2,956 

 

 

2,177 

 

 

1,508 

 

 

2,450 

 

 

1,762 

Net income

 

1,660 

 

 

1,407 

 

 

888 

 

 

1,450 

 

 

828 

Net earnings per common share, basic (1)

 

3.21 

 

 

2.79 

 

 

1.81 

 

 

3.07 

 

 

1.83 

Net earnings per common share, diluted

 

3.21 

 

 

2.78 

 

 

1.79 

 

 

3.06 

 

 

1.83 

Dividends declared per common share (2)

 

1.55 

 

 

1.93 

 

 

1.82 

 

 

1.82 

 

 

1.82 

At Year-End 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common stock price per share

$

44.83 

 

$

60.77 

 

$

53.19 

 

$

53.24 

 

$

40.28 

Total assets

 

68,012 

 

 

68,598 

 

 

63,234 

 

 

60,228 

 

 

55,693 

Long-term debt (excluding current portion)

 

17,753 

 

 

16,220 

 

 

15,925 

 

 

15,151 

 

 

12,805 

Capital lease obligations (excluding current portion) (3)

 

18 

 

 

31 

 

 

49 

 

 

69 

 

 

90 

Pacific Gas and Electric Company

 

 

 

 

 

 

 

 

 

 

 

 

 

 

For the Year 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating revenues

$

17,138 

 

$

17,667 

 

$

16,833 

 

$

17,088 

 

$

15,593 

Operating income

 

2,900 

 

 

2,181 

 

 

1,511 

 

 

2,452 

 

 

1,790 

Income available for common stock

 

1,677 

 

 

1,388 

 

 

848 

 

 

1,419 

 

 

852 

At Year-End 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total assets

 

67,884 

 

 

68,374 

 

 

63,037 

 

 

59,964 

 

 

55,137 

Long-term debt (excluding current portion)

 

17,403 

 

 

15,872 

 

 

15,577 

 

 

14,799 

 

 

12,805 

Capital lease obligations (excluding current portion) (3)

 

18 

 

 

31 

 

 

49 

 

 

69 

 

 

90 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) See “Overview – 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 Item 7. MD&A 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.

 


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

 

OVERVIEW

 

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California.  The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.

 

The Utility’s base revenue requirements are set by the CPUC in its GRC and GT&S rate case and by the FERC in its TO rate cases based on forecast costs.  Differences between forecast costs and actual costs can occur for numerous reasons, including the volume of work required and the impact of market forces on the cost of labor and materials.  Differences in costs can also arise from changes in laws and regulations at both the state and federal level.  Generally, differences between actual costs and forecast costs affect the Utility’s ability to earn its authorized return (referred to as “Utility Revenues and Costs that Impacted Earnings” in Results of Operations below).  However, for certain operating costs, such as costs associated with pension and other employee benefits, the Utility is authorized to track the difference between actual amounts and forecast amounts and recover or refund the difference through rates (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below).  The Utility also collects revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers, such as the costs to procure electricity or natural gas for its customers.  Therefore, although these costs can fluctuate, they generally do not impact net income (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below).  See “Ratemaking Mechanisms” in Item 1 for further discussion.

 

This is a combined report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities.  This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8.

 

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Del Norte, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “Northern California wildfires”).  According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in California that, in total, burned over 245,000 acres, resulted in 43 fatalities, and destroyed an estimated 8,900 structures.  Subsequently, the number of fatalities increased to 44.

 

The fires are being investigated by Cal Fire and the CPUC, including the possible role of the Utility’s power lines and other facilities.  The Utility expects that Cal Fire will issue a report or reports stating its conclusions as to the sources of ignition of the fires and the way that they progressed.  The CPUC’s SED is also conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire impacted areas.  According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response.  It is uncertain when the investigations will be complete and whether Cal Fire will release any preliminary findings before its investigation is complete.  

 

PG&E Corporation and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected by potential losses resulting from the impact of the Northern California wildfires.  See Item 1A. Risk Factors

 

Tax Cuts and Jobs Act of 2017

 

On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act.  Among other provisions, the Tax Act reduces the federal income tax rate from 35 percent to 21 percent beginning on January 1, 2018 and eliminated bonus depreciation for utilities. 

 

 


The Tax Act also required PG&E Corporation and the Utility to re-measure existing deferred income tax assets and liabilities to reflect the lower federal tax rate.  During the three months and year ended December 31, 2017, PG&E Corporation, on a consolidated basis, recorded a one-time provisional tax expense of $147 million to reflect the transitional impacts of the Tax Act.  Of this amount, $83 million is attributable to the re-measurement of PG&E Corporation’s net deferred tax asset comprised primarily of net operating loss carry-forwards and compensation-related items.  The remaining $64 million is related to the re-measurement of the Utility’s deferred taxes not reflected in authorized revenue requirements, such as disallowed plant.  The Utility also recorded a provisional $5.7 billion re-measurement of its deferred tax balances (related to flow-through and normalized timing differences for plant-related items) which was offset by a change from a net deferred income tax regulatory asset to a net regulatory liability.  The net deferred income tax regulatory liability will be refunded to customers over the regulatory lives of the related assets.  The final transition impacts of the Tax Act may materially vary from the above recorded amounts due to, among other things, future regulatory decisions from the CPUC that could differ from the Utility’s determination of how the impacts of the Tax Act are allocated between customers and shareholders. 

 

As a result of the Tax Act, the Utility intends to file by the end of March 2018 (i) revised revenue requirements and rate base in its 2017 GRC (for years 2018 and 2019) and 2015 GT&S rate case (for 2018) as well as a proposed implementation plan in connection thereto, and (ii) revised revenue requirement and rate base forecast in its 2019 GT&S rate case.  The Utility is unable to predict the timing and outcome of the CPUC decision in connection with such filings.

 

On an aggregate basis, the Utility anticipates an annual reduction to revenue requirements of approximately $500 million starting in 2018, and incremental increases to rate base of approximately $500 million in 2018 and $800 million in 2019 as a result of the Tax Act.  The estimated benefit to customers is driven by the lower federal income tax rate applied to future earnings and the return of excess deferred income taxes.  These benefits are partially offset by earnings on higher rate base and lower tax benefits from flow-through items.

 

In addition to this reduction in future revenue requirements, the Tax Act is expected to accelerate when PG&E Corporation resumes paying federal taxes, primarily due to the elimination of bonus depreciation; although future taxes are expected to be lower due to the lower federal tax rate.  PG&E Corporation now expects to pay federal taxes starting in 2020, although that timing would be impacted by any significant changes to future results of operationsAdditionally, because the revenue reduction is expected to precede the reduction in federal income tax payments, PG&E Corporation’s and the Utility’s operating cash flows will be negatively impacted resulting in additional financing needs.

 


Summary of Changes in Net Income and Earnings per Share

 

The tables below include a summary reconciliation of PG&E Corporation’s consolidated income available for common shareholders and EPS to earnings from operations and EPS based on earnings from operations for the three months and twelve months ended December 31, 2017 compared to the three months and twelve months ended December 31, 2016 and a summary reconciliation of the key drivers of PG&E Corporation’s earnings from operations and EPS based on earnings from operations for the three months and twelve months ended December 31, 2017 compared to the three months and twelve months ended December 31, 2016.  Earnings from operations is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability.  Items impacting comparability represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods.  PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short and long-term operating plans, and employee incentive compensation.  PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance.  Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

 

 

Three Months Ended December 31,

 

Year Ended December 31,

 

 

 

 

 

 

 

Earnings per

 

 

 

 

 

 

 

Earnings per

 

 

 

 

 

 

 

Common Share

 

 

 

 

 

 

 

Common Share

(in millions,

Earnings

 

(Diluted)

 

Earnings

 

(Diluted)

except per share amounts)

2017

 

2016

 

2017

 

2016

 

2017

 

2016

 

2017

 

2016

PG&E Corporation’s

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings on a GAAP basis

$

114 

 

$

692 

 

$

0.22 

 

$

1.36 

 

$

1,646 

 

$

1,393 

 

$

3.21 

 

$

2.78 

Items Impacting

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comparability: (1)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Tax Cuts and Jobs Act

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

transition impact (2)

 

147 

 

 

- 

 

 

0.29 

 

 

- 

 

 

147 

 

 

- 

 

 

0.29 

 

 

- 

Northern California wildfire-

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

related costs (3)

 

49 

 

 

- 

 

 

0.09 

 

 

- 

 

 

49 

 

 

- 

 

 

0.09 

 

 

- 

Butte fire-related costs,

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

net of insurance (4)

 

9 

 

 

27 

 

 

0.02 

 

 

0.05 

 

 

36 

 

 

137 

 

 

0.07 

 

 

0.27 

Pipeline related expenses (5)

 

7 

 

 

20 

 

 

0.01 

 

 

0.04 

 

 

52 

 

 

67 

 

 

0.10 

 

 

0.13 

Legal and regulatory

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

related expenses (6)

 

1 

 

 

11 

 

 

- 

 

 

0.02 

 

 

6 

 

 

43 

 

 

0.01 

 

 

0.09 

Fines and penalties (7) 

 

- 

 

 

101 

 

 

- 

 

 

0.20 

 

 

47 

 

 

307 

 

 

0.09 

 

 

0.61 

Diablo Canyon settlement-related

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

disallowance (8)

 

- 

 

 

- 

 

 

- 

 

 

- 

 

 

32 

 

 

- 

 

 

0.06 

 

 

- 

GT&S revenue timing impact (9)

 

- 

 

 

(193)

 

 

- 

 

 

(0.38)

 

 

(88)

 

 

(193)

 

 

(0.17)

 

 

(0.38)

Net benefit from derivative