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EXHIBIT 2 

WOLTERING DECLARATION

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HOSTETLER LLP

ATTORNEYS AT LAW

SAN FRANCISCO

Robert A. Julian (SBN 99469) 

Cecily A. Dumas (SBN 111449) 

BAKER & HOSTETLER LLP 

1160 Battery Street, Suite 100 

San Francisco, CA 94111 

Telephone: 628.208.6434 

Facsimile: 310.820.8859 

Email: rjulian@bakerlaw.com 

Email: cdumas@bakerlaw.com 

Eric E. Sagerman (SBN 155496) 

Lauren T. Attard (SBN 320898) 

BAKER & HOSTETLER LLP 

11601 Wilshire Boulevard 

Suite 1400 

Los Angeles, CA 90025 

Telephone: 310.820.8800 

Facsimile: 310.820.8859 

Email: esagerman@bakerlaw.com 

Email: lattard@bakerlaw.com 

Counsel for Official Committee of Tort Claimants 

UNITED STATES BANKRUPTCY COURT 

NORTHERN DISTRICT OF CALIFORNIA 

SAN FRANCISCO DIVISION 

In re: 

PG&E CORPORATION 

-andPACIFIC GAS AND ELECTRIC 

COMPANY, 

 Debtors. 

□ Affects PG&E Corporation 

□ Affects Pacific Gas and Electric Company 

■ Affects both Debtors 

*All papers shall be filed in the Lead Case, 

No. 19-30088 (DM) 

Bankruptcy Case 

No. 19-30088 (DM) 

Chapter 11 

(Lead Case) 

(Jointly Administered) 

DECLARATION OF CATHERINE E. 

WOLTERING IN SUPPORT OF 

OBJECTION OF THE OFFICIAL 

COMMITTEE OF TORT CLAIMANTS 

TO MOTION OF THE DEBTORS FOR 

ORDER (I) ESTABLISHING DEADLINE 

FOR FILING PROOFS OF CLAIM, 

(II) ESTABLISHING THE FORM AND 

MANNER OF NOTICE THEREOF, AND 

(III) APPROVING PROCEDURES FOR 

PROVIDING NOTICE OF BAR DATE 

AND OTHER INFORMATION TO ALL 

CREDITORS AND POTENTIAL 

CREDITORS (DKT. NO. 1784) 

Date: June 11, 2019 

Time: 9:30 a.m. (Pacific Time) 

Place: United States Bankruptcy Court 

 Courtroom 17, 16th Floor 

 San Francisco, CA 94102 

Objection Deadline: May 31, 2019

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2 

CATHERINE E. WOLTERING declares as follows under penalty of perjury:

1. I am a partner at Baker & Hostetler LLP, counsel to the Official Committee of Tort 

Claimants in the above-captioned chapter 11 cases of PG&E Corporation and Pacific Gas and 

Electric Company. I have personal knowledge of the facts stated herein except as to matters where 

I indicate otherwise, and as to those matters, I believe them to be true. If called upon to testify, 

I could and would competently do so. 

2. I make this declaration in support of the Objection of the Official Committee of Tort 

Claimants to Motion of the Debtors for Order (I) Establishing Deadline for Filing Proofs of Claim, 

(II) Establishing the Form and Manner of Notice Thereof, and (III) Approving Procedures for 

Providing Notice of Bar Date and Other Information to All Creditors and Potential Creditors 

(the “Objection”) filed concurrently herewith. 

3. For the Court’s reference in its consideration of the Objection, attached hereto as 

Exhibit A through Exhibit I are true and accurate copies of press releases from the California 

Department of Forestry and Fire Protection’s (“Cal Fire”) website, court filings, and PG&E’s SEC 

filings, the source for each being noted below: 

A Cal Fire Investigators Determine Cause of Destructive Butte Fire, Cal Fire News 

Release, April 28, 2016.1

B 2016 Joint Annual Report to Shareholders, PG&E Corporation and Pacific Gas and 

Electric Company.2

C 2017 Joint Annual Report to Shareholders, PG&E Corporation and Pacific Gas and 

Electric Company.3

D Master Complaint, In re Ghost Ship Fire Litigation, Case No. RG16843631 (Superior 

Ct. Cal. May 16, 2017).4

E Quarterly Report on Form 10-Q, PG&E Corporation and Pacific Gas and Electric 

Company, September 30, 2017.5

 

1

 Available at http://calfire.ca.gov/communications/downloads/newsreleases/2016/ButteFireCause.pdf. 

2

 Available at: 

http://pgecorp.com/investors/financial_reports/annual_report_proxy_statement/ar_pdf/2016/2016_Annual_Report.pd

f. 

3

 Available at: http://s1.q4cdn.com/880135780/files/doc_financials/2017/annual/2017-Annual-Report-Final.pdf. 

4

 Available at: https://www.maryalexanderlaw.com/uploads/2017/05/Ghost-Ship-Master-Complaint-file-endorsed.pdf 

5

 Available at: http://s1.q4cdn.com/880135780/files/doc_financials/2017/Q3/Third-Quarter-2017-Form-10-Q.pdf. 

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F Case Management Order 1, California North Bay Fire Cases, No. JCCP 4955 

(Superior Ct. Cal. Mar. 6, 2018).6

G Case Management Order 5, California North Bay Fire Cases, No. JCCP 4955 

(Superior Ct. Cal. Dec. 31, 2018). 

H Cal Fire Investigators Determine the Cause of the Camp Fire, Cal Fire News Release, 

May 15, 2019.7

I Quarterly Report on Form 10-Q, PG&E Corporation and Pacific Gas and Electric 

Company, March 31, 20198

4. I declare under penalty of perjury that the foregoing is true and correct.

Executed this 31st day of May, 2019, 

at Columbus, Ohio, 

 CATHERINE E. WOLTERING 

6

 Available at: https://www.walkuplawoffice.com/wp-content/uploads/2018/05/2018.03.06-CMO-1-structure-ofJCCP.pdf. 

7

 Available at http://calfire.ca.gov/communications/downloads/newsreleases/2019/CampFire_Cause.pdf. 

8

 Available at: http://s1.q4cdn.com/880135780/files/doc_financials/2019/q1/PGE-03-31-19-10Q-Final.pdf 

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ATTOR NE YS AT LAW

SAN FRANCISCO

 

EXHIBIT A 

CAL FIRE INVESTIGATORS DETERMINE CAUSE OF DESTRUCTIVE BUTTE FIRE, 

CAL FIRE NEWS RELEASE, APRIL 28, 2016 

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CAL FIRE investigators determine cause of destructive Butte Fire 

Sacramento – After a thorough investigation, CAL FIRE has determined that the 2015 Butte Fire was 

sparked by a tree that came into contact with a Pacific Gas & Electric Company powerline. 

TWEET THIS: .@CAL_FIRE investigators determine power lines were cause of destructive 

#ButteFire.

Investigators were dispatched as part of the initial response to the Butte Fire and immediately began 

working to determine the origin and cause of the fire. The ensuing investigation uncovered evidence 

that contact between a tree and a PG&E powerline near Butte Mountain Road in Amador County 

sparked the fire on September 9, 2015. 

The fire burned for 22 days and spread into Calaveras County before the blaze was fully contained. 

The fire became the 7th most destructive wildfire in California’s history. Two civilians lost their lives 

and more than 900 structures were destroyed by the fire. At its peak, nearly 5,000 firefighters battled 

the blaze. Resources included 519 fire engines, 18 helicopters, 8 airtankers, 92 hand crews, 115 

bulldozers, and 60 water tenders. 

Under California’s Health and Safety Code, CAL FIRE has the ability to seek recovery of costs 

incurred battling wildfires that are determined to be sparked due to negligence or violations of the law. 

CAL FIRE will seek to recover firefighting costs in excess of $90 million from PG&E. 

Everyone must take steps to prevent sparking wildfires. One Less Spark truly means, One Less 

Wildfire. Learn more at ReadyForWildfire.org. 

 

CAL FIRE has submitted the Butte Fire Investigation Report to the Amador and Calaveras County 

District Attorneys for their review. A copy of the final report can be found here: 

http://calfire.ca.gov/fire_protection/fire_protection_firereports. 

# # # 

CONTACT: Daniel Berlant 

Information Officer

(916) 651-FIRE (3473) 

@CALFIRE_PIO

RELEASE 

 DATE: April 28, 2016

California Department of Forestry and Fire Protection 

CAL FIRE NEWS RELEASE

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Media Notes 

Click here to download high resolution video 

Important links: 

www.fire.ca.gov

www.ReadyForWildfire.org

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EXHIBIT B 

2016 JOINT ANNUAL REPORT TO SHAREHOLDERS, PG&E CORPORATION AND 

PACIFIC GAS AND ELECTRIC COMPANY 

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2016 Joint Annual 

Report to Shareholders

PG&E Corporation 

Pacific Gas and Electric Company

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Table of Contents

A Letter from the Executive Chair of the Board ...................................................................................................... ii

Financial Highlights ..................................................................................................................................................iv

Comparison of Five-Year Cumulative Total Shareholder Return .............................................................v

Form 10-K Cover Page ..............................................................................................................................................1

Form 10-K Table of Contents .................................................................................................................................3

Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company .....................152

Officers of PG&E Corporation and Pacific Gas and Electric Company .............................................152

Shareholder Information .....................................................................................................................................154

Important notice: This 2016 Joint Annual Report to Shareholders (this “Annual Report”) includes PG&E Corporation 

and Pacific Gas and Electric Company’s joint Annual Report on Form 10-K for the year ended December 31, 2016 that 

was filed with the Securities and Exchange Commission on February 16, 2017 (the “Form 10-K”), reformatted to make 

the information more reader-friendly. Except for formatting changes, this Annual Report does not modify, amend or 

update the information contained in the Form 10-K.

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ii

* “PG&E” refers to PG&E Corporation and Pacific Gas and Electric Company.

A Letter from the Executive Chair of the Board

The 16 million people whom PG&E* serves count on us each and every day to provide energy that is safe, reliable, 

affordable and clean. Just as important, they look to us to prepare for tomorrow, with a focus on developing smart, 

sustainable long-term energy solutions that will ensure our communities continue to prosper and thrive.

PG&E’s accomplishments in 2016 show we are committed to meeting these crucial challenges. 

We built upon our industry-leading progress on safety, earning an unprecedented number of independent certifications 

for the quality and integrity of our gas operations – recognition we welcomed with the understanding that our safety 

work is never finished, and there is always more to do. We recorded the second-best performance for electric system 

reliability in our entire history, despite a winter of exceptionally powerful storms. And our customer satisfaction scores 

climbed to the highest level in years. 

At the same time, we continued to set the pace in providing power that is among the cleanest in the nation. Nearly 

one-third of the electricity we delivered in 2016 came from state-qualified renewable resources – four years ahead 

of California’s schedule. Even more significant, nearly 70 percent of PG&E’s electricity mix now comes from sources 

that emit no greenhouse gases. 

We also delivered solid financial results for the year and announced our first dividend increase in six years – a step 

that will help enable PG&E to compete more efficiently and affordably for capital to fund further investments in safety, 

reliability and clean energy in the years ahead.

Looking forward, we are focused on three major areas: further strengthening our operational excellence, above all on 

safety; remaining our customers’ provider of choice as they consider a growing array of energy options; and positioning 

PG&E for the future as California transitions to a clean energy economy.

We recognize that our customers’ needs and expectations are evolving faster today than ever before. We also recognize 

that California’s clean energy goals, which PG&E firmly supports, will continue to drive large-scale transformation in 

the state’s energy sector, and that PG&E will play a vital role.

Our customers, many of whom pride themselves on their environmental stewardship, are already leading the way. PG&E 

has now connected nearly 300,000 private rooftop solar arrays – or 25 percent of the total for the entire country. The 

same is true for transportation, with PG&E’s grid supporting one in five of the nation’s electric vehicles.

Meanwhile, state leaders continue to assert California’s policy leadership on climate change and the State’s resolve to 

dramatically reduce greenhouse gas emissions. 

We see these shifts in our sector as an opportunity. Achieving California’s vision will require sustained and smart 

investments. It will require innovation. And it will require working in close partnership with others at the local, state 

and national levels who can help us achieve our shared aims. 

Last year’s landmark agreement to phase out PG&E’s Diablo Canyon nuclear plant by 2025 is a prime example. The joint 

proposal we submitted to the California Public Utilities Commission, in partnership with key labor and environmental 

partners, will increase investment in energy efficiency and renewables beyond the current state mandates. The proposal 

includes PG&E’s voluntary commitment to a 55 percent renewable energy target in 2031, an unprecedented pledge 

by a major U.S. energy company.

PG&E is now making new capital investments at a pace of approximately $6 billion per year as we continue to modernize 

our system, integrate renewables and other distributed energy resources, and take advantage of new technologies 

coming out of Silicon Valley and elsewhere.

One pivotal development came in December, when our state regulator authorized PG&E to invest $130 million over 

the next three years to install the infrastructure for 7,500 public charging stations to support the growth of electric 

vehicles across our service area. 

Combined with our improvements in safety and reliability over the last six years, such investments have put PG&E in a 

position to produce tangible value for customers and shareholders. Even so, we understand that additional investments 

come at a cost, and that to be successful we must keep our service affordable. 

Over the last few years, we’ve reduced PG&E’s cost structure in a number of areas. This January, we announced steps 

that will deliver further savings in 2017. Going forward, we are determined to find additional opportunities to reduce 

costs, while never compromising on safety.

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iii

A Letter from the Executive Chair of the Board (continued)

The vital importance of our safety commitment was underscored last year by the August verdict that found Pacific 

Gas and Electric Company guilty of 6 of the 12 charges brought by the federal government in a case stemming from 

the 2010 gas pipeline explosion in San Bruno: the convictions included one count of obstructing a federal agency 

proceeding and five counts of violating federal pipeline safety regulations.

Even though it involved events of the past, this was a painful verdict. Ultimately, we made the choice not appeal the 

jury’s decision, concluding that was the right outcome for everyone. 

Nothing can ever give back the San Bruno victims and their families what they lost. The best way we can honor them 

is to demonstrate, through our actions, an unwavering dedication to the safety of the public, our employees and 

contractors. 

With that in mind, we will be focused on fulfilling the terms of the probation and working with a court-appointed 

outside monitor to become the safest, most reliable energy company in the country. 

I have no doubts about what PG&E can achieve in the years to come. I’m also convinced that we have the leadership 

that future will require. 

On March 1, 2017, Geisha Williams, who most recently served as President, Electric of Pacific Gas and Electric Company, 

succeeded me as CEO and President of PG&E Corporation. Nick Stavropoulos, formerly President, Gas of Pacific Gas 

and Electric Company, became President and Chief Operating Officer of Pacific Gas and Electric Company. Together, 

they have more than six decades of experience in our business.

Having worked alongside Geisha and Nick for many years and knowing their record of accomplishment, I have every 

confidence in PG&E’s continued success under their leadership. I look forward to continuing to work with them in my 

new role as Executive Chair of the Board of PG&E Corporation.

As I step aside after six years as CEO and President of PG&E Corporation, I am grateful to our 23,000 employees for 

the strides they have made and I am proud of the direction we’ve set. 

Thank you also to our customers, investors and other stakeholders for following PG&E’s progress and for your support 

as we work together to build a better California.

Sincerely,

Anthony F. Earley, Jr. 

Executive Chair of the Board 

PG&E Corporation

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iv

 Financial Highlights(1)

PG&E Corporation

(unaudited, in millions, except share and per share amounts) 2016 2015

Operating Revenues $ 17,666 $ 16,833

Income Available for Common Shareholders

Earnings from operations(2) 1,884 1,519

Less items impacting comparability(3)

Butte fire related costs (net of insurance)(4) (137) –

Fines and penalties(5) (307) (578)

Pipeline-related expenses(6) (67) (61)

Legal and regulatory related expenses(7) (43) (35)

GT&S capital disallowance(8) (130) – 

GT&S revenue timing impact(9) 193 –

Insurance recoveries – 29

Reported consolidated income available for common shareholders 1,393 874

Income Per Common Share, diluted 

Earnings from operations(2) 3.76 3.12

Less items impacting comparability(3)

Butte fire related costs (net of insurance)(4) (0.27) –

Fines and penalties(5) (0.61) (1.19)

Pipeline-related expenses(6) (0.13) (0.13)

Legal and regulatory related expenses(7) (0.09) (0.07)

GT&S capital disallowance(8) (0.26) –

GT&S revenue timing impact(9) 0.38 –

Insurance recoveries – 0.06

Reported consolidated net earnings per common share, diluted 2.78 1.79

Dividends Declared Per Common Share 1.93 1.82

Total Assets at December 31(10) $ 68,598 $ 63,234

Number of common shares outstanding at December 31 506,891,874 492,025,443

(1) This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company (the “Utility”). PG&E Corporation’s 

Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and subsidiaries, and have been 

prepared in accordance with Generally Accepted Accounting Principles (“GAAP”). All amounts presented in the table above are 

tax-adjusted at PG&E Corporation’s tax rate of 40.75% except for fines, which are not tax deductible.

(2) “Earnings from operations” is a non-GAAP financial measure and is calculated as consolidated income available for common 

shareholders less “Items impacting comparability” as described in Note (3) below. 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. 

(3) “Items impacting comparability” represent items that management does not consider part of the normal course of operations 

and that affect comparability of financial results between periods. Items impacting comparability reconcile earnings from 

operations with consolidated income available for common shareholders as reported in accordance with GAAP.

(4) The Utility recorded costs of $232 million, pre-tax, during the year ended December 31, 2016 associated with the Butte fire, net 

of insurance. This includes accrued charges of $750 million, pre-tax, related to estimated third-party claims in connection with 

the Butte fire, partially offset by $625 million, pre-tax, as probable of insurance recovery. The Utility also incurred charges of 

$107 million, pre-tax, for Utility clean-up, repair, and legal costs associated with the Butte fire. 

(5) The Utility incurred costs of $498 million, pre-tax, during the year ended December 31, 2016 associated with fines and 

penalties. This includes costs of $412 million, pre-tax, associated with safety-related cost disallowances imposed by the 

California Public Utilities Commission (the “CPUC”) in its April 9, 2015 decision in the gas transmission pipeline investigations. 

The Utility also recorded $57 million, pre-tax, for disallowances imposed by the CPUC in its final phase two decision of the 

2015 Gas Transmission and Storage (GT&S) rate case for prohibited ex parte communications. In addition, the Utility accrued 

fines of $26 million in connection with the final decision approved by the CPUC on August 18, 2016 in its investigation 

regarding natural gas distribution record-keeping practices and $3 million in connection with the maximum statutory fine 

imposed on January 26, 2017 in the federal criminal trial against the Utility. These fines are not tax deductible. Future fines

or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding natural gas 

matters and regulatory communications.

(6) The Utility incurred costs of $113 million, pre-tax, during the year ended December 31, 2016 for pipeline related expenses 

incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights of way.

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v

(1) Assumes $100 invested on December 31, 2011 in PG&E Corporation common stock, the Standard & Poor’s 500 Stock Index, and 

the Dow Jones Utilities Index, and assumes quarterly reinvestment of dividends. The total shareholder returns shown are not 

necessarily indicative of future returns.

(7) The Utility incurred costs of $72 million, pre-tax, during the year ended December 31, 2016 for legal and regulatory related 

expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters 

and regulatory communications. 

(8) The Utility incurred charges of $219 million, pre-tax, during the year ended December 31, 2016 for disallowed capital 

expenditures based on the CPUC final phase one decision dated June 23, 2016 in the 2015 GT&S rate case, including 

$134 million, pre-tax, for the disallowed portion of the 2011 through 2014 capital expenditures in excess of adopted 

amounts and $85 million, pre-tax, for the Utility’s estimate of 2015 through 2018 capital expenditures that are likely to 

exceed authorized amounts. 

(9) As a result of the timing of the CPUC’s final phase two decision in the 2015 GT&S rate case, the Utility recorded $325 million, 

pre-tax, in excess of the 2016 authorized revenue requirement during the twelve months ended December 31, 2016.

(10) In accordance with Accounting Standard Update 2015-03, PG&E Corporation restated $105 million in 2015 of debt issuance 

costs. Total assets and liabilities were each reduced by this amount with no impact to net income or total shareholder’s 

equity previously reported.

Comparison of Five-Year Cumulative Total Shareholder Return(1)

PG&E Corporation common stock is traded on the New York Stock Exchange under the symbol “PCG.”

This graph compares the cumulative total return on PG&E Corporation common stock (equal to dividends plus stock 

price appreciation) during the past five fiscal years with that of the Standard & Poor’s 500 Stock Index and the Dow 

Jones Utilities Index.

2011 2012 2013 2014 2015 2016

PG&E Corporation Dow Jones Utilities Index S&P 500 Index

Comparison of 5-Year Cumulative Total Returns

$0

$50

$100

$150

$200

$101.60

$101.72

$115.99

$106.43

$114.48

$153.54

$146.18

$149.57

$174.54

$144.99

$151.24

$176.95

$198.09

$178.31

$171.36

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Intentionally left blank

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the Fiscal Year Ended December 31, 2016

 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:

Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%

Nonredeemable: 6%, 5.50%, 5%

NYSE MKT LLC 

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 ;

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a 

smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):

PG&E Corporation Pacific Gas and Electric Company

Large accelerated filer ;

Accelerated filer 

Non-accelerated filer 

Smaller reporting company 

Large accelerated filer 

Accelerated filer 

Non-accelerated filer ;

Smaller reporting company 

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

Exchange Act).

PG&E Corporation Yes  No ;

Pacific Gas and Electric Company Yes  No ;

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 

2016, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation common stock

Pacific Gas and Electric Company common stock

$31,807 million

Wholly owned by PG&E Corporation

Common Stock outstanding as of February 7, 2017:

PG&E Corporation:

Pacific Gas and Electric Company:

507,782,249 shares

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 2017 Annual Meetings of Shareholders

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

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Table of Contents

 Units of Measurement ...............................................................................................................................................................................................................................................................................................................................................5

Glossary ...............................................................................................................................................................................................................................................................................................................................................................................................................................................................5

PART I 7

ITEM 1. Business ............................................................................................................................................................................................................................................................................................................................................................7

 Regulatory Environment ............................................................................................................................................................................................................................................................................7

 Ratemaking Mechanisms ..........................................................................................................................................................................................................................................................................9

 Electric Utility Operations .................................................................................................................................................................................................................................................................12

 Natural Gas Utility Operations .............................................................................................................................................................................................................................................16

 Competition ................................................................................................................................................................................................................................................................................................................................17

 Environmental Regulation ................................................................................................................................................................................................................................................................18

ITEM 1A. Risk Factors ......................................................................................................................................................................................................................................................................................................................................22

ITEM 1B. Unresolved Staff Comments ...........................................................................................................................................................................................................................................................33

ITEM 2. Properties ...............................................................................................................................................................................................................................................................................................................................................33

ITEM 3. Legal Proceedings.........................................................................................................................................................................................................................................................................................................34

ITEM 4. Mine Safety Disclosures ................................................................................................................................................................................................................................................................................37

Executive Officers of the Registrants .................................................................................................................................................................................................................................................................................................37

PART II 40

ITEM 5. Market for Registrant’s Common Equity, Related Shareholder Matters 

and Issuer Purchases of Equity Securities ..............................................................................................................................................................................................40

ITEM 6. Selected Financial Data .................................................................................................................................................................................................................................................................................41

ITEM 7. Management’s Discussion and Analysis of Financial Condition 

and Results of Operations .....................................................................................................................................................................................................................................................................41

 Overview ..............................................................................................................................................................................................................................................................................................................................................41

 Results of Operations .....................................................................................................................................................................................................................................................................................44

 Liquidity and Financial Resources ............................................................................................................................................................................................................................48

 Contractual Commitments ..............................................................................................................................................................................................................................................................51

 Enforcement and Litigation Matters...................................................................................................................................................................................................................52

 Regulatory Matters ................................................................................................................................................................................................................................................................................................54

 Legislative and Regulatory Initiatives.............................................................................................................................................................................................................61

 Environmental Matters ................................................................................................................................................................................................................................................................................64

 Risk Management Activities........................................................................................................................................................................................................................................................64

 Critical Accounting Policies .........................................................................................................................................................................................................................................................66

 New Accounting Pronouncements .........................................................................................................................................................................................................................69

 Forward-Looking Statements ................................................................................................................................................................................................................................................69

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................................................................71

ITEM 8. Financial Statements and Supplementary Data ....................................................................................................................................................................72

 PG&E Corporation .........................................................................................................................................................................................................................................................................................................72

 Consolidated Statements of Income ................................................................................................................................................................................................................72

 Consolidated Statements of Comprehensive Income....................................................................................................................................73

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 Consolidated Balance Sheets ......................................................................................................................................................................................................................................................74

 Consolidated Statements of Cash Flows .............................................................................................................................................................................................76

 Consolidated Statements of Equity ....................................................................................................................................................................................................................78

 Pacific Gas and Electric Company ................................................................................................................................................................................................................................79

 Consolidated Statements of Income .................................................................................................................................................................................................................79

 Consolidated Statements of Comprehensive Income ....................................................................................................................................80

 Consolidated Balance Sheets .................................................................................................................................................................................................................................................81

 Consolidated Statements of Cash Flows ..............................................................................................................................................................................................83

 Consolidated Statements of Shareholders’ Equity ..................................................................................................................................................85

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS .......................................................................................................................................................................................................86

NOTE 1: Organization and Basis of Presentation ................................................................................................................................................................................................86

NOTE 2: Summary of Significant Accounting Policies ..........................................................................................................................................................................86

NOTE 3: Regulatory Assets, Liabilities, and Balancing Accounts ........................................................................................................................92

NOTE 4: Debt ..................................................................................................................................................................................................................................................................................................................................................................94

NOTE 5: Common Stock and Share-Based Compensation .....................................................................................................................................................96

NOTE 6: Preferred Stock ...............................................................................................................................................................................................................................................................................................................98

NOTE 7: Earnings Per Share ...............................................................................................................................................................................................................................................................................................98

NOTE 8: Income Taxes .........................................................................................................................................................................................................................................................................................................................99

NOTE 9: Derivatives................................................................................................................................................................................................................................................................................................................................102

NOTE 10: Fair Value Measurements .............................................................................................................................................................................................................................................................103

NOTE 11: Employee Benefit Plans ....................................................................................................................................................................................................................................................................108

NOTE 12: Related Party Agreements and Transactions ....................................................................................................................................................................115

NOTE 13: Contingencies and Commitments ......................................................................................................................................................................................................................116

Quarterly Consolidated Financial Data (Unaudited) .................................................................................................................................................................................................................126

Management’s Report on Internal Control Over Financial Reporting ............................................................................................................................128

Report of Independent Registered Public Accounting Firm .........................................................................................................................................................................129

ITEM 9. Changes in and Disagreements with Accountants on Accounting 

and Financial Disclosure ........................................................................................................................................................................................................................................................................131

ITEM 9A. Controls and Procedures ......................................................................................................................................................................................................................................................................131

ITEM 9B. Other Information......................................................................................................................................................................................................................................................................................................131

PART III 132

ITEM 10. Directors, Executive Officers and Corporate Governance .................................................................................................................132

ITEM 11. Executive Compensation .....................................................................................................................................................................................................................................................................133

ITEM 12. Security Ownership of Certain Beneficial Owners and Management 

and Related Stockholder Matters ...............................................................................................................................................................................................................................133

ITEM 13. Certain Relationships and Related Transactions, and Director Independence ..................................134

ITEM 14. Principal Accountant Fees and Services ................................................................................................................................................................................................134

PART IV 135

ITEM 15. Exhibits and Financial Statement Schedules ............................................................................................................................................................................135

Signatures .....................................................................................................................................................................................................................................................................................................................................................................................................................................144

Report of Independent Registered Public Accounting Firm .........................................................................................................................................................................146

TABLE OF CONTENTS

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5

GLOSSARY  

Units of Measurement

1 Kilowatt (kW) = One thousand watts

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 (GW) = One million kilowatts

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

1 Bcf = One billion cubic feet

1 MDth = One thousand decatherms

Glossary

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

2016 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, 2016

AB Assembly Bill

AFUDC allowance for funds used during construction

ALJ administrative law judge 

ARO asset retirement obligation

ASU accounting standard update issued by the FASB (see below)

CAISO California Independent System Operator

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

CO2 carbon dioxide

CPUC California Public Utilities Commission

CRRs congestion revenue rights

DER distributed energy resources

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

DTSC Department of Toxic Substances Control

EMANI European Mutual Association for Nuclear Insurance

EPA Environmental Protection Agency

EPS earnings per common share

EV electric vehicle

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GLOSSARY  

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

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

MOU memorandum of understanding

NAV net asset value

NDTCP Nuclear Decommissioning Cost Triennial Proceedings

NEIL Nuclear Electric Insurance Limited

NEM net energy metering 

NRC Nuclear Regulatory Commission

NTSB National Transportation Safety Board

OII order instituting investigation

ORA Office of Ratepayer Advocates

PHMSA Pipeline and Hazardous Materials Safety Administration

PSEP pipeline safety enhancement plan

QF qualifying facility

Regional Board California Regional Water Quality Control Board, Lahontan Region

REITS real estate investment trust

RFO requests for offers

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

TE transportation electrification

TO transmission owner

TURN The Utility Reform Network

Utility Pacific Gas and Electric Company

VIE(s) variable interest entity(ies)

Water Board California State Water Resources Control Board

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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, 2016, PG&E Corporation and the Utility had 

approximately 24,000 regular employees, approximately 

30 of which were employees of PG&E Corporation. Of 

the Utility’s regular employees, approximately 14,000 

are covered by collective bargaining agreements with 

the local chapters of three labor unions: the International 

Brotherhood of Electrical Workers (“IBEW”); the Engineers 

and Scientists of California (“ESC”); and the Service 

Employees International Union (“SEIU”). A new SEIU 

collective bargaining agreement was ratified in December 

2016 and is effective August 1, 2016 through December 31, 

2019. Two new agreements (Physical and Clerical) with 

IBEW and an agreement with ESC were ratified in 2016 

and were retroactive to January 1, 2016. They 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 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 these websites is not part of 

this or any other report that PG&E Corporation or the 

Utility files with, or furnishes to, the SEC.

This Annual Report on Form 10-K contains forward-looking 

statements that are necessarily subject to various risks 

and uncertainties. For a discussion of the significant risks 

that could affect the outcome of these forward-looking 

statements and PG&E Corporation’s and the Utility’s future 

financial condition and results of operations, see “Item 1A. 

Risk Factors” and the section entitled “Forward-Looking 

Statements” in MD&A. 

Regulatory Environment 

The Utility’s business is subject to the regulatory jurisdiction 

of various agencies at the federal, state, and local levels. 

At the state level, the Utility is regulated primarily by 

the CPUC. At the federal level, the Utility is subject to 

the jurisdiction of the FERC and the NRC. The Utility is 

also subject to the requirements of other federal, state 

and local regulatory agencies with respect to safety, the 

environment, and health. This section and the “Ratemaking 

Mechanisms” section below summarize some of the more 

significant laws, regulations, and regulatory proceedings 

affecting the Utility. 

PG&E Corporation is a “public utility holding company” as 

defined under the Public Utility Holding Company Act of 

2005 and is subject to regulatory oversight by the FERC. 

PG&E Corporation and its subsidiaries are exempt from 

all requirements of the Public Utility Holding Company 

Act of 2005 other than the obligation to provide access 

to their books and records to the FERC and the CPUC 

for ratemaking purposes.

The California Public Utilities Commission 

The CPUC is a regulatory agency that regulates privately 

owned public utilities in California. The CPUC consists 

of five commissioners appointed by the Governor of 

California and confirmed by the California State Senate 

for staggered six-year terms. The CPUC has jurisdiction 

over the rates and terms and conditions of service for the 

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ITEM 1.  BUSINESS

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 electricity and natural gas retail customers, rates 

of return, rates of depreciation, oversight of nuclear 

decommissioning, and aspects of the siting of facilities 

used in providing electric and natural gas utility service.

The CPUC enforces state laws and regulations that 

set forth safety requirements pertaining to the design, 

construction, testing, operation, and maintenance of 

utility gas and electric facilities. The CPUC can impose 

penalties of up to $50,000 per day, per violation, for 

violations that occurred after January 1, 2012. (The 

statutory maximum penalty for violations that occurred 

before January 1, 2012 is $20,000 per violation.) The 

CPUC has wide discretion to determine the amount of 

penalties based on the totality of the circumstances, 

including such factors as the gravity of the violations; the 

type of harm caused by the violations and the number 

of persons affected; and the good faith of the entity 

charged in attempting to achieve compliance, after 

notification of a violation. The CPUC also is required 

to consider the appropriateness of the amount of the 

penalty to the size of the entity charged. 

The CPUC has delegated authority to the SED to issue 

citations and impose penalties for violations identified 

through audits, investigations, or self-reports. Under both 

the gas and electric programs, 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. 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. In September 2016, the CPUC adopted 

improvements and refinements to its gas and electric 

safety citation programs. Specifically, the final decision 

refines the criteria for the SED to use in determining 

whether to issue a citation and the amount of penalty, 

sets an administrative limit of $8 million per citation 

issued, makes self-reporting voluntary in both gas and 

electric programs, adopts detailed criteria for the utilities 

to use to voluntarily self-report a potential violation, and 

refines other issues in the programs. The decision also 

merges the rules applicable to its gas and electric safety 

citation programs into a single set of rules that replaces 

the previous safety citation programs. 

The California State Legislature also directs the CPUC 

to implement state laws and policies, such as the laws 

relating to increasing renewable energy resources, the 

development and widespread deployment of distributed 

generation and self-generation resources, the reduction 

of GHG emissions, the establishment of energy storage 

procurement targets, and the development of a statewide electric vehicle charging infrastructure. The CPUC 

is responsible for approving funding and administration 

of state-mandated public purpose programs such as 

energy efficiency and other customer programs. The 

CPUC also conducts audits and reviews of the Utility’s 

accounting, performance, and compliance with regulatory 

guidelines.

The CPUC has imposed various conditions that govern the 

relationship between the Utility and PG&E Corporation and 

other affiliates, including financial conditions that require 

PG&E Corporation’s Board of Directors to give first priority 

to the capital requirements of the Utility, as determined to 

be necessary and prudent to meet the Utility’s obligation 

to serve or to operate the Utility in a prudent and efficient 

manner. (For more information, see “Liquidity and Financial 

Resources” in MD&A and Item 1A. Risk Factors.) 

The Federal Energy Regulatory Commission and the 

California Independent System Operator

The FERC has jurisdiction over the Utility’s 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 MD&A 

and Item 1A. Risk Factors below.)

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ITEM 1.  BUSINESS

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.

Ratemaking Mechanisms

The Utility’s rates for electricity and natural gas utility 

services are set at levels that are intended to allow the 

Utility to recover its costs of providing service including a 

return on invested capital (“cost-of-service ratemaking”). 

Before setting rates, the CPUC and the FERC conduct 

proceedings to determine the annual amount that the 

Utility will be authorized to collect from its customers 

(“revenue requirements”). The Utility’s revenue requirements 

consist primarily of a base amount set to enable the 

Utility to recover its reasonable operating expenses 

(e.g., maintenance, administration and general expenses) 

and capital costs (e.g., depreciation, tax, and financing 

expenses). In addition, the CPUC authorizes the Utility 

to collect revenues to recover costs that the Utility is 

allowed to “pass-through” to customers (referred to as 

“Utility Revenues and Costs that did not Impact Earnings” 

in MD&A), including its costs to procure electricity, natural 

gas and nuclear fuel, to administer public purpose and 

customer programs, and to decommission its nuclear 

facilities.

The Utility’s rate of return on electric transmission assets is 

determined in the FERC TO proceedings. The authorized 

rate of return on all other 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, ensure that the Utility 

will fully collect its authorized base revenue requirements. 

The Utility’s earnings primarily depend on its ability to 

manage its base operating and capital costs (referred to 

as “Utility Revenues and Costs that Impacted Earnings” in 

MD&A) within its authorized base revenue requirements.

Both electric and gas rates vary depending on seasons 

mostly due to the influence of weather. Electricity rates 

increase during the summer months (May – October) 

because of higher demand, driven by air conditioning 

loads, while gas service rates generally increase during 

the winter months (November – March) to account for 

the gas peak due to heating. 

During 2016, 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 “Legislative and Regulatory Initiatives” in 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 – 

2014 – 2015 Energy Efficiency Incentive Awards” in MD&A.)

Base Revenues

General Rate Cases 

The GRC is the primary proceeding in which the CPUC 

determines the amount of base revenue requirements 

that the Utility is authorized to collect from customers 

to recover the Utility’s anticipated costs, including return 

on rate base, related to its electricity distribution, natural 

gas distribution, and Utility owned electricity 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 

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PART I

ITEM 1.  BUSINESS

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. (For more 

information about the Utility’s current GRC proceeding, see 

“Regulatory Matters −2017 General Rate Case” in MD&A.)

Natural Gas Transmission and Storage Rate Cases 

The CPUC determines the Utility’s authorized revenue 

requirements and rates for its natural gas transmission and 

storage services in the GT&S rate case. The CPUC generally 

conducts a GT&S rate case every three or four years.  Similar to 

the GRC proceeding, the CPUC approves the annual revenue 

requirements for the first year (or “test year”) of the GT&S 

period and typically determines annual increases in revenue 

requirements for attrition years of the GT&S 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, and union interests. 

(For more information, see “Regulatory Matters − 2015 

Gas Transmission and Storage Rate Case” in 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 2017, 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%. 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. On February 25, 2016, the CPUC issued a 

decision granting a petition for modification filed by the 

Utility and the other California IOUs to clarify that the 

CPUC’s previously adopted cost of capital adjustment 

mechanism would not be triggered for 2017. 

On February 6, 2017, the Utility and other California IOUs 

entered into a MOU with the CPUC, ORA, and TURN to 

extend the next cost of capital application filing deadline 

two years to April 22, 2019 for the year 2020. To implement 

the MOU, on February 7, 2016, the IOUs, ORA, and TURN 

filed with the CPUC a petition for modification of prior 

CPUC decisions addressing cost of capital. If the petition 

for modification is approved as submitted it would reduce 

the Utility’s ROE from 10.40% to 10.25% and reset the 

Utility’s authorized cost of long-term debt and preferred 

stock beginning January 1, 2018. The Utility’s current capital 

structure of 52% common equity, 47% long-term debt, 

and 1% preferred equity would remain unchanged. The 

Utility’s cost of capital adjustment mechanism would not 

operate in 2017 but could operate in 2018 to change the 

cost of capital for 2019. If the mechanism is activated for 

2019, the Utility’s cost of capital, including its new ROE of 

10.25%, will be adjusted according to the existing terms 

of the mechanism. Concurrently with the petition for 

modification, the Utility and other California IOUs also sent 

a letter to the executive director of the CPUC requesting 

that the existing April 2017 filing due date for the 2018 

cost of capital be deferred while the CPUC is considering 

the petition for modification. On February 13, 2017, the 

executive director of the CPUC granted the request. As 

extended, the Utility and the other California IOUs would 

file their next cost of capital applications 60 days after 

the effective date of the CPUC decision on the petition 

for modification, or April 20, 2017, whichever is later, if 

the CPUC does not grant the petition for modification.

The Utility expects that the CPUC may issue a decision in 

the first half of 2017. (For more information, see “Regulatory 

Matters – CPUC Cost of Capital” in 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 generally files a TO rate 

case every year. The FERC typically authorizes the Utility 

to charge new rates based on the requested revenue 

requirement, subject to refund, before the FERC has 

issued a final decision. These FERC-approved rates are 

included: 1) by the CPUC in the Utility’s retail electric 

rates and are collected from retail electric customers; 

and 2) by the CAISO in its Transmission Access Charges 

to wholesale customers. (For more information, see 

“Regulatory Matters – FERC Transmission Owner Rate 

Cases” in MD&A.) The Utility also recovers a portion of its 

revenue requirements for its wholesale electric transmission 

costs through charges collected under specific contracts 

with wholesale transmission customers that the Utility 

entered into before the CAISO began its operations. 

These wholesale customers are charged individualized 

rates based on the terms of their contracts.

Revenues to Recover Energy Procurement and 

Other Pass-Through Costs 

Electricity Procurement Costs

California investor-owned electric utilities are responsible 

for procuring electrical capacity required to meet bundled 

customer demand, plus applicable reserve margins, that 

are not satisfied from their own generation facilities and 

existing electricity contracts. The utilities are responsible 

for scheduling and bidding electric generation resources, 

including 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. The Utility’s most recent 

bundled customer procurement plan was approved in 

October 2015, and will remain in effect until the plan is 

superseded by a subsequent CPUC-approved plan. 

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California law allows electric utilities to recover the costs 

incurred in compliance with their CPUC-approved bundled 

customer procurement plans without further after-thefact reasonableness review by the CPUC. The CPUC may 

disallow costs associated with electricity purchases if the 

costs were not incurred in compliance with the CPUCapproved plan or if the CPUC determines that the utility 

failed to follow the principles of least-cost dispatch. 

Additionally, the cost of replacement power procured 

due to unplanned outages at Utility owned generation 

facilities may be disallowed.

The Utility recovers its electricity procurement costs 

annually primarily through the energy resource recovery 

account. (See Note 3 of the Notes to the Consolidated 

Financial Statements in Item 8.) Each year, the CPUC 

reviews the Utility’s forecasted procurement costs related 

to power purchase agreements, derivative instruments, 

GHG emissions costs, and generation fuel expense, and 

approves a forecasted revenue requirement. The CPUC may 

adjust the Utility’s retail electricity rates more frequently 

if the forecasted aggregate over-collections or undercollections in the energy resource recovery account 

exceed 5% of its prior year electricity procurement and 

utility-owned generation revenues. The CPUC performs 

an annual compliance review of the transactions recorded 

in the energy resource recovery account.

The CPUC has approved various power purchase 

agreements that the Utility has entered into with third 

parties in accordance with the Utility’s CPUC-approved 

procurement plan, to meet mandatory renewable 

energy targets, and to comply with resource adequacy 

requirements. (For 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 electricity 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 FERCapproved 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 

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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 August 11, 2016, the Utility submitted an application to 

the CPUC to retire Diablo Canyon at the expiration of its 

current operating licenses in 2024 and 2025. (For more 

information, see “Legislative and Regulatory Initiatives” 

in MD&A.)

Electric Utility Operations

The Utility generates electricity and provides electricity 

transmission and distribution services throughout its 

service territory in northern and central California to 

residential, commercial, industrial, and agricultural 

customers. The Utility provides “bundled” services (i.e., 

electricity, transmission and distribution services) to 

most customers in its service territory. Customers also 

can obtain electricity from alternative providers such as 

municipalities or CCAs, as well as from self-generation 

resources, such as rooftop solar installations.

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 addition, in December 2016, the CPUC 

issued a final decision establishing a three-year EV program 

for the Utility to deploy up to 7,500 charging stations. 

(For more information, see “Legislative and Regulatory 

Initiatives” in MD&A.)

Electricity Resources

The Utility is required to maintain generating capacity adequate 

to meet its customers’ demand for electricity (“load”), including 

peak demand and planning and operating reserves, deliverable 

to the locations and at times as may be necessary to provide 

reliable electric service. The Utility is required to dispatch, or 

schedule all of the electricity resources within its portfolio in 

the most cost-effective way.

The following table shows the percentage of the Utility’s 

total deliveries of electricity to customers in 2016 

represented by each major electricity resource, and further 

discussed below.

Total 2016 Actual Electricity Generated and Procured – 68,441 GWh(1):

Percent of Bundled Retail Sales

Owned Generation Facilities

Nuclear 24.2%

Small Hydroelectric 1.3%

Large Hydroelectric 9.8%

Fossil fuel-fired 7.3%

Solar 0.5%

Total 43.1%

Qualifying Facilities

Renewable 2.6%

Non-Renewable 5.1%

Total 7.7%

Irrigation Districts and Water Agencies

Large Hydroelectric 0.5%

Total 0.5%

Other Third-Party Purchase Agreements

Renewable 28.4%

Large Hydroelectric 2.1%

Non-Renewable 4.8%

Total 35.3%

Others, Net(2) 13.4%

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 

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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. 

As indicated below, the Utility’s application and joint 

proposal to retire Diablo Canyon include a voluntary 

increase in the Utility’s target for RPS-eligible resources 

to 55%, effective in 2031 through 2045, as compared to 

the state’s goal of 50% renewables. (For more information, 

see “Legislative and Regulatory Initiatives” in MD&A.)

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 2016, 32.8% 

of the Utility’s energy deliveries were from renewable 

energy sources, exceeding the annual RPS target of 23.3%. 

Approximately 28.4% of the renewable energy delivered to 

the Utility’s customers was purchased from non-QF third 

parties. Additional renewable resources were provided 

by QFs (2.6%), the Utility’s small hydroelectric facilities 

(1.3%), and the Utility’s solar facilities (0.5%). 

The total 2016 renewable deliveries shown above were comprised of the following:

Type GWh Percent of Bundled Retail Sales

Biopower 2,958 4.3%

Geothermal 3,705 5.4%

Small Hydroelectric 1,800 2.6%

Solar 8,598 12.6%

Wind 5,419 7.9%

Total 22,480 32.8%

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 RFOs to help meet its 

interim storage targets. 

The Utility conducted an RFO in 2014. The Utility’s 2014 

energy storage target was 90 MW, some of which the 

Utility met through already existing projects, or projects 

anticipated to result from other CPUC proceedings. As 

a result of the 2014 RFO, 70 MW of transmission and 

distribution contracts have been approved by the CPUC. 

Contracts for 6MW were rejected by the CPUC, including 

a behind-the-meter project. Additionally, contracts for 

13 MW were withdrawn by the Utility. 

The Utility’s 2016 energy storage target is 120 MW. On 

November 30, 2016, the Utility issued its 2016 RFO. The 

Utility must submit all executed contracts from the 2016 

RFO to the CPUC for approval by December 1, 2017. The 

Utility expects to increase the amount of storage it is 

attempting to procure in its 2016 RFO by the shortfall 

from the 2014 target. 

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Owned Generation Facilities

At December 31, 2016, the Utility owned the following generation facilities, all located in California, listed by energy 

source and further described below:

Generation Type County Location Number of Units Net Operating Capacity (MW)

Nuclear(1): 

Diablo Canyon San Luis Obispo 2 2,240

Hydroelectric(2): 

Conventional 16 counties in northern and 

central California

104 2,684

Helms pumped storage Fresno 3 1,212

Fossil fuel-fired: 

Colusa Generating Station Colusa 1 657

Gateway Generating 

Station 

Contra Costa 1 580

Humboldt Bay Generating 

Station

Humboldt 10 163

Fuel Cell:

CSU East Bay Fuel Cell Alameda 1 1

SF State Fuel Cell San Francisco 2 2

Photovoltaic(3): Various 13 152

Total 137 7,691

(1) The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. The NRC operating 

licenses expire in 2024 and 2025, respectively. (See “Diablo Canyon Nuclear Power Plant” in. MD&A and Item 1A. Risk 

Factors.) 

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

licensed by the FERC (except for two small powerhouses not subject to FERC licensing requirements), with license terms 

between 30 and 50 years.

(3) The Utility’s large photovoltaic facilities are Five Points solar station (15 MW), Westside solar station (15 MW), Stroud solar 

station (20 MW), Huron solar station (20 MW), Cantua solar station (20 MW), Giffen solar station (10 MW), Gates solar 

station (20 MW), West Gates solar station (10 MW) and Guernsey solar station (20 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 CPUCapproved 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, 2016, the Utility owned approximately 

18,400 circuit miles of interconnected transmission lines 

operating at voltages ranging from 60 kV to 500 kV. The 

Utility also operated 92 electric transmission substations 

with a capacity of approximately 64,600 MVA. The Utility’s 

electric transmission system is interconnected with electric 

power systems in the Western Electricity Coordinating 

Council, which includes many western states, Alberta and 

British Columbia, and parts of Mexico.

In 2013, the Utility, MidAmerican Transmission, LLC, 

and Citizens Energy Corporation were selected by the 

CAISO to jointly develop a new 230-kV transmission line 

to address the growing power demand in the Fresno, 

Madera and Kings counties area. The CAISO has stated 

that the 2022 in-service date for the 70-mile line has 

been postponed, and 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 conducted a review of a 

number of local area low voltage transmission projects 

in the Utility’s service territory that were predominantly 

load forecast driven. As a result of the review, 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.

On March 29, 2016, the Utility entered into an agreement 

with TransCanyon, LLC, a joint venture between subsidiaries 

of Berkshire Hathaway Energy and Pinnacle West Capital 

Corporation, to jointly pursue competitive transmission 

opportunities solicited by the CAISO. The Utility and 

TransCanyon intend to jointly engage in the development 

of future transmission infrastructure and compete to 

develop, build, own and operate transmission projects 

approved by the CAISO.

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Throughout 2016, the Utility upgraded several critical 

substations and re-conductored a number of transmission 

lines to improve maintenance and system flexibility, reliability 

and safety. The Utility expects to undertake various additional 

transmission projects over the next several years to upgrade 

and expand the capacity of its transmission system to 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 electricity distribution network consists 

of approximately 142,000 circuit miles of distribution 

lines (of which approximately 20% are underground 

and approximately 80% are overhead), 59 transmission 

switching substations, and 606 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 endusers. In some cases, the Utility sells electricity from its 

distribution facilities to entities, such as municipal and 

other utilities, that resell the electricity. In 2016 the Utility 

commenced operations in a new electric distribution 

control center facility in Concord, California; along with 

the existing distribution control centers in Rocklin and 

Fresno, California, these control centers form a key part of 

the Utility’s efforts to create a smarter, more resilient grid.

In 2016, the Utility continued to deploy its Fault Location, 

Isolation, and Service Restoration circuit technology which 

involves the rapid operation of smart switches to reduce 

the duration of customer outages. Another 89 circuits were 

outfitted with this equipment, bringing the total deployment 

to 789 of the Utility’s 3,200 distribution circuits. The Utility 

plans to continue performing work to improve the reliability 

and safety of its electricity distribution operations in 2017.

Electricity Operating Statistics

The following table shows certain of the Utility’s operating 

statistics from 2014 to 2016 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 2016, 

2015 and 2014.

2016 2015 2014

Customers (average for the year) 5,349,691 5,311,178 5,276,025

Deliveries (in GWh)(1) 83,017 85,860 86,303

Revenues (in millions): 

Residential $ 5,409 $ 5,032 $ 4,784

Commercial 5,396 5,278 5,141

Industrial 1,525 1,555 1,543

Agricultural 1,226 1,233 1,172

Public street and highway lighting 80 83 79

Other(2) (68) (84) (172)

Subtotal 13,568 13,097 12,547

Regulatory balancing accounts(3) 297 560 1,109

Total operating revenues $ 13,865 $ 13,657 $ 13,656

Selected Statistics: 

Average annual residential usage (kWh) 6,115 6,294 6,458

Average billed revenues per kWh: 

Residential $ 0.1887 $ 0.1719 $ 0.1603

Commercial 0.1716 0.1640 0.1585

Industrial 0.0990 0.0973 0.0998

Agricultural 0.1814 0.1610 0.1516

Net plant investment per customer $ 7,195 $ 6,660 $ 6,339

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

(2) This activity is primarily related to a remittance of revenue to the Department of Water Resources (“DWR”) (the Utility acts 

as a billing and collection agent on behalf of the DWR), partially offset by other miscellaneous revenue items.

(3) These amounts represent revenues authorized to be billed. 

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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 90% 

of core customers, representing nearly 78% of the annual 

core market demand, receive bundled natural gas service 

from the Utility.

The Utility does not provide procurement service to noncore customers, who must purchase their gas supplies 

from third-party suppliers. The Utility offers backbone 

gas transmission, gas delivery (local transmission and 

distribution), and gas storage services as separate and 

distinct services to its non-core customers. Access to the 

Utility’s backbone gas transmission system is available 

for all natural gas marketers and shippers, as well as noncore 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 

fluctuated generally based on market conditions. During 

2016, the Utility purchased approximately 307,100 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 2016.

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, 2016, the Utility’s natural gas system consisted 

of approximately 42,800 miles of distribution pipelines, 

over 6,700 miles of backbone and local transmission 

pipelines, and various storage facilities. The Utility owns 

and operates eight natural gas compressor stations on 

its backbone transmission system and one small station 

on its local transmission system that are used to move 

gas through the Utility’s pipelines. The Utility’s backbone 

transmission system, composed primarily of Lines 300, 

400, and 401, is used to transport gas from the Utility’s 

interconnection with interstate pipelines, other local 

distribution companies, and California gas fields to the 

Utility’s local transmission and distribution systems.

The Utility has firm transportation agreements for delivery of 

natural gas from western Canada to the United States-Canada 

border with TransCanada NOVA Gas Transmission, Ltd. and 

TransCanada Foothills Pipe Lines Ltd., B.C. System. These 

companies’ pipeline systems connect at the border to the 

pipeline system owned by Gas Transmission Northwest, 

LLC, which provides natural gas transportation services 

to a point of interconnection with the Utility’s natural gas 

transportation system on the Oregon-California border 

near Malin, Oregon. The Utility also has firm transportation 

agreements with Ruby Pipeline, LLC to transport 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.

As of December 31, 2016 the Utility had installed 268 

automatic and remote control shut-off valves on its gas 

transmission system, as specified in the eleventh of twelve 

safety recommendations made by the NTSB following 

its investigation of the San Bruno accident. The NTSB 

closed that recommendation in 2015. The final safety 

recommendation, considered open and acceptable by the 

NTSB, involves ensuring that all high consequence pipeline 

mileage in the Utility’s gas transmission system has been 

hydrostatically tested. As of December 31, 2016, the Utility 

has hydrostatically tested about 840 miles and completed 

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the majority of this safety recommendation. The Utility 

currently plans to complete the NTSB recommendation 

by 2022 for the remaining approximately 28 aggregate 

pipeline miles (involving hundreds of primarily short pipeline 

segments that include tie-in pieces, fittings or smaller 

diameter off-takes from the larger transmission pipelines).

In addition, in 2016, the Utility inspected 260 miles of 

transmission pipeline using in-line inspection tools and 

upgraded an additional 107 miles of transmission pipeline to 

allow for the use in-line inspection tools, replaced 127 miles 

of distribution main, and completed the installation of over 

25,000 line makers to more easily identify the locations 

of gas pipelines.

Natural Gas Operating Statistics 

The following table shows the Utility’s operating statistics from 2014 through 2016 (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 2016, 2015 and 2014.

2016 2015 2014

Customers (average for the year) 4,442,379 4,415,332 4,394,283

Gas purchased (MMcf) 208,260 209,194 202,215

Average price of natural gas purchased $ 1.83 $ 2.11 $ 4.09

Bundled gas sales (MMcf): 

Residential 149,483 144,885 143,514

Commercial 46,507 43,888 42,080

Total Bundled Gas Sales 195,990 188,773 185,594

Revenues (in millions): 

Bundled gas sales: 

Residential $ 1,968 $ 1,816 $ 1,683

Commercial 439 403 419

Other 149 125 51

Bundled gas revenues 2,556 2,344 2,153

Transportation service only revenue 800 649 662

Subtotal 3,356 2,993 2,815

Regulatory balancing accounts 446 183 617

Total operating revenues $ 3,802 $ 3,176 $ 3,432

Selected Statistics: 

Average annual residential usage (Mcf) 36 35 34

Average billed bundled gas sales revenues per Mcf: 

Residential $ 13.10 $ 12.53 $ 11.72

Commercial 9.45 9.18 9.96

Net plant investment per customer $ 2,808 $ 2,573 $ 2,468

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 which do not affirmatively elect to continue 

to receive electricity from a utility.

The Utility continues to provide transmission, distribution, 

metering, and billing services to direct access customers, 

although these customers can choose to obtain metering 

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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 generationrelated costs that the Utility incurred on behalf of direct 

access and CCA customers while they were the Utility’s 

customers. The Utility remains the electricity provider of 

last resort for these customers.

In some circumstances, governmental entities such as cities 

and irrigation districts, which have authority under the state 

constitution or state statute to provide retail electric service, 

may seek to acquire the Utility’s distribution facilities, 

generally through eminent domain. These same entities 

may, and sometimes do, construct duplicate distribution 

facilities to serve existing or new Utility 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, 

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.

The Utility also competes for the opportunity to develop 

and construct certain types of electric transmission facilities 

within, or interconnected to, its service territory through 

a competitive bidding process managed by the CAISO.

Competition in the Natural Gas Industry

The Utility 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 thirdparty 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 Department of Toxic Substances Control, 

several California regional water quality control boards, 

and various other federal, state, and local agencies. The 

Utility has incurred significant environmental remediation 

liabilities associated with former manufactured gas plant 

sites, power plant sites, gas gathering sites, sites where 

natural gas compressor stations are located, and sites 

used by the Utility for the storage, recycling, or disposal 

of potentially hazardous substances. Groundwater at 

the Utility’s Hinkley and Topock natural gas compressor 

stations contains hexavalent chromium as a result of the 

Utility’s past operating practices. The Utility is responsible 

for remediating this groundwater contamination and 

for abating the effects of the contamination on the 

environment.

For more information about environmental remediation 

liabilities, see Note 13 of the Notes to the Consolidated 

Financial Statements in Item 8.

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ITEM 1.  BUSINESS

Air Quality and Climate Change 

The Utility’s electricity generation plants, natural gas 

pipeline operations, fleet, and fuel storage tanks are 

subject to numerous air pollution control laws, including 

the federal Clean Air Act, as well as state and local statutes. 

These laws and regulations cover, among other pollutants, 

those contributing to the formation of ground-level ozone, 

CO2, sulfur dioxide (SO2), mono-nitrogen oxide (NOx), 

particulate matter, and other GHG emissions.

In December 2009, the EPA concluded that GHG emissions 

contribute to climate change and issued a finding that 

GHG emissions cause or contribute to air pollution that 

endangers public health and welfare. In May 2014, the 

U.S. Global Change Research Program (a confederation 

of the research arms of thirteen federal departments and 

agencies) released its third National Climate Assessment, 

which stated that the global climate is changing and that 

impacts related to climate change are already evident in 

many sectors and are expected to become increasingly 

disruptive across the nation throughout this century and 

beyond.

Federal Regulation

At the federal level, the EPA is charged with implementation 

and enforcement of the Clean Air Act. Although there 

have been several legislative attempts to address climate 

change through imposition of nationwide regulatory limits 

on GHG emissions, comprehensive federal legislation has 

not yet been enacted. In the absence of federal legislative 

action, the EPA has used its existing authority under the 

Clean Air Act to address GHG emissions.

In August 2015, the EPA published final regulations 

under section 111(b) of the Clean Air Act to control CO2

emissions from new fossil fuel-fired power plants. While 

these regulations do not affect the Utility’s existing power 

plants, the regulations impose emission limitations on 

fossil fuel-fired power plants constructed after January 8, 

2014 and will affect the design, construction, operation 

and cost of such power plants. 

In August 2015, the EPA also published final regulations 

under section 111(d) of the Clean Air Act to control CO2

emissions from existing fossil fuel-fired power plants. 

These regulations are designed to reduce power plant 

CO2 emissions on a national basis by as much as 32% by 

2030, compared with 2005 levels. States were required 

to submit final plans to comply with these regulations 

by September 2016, but were permitted to request an 

extension to file such plans until September 2018. It is 

uncertain whether and how these federal regulations 

will ultimately impact California, since existing state 

regulation currently requires, among other things, the 

gradual reduction of state-wide GHG emissions to 40% 

below 1990 levels by 2030. Following publication of the 

EPA’s regulations, in October 2015 West Virginia and several 

other states and parties challenged the EPA’s section 111(d) 

regulations in the United States Court of Appeals for the 

District of Columbia Circuit and petitioned the Court to 

stay the regulations pending review of the appeal on the 

merits. The D.C. Circuit denied the request for stay but in 

February 2016, the United States Supreme Court granted 

a stay of the section 111(d) regulations pending review 

of the appeal by the D.C. Circuit. The Supreme Court’s 

decision may affect the nature, extent and timing of 

implementation of these regulations. As described below, 

the Utility expects all costs and revenues associated with 

the state-wide, comprehensive cap-and-trade program 

to be passed through to customers.

With the change in federal administration from President 

Barack Obama to President Donald Trump, there is 

significant uncertainty with regard to what further actions 

may occur regarding climate change at the federal level. 

The new administration has indicated that it intends to 

revoke the Clean Power Plan regulations and possibly 

withdraw from international efforts to combat climate 

change. 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, pending further review. It is 

assumed that the new administration also will take action 

to suspend all climate related regulatory and funding 

activities. In light of the potential 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 statewide GHG emissions to 1990 levels by 2020. The CARB 

has approved various regulations to achieve the 2020 

target, including GHG emissions reporting and a statewide, 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-andtrade program’s first compliance period, which began 

on January 1, 2013, applied to the electricity generation 

and large industrial sectors. The next compliance period, 

which began on January 1, 2015, expanded to include the 

natural gas and transportation sectors, effectively covering 

all the economy’s major sectors until 2020. The Utility’s 

compliance obligation as a natural gas supplier applies 

to the GHG emissions attributable to the combustion 

of natural gas delivered to the Utility’s customers other 

than natural gas delivery customers that are separately 

regulated as covered entities and have their own compliance 

obligation. During each year of the program, the CARB 

issues emission allowances (i.e., the rights to emit GHGs) 

equal to the amount of GHG emissions allowed for that 

year. Emitters can obtain allowances from the CARB at 

quarterly auctions or from third parties or exchanges. 

Emitters may also satisfy a portion of their compliance 

obligation through the purchase of offset credits; e.g., 

credits for GHG reductions achieved by third parties (such 

as landowners, livestock owners, and farmers) that occur 

outside of the emitters’ facilities through CARB-qualified 

offset projects such as reforestation or biomass projects. 

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Additionally, Senate Bill 32 (2016) requires that CARB 

ensure a 40% reduction in greenhouse gases by 2030 

compared to 1990 levels. CARB is currently considering 

regulatory amendments to the cap-and-trade program 

to extend the program’s authority 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 Mitigation and Adaptation Strategies

During 2016, the Utility continued its programs to develop 

strategies to mitigate the impact of the Utility’s operations 

(including customer energy usage) on the environment 

and to plan for the actions that it will need to take to 

adapt to the likely impacts of climate change on the 

Utility’s future operations, including forming an officerlevel coordinating committee to govern and oversee the 

Utility’s activities. The Utility regularly reviews the most 

relevant scientific literature on climate change such as 

sea level rise, temperature changes, rainfall and runoff 

patterns, and wildfire risk, to help the Utility identify and 

evaluate climate change-related risks and develop the 

necessary adaptation strategies. The Utility maintains 

emergency response plans and procedures to address a 

range of near-term risks, including extreme storms, heat 

waves and wildfires and uses its risk-assessment process to 

prioritize infrastructure investments for longer-term risks 

associated with climate change. The Utility also engages 

with leaders from business, government, academia, and 

non-profit organizations to share information and plan 

for the future.

With respect to electric operations, climate scientists 

project that, sometime in the next several decades, climate 

change will lead to increased electricity demand due to 

more extreme, persistent, and frequent hot weather. The 

Utility believes its strategies to reduce GHG emissions 

through energy efficiency and demand response programs, 

infrastructure improvements, and the use of renewable 

energy and energy storage are effective strategies for 

adapting to the expected 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. The Utility’s 

vegetation management activities also reduce the risk 

of wildfire impacts on electric and gas facilities. Over the 

long-term, the Utility also faces the risk of higher flooding 

and inundation potential at coastal and low elevation 

facilities due to sea level rise combined with high tides, 

storm runoff and storm surges.

Notwithstanding the current high snowpack, 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 safetyrelated 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 

2015 totaled more than 54 million metric tonnes of CO2

equivalent, two-thirds of which came from customer 

natural gas use. The following table shows the 2015 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 equivalent)

Fossil Fuel-Fired Plants(1) 2,875,176

Natural Gas Compressor Stations and Storage Facilities(2) 362,472

Distribution Fugitive Natural Gas Emissions 676,458

Customer Natural Gas Use(3) 43,022,557

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

(2) Including, but not limited to, compressor stations and storage facilities emitting more than 25,000 metric tonnes of CO2

equivalent annually.

(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, with the 

exception of gas delivered to other natural gas local distribution companies. This figure does not represent the Utility’s 

compliance obligation under AB 32, which will be equivalent to the above reported value less the fuel that is delivered to 

covered entities, as calculated by the CARB.

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The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered 

to customers in 2015 as compared to the national average for electric utilities:

Amount (pounds of CO2 per MWh)

U.S. Average(1) 1,143

Pacific Gas and Electric Company(2) 405

(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 40% of the Utility’s delivered electricity in 2015. PG&E Corporation and the Utility also publish 

air emissions data in their annual Corporate Responsibility and Sustainability Report.

2015 2014

Total NOx Emissions (tons) 160 141

NOx Emissions Rate (pounds/MWh) 0.01 0.01

Total SO2 Emissions (tons) 17 14

SO2 Emissions Rate (pounds/MWh) 0.0011 0.0010

Water Quality

On May 19, 2014, the EPA issued final regulations to 

implement the requirements of the federal Clean Water 

Act that require cooling water intake structures at electric 

power plants, such as the nuclear generation facilities at 

Diablo Canyon, to reflect the best technology available to 

minimize adverse environmental impacts. Various industry 

and environmental groups have challenged the federal 

regulations in proceedings pending in the U.S. Court of 

Appeals for the Fourth Circuit. California’s once-through 

cooling policy discussed below is considered to be at least 

as stringent as the new federal regulations. Therefore, 

California’s implementation process for the state policy 

will likely continue without any significant change.

At the state level, in 2010, the California Water Board 

adopted a policy on once-through cooling that generally 

requires the installation of cooling towers or other 

significant measures to reduce the impact on marine life 

from existing power generation facilities in California by 

at least 85%. 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. The Utility’s 

Diablo Canyon operations must be in compliance with 

the California Water Board’s policy by December 31, 2024.

On June 20, 2016, the Utility entered into a joint proposal 

with certain parties to retire Diablo Canyon at the expiration 

of its current operating licenses in 2024 and 2025, 

and replace it with a GHG-free portfolio of energy 

efficiency, renewables and energy storage. As a result of 

the planned retirement, the California Water Board will no 

longer need to address alternative compliance measures 

for Diablo Canyon. Beginning in 2017, as required under 

the policy, the Utility will pay an annual interim mitigation 

fee until operations cease in 2024 and 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 Water 

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 

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.

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ITEM 1A.  RISK FACTORS

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 2016, the 

Utility has been awarded an additional $99 million through 

these annual submissions, including $28 million for costs 

incurred between June 1, 2014 and May 31, 2015. The 

claim for the period June 1, 2015 through May 31, 2016 is 

currently under review by the DOE. These proceeds are 

being refunded to customers through rates. The settlement 

agreement, as amended, does not address costs incurred 

for spent fuel storage beyond 2016; an extension of the 

agreement for costs through 2019 is pending DOJ approval. 

Costs beyond 2016 could be subject to future litigation. 

Considerable uncertainty continues to exist regarding 

when and whether the DOE will meet its contractual 

obligation to the Utility and other nuclear power plant 

owners to dispose of spent fuel.

ITEM 1A. Risk Factors

PG&E Corporation’s and the Utility’s financial results 

can be affected by many factors, including estimates 

and assumptions used in the critical accounting policies 

described in MD&A, that can cause their actual financial 

results to differ materially from historical results or from 

anticipated future financial results. The following discussion 

of key risk factors should be considered in evaluating an 

investment in PG&E Corporation and the Utility and should 

be read in conjunction with MD&A and the consolidated 

financial statements and related notes in Part II, Item 8, 

“Financial Statements and Supplementary Data” of this 

Form 10-K. Any of these factors, in whole or in part, could 

materially affect PG&E Corporation’s and the Utility’s 

business, results of operations, financial condition, and 

stock price. 

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

PG&E Corporation’s and the Utility’s financial 

condition, results of operations, 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 a press release also issued 

on April 28, 2016, Cal Fire indicated that it will seek to 

recover firefighting costs in excess of $90 million from 

the Utility.

On May 23, 2016, individual plaintiffs filed a master 

complaint against the Utility and its two vegetation 

management contractors in the Superior Court of California 

for Sacramento County. Subrogation insurers also filed a 

separate master complaint on the same date. The California 

Judicial Council had previously authorized the coordination 

of all cases in Sacramento County. As of December 31, 2016, 

complaints have been filed against the Utility and its two 

vegetation management contractors in the Superior Court 

of California in the Counties of Calaveras, San Francisco, 

Sacramento, and Amador involving approximately 

1,950 individual plaintiffs representing approximately 

950 households and their insurance companies. These 

complaints are part of or are in the process of being 

added to the two master complaints. Plaintiffs seek to 

recover damages and other costs, principally based on 

inverse condemnation and negligence theories of liability. 

The number of individual complaints and plaintiffs may 

increase in the future. 

In connection with this matter, the Utility may be liable for 

property damages, interest, and attorneys’ fees without 

having been found negligent, through the theory 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. 

The Utility believes that it is probable that it will incur 

a loss of at least $750 million for all potential damages 

described above. The Utility has liability insurance from 

various insurers, which provides coverage for third-party 

liability attributable to the Butte fire in an aggregate amount 

of approximately $900 million. Such insurance coverage 

is subject to the terms and limitations of the applicable 

policies and may not be sufficient to cover the Utility’s 

ultimate liability. 

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ITEM 1A.  RISK FACTORS

The process for estimating costs associated with claims 

relating to the Butte fire requires management to exercise 

significant judgment based on a number of assumptions 

and subjective factors. As more information becomes 

known, including additional discovery from the plaintiffs 

and results from the ongoing mediation and settlement 

process, management estimates and assumptions regarding 

the financial impact of the Butte fire may change. 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 

and the results of operations during the period such 

change occurred. 

If the Utility records losses in connection with claims relating 

to the Butte fire that materially exceed the amount the 

Utility accrued for these liabilities, PG&E Corporation’s and 

the Utility’s financial condition, results of operations, or 

cash flows could be materially affected in the reporting 

periods during which additional charges are recorded, 

depending on whether the Utility is able to record or 

collect insurance recoveries in amounts sufficient to 

offset such additional accruals. (For more information, 

see “Enforcement and Litigation Matters” in Item 7. MD&A 

and in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.)

PG&E Corporation’s and the Utility’s future financial 

results may be materially affected by the outcomes 

of the CPUC’s investigative enforcement proceedings 

against the Utility, other known enforcement matters, 

and other ongoing state and federal investigations 

and requests for information. The Utility also could 

incur material costs and fines in connection with future 

investigations, citations, audits, or enforcement actions. 

The Utility could incur material charges, including fines and 

other penalties, in connection with a potential settlement, 

or litigated outcome of the CPUC’s investigation of the 

Utility’s compliance with the CPUC’s rules regarding 

ex parte communications. While on October 14, 2016, 

the Cities of San Bruno and San Carlos, ORA, the SED, 

TURN, and the Utility submitted a status report to the 

CPUC which proposed an update to the framework for 

resolving the proceeding and included a total of 164 

communications in the scope of the proceeding, the 

Utility expects that the other parties may argue that the 

number of violations exceeds the 164 communications 

referenced in the status report either because a single 

communication may have violated more than one rule 

or because they believe some of the material provided 

during discovery constitutes impermissible ex parte 

communications. The Utility expects to contest many of 

these assertions. If the matter does not settle, the CPUC 

will determine which communications included within the 

scope of the proceeding were in violation of its rules. The 

CPUC will also determine whether to impose penalties or 

other remedies, as a result of a potential settlement or 

otherwise. The CPUC can impose fines up to $50,000 for 

each violation, and up to $50,000 per day if the CPUC 

determines that the violation was continuing. The CPUC 

has wide discretion to determine the amount of penalties 

based on the totality of the circumstances, including such 

factors as how many days each violation continued; 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 

is also required to consider the appropriateness of the 

amount of the penalty to the size of the entity charged. 

The CPUC has historically 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 

the discussion under the heading “Regulatory Matters” 

in MD&A.)

The Utility also is a target of a number of investigations 

and government requests for information. 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. In addition, in 

October 2016, the Utility received a grand jury subpoena 

and letter from the U.S. Attorney for the Northern District 

of California advising that the Utility is a target of a federal 

investigation regarding possible criminal violations of the 

Migratory Bird Treaty Act and conspiracy to violate the 

act. The Utility was also contacted by certain other federal 

agencies with requests for information. While the Utility 

believes that these requests for information are routine, 

their outcome is uncertain. The Utility also is unable to 

predict the outcome of pending investigations, including 

whether any charges will be brought against the Utility.

If these investigations or requests for information result in 

enforcement action against the Utility, the Utility could incur 

additional fines or penalties or suffer negative consequences 

described above in the immediately preceding risk factor. In 

addition, a negative outcome in any of these investigations 

or future enforcement actions may negatively affect the 

outcome of future ratemaking and regulatory proceedings; 

for example, by enabling parties to challenge the Utility’s 

request to recover costs that the parties allege are somehow 

related to the Utility’s violations. 

The Utility may incur fines and penalties in connection with 

the Utility’s efforts to identify and remove encroachments 

from transmission pipeline rights of way and the Penalty 

Decision. The Penalty Decision requires the SED to review 

the Utility’s gas transmission operations (including the 

Utility’s compliance with the remedies ordered by the 

Penalty Decision) and to perform annual audits of the 

Utility’s record-keeping practices for a minimum of 

ten years. The SED could impose fines on the Utility 

or require the Utility to incur unrecoverable costs, or 

both, based on the outcome of these future audits. In 

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addition, although PG&E Corporation and the Utility do 

not currently face the possibility of fines or penalties in 

the first phase of the CPUC’s pending investigation into 

the Utility’s safety culture since it has been categorized 

as rate setting, it is uncertain how a next phase, if any, 

would be categorized. (See the discussion under the 

heading “Regulatory Matters” in MD&A.)

The Utility could be subject to additional regulatory or 

governmental enforcement action in the future with 

respect to compliance with federal, state or local laws, 

regulations or orders that could result in additional fines, 

penalties or customer refunds, including those regarding 

renewable energy and resource adequacy requirements; 

customer billing; customer service; affiliate transactions; 

vegetation management; design, construction, operating 

and maintenance practices; safety and inspection practices; 

compliance with CPUC general orders or other applicable 

CPUC decisions or regulations; federal electric reliability 

standards; and environmental compliance. CPUC staff could 

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 results. 

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.

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 Utility has decided not to 

appeal the convictions. 

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 is 

required to retain a third-party monitor. The goal of the 

monitorship will be to prevent the criminal conduct with 

respect to gas pipeline transmission safety that gave rise 

to the conviction. To that end, the goal of the monitor 

will be to help ensure that the Utility takes reasonable 

and appropriate steps to maintain the safety of the gas 

transmission pipeline system, performs appropriate integrity 

management assessments on its gas transmission pipelines, 

and maintains an effective ethics and compliance program 

and safety related incentive program.

After an initial assessment is conducted and an initial 

report is prepared by the monitor, the monitor will prepare 

reports on a semi-annual basis setting forth the monitor’s 

continued assessment and making recommendations 

consistent with the goals and scope of the monitorship. 

The Utility expects that the monitor will be retained before 

the end of the second quarter of 2017.

At December 31, 2016, PG&E Corporation and the Utility’s 

Consolidated Balance Sheets included a $3 million accrual 

in connection with this matter. 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 the monitor’s 

compensation or costs resulting from recommendations 

of the monitor).

Also, in September 2015, the Utility was notified that 

the DOI had initiated an 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. 

The agreement will be effective until superseded by an 

amended agreement or determination. The agreement 

also provides that the DOI is still conducting a review to 

determine whether the Utility has an effective compliance 

and ethics program and that the DOI is required to use 

its best efforts to complete its review before the end of 

2017. If the DOI determines that the Utility’s 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 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.  As 

discussed under the heading “Regulatory Matters” in Item 

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7. MD&A, the SED continues evaluating PG&E Corporation’s 

and the Utility’s organizational culture and governance in 

the CPUC’s pending investigation to examine the Utility’s 

safety culture. 

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 Utility’s reputation (especially 

as a result of the Utility’s conviction in the federal criminal 

trial), the level of opposition by intervening parties; potential 

rate impacts; increasing levels of regulatory review; changes 

in the political, regulatory, or legislative environments; 

and the opinions of the Utility’s regulators, consumer and 

other stakeholder organizations, and customers, about 

the Utility’s ability to provide safe, reliable, and affordable 

electric and gas services.

The Utility also is required to incur costs to comply with 

legislative and regulatory requirements and initiatives, 

such as those relating to the development of a state-wide 

electric vehicle charging infrastructure, the deployment of 

distributed energy resources, implementation of demand 

response and customer energy efficiency programs, energy 

storage and renewable energy targets, 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 changes in customer demand 

for the Utility’s electricity and natural gas services. 

In addition to the amount of authorized revenues, PG&E 

Corporation’s and the Utility’s financial results could be 

materially affected if the Utility’s actual costs to safely 

and reliably serve its customers differ from authorized or 

forecast costs. The Utility may incur additional costs for 

many reasons including changing market circumstances, 

unanticipated events (such as storms, fires, accidents, 

catastrophic or other events affecting the Utility’s 

operations), or compliance with new state laws or policies. 

Although the Utility may be allowed to recover some or 

all of the additional costs, there may be a substantial time 

lag between when the Utility incurs the costs and when 

the Utility is authorized to collect revenues to recover 

such costs. Alternatively, the CPUC or the FERC may 

disallow costs that they determine were not reasonably 

or prudently incurred by the Utility.

The Utility’s ability to recover its costs also may be affected 

by the economy and its impact on the Utility’s customers. 

For example, a sustained downturn or sluggishness in the 

economy could reduce the Utility’s sales to industrial and 

commercial customers or the level of uncollectible bills 

could increase. Although the Utility generally recovers 

its costs through rates, regardless of sales volume, rate 

pressures increase when the costs are borne by a smaller 

sales base. 

Changes in commodity prices also may have an adverse 

effect on the Utility’s ability to timely recover its operating 

costs and earn its authorized ROE. Although the 

Utility generally recovers its electricity and natural gas 

procurement costs from customers as “pass-through” 

costs, a significant and sustained rise in commodity 

prices could create overall rate pressures that make it 

more difficult for the Utility to recover its costs that are 

not categorized as “pass-through” costs. To relieve some 

of this upward rate pressure, the CPUC could authorize 

lower revenues than the Utility requested or disallow full 

cost recovery. 

PG&E Corporation’s and the Utility’s financial results 

depend upon the Utility’s continuing ability to recover 

“pass-through” costs, including electricity and natural 

gas procurement costs, from customers in a timely 

manner. The CPUC may disallow procurement costs 

for a variety of reasons. In addition, the Utility’s ability 

to recover these costs could be affected by the loss 

of Utility customers and decreased new customer 

growth, if the CPUC fails to adjust the Utility’s rates to 

reflect such events.

The Utility meets customer demand for electricity from 

a variety of sources, including electricity generated from 

the Utility’s own generation facilities, electricity provided 

by third parties under power purchase agreements, and 

purchases on the wholesale electricity market. The Utility 

must manage these sources using the commercial and 

CPUC regulatory principles of “least cost dispatch” and 

prudent administration of power purchase agreements in 

compliance with its CPUC-approved long-term procurement 

plan. The CPUC could disallow procurement costs incurred 

by the Utility if the CPUC determines that the Utility did 

not comply with these principles or if the Utility did not 

comply with its procurement plan. 

Further, the contractual prices for electricity under the 

Utility’s current or future power purchase agreements 

could become uneconomic in the future for a variety of 

reasons, including developments in alternative energy 

technology, increased self-generation by customers, an 

increase in distributed generation, and lower customer 

demand due to adverse economic conditions or the 

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loss of the Utility’s customers to other retail providers. 

In particular, the Utility will incur additional costs to 

procure renewable energy to meet the higher targets 

established by California SB 350 that became effective 

on January 1, 2016. Despite the CPUC’s current approval 

of the contracts, the CPUC could disallow contract 

costs in the future if it determines that the costs are 

unreasonably above market. 

The Utility’s ability to recover the costs it incurs in the 

wholesale electricity market may be affected by 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 net energy metering (“NEM”), which allows 

self-generating customers to receive bill credits for surplus 

power at the full retail rate, puts upward rate pressure on 

remaining customers. In January 2016, the CPUC adopted 

new NEM rules and rates. The new rules and rates became 

effective for new NEM customers of the Utility in December 

2016. New NEM customers will be required to pay an 

interconnection fee, will go on time of use rates, and will 

be required to pay some non-bypassable charges to help 

fund some of the costs of low income, energy efficiency, 

and other programs that other customers pay. However, 

the resulting rules will still put upward rate pressure on 

remaining customers, and remove the cap on the number 

of NEM customers. Significantly higher bills for remaining 

customers may result in a decline of the number of such 

customers as they may seek alternative energy providers. 

The CPUC states that it intends to revisit these rules in 2019.

A confluence of technology-related cost declines 

and sustained federal or state subsidies could make 

a combination of distributed generation and energy 

storage a viable, cost-effective alternative to the Utility’s 

bundled electric service which could further threaten the 

Utility’s ability to recover its generation, transmission, and 

distribution investments. If the number of the Utility’s 

customers decreases or grows at a slower rate than 

anticipated, the Utility’s level of capital investment would 

likely decline as well, in turn leading to a slower growth 

in rate base and earnings. Reduced energy demand or 

significantly slowed growth in demand due to customer 

migration to other energy providers, adoption of energy 

efficient technology, conservation, increasing levels 

of distributed generation and self-generation, unless 

substantially offset through regulatory cost allocations, 

could adversely impact PG&E Corporation’s and the 

Utility’s financial results. 

The CPUC has begun to implement rate reform to allow 

residential electric rates to more closely reflect the utilities’ 

actual costs of providing service and decrease costsubsidization among customer classes. Many aspects 

of rate reform are not yet finalized, including time-ofuse rates and whether the utilities can impose a fixed 

charge on certain customers. If the Utility is unable to 

recover a material portion of its procurement costs and/

or if the CPUC fails to adjust the Utility’s rates to reflect 

the impact of changing loads, the wide deployment of 

distributed generation, and the development of new 

electricity generation and energy storage technologies, 

PG&E Corporation’s and the Utility’s financial results could 

be materially affected. 

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ITEM 1A.  RISK FACTORS

Risks Related to Liquidity and Capital Requirements

PG&E Corporation’s and the Utility’s financial results 

will be affected by their ability to continue accessing 

the capital markets and by the terms of debt and 

equity financings. 

PG&E Corporation and the Utility will continue to seek funds 

in the capital and credit markets to enable the Utility to 

make capital investments, pay fines that may be imposed 

in the future, 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 the pending CPUC investigations 

and ratemaking proceedings. If PG&E Corporation’s or 

the Utility’s credit ratings were downgraded to below 

investment grade, their ability to access the capital and 

credit markets would be negatively affected and could 

result in higher borrowing costs, fewer financing options, 

including reduced, or lack of, access to the commercial 

paper market, additional collateral posting requirements, 

which in turn could affect liquidity and lead to an increased 

financing need. Other factors can affect the availability 

and terms of debt and equity financing, including changes 

in the federal or state regulatory environment affecting 

energy companies generally or PG&E Corporation and 

the Utility in particular, the overall health of the energy 

industry, volatility in electricity or natural gas prices, an 

increase in interest rates by the Federal Reserve Bank, 

and general economic and financial market conditions.

The reputations of PG&E Corporation and the Utility 

continue to suffer from the negative publicity about 

matters discussed under “Enforcement and Litigation 

Matters” in Item 7. MD&A. The negative publicity and 

the uncertainty about the outcomes of these matters 

may undermine 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. 

If the Utility were unable to access the capital markets, 

it could be required to decrease or suspend dividends 

to PG&E Corporation and PG&E Corporation could be 

required to contribute capital to the Utility to enable the 

Utility to fulfill its obligation to serve. To maintain PG&E 

Corporation’s dividend level in these circumstances, PG&E 

Corporation would be further required to access the 

capital or credit markets. PG&E Corporation may need 

to decrease or discontinue its common stock dividend 

if it is unable to access the capital or credit markets on 

reasonable terms. 

PG&E Corporation’s ability to meet its debt service 

and other financial obligations and to pay dividends 

on its common stock depends on the Utility’s earnings 

and cash flows. 

PG&E Corporation is a holding company with no revenue 

generating operations of its own. The Utility must use 

its resources to satisfy its own obligations, including its 

obligation to serve customers, to pay principal and interest 

on outstanding debt, to pay preferred stock dividends, 

and meet its obligations to employees and creditors, 

before it can distribute cash to PG&E Corporation. Under 

the CPUC’s rules applicable to utility holding companies, 

the Utility’s dividend policy must be established by the 

Utility’s Board of Directors as though the Utility were a 

stand-alone utility company and PG&E Corporation’s 

Board of Directors give “first priority” to the Utility’s capital 

requirements, as determined to be necessary and prudent 

to meet the Utility’s obligation to serve or to operate the 

Utility in a prudent and efficient manner. The CPUC has 

interpreted this “first priority” obligation to include the 

requirement that PG&E Corporation “infuse the Utility 

with all types of capital necessary for the Utility to fulfill 

its obligation to serve.” In addition, before the Utility can 

pay common stock dividends to PG&E Corporation, the 

Utility must maintain its authorized capital structure with 

an average 52% equity component. 

If the Utility were required to pay a material amount of fines 

or incur material unrecoverable costs in connection with 

the terms of the probation or monitorship, the pending 

CPUC investigations, or other 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 EPS. (See 

“Liquidity and Financial Resources” in Item 7. MD&A.) 

Further, if PG&E Corporation were required to infuse the 

Utility with significant capital or if the Utility was unable 

to distribute cash to PG&E Corporation, or both, PG&E 

Corporation may be unable to pay principal and interest 

on its outstanding debt, pay its common stock dividend, 

or meet other obligations.

PG&E Corporation’s and the Utility’s ability to pay dividends 

also could be affected by financial covenants contained 

in their respective credit agreements that require each 

company to maintain a ratio of consolidated total debt 

to consolidated capitalization of at most 65%.

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Risks Related to Operations and Information Technology

The Utility’s electricity and natural gas operations 

are inherently hazardous and involve significant risks 

which, if they materialize, can adversely affect PG&E 

Corporation’s and the Utility’s financial results. The 

Utility’s insurance may not be sufficient to cover 

losses caused by an operating failure or catastrophic 

event, or may not become available at a reasonable 

cost, or available at all. 

The Utility owns and operates extensive electricity and 

natural gas facilities, including two nuclear generation 

units and an extensive hydroelectric generating system. 

(See “Electric Utility Operations” and “Natural Gas Utility 

Operations” in Item 1. Business.) The Utility’s ability to earn 

its authorized ROE depends on its ability to efficiently 

maintain, operate, and protect its facilities, and provide 

electricity and natural gas services safely and reliably. The 

Utility undertakes substantial capital investment projects 

to construct, replace, and improve its electricity and 

natural gas facilities. In addition, the Utility is obligated 

to decommission its electricity generation facilities at 

the end of their useful operating lives. The Utility’s ability 

to safely and reliably operate, maintain, construct and 

decommission its facilities is subject to numerous risks, 

many of which are beyond the Utility’s control, including 

those that arise from: 

đ 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;

đ 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; 

đ 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;

đ 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;

đ 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;

đ the release of radioactive materials caused by a nuclear 

accident, seismic activity, natural disaster, or terrorist act; 

đ 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;

đ the failure to take expeditious or sufficient action to 

mitigate operating conditions, facilities, or equipment, 

that the Utility has identified, or reasonably should 

have identified, as unsafe, which failure then leads to a 

catastrophic event (such as a wild land fire or natural 

gas explosion), and the failure to respond effectively 

to a catastrophic event;

đ 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;

đ severe weather events such as storms, tornadoes, floods, 

drought, earthquakes, tsunamis, wild land and other 

fires, pandemics, solar events, electromagnetic events, 

or other natural disasters;

đ operator or other human error;

đ an ineffective records management program that results 

in the failure to construct, operate and maintain a utility 

system safely and prudently;

đ construction performed by third parties that damage the 

Utility’s underground or overhead facilities, including, for 

example, ground excavations or “dig-ins” that damage 

the Utility’s underground pipelines;

đ 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

đ attacks by third parties, including cyber-attacks, acts 

of terrorism, vandalism, or war.

The occurrence of any of these events could interrupt 

fuel supplies; affect demand for electricity or natural gas; 

cause unplanned outages or reduce generating output; 

damage the Utility’s assets or operations; damage the 

assets or operations of third parties on which the Utility 

relies; damage property owned by customers or others; 

and cause personal injury or death. As a result, the Utility 

could incur costs to purchase replacement power, to repair 

assets and restore service, and to compensate third parties. 

In particular, the Utility may incur material liability in 

connection with the Butte fire. (See “PG&E Corporation 

and the Utility may incur material liability in connection 

with Butte Fire” above.) Additionally, on January 12, 2017, a 

residential structure fire occurred in Yuba City, California, 

resulting in the collapse of the house and injuries to 

two persons inside the house. The CPUC, a third-party 

engineering firm, and local fire and police officials are 

investigating the origin and cause of the incident. The 

Utility may incur material costs, including as a result of 

these investigations or any proceedings that could be 

commenced in connection with this incident.

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 

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ITEM 1A.  RISK FACTORS

action if the contractor violates applicable laws, rules, 

regulations, or orders. The Utility may also be subject 

to liability, penalties or other enforcement action as a 

result of personal injury or death caused by third-party 

contractor actions. 

Insurance, equipment warranties, or other contractual 

indemnification requirements may not be sufficient or 

effective to provide full or even partial recovery under 

all circumstances or against all hazards or liabilities to 

which the Utility may become subject. An uninsured loss 

could have a material effect on PG&E Corporation’s and 

the Utility’s financial results. Future insurance coverage 

may not be available at rates and on terms as favorable 

as the Utility’s current insurance coverage or may not be 

available at all. 

Further, 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 

and takings as a result of the design, construction and 

maintenance of utility facilities, including its electric 

transmission lines. As a result of the strict liability standard 

applied to wildfires, recent losses recorded by insurance 

companies, the risk of increase of wildfires including as a 

result of the ongoing drought, 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. 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, or cash flows could be materially affected.

The Utility’s operational and information technology 

systems could fail to function properly or be 

improperly accessed or damaged by third parties 

(including cyber-attacks and physical acts) or 

damaged by severe weather, natural disasters, or 

other events. Any of these events could disrupt the 

Utility’s operations and cause the Utility to incur 

unanticipated losses and expense or liability to third 

parties.

The operation of the Utility’s extensive electricity and 

natural gas systems relies on evolving and increasingly 

complex operational and information technology systems 

and network infrastructures that are interconnected with 

the systems and network infrastructure owned by third 

parties. All of the Utility’s operational and technology 

systems and network infrastructure are vulnerable to 

disability or failures in the event of cyber-attacks and 

physical acts. Cyber-attacks are increasingly sophisticated 

and may include computer hacking, viruses, malware, 

social engineering, denial of service attacks, ransomware, 

destructive malware, or other means of disruption, 

destruction, or unauthorized access, acquisition or control. 

In addition, hardware, software, or applications the Utility 

develops or procures from third parties may contain defects 

in design or manufacture or other problems that could 

unexpectedly compromise information security. Physical 

attacks may include acts of sabotage, acts of war, acts of 

terrorism, or other physical acts. The Utility’s operational 

and information technology systems and networks are 

deemed critical infrastructure, and any failure or decrease 

in their functionality could, among other things, cause 

harm to the public or employees, significantly disrupt 

operations, negatively impact the Utility’s ability to generate, 

transport, deliver and store energy and gas, or otherwise 

operate in the most efficient manner or at all, undermine 

the Utility’s performance of critical business functions, 

damage the Utility’s assets or operations or those of third 

parties, and lead to reputational harm. As a result, such 

events could subject the Utility to significant expenses, 

claims by customers or third parties, government inquiries, 

investigations, and regulatory actions that could result in 

fines and penalties, and loss of customers, any of which 

could have a material effect on PG&E Corporation’s and 

the Utility’s financial condition and results of operations.

The Utility’s systems, including its financial information, 

operational systems, advanced metering, and billing 

systems, require ongoing maintenance, modification, and 

updating, which can be costly and increase the risk of 

errors and malfunction. The Utility often relies on thirdparty vendors to host, maintain, modify, and update its 

systems and these third-party vendors could cease to 

exist, fail to establish adequate processes to protect the 

Utility’s systems and information, or experience internal 

or external security incidents. Any incidents, disruptions 

or deficiencies in existing systems, or disruptions, delays 

or deficiencies in the modification of existing systems or 

implementation of new systems could result in increased 

costs, the inability to track or collect revenues, or diversion 

of management’s and employees’ attention and resources, 

or negatively affect the Utility’s ability to maintain effective 

financial controls or timely file required regulatory reports. 

The Utility also could be subject to patent infringement 

claims arising from the use of third-party technology by 

the Utility or by a third-party vendor. 

In addition, the Utility’s information systems contain 

confidential information, including information about 

customers and employees. A data breach involving theft, 

improper disclosure, or other unauthorized access to 

or acquisition of confidential information could subject 

the Utility to penalties for violation of applicable privacy 

laws, claims by third parties, and enforcement actions by 

government agencies. It could also reduce the value of 

proprietary information, and harm the Utility’s reputation. 

The Utility and its third party vendors have been subject, 

and will likely continue to be subject, to attempts to 

gain unauthorized access to the Utility’s information 

technology systems, or confidential data, or to disrupt 

the Utility’s operations. None of these attempts or 

breaches has individually or in the aggregate resulted 

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ITEM 1A.  RISK FACTORS

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 systems, infrastructure, or data, or the disruption 

of its operations, either of which could materially affect 

PG&E Corporation’s and the Utility’s financial condition 

and results of operations. 

While the Utility maintains cyber liability insurance that 

covers certain damages caused by cyber incidents, 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 power plants expose it to potentially 

significant liabilities and the Utility may not be able 

to fully recover its costs if regulatory requirements 

change or the plant ceases operations before the 

licenses expire.

The operation of the Utility’s nuclear generation facilities 

exposes it to potentially significant liabilities from 

environmental, health and financial risks, such as risks 

relating to the storage, handling and disposal of spent 

nuclear fuel, and the release of radioactive materials caused 

by a nuclear accident, seismic activity, natural disaster, or 

terrorist act. If the Utility incurs losses that are either not 

covered by insurance or exceed the amount of insurance 

available, such losses could have a material effect on PG&E 

Corporation’s and the Utility’s financial results. In addition, 

the Utility may be required under federal law to pay up 

to $255 million of liabilities arising out of each nuclear 

incident occurring not only at the Utility’s Diablo Canyon 

facility but at any other nuclear power plant in the United 

States. (See Note 13 of the Notes to the Consolidated 

Financial Statements in Item 8.)  

On August 11, 2016, the Utility submitted an application to 

the CPUC to retire Diablo Canyon at the expiration of its 

current operating licenses in 2024 and 2025 and replace 

it with a portfolio of energy efficiency and GHG-free 

resources. The application includes a joint proposal between 

the Utility and certain interested parties, entered into on 

June 20, 2016. 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 the licenses 

expire in 2024 and 2025. In such an instance, the Utility 

could be required to record a charge for the remaining 

amount of its unrecovered investment and such charge 

could have a material effect on PG&E Corporation and 

the Utility’s financial results. 

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. The Utility currently estimates that the 

additional cost of the employee retention program and 

the employee retraining and development program will 

be approximately $350 million. The Joint Proposal seeks 

confirmation from the CPUC that these costs will be 

recovered through the Utility’s nuclear decommissioning 

electric rates. The employee retention and retraining and 

development programs are subject to bargaining with 

the Utility’s labor unions. The Utility will also incur costs 

in connection with an employee severance program. The 

severance program was previously approved by the CPUC 

in prior nuclear decommissioning ratemaking proceedings.

The Utility has incurred, and may continue to incur, 

substantial costs to comply with NRC regulations and 

orders. (See “Regulatory Environment” in Item 1. Business.) 

If the Utility were unable to recover these costs, PG&E 

Corporation’s and the Utility’s financial results could 

be materially affected. The Utility may determine that 

it cannot comply with the new regulations or orders in 

a feasible and economic manner and voluntarily cease 

operations; alternatively, the NRC may order the Utility 

to cease operations until the Utility can comply with new 

regulations, orders, or decisions. The Utility may incur a 

material charge if it ceases operations at Diablo Canyon 

before the licenses expire in 2024 and 2025. At December 

31, 2016, the Utility’s unrecovered investment in Diablo 

Canyon was $1.7 billion. 

At the state level, the California Water Board has adopted 

a policy on once-through cooling that generally requires 

the installation of cooling towers or other significant 

measures to reduce the impact on marine life from existing 

power generation facilities in California by at least 85%. 

If the California Water Board requires the installation of 

cooling towers that the Utility believes are not technically 

or economically feasible, the Utility may be forced to cease 

operations at Diablo Canyon and may incur a material 

charge. If the Utility obtains contingent approvals referred 

to herein that will result in retiring Diablo Canyon at the 

end of the current NRC operating licenses, the Utility will 

not be required to install cooling towers or implement 

alternative measures in order to comply with the California 

State Water Board Once-Through Cooling Water Policy, 

thus eliminating the regulatory uncertainty regarding the 

measures that could have been imposed on the Utility or 

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ITEM 1A.  RISK FACTORS

of incurring a material charge related thereto. Even if the 

Utility is ultimately not required to install cooling towers, 

under the State Water Board’s interim mitigation measures 

applicable to Diablo Canyon’s operations prior to 2025, 

starting in 2016, it will be required to make payments 

to the California Coastal Conservancy to fund various 

environmental mitigation projects, that the Utility does 

not expect to exceed $5 million per year. 

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 results could be materially affected.

Risks Related to Environmental Factors

The Utility’s operations are subject to extensive 

environmental laws and changes in or liabilities under 

these laws could adversely affect PG&E Corporation’s 

and the Utility’s financial results.

The Utility’s operations are subject to extensive federal, 

state, and local environmental laws, regulations, orders, 

relating to air quality, water quality and usage, remediation 

of hazardous wastes, and the protection and conservation 

of natural resources and wildlife. The Utility incurs 

significant capital, operating, and other costs associated 

with compliance with these environmental statutes, rules, 

and regulations. The Utility has been in the past, and 

may be in the future, required to pay for environmental 

remediation costs at sites where it is identified as a 

potentially responsible party under federal and state 

environmental laws. Although the Utility has recorded 

liabilities for known environmental obligations, these costs 

can be difficult to estimate due to uncertainties about 

the extent of contamination, remediation alternatives, the 

applicable remediation levels, and the financial ability of 

other potentially responsible parties. (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.) The 

Utility’s costs to remediate groundwater contamination near 

the Hinkley natural gas compressor site and to abate the 

effects of the contamination have had, and may continue 

to have, a material effect on PG&E Corporation’s and the 

Utility’s financial results. Their financial results also can be 

materially affected by changes in estimated costs and by 

the extent to which actual remediation costs differ from 

recorded liabilities. 

The Utility’s future operations may be affected by 

climate change that may have a material impact 

on PG&E Corporation’s and the Utility’s financial 

condition, results of operations, and cash flows. 

The Utility has been studying the potential effects of climate 

change (increased temperatures, changing precipitation 

patterns, rising sea levels) on the Utility’s operations 

and is developing contingency plans to adapt to those 

events and conditions that the Utility believes are most 

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PART I

ITEM 1A.  RISK FACTORS

significant. Scientists project that climate change will 

increase electricity demand due to more extreme, persistent 

and hot weather. While snowpack in the Sierra Nevada 

Mountains has been at higher than normal levels this winter, 

California has experienced ongoing drought in the past. If 

temperatures and the levels of precipitation in the Utility’s 

service territory continue to change, that could impact 

the levels of snowpack in the Sierra Nevada Mountains. 

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, 

increasing temperatures and lower levels of precipitation 

could increase the occurrence of wildfires in the Utility’s 

service territory causing damage to the Utility’s facilities 

or the facilities of third parties on which the Utility relies 

to provide service, damage to third parties for loss of 

property, personal injury, or loss of life. In addition, flooding 

caused by rising sea levels could damage the Utility’s 

facilities, including hydroelectric assets such as dams 

and canals, and the electric transmission and distribution 

assets. The Utility could incur substantial costs to repair or 

replace facilities, restore service, compensate customers 

and other third parties for damages or injuries. The Utility 

anticipates that the increased costs would be recovered 

through rates, but as rate pressures increase, the likelihood 

of disallowance or non-recovery may increase. 

Events or conditions caused by climate change could 

have a greater impact on the Utility’s operations than 

the Utility’s studies suggest and could result in lower 

revenues or increased expenses, or both. If the CPUC 

fails to adjust the Utility’s rates to reflect the impact of 

events or conditions caused by climate change, PG&E 

Corporation’s and the Utility’s financial condition, results 

of operations, and cash flows could be materially affected.

Other Risk Factors

PG&E Corporation’s and the Utility’s financial results 

could be materially affected as a result of political and 

legislative developments. 

The Utility’s financial results could be materially affected 

as a result of the recent change in federal administration 

from President Barack Obama to President Donald Trump. 

For example, the new administration has indicated tax 

reform as a priority. Tax reform outlines produced by both 

President Trump and the Tax Reform Task Force include 

proposals related to federal tax rates, deductions for 

state income taxes (and potentially property tax), interest 

expense deduction, capital expenditure deduction, and 

expensing plant. It is unclear what tax reform may be 

ultimately adopted. It is generally expected that a tax 

reform bill will be introduced in early 2017. 

The Utility may be required to incur substantial costs 

in order to obtain or renew licenses and permits 

needed to operate the Utility’s business and the Utility 

may be subject to fines and penalties for failure to 

comply or obtain license renewal. 

The Utility must comply with the terms of various 

governmental permits, authorizations, and licenses, 

including those issued by the FERC for the continued 

operation of the Utility’s hydroelectric generation facilities, 

and those issued by environmental and other federal, 

state and local governmental agencies. Many of the 

Utility’s capital investment projects, and some maintenance 

activities, often require the Utility to obtain land use, 

construction, environmental, or other governmental permits. 

These permits, authorizations, and licenses may be difficult 

to obtain on a timely basis, causing work delays. Further, 

existing permits and licenses could be revoked or modified 

by the agencies that granted them if facts develop that 

differ significantly from the facts assumed when they were 

issued. In addition, the Utility often seeks periodic renewal 

of a license or permit, such as a waste discharge permit or 

a FERC operating license for a hydroelectric generation 

facility. If a license or permit is not renewed for a particular 

facility and the Utility is required to cease operations at 

that facility, the Utility could incur an impairment charge 

or other costs. Before renewing a permit or license, the 

issuing agency may impose additional requirements that 

may increase the Utility’s compliance costs. In particular, 

in connection with a license renewal for one or more of 

the Utility’s hydroelectric generation facilities or assets, 

the FERC may impose new license conditions that could, 

among other things, require increased expenditures or 

result in reduced electricity output and/or capacity at 

the facility. In addition, local governments may attempt 

to assert jurisdiction over various utility operations by 

requiring permits or other approvals that the Utility has 

not been previously required to obtain. 

The Utility may incur penalties and sanctions for failure 

to comply with the terms and conditions of licenses and 

permits which could have a material effect on PG&E 

Corporation’s and the Utility’s financial condition, results 

of operations, and cash flows. If the Utility cannot obtain, 

renew, or comply with necessary governmental permits, 

authorizations, licenses, ordinances, or other requirements, 

or if the Utility cannot recover the increase in associated 

compliance and other costs in a timely manner, PG&E 

Corporation’s and the Utility’s financial results could be 

materially affected. 

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PART I

ITEM 2.  PROPERTIES

Poor investment performance or other factors could 

require PG&E Corporation and the Utility to make 

significant unplanned contributions to its pension 

plan, other postretirement benefits plans, and nuclear 

decommissioning trusts. 

PG&E Corporation and the Utility provide defined benefit 

pension plans and other postretirement benefits for eligible 

employees and retirees. The Utility also maintains three trusts 

for the purposes of providing funds to decommission its 

nuclear facilities. The performance of the debt and equity 

markets affects the value of plan assets and trust assets. 

A decline in the market value may increase the funding 

requirements for these plans and trusts. The cost of providing 

pension and other postretirement benefits is also affected 

by other factors, including interest rates used to measure 

the required minimum funding levels, the rate of return on 

plan assets, employee demographics, discount rates used in 

determining future benefit obligations, rates of increase in 

health care costs, future government regulation, and prior 

contributions to the plans. Similarly, funding requirements for 

the nuclear decommissioning trusts are affected by the rates 

of return on trust assets, changes in the laws or regulations 

regarding nuclear decommissioning or decommissioning 

funding requirements as well as changes in assumptions 

or forecasts related to decommissioning dates, technology 

and the cost of labor, materials and equipment. (See Note 

2: Summary of Significant Accounting Policies of the 

Notes to the Consolidated Financial Statements in Item 

8.) If the Utility is required to make significant unplanned 

contributions to fund the pension and postretirement plans 

or if actual nuclear decommissioning costs exceed the 

amount of nuclear decommissioning trust funds and the 

Utility is unable to recover the contributions or additional 

costs in rates, PG&E Corporation’s and the Utility’s financial 

results could be materially affected. 

The Utility’s success depends on the availability 

of the services of a qualified workforce and its 

ability to maintain satisfactory collective bargaining 

agreements which cover a substantial number of 

employees. PG&E Corporation’s and the Utility’s 

results may suffer if the Utility is unable to attract and 

retain qualified personnel and senior management 

talent, or if prolonged labor disruptions occur. 

The Utility’s workforce is aging and many employees are 

or will become eligible to retire within the next few years. 

Although the Utility has undertaken efforts to recruit and 

train new field service personnel, the Utility may be faced 

with a shortage of experienced and qualified personnel. 

The majority of the Utility’s employees are covered by 

collective bargaining agreements with three unions. Labor 

disruptions could occur depending on the outcome of 

negotiations to renew the terms of these agreements with 

the unions or if tentative new agreements are not ratified 

by their members. In addition, some of the remaining 

non-represented Utility employees could join one of these 

unions in the future. 

PG&E Corporation and the Utility also may face 

challenges in attracting and retaining senior management 

talent especially if they are unable to restore the 

reputational harm generated by the negative publicity 

stemming from the ongoing enforcement proceedings. 

Any such occurrences could negatively impact PG&E 

Corporation’s and the Utility’s financial condition and 

results of operations.

ITEM 1B. Unresolved Staff Comments

None.

ITEM 2. Properties

The Utility owns or has obtained the right to occupy and/

or use real property comprising the Utility’s electricity and 

natural gas distribution facilities, natural gas gathering 

facilities and generation facilities, and natural gas and 

electricity transmission facilities, which are described in 

Item 1. Business, under “Electric Utility Operations” and 

“Natural Gas Utility Operations.” The Utility occupies or 

uses real property that it does not own primarily through 

various leases, easements, rights-of-way, permits, or licenses 

from private landowners or governmental authorities. 

In total, the Utility occupies 11 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 167,000 acres of 

land, including approximately 140,000 acres of watershed 

lands. In 2002 the Utility agreed to implement its “Land 

Conservation Commitment” (“LCC”) to permanently 

preserve the six “beneficial public values” on all the 

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ITEM 3.  LEGAL PROCEEDINGS

watershed lands through conservation easements or 

equivalent protections, as well as to make approximately 

70,000 acres of the watershed lands available for donation 

to qualified organizations. The six “beneficial public values” 

being preserved by the LCC include: natural habitat of fish, 

wildlife, and plants; open space; outdoor recreation by the 

general public; sustainable forestry; agricultural uses; and 

historic values. The Utility’s goal is to implement all the 

transactions needed to implement the LCC by the end of 

2018, subject to securing all required regulatory approvals.

ITEM 3. Legal Proceedings

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory 

proceedings in the ordinary course of their business.  For more information regarding material lawsuits and proceedings, 

see “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 

and in Item 7. MD&A.

Penalty Decision Related to the CPUC’s 

Investigative Enforcement Proceedings Related 

to Natural Gas Transmission 

On April 9, 2015, the CPUC 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 that could have led to or contributed 

to the natural gas explosion that occurred in the City of 

San Bruno, California on September 9, 2010. In January 

2016, the CPUC closed the investigative proceedings. 

The total penalty included (1) a $300 million fine, (2) a 

one-time $400 million bill credit to the Utility’s natural 

gas customers, (3) $850 million to fund pipeline safety 

projects and programs, and (4) remedial measures that 

the CPUC estimates will cost the Utility at least $50 million. 

The Utility refunded the $400 million to its customers 

in the second quarter of 2016 and paid the $300 million 

fine in the third quarter of 2015. On December 1, 2016, 

the CPUC approved a final phase two decision in the 

Utility’s 2015 GT&S rate case, which applies $689 million 

of the $850 million penalty to capital expenditures. The 

Utility is precluded from including these capital costs in 

rate base. The final phase two decision also approves the 

Utility’s list of programs and projects that meet the CPUC’s 

definition of “safety related,” the costs of which are to 

be funded through the $850 million penalty. For more 

information, see “Enforcement and Litigation Matters” 

in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.

Federal Criminal Trial 

On June 14, 2016, a federal criminal trial against the Utility 

began in the United States District Court for the Northern 

District of California, in San Francisco, on 12 felony counts 

alleging that the Utility knowingly and willfully violated 

minimum safety standards under the Natural Gas Pipeline 

Safety Act relating to record-keeping, pipeline integrity 

management, and identification of pipeline threats, and one 

felony count charging that the Utility obstructed the NTSB 

investigation into the cause of the San Bruno accident. On 

July 26, 2016, the court granted the government’s motion 

to dismiss one count alleging that the Utility knowingly 

and willfully failed to retain a strength test pressure record 

with respect to a distribution feeder main, thereby reducing 

the total number of counts from 13 to 12. 

On August 9, 2016, the jury returned its verdict. The 

jury acquitted the Utility on all six of the record-keeping 

allegations but found the Utility guilty on six felony counts 

that include 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 sentencing 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 Utility has 

decided not to appeal the convictions. 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 is required to retain a 

third-party monitor. The goal of the monitorship will be to 

prevent the criminal conduct with respect to gas pipeline 

transmission safety that gave rise to the conviction. To 

that end, the goal of the monitor will be to help ensure 

that the Utility takes reasonable and appropriate steps 

to maintain the safety of the gas transmission pipeline 

system, performs appropriate integrity management 

assessments on its gas transmission pipelines, and maintains 

an effective ethics and compliance program and safety 

related incentive program.

After an initial assessment is conducted and an initial 

report is prepared by the monitor, the monitor will prepare 

reports on a semi-annual basis setting forth the monitor’s 

continued assessment and making recommendations 

consistent with the goals and scope of the monitorship. The 

Utility expects that the monitor will be retained before the 

end of the second quarter of 2017. For more information, 

see “Enforcement and Litigation Matters” in Note 13 of 

the Notes to the Consolidated Financial Statements in 

Item 8 and Item 1A. Risk Factors. 

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PART I

ITEM 3.  LEGAL PROCEEDINGS

Litigation Related to the San Bruno Accident 

and Natural Gas Spending

As of December 31, 2016, there were seven purported 

derivative lawsuits seeking recovery on behalf of PG&E 

Corporation and the Utility for alleged breaches of fiduciary 

duty by officers and directors, among other claims. 

Four of the complaints were consolidated as the San Bruno 

Fire Derivative Cases and are pending in the Superior 

Court of California, County of San Mateo. The remaining 

three cases are Tellardin v. Anthony F. Earley, Jr., et al.,

Iron Workers Mid-South Pension Fund v. Johns, et al., and 

Bushkin v. Rambo et al.

On December 8, 2015, the California Court of Appeal issued 

a writ of mandate to the Superior Court of California, San 

Mateo County, ordering the court to stay all proceedings 

in the four consolidated San Bruno Fire Derivative Cases

pending conclusion of the federal criminal proceedings 

against the Utility. On November 16, 2016, counsel in the 

four consolidated San Bruno Fire Derivative cases, as well 

as counsel in the Tellardin action, appeared for a status 

conference in the San Mateo Superior Court. The court 

reaffirmed that all proceedings in these actions were 

stayed until the conclusion of the Utility’s federal criminal 

proceeding, at which point they were directed to meet 

and confer and report back to the court. The parties 

completed a mediation session on December 8-9, 2016 

and continue discussions about the potential resolution 

of the matter. These actions remain stayed. 

Bushkin v. Rambo et al., pending in the United States 

District Court for the Northern District of California, has 

been designated by the plaintiff as related to the pending 

shareholder derivative suit Iron Workers Mid-South Pension 

Fund v. Johns, et al., discussed below. The plaintiff in the 

Bushkin lawsuit has agreed that this case should be stayed 

pending conclusion of the federal criminal trial against the 

Utility and, on May 3, 2016, the judge entered a stipulated 

order staying the case. The order also provides that the 

parties should meet and confer within 30 days after the 

criminal trial concludes and provide the court a status 

update. Despite the stay of his complaint, on June 20, 2016 

the Bushkin plaintiff filed a petition in the Superior Court 

of California, San Francisco County, seeking to enforce 

the plaintiff’s claimed right as a shareholder to inspect 

certain PG&E Corporation accounting books and records 

pursuant to section 1601 of the California Corporations 

Code. On July 25, 2016, PG&E Corporation filed a motion 

to stay plaintiff’s petition until the appellate stay of the

San Bruno Fire Derivative Cases has been lifted, or, in the 

alternative, a demurrer asking the court to dismiss plaintiff’s 

petition. On August 29, 2016, the San Francisco Superior 

Court granted PG&E Corporation’s motion, and indicated 

that plaintiff’s petition was stayed pending resolution of 

the criminal matter against the Utility. On January 13, 2017, 

the parties submitted a joint case management statement 

advising the court that, because the Utility had not yet 

been sentenced, the case should remain stayed until at 

least March 10, 2017, when the parties will advise the court 

of further developments. While the Utility was sentenced 

in the federal criminal proceeding on January 26, 2017, 

this matter remains stayed until at least March 10, 2017.

The Iron Workers action pending in the United States 

District Court for the Northern District of California has 

been stayed pending the resolution of the San Bruno Fire 

Derivative Cases. On May 5, 2016, the court ordered the 

parties to meet and confer within 30 days after the criminal 

trial concludes and provide the court a status update. At 

the court’s request, on August 22, 2016, the parties filed a 

statement requesting that the case continue to be stayed 

until resolution of the San Bruno Fire Derivative Cases. 

On August 31, 2016, the court set a case management 

conference for September 30, 2016, and requested 

the parties to file a joint case management conference 

statement by September 23, 2016. On September 30, 

2016, the court decided to continue the stay pending the 

resolution of the federal criminal proceeding against the 

Utility and ordered the parties to submit a joint status 

report on or before March 15, 2017. This matter remains 

stayed until at least March 15, 2017.

PG&E Corporation and the Utility are uncertain when and 

how the above lawsuits will be resolved.

Butte Fire Litigation

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 a press release also issued on 

April 28, 2016, Cal Fire indicated that it will seek to recover 

firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master 

complaint against the Utility and its two vegetation 

management contractors in the Superior Court of California 

for Sacramento County. Subrogation insurers also filed a 

separate master complaint on the same date. The California 

Judicial Council had previously authorized the coordination 

of all cases in Sacramento County. As of December 31, 2016, 

complaints have been filed against the Utility and its two 

vegetation management contractors in the Superior Court 

of California in the Counties of Calaveras, San Francisco, 

Sacramento, and Amador involving approximately 1,950 

individual plaintiffs representing approximately 950 

households and their insurance companies. These 

complaints are part of or are in the process of being 

added to the two master complaints. Plaintiffs seek to 

recover damages and other costs, principally based on 

inverse condemnation and negligence theories of liability. 

The number of individual complaints and plaintiffs may 

increase in the future. 

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PART I

ITEM 3.  LEGAL PROCEEDINGS

The Utility continues mediating and settling cases. The 

next case management conference is scheduled for 

March 2, 2017.

In connection with this matter, the Utility may be liable for 

property damages, interest, and attorneys’ fees without 

having been found negligent, through the theory 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. The Utility believes it was not negligent; 

however, there can be no assurance that a court or jury 

would agree with the Utility. The Utility believes that it is 

probable that it will incur a loss of at least $750 million 

for all potential damages described above. This amount is 

based on assumptions about the number, size, and type 

of structures damaged or destroyed, the contents of such 

structures, the number and types of trees damaged or 

destroyed, as well as assumptions about personal injury 

damages, attorneys’ fees, fire suppression costs, and 

other damages that the Utility could be liable for under 

the theories of inverse condemnation and/or negligence. 

For additional information, see “Enforcement and Litigation 

Matters” in Note 13 of the Notes to the Consolidated 

Financial Statements in Item 8.

Other Enforcement Matters

Fines may be imposed, or other regulatory or governmental 

enforcement action could be taken, with respect to the 

Utility’s self-reports of noncompliance with electric 

and natural gas safety regulations, prohibited ex parte 

communications between the Utility and CPUC personnel, 

and other enforcement matters. See “Enforcement 

and Litigation Matters” in Note 13 of the Notes to the 

Consolidated Financial Statements in Item 8. 

Diablo Canyon Nuclear Power Plant

The Utility’s Diablo Canyon power plant employs a “oncethrough” 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. 

Subsequently, the California State Water Resources Control 

Board adopted a Once-Through Cooling Water Policy in 

May 2010 which requires Diablo Canyon to be in compliance 

with the policy by December 2024 and allows for alternative 

compliance measures at nuclear power plants. 

On June 20, 2016, the Utility entered into a joint proposal 

with certain parties to retire Diablo Canyon at the expiration 

of its current operating licenses in 2024 and 2025 and 

replace it with a GHG-free portfolio of energy efficiency, 

renewables and energy storage. The Utility expects that 

the State Board’s OTC Policy and its decision to retire 

Diablo Canyon will affect the terms of a final settlement 

agreement between the Utility, the Central Coast Water 

Board and the California Attorney General’s Office. Also, 

as required under the State Board’s OTC Policy, beginning 

in 2017, the Utility will pay an annual interim mitigation fee 

until operations cease at the end of the current licenses. 

PG&E Corporation and the Utility believe that the ultimate 

outcome of this matter will not have a material impact on 

the Utility’s financial condition or results of operations.   

Venting Incidents in San Benito County 

As part of its regular maintenance and inspection practices 

for its natural gas transmission system, the Utility performs 

in-line inspections of pipelines using devices called “pigs” 

that travel through the pipeline to inspect and clean the 

walls of the pipe. When in-line inspections are performed, 

natural gas in the pipeline must be released or vented 

at the pipeline station where the device is removed. In 

February 2014, the Utility conducted an in-line inspection 

of a natural gas transmission pipeline that traverses San 

Benito County and vented the natural gas at the Utility’s 

transmission station located in Hollister, which is next to 

an elementary school. The Utility vented the natural gas 

during school hours on three occasions that month. After 

being informed of the venting by the local air district, the 

San Benito County district attorney notified the Utility in 

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PART I

ITEM 4.  MINE SAFETY DISCLOSURES

December 2014 that it was contemplating bringing a civil 

legal action against the Utility for violation of Health and 

Safety Code section 41700, which prohibits discharges 

of air contaminants that cause a public nuisance. In 

January 2017, the Utility and the district attorney reached 

an agreement on a stipulated judgement that resolves 

the matter. The stipulated judgment includes a fine of 

approximately $175,000. In addition, a $75,000 fine will 

be held in abeyance for 5 years, and would be payable 

to the San Benito County district attorney in case of 

non-compliance with certain remedial requirements of 

the stipulated judgment.  The stipulated judgment was 

executed by the court on January 27, 2017.

Transformer Oil Release in Sonoma County

During a rain storm in February 2015, transformer oil was 

released into an underground vault in the City of Santa 

Rosa, in Sonoma County, while a Utility crew was replacing 

a broken transformer. Following further rains, the oil 

released from the vault and reached a nearby creek. The 

event was investigated by Santa Rosa Fire Department, 

the local environmental enforcement authority, and later 

referred to the Sonoma County District Attorney’s Office. 

In May 2016, the District Attorney informed the Utility that 

it would seek penalties and costs in excess of $100,000 

for alleged violations of several sections of the California 

Health and Safety and California Government codes which 

prohibit unauthorized spills or releases of oil into waters 

of the state and require that releases be reported to the 

Office of Emergency Services. In November 2016, the 

Utility and the Sonoma County district attorney reached 

an agreement on a stipulated judgment that resolves the 

matter. The stipulated judgment includes a fine of $80,000, 

reimbursement of enforcement costs of $40,000, and 

injunctive provisions requiring improvements to the Utility’s 

vault dewatering procedure and training. In November 

2016, the court approved the stipulated judgment. 

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 16, 2017. 

Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

Name Age Positions Held Over Last Five Years Time in Position

Anthony F. Earley, Jr.(2) 67 Chairman of the Board, Chief Executive 

Officer, and President, PG&E Corporation

September 13, 2011 to present

Executive Chairman of the Board, DTE 

Energy Company

October 1, 2010 to September 12, 2011

Nickolas Stavropoulos(2) 58 President, Gas September 15, 2015 to present

President, Gas Operations August 17, 2015 to September 15, 2015

Executive Vice President, Gas Operations June 13, 2011 to August 16, 2015

Geisha J. Williams(2) 55 President, Electric September 15, 2015 to present

President, Electric Operations August 17, 2015 to September 15, 2015

Executive Vice President, Electric 

Operations

June 1, 2011 to August 16, 2015

Jason P. Wells 39 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 52 Executive Vice President, Corporate 

Services and Human Resources, PG&E 

Corporation

August 17, 2015 to present

Senior Vice President, Human Resources, 

PG&E Corporation and Pacific Gas and 

Electric Company 

April 16, 2007 to August 16, 2015

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PART I

EXECUTIVE OFFICERS OF THE REGISTRANTS

Name Age Positions Held Over Last Five Years Time in Position

Karen A. Austin 55 Senior Vice President and Chief 

Information Officer

June 1, 2011 to present

President, Consumer Electronics, Sears 

Holdings

February 2009 to May 2011

Desmond A. Bell(3) 54 Senior Vice President, Safety and Shared 

Services 

January 1, 2012 to present 

Helen A. Burt(3) 60 Senior Vice President, External Affairs 

and Public Policy, PG&E Corporation and 

Pacific Gas and Electric Company

September 30, 2015 to present

Senior Vice President, Corporate Affairs, 

PG&E Corporation 

September 18, 2014 to September 30, 

2015 

Senior Vice President and Chief Customer 

Officer

February 27, 2006 to September 17, 2014

Loraine M. Giammona 49 Senior Vice President and Chief Customer 

Officer

September 18, 2014 to present

Vice President, Customer Service January 23, 2012 to September 17, 2014

Regional Vice President, Customer Care, 

Comcast Cable 

November 2002 to January 2012

Edward D. Halpin 55 Senior Vice President, Generation and 

Chief Nuclear Officer

March 28, 2016 to present

Senior Vice President, Power Generation 

and Chief Nuclear Officer

September 8, 2015 to March 27, 2016

Senior Vice President and Chief Nuclear 

Officer

April 2, 2012 to September 8, 2015

President, Chief Executive Officer and 

Chief Nuclear Officer, South Texas Project 

Nuclear Operating Company

December 2009 to March 2012

Patrick M. Hogan 53 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 58 Senior Vice President and Chief Ethics and 

Compliance Officer, PG&E Corporation and 

Pacific Gas and Electric Company

May 18, 2015 to present

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 44 Senior Vice President, Regulatory Affairs September 18, 2014 to present

Vice President, Customer Energy Solutions May 15, 2011 to September 17, 2014

Vice President, Integrated Demand Side 

Management

July 1, 2010 to May 14, 2011

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PART I

EXECUTIVE OFFICERS OF THE REGISTRANTS 

Name Age Positions Held Over Last Five Years Time in Position

Dinyar B. Mistry 55 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

Hyun Park(4) 55 Senior Vice President and General Counsel, 

PG&E Corporation

November 13, 2006 to present

Jesus Soto, Jr. 49 Senior Vice President, Gas Operations September 8, 2015 to present

Senior Vice President, Engineering, 

Construction and Operations

September 16, 2013 to September 8, 2015

Senior Vice President, Gas Transmission 

Operations

May 29, 2012 to September 15, 2013

Vice President, Operations Services, El 

Paso Pipeline Group

May 2007 to May 2012

Fong Wan 55 Senior Vice President, Energy Policy and 

Procurement

September 8, 2015 to present

Senior Vice President, Energy Procurement October 1, 2008 to September 8, 2015

David S. Thomason 41 Vice President, Chief Financial Officer, and 

Controller

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

Director, Planning, Forecasting and 

Reporting

October 3, 2011 to August 31, 2012

(1) Mr. Earley, Mr. Stavropoulos, Ms. Williams, Mr. Simon, Ms. Burt, Ms. Kane, Mr. Mistry, Mr. Park, and Mr. Wells are executive 

officers of both PG&E Corporation and the Utility. All other listed officers are executive officers of the Utility only.

(2) On November 14, 2016, the Board of Directors of PG&E Corporation elected Mr. Earley to the role of Executive Chair of 

the Board of PG&E Corporation and Ms. Williams to the role of Chief Executive Officer and President of PG&E Corporation, 

both effective March 1, 2017. Also on November 14, 2016, the Board of Directors of the Utility elected Mr. Stavropoulos as 

President and Chief Operating Officer of the Utility effective March 1, 2017. 

(3) Mr. Bell and Ms. Burt will step down from their positions effective March 1, 2017.

(4) Mr. Park will step down from his position effective March 1, 2017 but is expected to remain with PG&E Corporation until 

September 1, 2017.

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PART II

ITEM 5. Market for Registrant’s Common Equity, Related 

Shareholder Matters and Issuer Purchases of Equity 

Securities 

As of February 7, 2017, there were 56,835 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 

PG&E Corporation’s Consolidated Statements of Equity, the 

Utility’s Consolidated Statements of Shareholders’ Equity, 

and Note 5 of the Notes to the Consolidated Financial 

Statements in Item 8 and in “Liquidity and Financial 

Resources – Dividends” in Item 7 below.

Sales of Unregistered Equity Securities

PG&E Corporation made equity contributions to the 

Utility totaling $95 million during the quarter ended 

December 31, 2016. PG&E Corporation did not make 

any sales of unregistered equity securities during 2016 

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, 2016, 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, 2016, the Utility did not 

redeem or repurchase any shares of its various series of 

preferred stock outstanding. 

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PART II

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

ITEM 6. Selected Financial Data 

(in millions, except per share amounts) 2016 2015   2014   2013   2012

PG&E Corporation 

For the Year 

                       

Operating revenues $17,666 $16,833 $17,090 $15,598 $ 15,040

Operating income 2,177 1,508 2,450 1,762 1,693

Net income 1,407 888 1,450 828 830

Net earnings per common share, basic(1) 2.79 1.81 3.07 1.83 1.92

Net earnings per common share, diluted 2.78 1.79 3.06 1.83 1.92

Dividends declared per common share(2) 1.93 1.82 1.82 1.82 1.82

At Year-End 

Common stock price per share $ 60.77 $ 53.19 $ 53.24 $ 40.28 $ 40.18

Total assets(3) 68,598 63,234 60,228 55,693 52,530

Long-term debt (excluding current portion)(3) 16,220 15,925 15,151 12,805 12,598

Capital lease obligations (excluding current 

portion)(4) 31 49 69 90 113

Pacific Gas and Electric Company 

For the Year 

Operating revenues $17,667 $16,833 $17,088 $15,593 $ 15,035

Operating income 2,181 1,511 2,452 1,790 1,695

Income available for common stock 1,388 848 1,419 852 797

At Year-End 

Total assets(5) 68,374 63,037 59,964 55,137 52,003

Long-term debt (excluding current portion)(5) 15,872 15,577 14,799 12,805 12,247

Capital lease obligations (excluding current 

portion)(4) 31 49 69 90 113

(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 MD&A in Item 7 and in PG&E Corporation’s Consolidated Statements of 

Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 in Item 8.

(3) In accordance with ASU No. 2015-03, PG&E Corporation restated $105 million in 2015, $101 million in 2014, $88 million in 

2013, and $81 million in 2012, of debt issuance costs. Total assets and total liabilities were each reduced by the amounts 

above with no impact to net income or total shareholders’ equity previously reported.

(4) The capital lease obligations amounts are included in noncurrent liabilities – other in PG&E Corporation’s and the Utility’s 

Consolidated Balance Sheets.

(5) In accordance with ASU No. 2015-03, the Utility restated $103 million in 2015, $99 million in 2014, $88 million in 2013, and 

$80 million in 2012, of debt issuance costs. Total assets and total liabilities were each reduced by the amounts above with no 

impact to net income or total shareholders’ equity previously reported.

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 

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

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. 

Summary of Changes in Net Income and Earnings per Share 

The following table is a summary reconciliation of the 

key changes, after-tax, in PG&E Corporation’s income 

available for common shareholders and EPS (as well as 

earnings from operations and EPS based on earnings 

from operations) for the year ended December 31, 2016 

compared to the year ended December 31, 2015 (see 

“Results of Operations” below). “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.

(in millions, except per share amounts) Earnings(1)   EPS (diluted)

Income Available for Common Shareholders - 2015 $ 874 $ 1.79

Add items impacting comparability:

Fines and penalties 578 1.19

Pipeline-related expenses 61 0.13

Legal and regulatory related expenses 35 0.07

Natural gas matters insurance recoveries (29) (0.06)

Earnings from Operations - 2015(2) $1,519 $ 3.12

2015 GT&S revenue(3) 300 0.60

Growth in rate base earnings 102 0.20

Regulatory and legal matters 1 –

Gain on disposition of SolarCity stock(4) (14) (0.03)

Increase in shares outstanding – (0.09)

Miscellaneous (24) (0.04)

Earnings from Operations - 2016(2) $1,884 $ 3.76

Less items impacting comparability:

Butte fire related costs (net of insurance)(5) (137) (0.27)

Fines and penalties(6) (307) (0.61)

Pipeline-related expenses(7) (67) (0.13)

Legal and regulatory related expenses(8) (43) (0.09)

GT&S capital disallowance(9) (130) (0.26)

GT&S revenue(10) 193 0.38

Income Available for Common Shareholders - 2016 $1,393 $ 2.78

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

(1) All amounts presented in the table above are tax-adjusted at PG&E Corporation’s tax rate of 40.75% except for fines, which 

are not tax deductible. See footnote (6) below.

(2) “Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability 

shown in footnotes (5) through (10).

(3) Represents the increase in 2016 revenues authorized December 1, 2016 in the final phase two decision of the Utility’s 2015 

GT&S rate case.

(4) Represents the gain recognized during the year ended December 31, 2015. No comparable gain was recognized in 2016.

(5) The Utility recorded costs of $232 million (before the tax impact of $95 million) during the year ended December 31, 2016 

associated with the Butte fire, net of insurance. This includes accrued charges of $750 million (before the tax impact of $306 

million) related to estimated third-party claims in connection with the Butte fire, partially offset by $625 million (before the 

tax impact of $255 million) as probable of insurance recovery. The Utility also incurred charges of $107 million (before the tax 

impact of $44 million) for Utility clean-up, repair, and legal costs associated with the Butte fire. 

(6) The Utility incurred costs of $498 million (before the tax impact of $191 million), during the year ended December 31, 2016

associated with fines and penalties. This includes costs of $412 million (before the tax impact of $168 million) associated 

with safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline 

investigations. The Utility also recorded $57 million (before the tax impact of $23 million) for disallowances imposed by the 

CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications. In addition, the 

Utility accrued fines of $26 million in connection with the final decision approved by the CPUC on August 18, 2016 in its 

investigation regarding natural gas distribution record-keeping practices and $3 million in connection with the maximum 

statutory fine imposed on January 26, 2017 in the federal criminal trial against the Utility. These fines are not tax deductible. 

Future fines or penalties may be imposed in connection with other enforcement, regulatory, and litigation activities regarding 

natural gas matters and regulatory communications. 

(7) The Utility incurred costs of $113 million (before the tax impact of $46 million), during the year ended December 31, 2016 

for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from 

transmission pipeline rights of way.

(8) The Utility incurred costs of $72 million (before the tax impact of $29 million), during the year ended December 31, 2016 for 

legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities 

regarding natural gas matters and regulatory communications. 

(9) The Utility incurred charges of $219 million (before the tax impact of $89 million), during the year ended December 31, 2016, 

for disallowed capital expenditures based on the CPUC final phase one decision dated June 23, 2016 in the 2015 GT&S rate 

case, including $134 million (before the tax impact of $54 million) for the disallowed portion of the 2011 through 2014 capital 

expenditures in excess of adopted amounts and $85 million (before the tax impact of $35 million) for the Utility’s estimate of 

2015 through 2018 capital expenditures that are likely to exceed authorized amounts. (See “Regulatory Matters” below for 

more information.)

(10) As a result of the timing of the CPUC’s final phase two decision in the 2015 GT&S rate case, the Utility recorded $325 million 

(before the tax impact of $132 million) in excess of the 2016 authorized revenue requirement during the twelve months 

ended December 31, 2016. 

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their future 

results of operations, financial condition, and cash flows 

will be materially affected by the following factors: 

đ The Outcome of Enforcement, Litigation, and Regulatory 

Matters. The Utility’s future financial results may continue 

to be impacted by the outcome of current and future 

enforcement, litigation, and regulatory matters, including 

the Butte fire litigation, potential costs associated with the 

alleged violations of the CPUC’s ex parte communication 

rules, the cost of complying with the terms of probation 

and monitorship imposed in the sentencing phase of 

the federal criminal trial and related remedial and other 

measures, and potential penalties in connection with 

the Utility’s self-report related to its customer service 

representatives’ drug and alcohol testing program. 

(See “Enforcement and Litigation Matters” in Note 13 

of the Notes to the Consolidated Financial Statements 

in Item 8.)

đ The Timing and Outcome of Ratemaking Proceedings. 

The Utility’s results may be impacted by the timing 

and outcome of its 2017 GRC, FERC TO rate case, and 

petition for modification related to its cost of capital. 

Based on the current schedule, the Utility expects a 

final decision in its 2017 GRC in the first half of 2017. 

(See “Regulatory Matters − 2017 General Rate Case” 

below for more information.) In addition, settlement 

negotiations are ongoing related to the Utility’s FERC TO 

rate case requesting a 2017 retail electric transmission 

revenue requirement. (See “Regulatory Matters − FERC 

Transmission Owner Rate Cases” below for more 

information.) Also, on February 7, 2017, the Utility filed 

with the CPUC a petition for modification related to its 

cost of capital. (See “Regulatory Matters – CPUC Cost 

of Capital” below for more information.) The outcome 

of regulatory proceedings can be affected by many 

factors, including arguments made by intervening 

parties, potential rate impacts, the Utility’s reputation, 

the regulatory and political environments, and other 

factors. 

đ The Ability of the Utility to Control and Recover 

Operating Costs and Capital Expenditures. The Utility 

is committed to delivering safe, reliable, sustainable, and 

affordable electric and gas services to its customers. 

Increasing demands from state laws and policies relating 

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

to increased renewable energy resources, the reduction 

of GHG emissions, the expansion of energy efficiency 

programs, the development and widespread deployment 

of distributed generation and self-generation resources, 

and the development of energy storage technologies have 

increased pressure on the Utility to achieve efficiencies 

in its operations in order to maintain the affordability 

of its service. In any given year the Utility’s ability to 

earn its authorized rate of return depends on its ability 

to manage costs within the amounts authorized in rate 

case decisions. The Utility forecasts that in 2017 it will 

incur unrecovered pipeline-related expenses ranging 

from $80 million to $125 million which primarily relate 

to costs to identify and remove encroachments from 

transmission pipeline rights-of-way. Also, the CPUC 

decision in the Utility’s 2015 GT&S rate case establishes 

various cost caps that will increase the risk of overspend 

over the rate case cycle. (See Note 13 of the Notes to 

the Consolidated Financial Statements in Item 8.)

đ The Amount and Timing of the Utility’s Financing Needs. 

PG&E Corporation contributes equity to the Utility 

as needed to maintain the Utility’s CPUC-authorized 

capital structure. In 2016, PG&E Corporation issued 

$842 million of common stock and used $835 million 

of the cash proceeds to make equity contributions 

to the Utility. PG&E Corporation forecasts that it will 

continue issuing a material amount of equity in future 

years, including $400 million to $600 million in 2017, 

primarily to support the Utility’s capital expenditures. 

PG&E Corporation may issue additional equity to fund 

unrecoverable pipeline-related expenses and to pay 

fines and penalties that may be required by the final 

outcomes of pending enforcement matters. These 

additional issuances could have a material dilutive impact 

on PG&E Corporation’s EPS. PG&E Corporation’s and 

the Utility’s ability to access the capital markets and the 

terms and rates of future financings could be affected by 

the outcome of the matters discussed in “Enforcement 

and Litigation Matters” in Note 13 of the Notes to the 

Consolidated Financial Statements in Item 8, changes 

in their respective credit ratings, general economic and 

market conditions, and other factors.

For more information about the factors and risks that 

could affect PG&E Corporation’s and the Utility’s future 

results of operations, financial condition, and cash flows, 

or that could cause future results to differ from historical 

results, see Item 1A. Risk Factors. In addition, this 2016 

Form 10-K contains forward-looking statements that are 

necessarily subject to various risks and uncertainties. 

These statements reflect management’s judgment and 

opinions that are based on current estimates, expectations, 

and projections about future events and assumptions 

regarding these events and management’s knowledge 

of facts as of the date of this 2016 Form 10-K. See the 

section entitled “Forward-Looking Statements” below for 

a list of some of the factors that may cause actual results 

to differ materially. PG&E Corporation and the Utility are 

not able to predict all the factors that may affect future 

results and do not undertake an obligation to update 

forward-looking statements, whether in response to new 

information, future events, or otherwise.

Results of Operations

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2016, 2015, and 2014. See 

“Key Factors Affecting Financial Results” above for further discussion about factors that could affect future results 

of operations.

PG&E Corporation

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the 

“Utility” section below. The following table provides a summary of net income available for common shareholders:

(in millions) 2016   2015   2014

Consolidated Total $1,393   $ 874   $1,436

PG&E Corporation   5     26     17

Utility $1,388   $ 848   $1,419

PG&E Corporation’s net income consists primarily of 

income taxes, interest expense on long-term debt, 

and other income from investments. Results include 

approximately $30 million and $45 million of realized 

gains and associated tax benefits related to an investment 

in SolarCity Corporation recognized in 2015 and 2014, 

respectively, with no corresponding gains in 2016.

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

Utility

The table below shows certain items from the Utility’s 

Consolidated Statements of Income for 2016, 2015, and 

2014. The table separately identifies the revenues and costs 

that impacted earnings from those that did not impact 

earnings. In general, expenses the Utility is authorized 

to pass through directly to customers (such as costs to 

purchase electricity and natural gas, as well as costs to 

fund public purpose programs) and the corresponding 

amount of revenues collected to recover those pass-through 

costs, do not impact earnings. In addition, expenses that 

have been specifically authorized (such as the payment 

of pension costs) and the corresponding revenues the 

Utility is authorized to collect to recover such costs, do 

not impact earnings.

Revenues that impact earnings are primarily those that have 

been authorized by the CPUC and the FERC to recover 

the Utility’s costs to own and operate its assets and to 

provide the Utility an opportunity to earn its authorized 

rate of return on rate base. Expenses that impact earnings 

are primarily those that the Utility incurs to own and 

operate its assets. 

2016 2015 2014

Revenues and Costs:       Revenues and Costs:       Revenues and Costs:    

(in millions)

That 

Impacted 

Earnings

That Did 

Not Impact 

Earnings

Total 

Utility  

That 

Impacted 

Earnings

That Did 

Not Impact 

Earnings

Total 

Utility  

That 

Impacted 

Earnings

That Did 

Not Impact 

Earnings

Total 

Utility

Electric operating revenues $ 7,955 $ 5,910 $13,865 $7,442 $6,215 $13,657 $ 7,059 $ 6,597 $13,656

Natural gas operating revenues 2,767 1,035 3,802 2,082 1,094 3,176 2,072 1,360 3,432

Total operating revenues 10,722 6,945 17,667 9,524 7,309 16,833 9,131 7,957 17,088

Cost of electricity – 4,765 4,765 – 5,099 5,099 – 5,615 5,615

Cost of natural gas – 615 615 – 663 663 – 954 954

Operating and maintenance 5,787 1,565 7,352 5,402 1,547 6,949 4,247 1,388 5,635

Depreciation, amortization, 

and decommissioning 2,754 – 2,754 2,611 – 2,611 2,432 – 2,432

Total operating expenses 8,541 6,945 15,486 8,013 7,309 15,322 6,679 7,957 14,636

Operating income 2,181 – 2,181 1,511 – 1,511 2,452 – 2,452

Interest income(1) 22 8 8

Interest expense(1) (819) (763) (720)

Other income, net(1) 88 87 77

Income before income taxes 1,472 843 1,817

Income tax provision 

(benefit)(1) 70 (19) 384

Net income 1,402 862 1,433

Preferred stock dividend 

requirement(1) 14 14 14

Income Available for 

Common Stock $ 1,388 $ 848 $ 1,419

(1) These items impacted earnings.

Utility Revenues and Costs that Impacted Earnings

The following discussion presents the Utility’s operating results for 2016, 2015, and 2014, focusing on revenues and 

expenses that impacted earnings for these periods.

Operating Revenues

The Utility’s electric and natural gas operating revenues 

that impacted earnings increased $1.2 billion or 13% in 2016 

compared to 2015, primarily as a result of approximately 

$700 million of incremental revenues authorized in the 

2015 GT&S rate case and approximately $425 million of 

additional base revenues as authorized by the CPUC in the 

2014 GRC decision and by the FERC in the TO rate case. 

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

The Utility included the authorized increase for the 2015 

GT&S rate case period in rates starting August 1, 2016. The 

Utility will collect, over a 36-month period, the difference 

between adopted revenue requirements and amounts 

previously collected in rates, retroactive to January 1, 2015. 

Accounting rules allow the Utility to recognize revenues in 

a given year only if they will be collected from customers 

within 24 months of the end of that year. As a result, the 

Utility will recognize the remaining $102 million in the 

first quarter of 2017. (See “Regulatory Matters” below.) 

The Utility’s electric and natural gas operating revenues 

that impacted earnings increased $393 million or 4% 

in 2015 compared to 2014, primarily as a result of 

approximately $490 million of additional base revenues 

as authorized by the CPUC in the 2014 GRC decision 

and by the FERC in the TO rate case. This increase was 

partially offset by the absence of approximately $110 

million of revenues the CPUC authorized the Utility to 

collect for recovery of certain PSEP-related costs during 

the same period in 2014.

Operating and Maintenance

The Utility’s operating and maintenance expenses that 

impacted earnings increased $385 million or 7% in 2016 

compared to 2015, primarily due to $857 million in charges 

for third-party claims, Utility clean-up, repair, and legal 

costs related to the Butte fire, $219 million in permanently 

disallowed capital spending (see “Regulatory Matters” 

below), $34 million in charges recorded in connection 

with the final CPUC decision related to the natural gas 

distribution facilities record-keeping investigation, the 

federal criminal trial, and the atmospheric corrosion 

inspection self-report, $24 million in higher pipeline-related 

expenses and legal and regulatory related expenses during 

the year ended December 31, 2016, an escalation related 

to labor, benefits, and service contracts, and accelerated 

transmission and distribution project work. These increases 

were partially offset by $500 million in charges associated 

with the Penalty Decision for customer refunds and fines 

incurred in 2015 with no corresponding charges in 2016 

and approximately $125 million in lower disallowed capital 

charges associated with the Penalty Decision in 2016. 

Additionally, the Utility recorded approximately $625 

million in probable insurance recoveries related to the Butte 

fire in the year ended December 31, 2016 as compared to 

$49 million of insurance recoveries for third-party claims 

related to the San Bruno accident for the same period 

in 2015. (See Note 13 of the Notes to the Consolidated 

Financial Statements in Item 8.) 

The Utility’s operating and maintenance expenses 

that impacted earnings increased $1.2 billion or 27% 

in 2015 compared to 2014, primarily due to $907 

million in charges associated with the Penalty Decision, 

consisting of $400 million for the customer bill credit, 

an additional $100 million charge for the fine payable to 

the state, and $407 million of disallowed capital charges. 

(See “Enforcement and Litigation Matters” in Note 13 

of the Notes to the Consolidated Financial Statements 

in Item 8.) The increase is also due to higher labor and 

benefit-related expenses of approximately $100 million 

and fewer insurance recoveries for third-party claims and 

associated legal costs of $63 million related to the San 

Bruno accident. No further insurance recoveries related 

to these claims are expected. These increases were offset 

by $116 million in disallowed capital recorded in 2014 

related to the PSEP. 

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning 

expenses increased $143 million or 5% in 2016 compared 

to 2015 and $179 million or 7% in 2015 compared to 2014. 

In 2016, the increase was primarily due to the impact of 

capital additions. In 2015, the increase was primarily due 

to the impact of capital additions and higher depreciation 

rates as authorized by the FERC in the TO rate case.

Interest Expense

The Utility’s interest expenses increased by $56 million or 7% 

in the year ended December 31, 2016 compared to the same 

period in 2015, primarily due to the issuance of additional 

long-term debt. The Utility’s interest expenses increased 

by $43 million or 6% in the year ended December 31, 

2015 compared to the same period in 2014, primarily due 

to the issuance of long-term debt.

Interest Income and Other Income, Net

There were no material changes to interest income and 

other income, net for the periods presented.

Income Tax Provision 

The Utility’s income tax provision increased $89 million, 

or 468%, in 2016 as compared to 2015. The increase in the 

tax provision was primarily the result of the statutory tax 

effect of higher pre-tax income in 2016 compared to 2015, 

partially offset by higher tax benefits from property-related 

timing differences in 2016 compared to 2015. The higher 

effective tax rate is driven by higher pre-tax earnings in 

2016, partially offset by rate impact from property-related 

timing differences.

The Utility’s income tax provision decreased $403 million, 

or 105%, in 2015 as compared to 2014. This is primarily 

the result of the statutory tax effect of lower pre-tax 

income and higher tax benefits from property-related 

timing differences in 2015 as compared to 2014. The lower 

effective tax rate in 2015 is the result of lower pre-tax 

earnings in 2015 and rate impact from property-related 

timing differences.

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

The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:

2016 2015   2014

Federal statutory income tax rate 35.0% 35.0% 35.0%

Increase (decrease) in income tax rate resulting from:

State income tax (net of federal benefit)(1) (2.2) (4.8) 1.6

Effect of regulatory treatment of fixed asset differences(2) (23.4) (33.7) (14.7)

Tax credits (0.8) (1.3) (0.7)

Benefit of loss carryback (1.1) (1.5) (0.8)

Non-deductible penalties(3) 0.8 4.3 0.3

Other, net(4) (3.5) (0.2) 0.4

Effective tax rate 4.8% (2.2)% 21.1%

(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts reflect an agreement with the IRS

on a 2011 audit related to electric transmission and distribution repairs deductions. 

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 

2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacted only 2016. All amounts are 

impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue 

requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and 

certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and 

the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. 

Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E 

Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts 

will be recovered from or returned to customers in future rates. 

(3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution facilities 

record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year ended 

December 31, 2015. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in Note 13 of 

the Notes to the Consolidated Financial Statements in Item 8. 

(4) In 2016, the amount primarily represents the impact of tax audit settlements.

Utility Revenues and Costs that did not Impact Earnings 

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs, see below for more 

detail.

Cost of Electricity

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy 

resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase 

agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk 

management activities. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.) 

(in millions) 2016   2015   2014

Cost of purchased power $ 4,510 $ 4,805 $ 5,266

Fuel used in own generation facilities 255 294 349

Total cost of electricity $ 4,765 $ 5,099 $ 5,615

Average cost of purchased power per kWh(1) $ 0.109 $ 0.100 $ 0.101

Total purchased power (in millions of kWh)(2) 41,324 48,175 52,008

(1) Cost of purchased power was impacted primarily by a higher percentage of renewable energy resources. 

(2) The decrease in purchased power primarily resulted from an increase in generation from the Utility’s Diablo Canyon nuclear 

power plant and its hydroelectric facilities as well as lower electric customer demand. 

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation 

facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of 

electricity.

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

Cost of Natural Gas

The Utility’s cost of natural gas includes the costs of 

procurement, storage and transportation of natural gas, 

costs to comply with California’s cap-and-trade program, 

and realized gains and losses on price risk management 

activities. (See Note 9 of the Notes to the Consolidated 

Financial Statements in Item 8.) The Utility’s cost of 

natural gas is impacted by the market price of natural 

gas, changes in the cost of storage and transportation, 

and changes in customer demand. 

(in millions) 2016   2015   2014

Cost of natural gas sold $ 481 $ 518 $ 813

Transportation cost of natural gas sold 134 145 141

Total cost of natural gas $ 615 $ 663 $ 954

Average cost per Mcf of natural gas sold $2.45 $2.74 $4.37

Total natural gas sold (in millions of Mcf) 196 189 186

Operating and Maintenance Expenses

The Utility’s operating expenses that did not impact 

earnings include certain costs that the Utility is authorized 

to recover as incurred such as pension contributions and 

public purpose programs costs. If the Utility were to spend 

more than authorized amounts, these expenses could 

have an impact to earnings. For 2016, 2015, and 2014, no 

material amounts were incurred above authorized amounts.

Liquidity and Financial Resources 

Overview

The Utility’s ability to fund operations, finance capital 

expenditures, and make distributions to PG&E Corporation 

depends on the levels of its operating cash flows and access 

to the capital and credit markets. The CPUC authorizes 

the Utility’s capital structure, the aggregate amount of 

long-term and short-term debt that the Utility may issue, 

and the revenue requirements the Utility is able to collect 

to recover its cost of capital. The Utility generally utilizes 

equity contributions from PG&E Corporation and longterm senior unsecured debt issuances to maintain its 

CPUC-authorized long-term capital structure consisting 

of 52% equity and 48% debt and preferred stock. (See 

“Ratemaking Mechanisms” in Item 1.) The Utility relies on 

short-term debt, including commercial paper, to fund 

temporary financing needs. 

PG&E Corporation’s ability to fund operations, make 

scheduled principal and interest payments, fund equity 

contributions to the Utility, and pay dividends primarily 

depends on the level of cash distributions received from 

the Utility and PG&E Corporation’s access to the capital 

and credit markets. PG&E Corporation has material 

stand-alone cash flows related to the issuance of equity 

and long-term debt, dividend payments, and issuances 

and repayments under its revolving credit facility and 

commercial paper program. PG&E Corporation relies on 

short-term debt, including commercial paper, to fund 

temporary financing needs.

PG&E Corporation’s and the Utility’s credit ratings may be 

affected by the ultimate outcome of pending enforcement 

and litigation matters. Credit rating downgrades may 

increase the cost and availability of short-term borrowing, 

including commercial paper, the costs associated with 

credit facilities, and long-term debt costs. In addition, some 

of the Utility’s commodity contracts contain collateral 

posting provisions tied to the Utility’s credit rating from 

each of the major credit rating agencies. If the Utility’s 

credit rating were to fall below investment grade, the Utility 

would be required to post additional cash immediately to 

fully collateralize some of its net liability positions. (See 

Notes 9 and 13 of the Notes to the Consolidated Financial 

Statements in Item 8.) 

PG&E Corporation’s equity contributions to the Utility 

are funded primarily through common stock issuances. 

PG&E Corporation forecasts that it will issue between 

$400 million and $600 million in common stock during 

2017, primarily to fund equity contributions to the Utility. 

The Utility’s equity needs will continue to be affected by 

the timing and outcome of unrecoverable pipeline-related 

expenses and by fines, penalties and claims that may be 

imposed in connection with the matters described in 

“Enforcement and Litigation Matters” in Note 13 of the 

Notes to the Consolidated Financial Statements in Item 8 

below. Common stock issuances by PG&E Corporation to 

fund these needs could have a material dilutive impact 

on PG&E Corporation’s EPS. 

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

Cash and Cash Equivalents 

Cash and cash equivalents consist of cash and short-term, 

highly liquid investments with original maturities of three 

months or less. PG&E Corporation and the Utility maintain 

separate bank accounts and primarily invest their cash 

in money market funds. In addition to cash and cash 

equivalents, the Utility holds restricted cash that, prior to 

October 2016, primarily consisted of cash held in escrow 

pending the resolution of the remaining disputed claims 

that were filed in the Utility’s reorganization proceeding 

under Chapter 11 of the U.S. Bankruptcy Code. In October 

2016, the Utility received approval from the bankruptcy 

court to release the remaining $161 million of cash held 

in escrow to unrestricted cash for use by the Utility. (See 

“Resolution of Remaining Chapter 11 Disputed Claims” 

in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.) 

Financial Resources

Debt and Equity Financings

The Utility issued $1.0 billion in long-term debt and 

$500 million in short-term debt during the year ended 

December 31, 2016. (See Note 4 of the Notes to the 

Consolidated Financial Statements in Item 8.) 

During 2016, PG&E Corporation sold 2.6 million shares of its 

common stock under the February 2015 equity distribution 

agreement for cash proceeds of $149 million, net of 

commissions paid of $1.3 million. As of December 31, 2016, 

the remaining gross sales available under this agreement 

were $275 million.

In August 2016, PG&E Corporation sold 4.9 million shares 

of its common stock in an underwritten public offering 

for net cash proceeds of $309 million.

In addition, during 2016, PG&E Corporation sold 7.4 million 

shares of common stock under its 401(k) plan, the Dividend 

Reinvestment and Stock Purchase Plan, and share-based 

compensation plans for total cash proceeds of $364 million. 

The proceeds from equity issuances were used for general 

corporate purposes, including the contribution of equity 

to the Utility. For the year ended December 31, 2016, PG&E 

Corporation made equity contributions to the Utility of 

$835 million. Additionally, PG&E Corporation and the Utility 

expect to continue to issue long-term and short-term 

debt for general corporate purposes and to maintain the 

CPUC-authorized capital structure during 2017.

Revolving Credit Facilities and Commercial 

Paper Programs

In June 2016, PG&E Corporation and the Utility each 

extended the termination dates of their existing revolving 

credit facilities by one year from April 27, 2020 to April 27, 

2021. At December 31, 2016, PG&E Corporation and the 

Utility had $300 million and $1.9 billion available under their 

respective $300 million and $3.0 billion revolving credit 

facilities. (See Note 4 of the Notes to the Consolidated 

Financial Statements in Item 8.)

PG&E Corporation and the Utility can issue commercial 

paper up to the maximum amounts of $300 million and 

$2.5 billion, respectively. For the year ended December 31, 

2016, PG&E Corporation and the Utility had an average 

outstanding commercial paper balance of $84 million 

and $837 million, and a maximum outstanding balance of 

$176 million and $1.4 billion, respectively. At December 31, 

2016, the Utility had an outstanding commercial paper 

balance of $1.0 billion and PG&E Corporation did not have 

any commercial paper outstanding. (See Note 4 of the 

Notes to the Consolidated Financial Statements in Item 8.) 

The revolving credit facilities require that PG&E Corporation 

and the Utility maintain a ratio of total consolidated debt 

to total consolidated capitalization of at most 65% as 

of the end of each fiscal quarter. At December 31, 2016, 

PG&E Corporation’s and the Utility’s total consolidated 

debt to total consolidated capitalization was 51% and 

50%, respectively. PG&E Corporation’s revolving credit 

facility agreement also requires that PG&E Corporation 

own, directly or indirectly, at least 80% of the common 

stock and at least 70% of the voting capital stock of the 

Utility. In addition, the revolving credit facilities include 

usual and customary provisions regarding events of 

default and covenants including covenants limiting liens 

to those permitted under PG&E Corporation’s and the 

Utility’s senior note indentures, mergers, and imposing 

conditions on the sale of all or substantially all of PG&E 

Corporation’s and the Utility’s assets and other fundamental 

changes. At December 31, 2016, PG&E Corporation and 

the Utility were in compliance with all covenants under 

their respective revolving credit facilities. 

Dividends 

In May 2016, the Board of Directors of PG&E Corporation 

and the Utility each adopted a new target dividend payout 

ratio range of 55% to 65% of earnings, with a target to 

reach a payout ratio of approximately 60% by 2019. 

Each Board of Directors retains authority to change the 

respective common stock dividend policy and dividend 

payout ratio at any time, especially if unexpected events 

occur that would change its view as to the prudent level 

of cash conservation. No dividend is payable unless and 

until declared by the applicable Board of Directors.

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

PG&E Corporation

For the first quarter of 2016, the Board of Directors of 

PG&E Corporation declared a common stock dividend 

of $0.455 per share. In May 2016, the Board of Directors 

of PG&E Corporation declared a new quarterly common 

stock dividend of $0.49 per share. As a result, for each of 

the second, third and fourth quarters of 2016, the Board 

of Directors of PG&E Corporation declared a common 

stock dividend of $0.49 per share. In 2016, total dividends 

were $1.925 per share. For each of the quarters in 2015 

and 2014, the Board of Directors of PG&E Corporation 

declared common stock dividends of $0.455 per share, 

for annual dividends of $1.82 per share. Dividends paid 

to common shareholders by PG&E Corporation were 

$921 million in 2016, $856 million in 2015, and $828 million 

in 2014. In December 2016, the Board of Directors of PG&E 

Corporation declared quarterly dividends of $0.49 per 

share, totaling $248 million, of which approximately 

$243 million was paid on January 15, 2017 to shareholders 

of record on December 30, 2016.

Utility

For the first quarter of 2016, the Board of Directors of the 

Utility declared a common stock dividend of $179 million 

to PG&E Corporation. For each of the second, third and 

fourth quarters of 2016, the Board of Directors of the Utility 

declared common stock dividends of $244 million to PG&E 

Corporation. In 2016, total dividends paid by the Utility 

to PG&E Corporation were $911 million. For each of the 

quarters in 2015 and 2014, the Board of Directors of the 

Utility declared common stock dividends of $179 million to 

PG&E Corporation for annual dividends paid of $716 million 

in 2015 and 2014. In addition, the Utility paid $14 million 

of dividends on preferred stock in each of 2016, 2015, and 

2014. The Utility’s preferred stock is cumulative and any 

dividends in arrears must be paid before the Utility may 

pay any common stock dividends. In December 2016, the 

Board of Directors of the Utility declared dividends on its 

outstanding series of preferred stock, payable on February 

15, 2017, to shareholders of record on January 31, 2017.

Utility Cash Flows

The Utility’s cash flows were as follows:

Year Ended December 31,

(in millions) 2016   2015  2014

Net cash provided by operating activities $ 4,344 $ 3,747 $ 3,632

Net cash used in investing activities (5,526) (5,211) (4,799)

Net cash provided by financing activities 1,194 1,468 1,157

Net change in cash and cash equivalents $ 12 $ 4 $ (10)

Operating Activities

The Utility’s cash flows from operating activities primarily 

consist of receipts from customers less payments of 

operating expenses, other than expenses such as 

depreciation that do not require the use of cash. During 

2016, net cash provided by operating activities increased by 

$597 million compared to 2015. This increase was partially 

due to the Utility receiving an additional $170 million in tax 

refunds in 2016 than in 2015. The remaining increase was 

primarily due to fluctuations in activities within the normal 

course of business such as timing and amount of customer 

billings and vendor billings and payments. During 2015, 

net cash provided by operating activities increased by 

$115 million compared to 2014. This increase was primarily 

due to higher base revenue collections authorized in the 

2014 GRC and lower purchased power costs (see “Cost of 

Electricity” under “Results of Operations – Utility Revenues 

and Costs that did not Impact Earnings” above), offset by 

the payment of a $300 million fine to the State General 

Fund as required by the Penalty Decision. 

Future cash flow from operating activities will be affected 

by various factors, including: 

đ the timing and outcome of ratemaking proceedings, 

including the 2017 GRC and the TO rate case, and cost 

of capital proceeding;

đ the timing and amounts of costs that may be incurred 

in connection with claims associated with Butte fire and 

the timing and amount of related insurance recoveries, 

fines or penalties that may be imposed in connection with 

the ex parte OII or costs in connection with a potential 

settlement, fines or penalties that may be imposed 

in connection with other enforcement and litigation 

matters, costs associated with the terms of probation 

and monitorship imposed in the sentencing phase of 

the federal criminal trial, and potential remedial and 

other measures that could be imposed on the Utility 

in connection with the DOI debarment proceeding 

(see “Enforcement and Litigation Matters” in Note 13 

of the Notes to the Consolidated Financial Statements 

in Item 8 below);

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đ the timing and amount of costs the Utility incurs, but 

does not recover, associated with its natural gas system;

đ the timing and amount of tax payments (including the 

bonus depreciation), tax refunds, net collateral payments, 

and interest payments, as well as changes in tax regulations 

that could be adopted by Congress as a result of the new 

federal administration and other proposals; and

đ the timing of the resolution of the Chapter 11 disputed 

claims and the amount of principal and interest on these 

claims that the Utility will be required to pay.

Investing Activities

Net cash used in investing activities increased by $315 million 

during 2016 as compared to 2015 primarily due to 

an increase of approximately $440 million in capital 

expenditures, partially offset by an increase in restricted 

cash released from escrow by approximately $160 million. 

(See “Resolution of Remaining Chapter 11 Disputed Claims” 

in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.) Net cash used in investing activities 

increased by $412 million during 2015 as compared to 

2014 primarily due to an increase of $340 million in 

capital expenditures and an increase in net purchases of 

nuclear decommissioning trust investments in 2015 as 

compared to net proceeds associated with sales of nuclear 

decommissioning trust investments in 2014. 

Future cash flows used in investing activities are 

largely dependent on the timing and amount of capital 

expenditures. The Utility estimates that it will incur 

approximately $6.0 billion in capital expenditures in each 

of the years 2017, 2018, and 2019.

Financing Activities

During 2016, net cash provided by financing activities 

decreased by $274 million as compared to 2015. During 

2015, net cash provided by financing activities increased 

by $311 million as compared to 2014. Cash provided by or 

used in financing activities is driven by the Utility’s financing 

needs, which depend on the level of cash provided by 

or used in operating activities, the level of cash provided 

by or used in investing activities, the conditions in the 

capital markets, and the maturity date of existing debt 

instruments. The Utility generally utilizes long-term debt 

issuances and equity contributions from PG&E Corporation 

to maintain its CPUC-authorized capital structure, and relies 

on short-term debt to fund temporary financing needs.

Contractual Commitments

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at 

December 31, 2016:

Payment due by period

(in millions)

Less Than

1 Year

1-3

Years

3-5

Years

More Than 

5 Years Total

Utility 

Long-term debt(1): $ 1,495 $ 2,408 $ 3,328 $ 22,452 $ 29,683

Purchase obligations(2): 

Power purchase agreements: 3,417 6,175 5,844 29,506 44,942

Natural gas supply, transportation, 

and storage

536 329 241 455 1,561

Nuclear fuel agreements 97 188 179 136 600

Pension and other benefits(3) 388 776 776 388 2,328

Operating leases(2) 44 80 75 168 367

Preferred dividends(4) 14 28 28 – 70

PG&E Corporation 

Long-term debt(1): 8 362 – – 370

Total Contractual Commitments $ 5,999 $ 10,346 $10,471 $ 53,105 $ 79,921

(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 

2016 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. (See Note 4 of the 

Notes to the Consolidated Financial Statements in Item 8.) 

(2) See “Purchase Commitments” and “Other Commitments” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

(3) See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. Payments into the pension and other benefits 

plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the 

amount shown in the column entitled “more than 5 years” represents only 1 year of contributions for the Utility’s pension and 

other benefit plans.

(4) Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed 

period of five years.

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The contractual commitments table above excludes 

potential payments associated with unrecognized tax 

positions. Due to the uncertainty surrounding tax audits, 

PG&E Corporation and the Utility cannot make reliable 

estimates of the amounts and periods of future payments 

to major tax jurisdictions related to unrecognized tax 

benefits. Matters relating to tax years that remain subject 

to examination are discussed in Note 8 of the Notes to 

the Consolidated Financial Statements in Item 8.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have any 

off-balance sheet arrangements that have had, or are 

reasonably likely to have, a current or future material effect 

on their financial condition, changes in financial condition, 

revenues or expenses, results of operations, liquidity, 

capital expenditures, or capital resources, other than those 

discussed in Note 13 of the Notes to the Consolidated 

Financial Statements (the Utility’s commodity purchase 

agreements) in Item 8.

Enforcement and Litigation Matters

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies 

related to the enforcement and litigation matters described in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8. The outcome of these matters, individually or in the aggregate, could have a material effect on 

PG&E Corporation’s and the Utility’s future financial results. 

Butte Fire Litigation

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 a press release also issued on April 

28, 2016, Cal Fire indicated that it will seek to recover 

firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master 

complaint against the Utility and its two vegetation 

management contractors in the Superior Court of California 

for Sacramento County. Subrogation insurers also filed a 

separate master complaint on the same date. The California 

Judicial Council had previously authorized the coordination 

of all cases in Sacramento County. As of December 31, 2016, 

complaints have been filed against the Utility and its two 

vegetation management contractors in the Superior Court 

of California in the Counties of Calaveras, San Francisco, 

Sacramento, and Amador involving approximately 

1,950 individual plaintiffs representing approximately 

950 households and their insurance companies. These 

complaints are part of or are in the process of being 

added to the two master complaints. Plaintiffs seek to 

recover damages and other costs, principally based on 

inverse condemnation and negligence theories of liability. 

The number of individual complaints and plaintiffs may 

increase in the future. 

The Utility continues mediating and settling cases. The 

next case management conference is scheduled for 

March 2, 2017.

In connection with this matter, the Utility may be liable for 

property damages, interest, and attorneys’ fees without 

having been found negligent, through the theory 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. The Utility believes it was not negligent; 

however, there can be no assurance that a court or jury 

would agree with the Utility. The Utility believes that it is 

probable that it will incur a loss of at least $750 million 

for all potential damages described above. This amount is 

based on assumptions about the number, size, and type 

of structures damaged or destroyed, the contents of such 

structures, the number and types of trees damaged or 

destroyed, as well as assumptions about personal injury 

damages, attorneys’ fees, fire suppression costs, and 

other damages that the Utility could be liable for under 

the theories of inverse condemnation and/or negligence.

The Utility believes that it is reasonably possible that it 

will incur losses related to Butte fire claims in excess of 

$750 million accrued through December 31, 2016 but is 

currently unable to reasonably estimate the upper end 

of the range of losses because it is still in an early stage 

of the evaluation of claims, the mediation and settlement 

process, and discovery. The process for estimating costs 

associated with claims relating to the Butte fire requires 

management to exercise significant judgment based on a 

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number of assumptions and subjective factors. As more 

information becomes known, including additional discovery 

from the plaintiffs and results from the ongoing mediation 

and settlement process, management estimates and 

assumptions regarding the financial impact of the Butte 

fire may result in material increases to the loss accrued. 

The Utility has liability insurance from various insurers, which 

provides coverage for third-party liability attributable to 

the Butte fire in an aggregate amount of approximately 

$900 million. Such insurance coverage is subject to the 

terms and limitations of the applicable policies and may 

not be sufficient to cover the Utility’s ultimate liability.

The Utility records insurance recoveries when it is deemed 

probable that a recovery will occur and the Utility can 

reasonably estimate the amount or its range. The Utility 

has recorded $625 million for probable insurance recoveries 

in connection with losses related to the Butte fire. While 

the Utility plans to seek recovery of all insured losses, it is 

unable to predict the ultimate amount and timing of such 

insurance recoveries. In addition, the Utility is pursuing 

coverage under the insurance policies of its two vegetation 

management contractors, including under policies where 

the Utility is listed as an additional insured. Recoveries 

of any amounts under these policies are uncertain. If the 

ultimate liability exceeds the amounts recovered through 

insurance, the Utility would expect to seek authorization 

from the CPUC and the FERC to recover any excess amounts 

from customers. The Utility is unable to predict the timing 

or outcome of any such proceeding, or the timing of 

recovery from customers, if any. The resolution of claims, 

any future regulatory proceeding, and the recoveries from 

other potentially responsible parties and customers could 

extend over a number of years. (For more information, see 

“Enforcement and Litigation Matters” in Note 13 of the 

Notes to the Consolidated Financial Statements in Item 8.)

Department of Interior Inquiry

In September 2015, the Utility was notified that the DOI 

had initiated an 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. The Utility filed 

its initial response on November 2, 2015 to demonstrate 

that it is a “presently responsible” contractor under 

federal procurement regulations and that it believes 

suspension or debarment is not appropriate. On April 8, 

2016, the Utility received a series of follow-up questions 

from the DOI regarding its November 2015 submission. 

On November 21, 2016, the Utility provided the DOI with 

a supplemental submission in which it addressed the 

DOI’s April 8, 2016 questions. The Utility continues to 

fully cooperate with the DOI. 

As a result of the August 9, 2016 jury’s verdict in the 

federal criminal trial, the Utility updated its registration on 

the federal government’s System for Award Management 

(SAM), a federal procurement database, to reflect the 

verdict. Under federal law, the government may not enter 

into a contract with any corporation that was convicted 

of a felony criminal violation under any federal law within 

the preceding 24 months, where the awarding agency is 

aware of the conviction, unless an agency has considered 

suspension or debarment of the corporation and made a 

determination that this action is not necessary to protect 

the interests of the government. 

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 federal 

government’s business interests. The agreement will be 

effective until superseded by an amended agreement 

or determination. The agreement also provides that the 

DOI is still conducting a review to determine whether the 

Utility has an effective compliance and ethics program 

and that the DOI is required to use its best efforts to 

complete its review before the end of 2017. If the DOI 

determines that the Utility’s 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 could incur material costs, not recoverable 

through rates, to implement remedial and other measures 

that could be imposed, the amount of which the Utility 

is currently unable to estimate.

Litigation Related to the San Bruno Accident 

and Natural Gas Spending

As of December 31, 2016, there were seven purported 

derivative lawsuits seeking recovery on behalf of PG&E 

Corporation and the Utility for alleged breaches of fiduciary 

duty by officers and directors, among other claims. 

Four of the complaints were consolidated as the San Bruno 

Fire Derivative Cases and are pending in the Superior 

Court of California, County of San Mateo. The remaining 

three cases are Tellardin v. Anthony F. Earley, Jr.,. et al., 

Iron Workers Mid-South Pension Fund v. Johns, et al., and

Bushkin v. Rambo et al.

On December 8, 2015, the California Court of Appeal issued 

a writ of mandate to the Superior Court of California, San 

Mateo County, ordering the court to stay all proceedings 

in the four consolidated San Bruno Fire Derivative Cases 

pending conclusion of the federal criminal proceedings 

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against the Utility. On November 16, 2016, counsel in the 

four consolidated San Bruno Fire Derivative cases, as well 

as counsel in the Tellardin action, appeared for a status 

conference in the San Mateo Superior Court. The court 

reaffirmed that all proceedings in these actions were 

stayed until the conclusion of the Utility’s federal criminal 

proceeding, at which point they were directed to meet 

and confer and report back to the court. The parties 

completed a mediation session on December 8-9, 2016 

and continue discussions about the potential resolution 

of the matter. These actions remain stayed. 

Bushkin v. Rambo et al., pending in the United States 

District Court for the Northern District of California, has 

been designated by the plaintiff as related to the pending 

shareholder derivative suit Iron Workers Mid-South Pension 

Fund v. Johns, et al., discussed below. The plaintiff in the 

Bushkin lawsuit has agreed that this case should be stayed 

pending conclusion of the federal criminal trial against the 

Utility and, on May 3, 2016, the judge entered a stipulated 

order staying the case. The order also provides that the 

parties should meet and confer within 30 days after the 

criminal trial concludes and provide the court a status 

update. Despite the stay of his complaint, on June 20, 2016 

the Bushkin plaintiff filed a petition in the Superior Court 

of California, San Francisco County, seeking to enforce 

the plaintiff’s claimed right as a shareholder to inspect 

certain PG&E Corporation accounting books and records 

pursuant to section 1601 of the California Corporations 

Code. On July 25, 2016, PG&E Corporation filed a motion 

to stay plaintiff’s petition until the appellate stay of the 

San Bruno Fire Derivative Cases has been lifted, or, in the 

alternative, a demurrer asking the court to dismiss plaintiff’s 

petition. On August 29, 2016, the San Francisco Superior 

Court granted PG&E Corporation’s motion, and indicated 

that plaintiff’s petition was stayed pending resolution of 

the criminal matter against the Utility. On January 13, 2017, 

the parties submitted a joint case management statement 

advising the court that, because the Utility had not yet been 

sentenced, the case should remain stayed until at least 

March 10, 2017, when the parties will advise the court of 

further developments. While the Utility was sentenced 

in the federal criminal proceeding on January 26, 2017, 

this matter remains stayed until at least March 10, 2017.

The Iron Workers action pending in the United States 

District Court for the Northern District of California has 

been stayed pending the resolution of the San Bruno Fire 

Derivative Cases. On May 5, 2016, the court ordered the 

parties to meet and confer within 30 days after the criminal 

trial concludes and provide the court a status update. At 

the court’s request, on August 22, 2016, the parties filed a 

statement requesting that the case continue to be stayed 

until resolution of the San Bruno Fire Derivative Cases. 

On August 31, 2016, the court set a case management 

conference for September 30, 2016, and requested 

the parties to file a joint case management conference 

statement by September 23, 2016. On September 30, 

2016, the court decided to continue the stay pending the 

resolution of the federal criminal proceeding against the 

Utility and ordered the parties to submit a joint status 

report on or before March 15, 2017. This matter remains 

stayed until at least March 15, 2017.

For more information about the federal criminal proceeding, 

see Note 13 of the Notes to the Consolidated Financial 

Statements and Item 3 Legal Proceedings.

PG&E Corporation and the Utility are uncertain when and 

how the above lawsuits will be resolved.

Regulatory Matters

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory 

agencies. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s financial 

condition, results of operations, and cash flows.

2017 General Rate Case 

On September 1, 2015, the Utility filed its 2017 GRC 

application with the CPUC. On August 3, 2016, the Utility, 

together with ORA, TURN, and 12 other intervening 

parties filed a motion with the CPUC seeking approval 

of a settlement agreement that resolves nearly all of 

the issues raised by the parties in the Utility’s 2017 GRC. 

All parties who filed testimony in the case joined the 

settlement agreement, which was the subject of a oneday workshop overseen by the assigned commissioner 

and ALJ. The settlement agreement will ultimately be 

considered by the full commission. In the GRC proceeding, 

the CPUC will determine the annual amount of base 

revenues (or “revenue requirements”) that the Utility will 

be authorized to collect from customers from 2017 through 

2019 or 2020 to recover its anticipated costs for electric 

distribution, natural gas distribution, and electric generation 

operations and to provide the Utility an opportunity to 

earn its authorized rate of return. (The Utility’s revenue 

requirements for other portions of its operations, such as 

electric transmission, natural gas transmission and storage 

services, and electricity and natural gas purchases, are 

authorized in other regulatory proceedings overseen by 

the CPUC or the FERC.) 

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Revenue Requirements and Attrition Year Revenues

The settlement agreement proposed that the Utility’s 

2016 authorized revenue requirement of $7.9 billion be 

increased by $88 million, effective January 1, 2017. The 

settlement agreement further proposed an increase to 

the authorized 2017 revenues of $444 million in 2018 and 

an additional increase of $361 million in 2019, as shown 

in the table below.

The settlement agreement identified two contested issues. 

First, the parties were unable to agree on whether there 

should be a third post-test year or “attrition” year for this 

GRC cycle. ORA and the Utility recommend a third posttest year for this cycle that would provide for an additional 

increase of $361 million in 2020. TURN and certain other 

settling parties oppose the third post-test year. The other 

contested issue concerns whether the Utility should be 

authorized to establish a new balancing account for costs 

arising from the CPUC’s rulemaking on natural gas leak 

abatement. The Utility and certain settling parties support 

the balancing account. TURN and certain other settling 

parties do not. ORA does not oppose it. Interested parties 

filed comments and reply comments on the contested 

issues and these issues were also discussed at a one-day 

workshop on August 30, 2016. 

The table below summarizes the differences between the 

amount of revenue requirement increases included in the 

Utility’s request, as updated in the Utility’s supplemental 

testimony filed on February 22, 2016 and its May 27, 2016 

rebuttal testimony, and the amount proposed in the 

settlement agreement:

(in millions)

Increase 

Requested in GRC 

Application 

Increase Proposed 

in Settlement 

Agreement 

Difference(1) 

(Decrease from GRC 

Application)

Year

2017 $ 319 $ 88 $(231)

2018 467 444 (23)

2019 368 361 (7)

2020(2) N/A 361 N/A

(1) Rounded for presentation purposes.

(2) Whether or not revenues should be authorized for 2020 is a contested issue.

The following table shows the difference between the Utility’s requested increases in 2017 revenue requirements by 

line of business and the amounts proposed in the settlement agreement:

(in millions)

Increase 

Requested in GRC 

Application

Increase/(Decrease) 

Proposed in Settlement 

Agreement 

Difference(1) 

(Decrease from GRC 

Application)

Line of Business:

Electric distribution $ 67 1.6% $ (62) (1.5)% $(128)

Gas distribution 59 3.4 (3) (0.2) (62)

Electric generation 193 9.9 153 7.8 (40)

2017 revenue requirement increases $ 319 4.0% $ 88 1.1% $(231)

(1) Rounded for presentation purposes. 

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The following table shows the differences, by line of business and cost category, between the amount of revenue 

requirements included in the GRC application and the amount proposed in the settlement agreement, as well as the 

differences between the 2016 authorized revenue requirements and (i) the GRC application and (ii) the amounts 

proposed in the settlement agreement:

(in millions)(1)

Amounts

Requested in

2017 GRC

Application

Amounts 

Proposed in

Settlement

Agreement 

Difference

(Decrease)

Increase/

(Decrease)

2016 vs. 2017

Application 

Increase/

(Decrease)

2016 vs. 

Agreement

Line of Business:

Electric distribution $ 4,279 $ 4,151 $(128) $ 67 $ (62)

Gas distribution 1,801 1,738 (62) 59 (3)

Electric generation 2,155 2,115 (40) 193 153

Total revenue requirements $ 8,235 $ 8,004 $(231) $ 319 $ 88

Cost Category:

(in millions)(1)

Operations and maintenance $ 1,825 $ 1,794 $ (31) $ 161 $131

Customer services 361 334 (27) 42 15

Administrative and general 975 912 (62) (36) (99)

Less: Revenue credits (140) (152) (12) (9) (21)

Franchise fees, taxes other than income, 

and other adjustments

184 170 (14) 146 132

Depreciation (including costs of asset 

removal), return, and income taxes

5,030 4,946 (84) 15 (70)

Total revenue requirements $ 8,235 $ 8,004 $(231) $ 319 $ 88

(1) Rounded for presentation purposes.

The settlement agreement proposed reductions in the 

following areas forecast in the GRC application. For 

gas distribution, reductions are proposed for corrosion 

control, leak management, gas operations technology, 

and new business. For electric distribution, reductions 

are proposed for overhead maintenance, capacity, 

technology, mapping and records, reliability, substation 

management, new business, and undergrounding work. 

For electric distribution, the capital-related reductions 

are offset in part by increases in the replacement and 

installation of additional units in specific asset areas. 

For electric generation, the settlement agreement 

proposed to move costs related to Diablo Canyon seismic 

studies from the GRC to the Utility’s Energy Resource 

Recovery Account proceeding. Proposed reductions in 

the customer service area largely relate to the removal 

of certain costs from the forecast related to residential 

rate reform implementation. Some of these costs would 

be recoverable through the existing Residential Rates 

Reform Memorandum Account, and the Utility could 

seek recovery of the remaining costs in a future filing 

with the CPUC. Additionally, a number of companywide reductions, including reductions to the ShortTerm Incentive Plan and certain employee benefits, are 

proposed in the settlement agreement.

Balancing Accounts

The settlement agreement proposes to retain certain 

existing balancing accounts, including the Tax Act Memo 

Account that was first established following the Tax Relief, 

Unemployment Insurance Reauthorization, and Job Creation 

Act of 2010, and to eliminate certain memorandum and 

balancing accounts that are no longer necessary. In addition 

to the contested balancing account for natural gas leak 

abatement mitigation costs, the settlement agreement 

proposes one new tax-related memorandum account to 

track the impact on the revenue requirement from certain 

types of changes in tax laws or regulations.

Capital Additions and Rate Base

The settlement agreement proposes capital expenditures of 

$3.9 billion for 2017 for the portions of the Utility’s business 

addressed in the GRC. Proposed capital expenditures are 

lower than the amount included in the GRC application of 

$4.0 billion for 2017, consistent with the provisions of the 

settlement agreement. While the settlement agreement 

proposes overall revenue requirement increases for 2018 

and 2019, it does not specify capital expenditures for 

those years. At the August 30, 2016 workshop, the Utility 

estimated authorized capital expenditures of $3.6 billion 

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for 2018 and $3.5 billion for 2019, based on a calculation 

method that is subject to CPUC approval, as compared 

to its request of approximately $4.0 billion each year. The 

Utility is unable to predict if the CPUC will approve its 

proposed calculation method.

The settlement agreement proposes a 2017 weighted 

average rate base of $24.3 billion for the portions of the 

Utility’s business reviewed in the GRC, compared with the 

Utility’s request of $24.5 billion. The $200 million difference 

is primarily due to the lower level of capital expenditures 

agreed to in the settlement. At the August 30, 2016 

workshop, the Utility also estimated a weighted average 

rate base of $25.4 billion for 2018 and $26.3 billion for 

2019, compared with the Utility’s request of $25.7 billion 

and $26.9 billion, respectively.

Evidentiary hearings were held on September 1, 2016. A 

workshop was held on January 11, 2017 to further explore 

the three-year versus four-year rate case cycle. Under the 

current schedule, a final CPUC decision is expected to 

be issued in the first half of 2017. On March 17, 2016, the 

CPUC issued a decision to allow the authorized revenue 

requirement changes to become effective on January 1, 

2017, even if the final decision is issued after that date.

PG&E Corporation and the Utility are unable to predict 

whether the CPUC will approve the settlement agreement.

2015 Gas Transmission and Storage Rate Case

On June 23, 2016, the CPUC approved a final decision 

in phase one of the Utility’s 2015 GT&S rate case. The 

decision adopts the revenue requirements that the Utility 

is authorized to collect through rates beginning August 1, 

2016, to recover its costs of gas transmission and storage 

services for the 2015 GT&S rate case period (see table 

below). The decision authorizes the Utility to collect, over a 

36-month period, the difference between adopted revenue 

requirements and amounts previously collected in rates, 

retroactive to January 1, 2015. Accounting rules allow the 

Utility to recognize revenues in a given year only if they will 

be collected from customers within 24 months of the end 

of that year. As a result, the Utility will complete recording 

$102 million of the retroactive revenue requirement increase 

in the first quarter of 2017.

The phase one decision excludes from rate base $696 million 

of capital spending in 2011 through 2014 in excess of the 

amount adopted. The decision permanently disallows 

$120 million of that amount and orders that the remaining 

$576 million be subject to a third party audit overseen by 

the CPUC staff, with the possibility that the Utility may 

seek recovery in a future proceeding. The decision also 

establishes various cost caps that will increase the risk of 

overspend over the current rate case cycle including new 

one-way capital balancing accounts. In the second quarter 

of 2016, the Utility incurred charges of $190 million for 

capital expenditures that the Utility believes are probable 

of disallowance based on the decision. This includes 

$134 million to the net plant balance for 2011 through 

2014 capital expenditures in excess of adopted amounts 

and $56 million for the Utility’s estimate of 2015 through 

2018 capital expenditures that are probable of exceeding 

authorized amounts. The Utility took an additional charge 

of $29 million in the fourth quarter of 2016 related to 2015 

through 2018 capital expenditures that are forecasted 

to exceed authorized amounts. Additional charges may 

be required in the future based on the Utility’s ability to 

manage its capital spending and on the outcome of the 

CPUC’s audit of 2011 through 2014 capital spending.

The phase one decision denies the Utility’s request for full 

balancing account treatment for recovery of authorized 

transportation and storage revenue requirements for 

non-core customers, and instead continues the revenue 

sharing mechanism authorized in the 2011 GT&S rate case 

that subjects a portion of the Utility’s transportation and 

storage revenue requirement to market risk. 

The phase one decision also authorizes the Utility’s 

request for cost recovery of up to $157 million for the 

construction of Line 407, a 25.5 mile, 30-inch pipeline in 

the Sacramento Valley expected to be built during this 

rate case period. The authorized revenue requirements 

will begin when Line 407 becomes operational. The 

decision also authorizes the Utility to track costs exceeding 

$157 million in a memorandum account. A reasonableness 

review of all costs for Line 407 will take place in the next 

GT&S rate case. 

On August 1, 2016, TURN, ORA, and Indicated Shippers filed 

an application for rehearing of the phase one decision. The 

application indicates that the decision contains language 

suggesting that the authorized revenue requirement is 

to comply with new federal and state safety mandates 

and should be removed from the final decision, allows 

recovery of shareholder costs in rates, and improperly 

sequences the calculation of the San Bruno Penalty and 

the ex parte disallowance. The Utility filed a response 

on August 16, 2016. The Utility cannot predict when or if 

the CPUC will grant the rehearing or if it will adopt the 

parties’ recommendations. 

On December 1, 2016, the CPUC approved a final decision 

in phase two of the Utility’s 2015 GT&S rate case, regarding 

the $850 million penalty assessed in the Penalty Decision. 

The final phase two decision applies $689 million of the 

$850 million penalty (81 percent) to capital expenditures 

and the remaining $161 million (19 percent) to expenses, and 

then reduces the 2015 revenue requirement by $72 million 

for the five-month delay caused by the Utility’s violation of 

the CPUC ex parte communication rules in this proceeding 

($57 million of the $72 million total ex parte disallowance 

was recognized in 2016 and the remaining $15 million 

will be recognized in the first quarter of 2017). The final 

decision also approves the Utility’s list of programs which 

meet the CPUC’s definition of “safety related,” the costs of 

which are to be funded through the $850 million penalty.

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The following table shows the revenue requirement amounts adopted in the Utility’s 2015 GT&S rate case including 

adjustments for the $850 million Penalty Decision disallowance and the ex parte disallowance:

(in millions) 2015   2016   2017 2018

Revenue Requirement Before Adjustments $1,046 $ 1,110 $ 1,220 $ 1,324

San Bruno Penalty Expense Allocation (161)

San Bruno Penalty Capital Revenue Requirement Allocation 5 (47) (93) (93)

Other Expense Adjustments (3) (2) (2) (1)

Adjusted Ex Parte Penalty (72)

Final Phase Two Revenue Requirement $ 815 $ 1,061 $ 1,125 $ 1,230

The final phase two decision adopts total weighted 

average rate base of $2.8 billion in 2015, $2.8 billion in 

2016, $3.0 billion in 2017, and $3.5 billion in 2018. The 

final phase two decision reduces rate base by the full 

amount of the disallowed capital expenditures but does 

not remove the associated deferred taxes, which the 

Utility believes creates a normalization violation. In the 

final decision, the CPUC authorizes the Utility to establish 

a Tax Normalization Memorandum Account to track 

relevant costs and clarifies that it does not intend the 

rate base offset or the penalty generally, to create tax 

timing differences. The final decision also affirms the 

CPUC’s intention to comply with normalization rules and 

to avoid the potential adverse consequences of a finding 

of a normalization violation by the IRS. Pursuant to the 

final phase two decision, on February 6, 2017, the Utility 

submitted an advice letter to the CPUC to provide 30 days 

advance notice of the Utility’s request to the IRS for a 

private letter ruling to determine whether the adopted 

rate base offset complies with IRS normalization rules. The 

final decision authorizes the Utility to subsequently seek 

an appropriate adjustment to its revenue requirements 

and rate base if the IRS finds a normalization violation. 

On January 4, 2017, TURN, ORA and Indicated Shippers 

filed an application for rehearing of the phase two decision. 

Specifically, the application argues that the decision 

inappropriately sequenced the San Bruno Penalty and 

the ex parte ratemaking disallowance. The Utility filed a 

response on January 19, 2017. The Utility cannot predict 

when or if the CPUC will grant the rehearing.

With the addition of a third attrition year, the Utility’s next 

GT&S cycle will begin in 2019. The decision requires the 

Utility to file its next GT&S application in 2017.

FERC Transmission Owner Rate Cases

On July 29, 2015, the Utility requested a 2016 retail electric 

transmission revenue requirement of $1.515 billion, a 

$314 million increase over the previous year’s authorized 

revenue requirement of $1.201 billion. The Utility’s proposed 

rates went into effect on March 1, 2016, subject to refund, 

and pending a final decision by the FERC. On September 1, 

2016, the Utility and other settling parties (including 

the CPUC) filed a motion at the FERC for approval of a 

settlement proposing that the Utility’s 2016 retail electric 

transmission revenue requirement be set at $1.331 billion, a 

$130 million increase over the previous year’s authorized 

revenue requirement. The Utility also filed a motion on 

September 1, 2016, requesting the implementation of interim 

rates, which was an agreed upon term of the settlement. 

The motion was granted and, as a result, the interim rates 

became effective for wholesale customers on September 1, 

2016 and for retail customers on October 1, 2016. The FERC 

approved the settlement on November 17, 2016.

On July 29, 2016, the Utility filed a rate case at the FERC 

requesting a 2017 retail electric transmission revenue 

requirement of $1.718 billion, a $387 million increase over the 

2016 revenue requirement of $1.331 billion. The forecasted 

network transmission rate base for 2017 is $6.7 billion. The 

Utility is also seeking a return on equity of 10.9% which 

includes an incentive component of 50 basis points for 

the Utility’s continuing participation in the CAISO. In the 

filing, the Utility forecasted that it will make investments 

of $1.296 billion in 2017 in various capital projects. 

On September 30, 2016, the FERC issued an order accepting 

the Utility’s July 2016 filing and set it for settlement 

negotiations. The order set an effective date for rates of 

March 1, 2017, and made the rates subject to hearing and 

refund. The next settlement conference is scheduled for 

March 16 and March 17, 2017. 

CPUC Cost of Capital

On February 6, 2017, the Utility and other California IOUs 

entered into a MOU with the CPUC, ORA, and TURN to 

extend the next cost of capital application filing deadline 

two years to April 22, 2019 for the year 2020. To implement 

the MOU, on February 7, 2016, the IOUs, ORA, and TURN 

filed with the CPUC a petition for modification of prior 

CPUC decisions addressing the cost of capital. If the 

petition for modification is approved as submitted it 

would reduce the Utility’s ROE from 10.40% to 10.25% and 

reset the Utility’s authorized cost of long-term debt and 

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preferred stock beginning January 1, 2018. The long-term 

debt cost reset will reflect actual embedded costs as of 

the end of August 2017 and forecasted interest rates for 

the new long-term debt scheduled to be issued for the 

remainder of 2017 and all of 2018. The Utility’s current 

capital structure of 52% common equity, 47% long-term 

debt, and 1% preferred equity would remain unchanged. 

If and once the petition for modification is granted by the 

CPUC, each IOU will submit to the CPUC in September 2017 

its respective updated cost of capital and corresponding 

revenue requirement impacts with an effective date of 

January 1, 2018. While the actual changes to the Utility’s 

revenue requirement resulting from the petition for 

modification will not be known until the Utility’s filing 

in September 2017, the Utility estimates that its annual 

revenue requirement will be reduced by approximately 

$100 million, beginning in 2018. These estimates are based 

on current and forecasted market interest rates. Changes 

in market interest rates can have material effects on the 

cost of the Utility’s future financings and consequently 

on the estimated change in annual revenue requirements.

The Utility’s cost of capital adjustment mechanism would 

not operate in 2017 but could operate in 2018 to change 

the cost of capital for 2019. If the mechanism is activated 

for 2019, the Utility’s cost of capital, including its new 

ROE of 10.25%, will be adjusted according to the existing 

terms of the mechanism. Concurrently with the petition 

for modification, the Utility and other California IOUs sent 

a letter to the executive director of the CPUC requesting 

that the existing April 2017 filing due date for the 2018 

cost of capital be deferred while the CPUC is considering 

the petition for modification. On February 13, 2017, the 

executive director of the CPUC granted the request. As 

extended, the Utility and the other California IOUs would 

file their next cost of capital applications 60 days after 

the effective date of the CPUC decision on the petition 

for modification, or April 20, 2017, whichever is later, if 

the CPUC does not grant the petition for modification. 

The Utility expects that the CPUC may issue a decision 

in the first half of 2017.

Diablo Canyon Nuclear Power Plant 

Joint Proposal for Plant Retirement 

On August 11, 2016, the Utility submitted an application to 

the CPUC to retire Diablo Canyon at the expiration of its 

current operating licenses in 2024 and 2025 and replace 

it with a portfolio of energy efficiency and GHG-free 

resources. The application implements a joint proposal 

between the Utility and the Friends of the Earth, Natural 

Resources Defense Council, Environment California, 

International Brotherhood of Electrical Workers Local 1245, 

Coalition of California Utility Employees, and Alliance for 

Nuclear Responsibility. 

The application and joint proposal include a voluntary 

increase in the Utility’s target for RPS-eligible resources 

to 55%, effective in 2031 through 2045, as compared to 

the state’s goal of 50% renewables. The parties to the joint 

proposal proposed that the Utility be authorized to procure 

GHG-free replacement resources in three competitive 

procurement tranches: in Tranche 1, the Utility would be 

authorized to obtain 2,000 gross GWh of energy efficiency 

savings to be implemented over the 2018 to 2024 time 

period; in Tranche 2, the Utility would be authorized to 

procure through a solicitation 2,000 GWh of GHG-free 

energy resources that will commence energy deliveries or 

add energy efficiency projects to the system in the 2025 

to 2030 time period; and in Tranche 3, the Utility would 

commit to a voluntary 55% RPS beginning in 2031, and 

would maintain this voluntary commitment through 2045 

or until superseded by action of the state legislature or 

the CPUC. The three tranches of resource procurement 

in the application and joint proposal are not intended to 

specify all energy resources that will be needed to ensure 

the orderly replacement of Diablo Canyon. Instead, the 

Utility expects that the full solution will be addressed in 

ongoing CPUC proceedings. 

Costs associated with energy efficiency projects or 

programs in Tranche 1 and Tranche 2 would be recovered 

through the Utility’s electric public purpose program rates 

as non-bypassable charges, consistent with the existing 

recovery mechanisms for energy efficiency program 

costs. GHG-free energy resources costs from Tranche 2 

are proposed to be recovered through a non-bypassable 

cost allocation mechanism called the Clean California 

Charge that (1) equitably allocates costs and benefits, 

such as RPS or Resource Adequacy credits, associated 

with the procurement among responsible load-serving 

entities, and (2) determines the net capacity costs of 

such procurement consistent with the methodology 

for the allocation of net capacity costs laid out by the 

CPUC. Costs associated with procurement for Tranche 3 

would be recovered through a separate renewable nonbypassable charge. 

The application seeks confirmation from the CPUC that the 

Utility’s full investment in Diablo Canyon and authorized rate 

of return will be recovered in rates by the time the facility 

ceases operations. Additionally, the Utility requests that the 

CPUC pre-approve the recovery of certain costs related to 

the closure of the Diablo Canyon. These include the nonbypassable cost allocation mechanism for procurement 

of GHG-free energy and the recovery of $1.3 billion for 

administration and acquisition of the new Tranche 1 energy 

efficiency procurement as authorized energy efficiency 

funding, subject to return of all unspent funds; the recovery 

of employee retention and retraining and development 

programs to continue safe and efficient operation of 

Diablo Canyon through the end of its license periods, 

estimated at approximately $360 million; and a community 

mitigation program to compensate San Luis Obispo 

County for the decline in local economic stimulus provided 

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by Diablo Canyon through a transition period ending in 

2025, estimated at $85 million. The Utility also seeks cost 

recovery of approximately $50 million in costs related to the 

federal and state Diablo Canyon license renewal process.

More than 40 parties have submitted responses and 

protests to the Utility’s application. A prehearing conference 

on the application was held on October 6, 2016 and public 

participation hearings were held in San Luis Obispo on 

October 20, 2016. On November 18, 2016, a scoping memo 

was issued that set the schedule and determined that 

land issues would be out of the scope of this proceeding. 

In December 2016, the Utility filed with the CPUC the 

community impact mitigation program settlement 

agreement of $85 million, compared to $50 million included 

in the original joint proposal filed on August 11, 2016. 

Intervenor testimonies were submitted to the CPUC in 

January 2017. Several intervenors indicated their support 

to retire Diablo Canyon at the expiration of its current 

operating licenses in 2024 and 2025. Several parties 

argued, however, that a component of the employee 

retention program and community impact mitigation 

program be funded by shareholders. Several intervenors 

also submitted proposals for modifications to certain 

aspects of the three GHG-free replacement tranches. 

Several parties recommended that the license renewal 

project cost recovery request be rejected and/or be paid 

for by both customers and shareholders. There were no 

direct challenges to the Diablo Canyon remaining net book 

value cost recovery proposal. Rebuttal testimony and 

comments on the community impact mitigation program 

settlement agreement are scheduled to be submitted to 

the CPUC on March 17, 2017 and evidentiary hearings are 

scheduled to take place in April 2017. Opening and reply 

briefs are due on May 26, 2017 and June 9, 2017, respectively. 

The Utility expects that a final decision will be issued by 

the end of 2017. Upon CPUC approval of the application 

and such approval becoming final and non-appealable, 

the Utility will withdraw its license renewal application 

currently pending before the NRC. PG&E Corporation 

and the Utility are unable to predict whether the CPUC 

will approve the application.

California State Lands Commission Lands Lease

On June 28, 2016, California State Lands Commission 

approved a new lands lease for the intake and discharge 

structures at Diablo Canyon to run concurrently with Diablo 

Canyon’s current operating licenses, until Diablo Canyon 

Unit 2 ceases operations in August 2025. The Utility 

believes that the approval of the new lease will ensure 

sufficient time for the Utility to identify and bring online 

a portfolio of GHG-free replacement resources. The Utility 

will submit a future lease extension request to address the 

period of time required for plant decommissioning, which 

under NRC regulations can take as long as 20 years. On 

August 28, 2016, the World Business Academy (WBA) filed 

a writ in the Los Angeles Superior Court. WBA asserts 

that the State Lands Commission committed legal error 

when it determined that the short term lease extension 

for an existing facility was exempt from review under the 

California Environmental Quality Act. If the petitioner 

prevails in its challenge, the State Lands Commission could 

be required to perform an environmental review of the 

new lands lease. The court has set a trial date of July 11, 

2017, with the petitioner’s opening brief due February 27, 

2017, opposition briefs due April 24, 2017, and reply briefs 

due May 22, 2017. 

Asset Retirement Obligations

The Utility expects that the decommissioning of 

Diablo Canyon will take many years after the expiration 

of its current operating licenses. Detailed studies of the 

cost to decommission the Utility’s nuclear generation 

facilities are conducted every three years in conjunction 

with the NDCTP. Actual decommissioning costs may 

vary from these estimates as a result of changes in 

assumptions such as decommissioning dates; regulatory 

requirements; technology; and costs of labor, materials, and 

equipment. The Utility recovers its revenue requirements 

for decommissioning costs from customers through a nonbypassable charge that the Utility expects will continue 

until those costs are fully recovered.

On March 1, 2016, the Utility submitted its updated 

decommissioning cost estimate with the CPUC. The 

estimated undiscounted cost to decommission the Utility’s 

nuclear power plants increased by approximately $1.4 billion, 

for a total estimated cost of $4.8 billion, due to increased 

estimated costs related to spent fuel storage, staffing, and 

out-of-state waste disposal. The Utility requested that 

the CPUC authorize the collection of increased annual 

revenue requirements beginning on January 1, 2017 based 

on these updated cost estimates. 

While the NDCTP forecast includes employee severance 

program estimates, it does not include estimated costs 

related to the joint proposal’s employee retention and 

retraining and development programs, and the San Luis 

Obispo County community mitigation program described 

above. The Utility intends to conduct a site-specific 

decommissioning study to update the 2015 NDCTP forecast 

and to submit the study to the CPUC by mid-2019. 

On July 15, 2016, the assigned CPUC commissioner and ALJ 

issued a scoping memo for the Utility’s 2015 NDCTP and 

excluded from the scope of the proceeding the issue on 

whether the Utility should be required to present additional 

analysis for a license extension scenario for Diablo Canyon, 

as a result of the Utility’s announcement of its plan to 

not seek relicensing of Diablo Canyon beyond its current 

operating authority. The scoping memo also adopts within 

the scope of the proceeding a reasonableness review 

of the Utility’s estimated updated cost to decommission 

the Utility’s nuclear power plants and of the forecasts 

of certain expenses and the decommissioning trust 

funds’ rates of return. Evidentiary hearings took place 

in September 2016 and opening briefs were submitted 

on October 14, 2016. Intervenor parties proposed several 

major recommendations including a reduction to the total 

spent nuclear fuel storage forecast, a reduction to the 

large component (reactor vessels, steam generators, and 

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other large plant components) removal cost estimate, and 

a reduction to the waste disposal estimate. Additionally, 

intervenors asserted that the CPUC should not permit 

the Utility to increase its Diablo Canyon-related revenue 

requirement at this time as it has not demonstrated its 

current estimate is reasonable. Parties also claimed that 

the Utility has not justified its increase to security costs 

and decommissioning oversight contractor staff costs. 

No party challenged the Utility’s decommissioning trust 

funds rates of return or cost escalation assumptions. Reply 

briefs were submitted on October 31, 2016. Intervenor 

parties reiterated that the Utility has not justified increases 

in costs due to large component removal, site security, 

decommissioning contractor staff, spent nuclear fuel 

storage, and waste disposal. The Utility confirmed that the 

testimony and work papers support the cost increases as 

well as the total estimate to decommission Diablo Canyon. 

The estimated nuclear decommissioning cost is 

discounted for GAAP purposes and recognized as an 

ARO on the Consolidated Balance Sheets. The total nuclear 

decommissioning obligation accrued in accordance with 

GAAP was $3.5 billion at December 31, 2016, which includes 

an $818 million adjustment to reflect the increased cost 

estimates and a $115 million increase resulting from the joint 

proposal described above, and $2.5 billion at December 31, 

2015. These estimates are based on decommissioning 

cost studies, prepared in accordance with the CPUC 

requirements. Changes in these estimates could materially 

affect the amount of the recorded ARO for these assets.

As of December 31, 2016, the nuclear decommissioning 

trust accounts’ total fair value was $2.9 billion. Changes in 

the estimated costs, the timing of decommissioning or the 

assumptions underlying these estimates could cause material 

revisions to the estimated total cost to decommission. 

CPUC Investigation of 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. The consultant’s work 

began in the second quarter of 2016.

The CPUC stated that the initial phase of the proceeding 

was categorized as rate setting because it will consider 

issues both of fact and policy and because the Utility 

and PG&E Corporation do not face the prospect of fines, 

penalties, or remedies in this phase. Upon completion 

of the consultant’s report, the assigned commissioner 

will determine the scope of any next actions in the 

proceeding. The timing, scope and potential outcome of 

the investigation are uncertain.

2014 – 2015 Energy Efficiency Incentive Awards

On December 15, 2016, the CPUC approved a final 2014-2015 

Energy Efficiency Incentive Award of $16.3 million, 

compared to the Utility’s request of $19.1 million. The 

award includes a $5.8 million reduction reflecting the 

approved settlement agreement related to the rehearing 

of the 2006-2008 customer energy efficiency shareholder 

incentives. The settlement agreement requires the Utility 

to reduce future energy efficiency shareholder incentives 

by $29.1 million, which will be applied in installments of 

$5.8 million per year for five years, provided that the Utility 

has sufficient energy efficiency incentive awards to offset 

that amount. Due to the application of the first offset of 

$5.8 million, the required future energy efficiency reduction 

currently corresponds to $23.3 million. If shareholder 

incentives are insufficient to offset this amount, the offset 

in the following year will be increased by the shortfall. At 

its discretion, the Utility may increase the amount of the 

offset to reduce the remaining offset obligation more 

quickly. If the amount has not been fully offset at the end 

of five years, the balance will be credited against future 

energy efficiency program spending.

Legislative and Regulatory Initiatives 

The California Legislature and the CPUC have adopted 

requirements, policies, and decisions to improve and refine 

gas and electric safety citation programs, implement new 

state law requirements applicable to natural gas storage 

facilities, accommodate the growth in distributed electric 

generation resources (including solar installations), increase 

the amount of renewable energy delivered to customers, 

promote customer energy efficiency and demand response 

programs, and foster the development of a state-wide 

electric vehicle charging infrastructure to encourage the 

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use of electric vehicles. In addition, the CPUC continues 

to implement state law requirements to reform 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. CPUC proceedings related to some of 

these matters are discussed below. 

The Utility’s ability to recover its costs, including investments 

associated with legislative and regulatory initiatives, as well 

as its electricity procurement and other operating costs, 

will, in large part, depend on the final form of legislative 

or regulatory requirements, and whether the associated 

ratemaking mechanisms can be timely adjusted to reflect 

changes in customer demand for the Utility’s electricity 

and natural gas service. 

Gas and Electric Safety Citation Program

The SED periodically audits utility operating practices 

and conducts investigations of potential violations of laws 

and regulations applicable to the safety of the California 

utilities’ electric and natural gas facilities and operations. 

The CPUC has delegated authority to the SED to issue 

citations and impose penalties for violations identified 

through audits, investigations, or self-reports. Under both 

the gas and electric programs, 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. 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.

On September 29, 2016, the CPUC issued a final decision 

adopting improvements and refinements to its gas 

and electric safety citation programs. Specifically, the 

final decision refines the criteria for the SED to use in 

determining whether to issue a citation and the amount 

of penalty, sets an administrative limit of $8 million per 

citation issued, makes self-reporting voluntary in both 

gas and electric programs, adopts detailed criteria for 

the utilities to use to voluntarily self-report a potential 

violation, and refines other issues in the programs. The 

decision also merges the rules applicable to its gas and 

electric safety citation programs into a single set of rules 

that replace the previous safety citation programs and 

adopts non-substantive changes to these programs so 

that the programs can be similar in structure and process 

where appropriate.

Natural Gas Storage Facilities

On January 6, 2016, the California Governor ordered the 

DOGGR to issue emergency regulations to require gas 

storage facility operators throughout California, including 

the Utility, to comply with new safety and reliability 

measures, including minimum daily inspection of gas 

storage well heads (using gas leak detection technology 

such as infrared imaging), ongoing verification of the 

mechanical integrity of all gas storage wells, ongoing 

measurement of annular gas pressure or annular gas flow 

within wells, regular testing of all safety valves used in 

wells, establishing minimum and maximum pressure limits 

for each gas storage facility in the state, and establishing 

a comprehensive risk management plan that evaluates 

and prepares for risks at each facility, including corrosion 

potential of pipes and equipment. On February 5, 2016, 

the DOGGR adopted the emergency regulations. The 

Utility implemented the regulations and submitted an 

Underground Storage Risk and Integrity Management 

Plan on August 5, 2016 that is pending DOGGR approval. 

Additionally, in September 2016, the California Governor 

signed SB 887 directing DOGGR and CARB to develop 

permanent regulations for gas storage facility operations 

in California, which are expected to be finalized in the 

second half of 2017. The PHMSA has also issued interim 

final rules effective January 18, 2017 regulating gas storage 

facilities at the federal level. The Utility may incur significant 

costs to comply with the new regulations related to 

(1) the development of a natural gas leak prevention 

and response program, (2) the development of a plan 

for corrosion monitoring and evaluation, (3) proactive 

replacement of equipment at risk of failure, and (4) a 

review of risk management plans to consider new risk 

factors. The Utility plans to file an advice letter with the 

CPUC in the first quarter of 2017 to request a memorandum 

account to track the future incremental costs associated 

with implementing the new regulations. Upon approval, a 

subsequent application would be submitted to the CPUC 

for recovery of the incremental costs being tracked. The 

Utility is unable to estimate the timing and outcome of 

such request. 

New Renewable Energy Targets

In October 2015, the California Governor signed SB 350 

into law, which became effective January 1, 2016. SB 350 

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. SB 350 includes increasing 

interim renewable energy targets for the periods between 

2020 and 2030 and continues to include 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. 

In December 2016, the CPUC issued the first of a series 

of decisions to implement the RPS-related provisions of 

SB 350. The decision addressed compliance periods and 

procurement quantity requirements. Subsequent rulings 

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and decisions are expected in 2017 to address scope and 

implementation details.

Additionally, as stated above, the Utility’s application and 

joint proposal to retire Diablo Canyon include a voluntary 

increase in the Utility’s target for RPS-eligible resources 

to 55%, effective in 2031 through 2045, as compared to 

the state’s goal of 50% renewables.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility 

filed its proposed electric distribution resources plan for 

approval by the CPUC. The Utility’s plan identifies optimal 

locations on its electric distribution system for deployment 

of DERs. The Utility’s proposal is designed to allow energy 

technologies to be interconnected with each other and 

integrated into the larger grid while continuing to provide 

customers with safe, reliable and affordable electric service. 

The Utility envisions a future electric grid that would 

allow customers to choose new advanced energy supply 

technologies and services to meet their needs consistent 

with safe, reliable and affordable electric service. 

On January 24, 2017, the CPUC convened a workshop aimed 

at informing the development of a CPUC framework to 

evaluate grid-modernization investments. The workshop 

was attended by the California IOUs, the DER industry, 

consumer advocates, the DOE, and the CPUC’s Energy 

Division staff. The Energy Division staff is expected to 

develop a grid modernization investment framework in 

the first quarter of 2017. Additionally, on February 9, 2017, 

the CPUC issued a decision approving two out of three 

of the Utility’s proposed field demonstration projects to 

test various distribution-related services that DERs might 

provide to the Utility. The Utility in unable to predict 

when a final CPUC decision approving, disapproving, or 

modifying the Utility’s electric distribution resources plan 

will be issued.

Integrated Distributed Energy Resources – 

Regulatory Incentives Pilot Program 

On April 4, 2016, the assigned CPUC commissioner and 

ALJ issued a ruling proposing to establish, on a pilot basis, 

an interim program offering regulatory incentives to the 

Utility and the other two large California IOUs for the 

deployment of cost-effective DERs. The ruling assumed 

that the incentive would take the form of an additional 

payment to the Utility of 3.5% (grossed up for taxes) of 

the payments made to the DER provider(s). The ruling 

also stated that it did not intend for this phase to adopt 

a new regulatory framework or business model for the 

California electric utilities.

On September 1, 2016, the assigned CPUC commissioner 

and ALJ issued an amended scoping memo and ruling 

that re-categorized all activities in the proceeding as ratesetting, consolidated remaining issues into one phase, 

and proposed a revised regulatory incentive pilot to test 

how an earnings opportunity affects DER sourcing. On 

December 22, 2016, the CPUC issued a final decision in the 

proceeding which authorizes a pilot to test a regulatory 

incentive mechanism through which the Utility will earn 

a 4% pre-tax incentive on annual payments for DERs, as 

well as test a regulatory process that will allow the Utility 

to competitively solicit DER services to defer distribution 

infrastructure. Each utility is required to conduct at least 

one pilot, but may conduct up to three additional pilots. 

Electric Rate Reform and Net Energy 

Metering (NEM)

On July 3, 2015, the CPUC approved a final decision to 

authorize the California IOUs to gradually flatten their 

tiered residential electric rate structures to two tiers by 

January 2019.  The decision approved higher minimum 

bill charges for residential customers and also allows the 

imposition of a surcharge on customers with extremely 

high electricity use beginning in 2017. The decision requires 

the Utility to file a proposal by January 1, 2018, to charge 

residential electric customers based on time-of-use rates 

(known as “default time-of-use rates”) unless customers 

elect otherwise. The Utility also may propose to impose 

a fixed charge on residential electric customers. Under 

the CPUC’s decision, default time-of-use rates must be 

implemented before the CPUC will permit the imposition 

of a fixed charge in electric rates. 

In January 2016, the CPUC adopted new NEM rules. The 

new rules became effective for new NEM customers in 

December 2016, when the Utility reached its NEM cap of 

2,409 MW. New NEM customers will be required to pay 

an interconnection fee, will be charged for energy use 

on time-of-use rates, and will be required to pay nonbypassable charges to help fund some of the costs of 

low-income, energy efficiency, and other programs that 

other customers pay. Unlike the initial NEM tariff, there is 

no cap on the total capacity of distributed generation that 

can be installed under the new rules, and there is no size 

limitation on the projects, so long as projects over 1MW 

pay actual interconnection costs. On March 7, 2016, the 

Utility and certain other parties, including TURN and CUE, 

filed applications for rehearing. The Utility requested that 

the CPUC vacate its January 2016 decision that the Utility 

asserts contains legal and factual errors. Many parties 

argued that the CPUC failed to complete its duties under 

AB 327, which required the CPUC to evaluate the costs 

and benefits of NEM. On September 15, 2016, the CPUC 

voted to deny the applications for rehearing, concluding 

that good cause had not been established to grant a 

rehearing and that the NEM decision adopted a successor 

tariff as required. The CPUC indicated that it may revisit 

the NEM successor tariff in 2019. 

Electric Vehicle (EV) Infrastructure Development

In December 2014, the CPUC issued a decision adopting a 

policy to expand the California utilities’ role in developing 

EV charging infrastructure to support California’s climate 

goals. On February 9, 2015, the Utility filed an application 

requesting that the CPUC approve the Utility’s proposal 

to deploy, own, and maintain EV charging stations and 

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the associated infrastructure. On December 15, 2016, the 

CPUC issued a final decision establishing a three-year 

EV program of $130 million (approximately $109 million 

in capital expenditures) to deploy up to 7,500 charging 

stations. Further deployment of light-duty EV infrastructure 

will be considered in a second phase of the proceeding.

Transportation Electrification (TE) Application 

SB 350 orders the CPUC, in consultation with the CARB 

and the CEC, to direct electrical corporations to file 

applications for programs and investments to accelerate 

widespread TE. In September 2016, the CPUC directed the 

large IOUs to file projects to accelerate TE in the state, 

including both one-year projects (of up to $20 million 

total) and two to five-year programs with a requested 

revenue requirement determined by the utility. On January 

20, 2017, the Utility filed its TE application with the CPUC 

requesting a total of up to $253 million (approximately 

$211 million in capital expenditures) in program funding 

over five years (2018-2022) primarily related to makeready infrastructure for TE in medium to heavy-duty 

sectors. Protests are due March 6, 2017 and a prehearing 

conference is scheduled for March 16, 2017. The Utility 

expects a decision to be issued within 12 to 18 months.

Environmental Matters 

The Utility’s operations are subject to extensive federal, 

state, and local laws and permits 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 the Utility’s activities, including 

the remediation of hazardous wastes; the reporting and 

reduction of CO2 and other GHG emissions; the discharge 

of pollutants into the air, water, and soil; the reporting of 

safety and reliability measures for natural gas storage 

facilities; and the transportation, handling, storage, and 

disposal of spent nuclear fuel. (See Item 1A. Risk Factors 

and “Environmental Regulation” in Item 1.) 

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating 

groundwater contamination caused by hexavalent 

chromium used in the past at the Utility’s natural gas 

compressor stations. The Utility is also required to take 

measures to abate the effects of the contamination on the 

environment. At December 31, 2016, $299 million and $135 

million was accrued in the Consolidated Balances Sheets 

for estimated undiscounted remediation costs associated 

with the Topock site and the Hinkley site, respectively. Costs 

associated with the Hinkley site are not recovered through 

rates. (See “Environmental Remediation Contingencies” 

in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.) 

Risk Management Activities

PG&E Corporation, mainly through its ownership of the 

Utility, and the Utility are exposed to risks associated with 

adverse changes in commodity prices, interest rates, and 

counterparty credit. 

The Utility actively manages market risk through risk 

management programs designed to support business 

objectives, discourage unauthorized risk-taking, reduce 

commodity cost volatility, and manage cash flows. The 

Utility uses derivative instruments only for non-trading 

purposes (i.e. risk mitigation) and not for speculative 

purposes. The Utility’s risk management activities include 

the use of physical and financial instruments such as 

forward contracts, futures, swaps, options, and other 

instruments and agreements, most of which are accounted 

for as derivative instruments. Some contracts are accounted 

for as leases.

Commodity Price Risk

The Utility is exposed to commodity price risk as a result 

of its electricity and natural gas procurement activities, 

including the procurement of natural gas and nuclear 

fuel necessary for electricity generation and natural gas 

procurement for core customers. As long as the Utility can 

conclude that it is probable that its reasonably incurred 

wholesale electricity procurement costs and natural gas 

costs are recoverable, fluctuations in electricity and natural 

gas prices will not affect earnings. Such fluctuations, 

however, may impact cash flows. The Utility’s natural gas 

transportation and storage costs for core customers are 

also fully recoverable through a ratemaking mechanism. 

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The Utility’s current authorized revenue requirement for 

natural gas transportation and storage service to non-core 

customers is not balancing account protected. The Utility 

recovers these costs through fixed reservation charges and 

volumetric charges from long-term contracts, resulting 

in price and volumetric risk. (See “2015 Gas Transmission 

and Storage Rate Case” above.)

The Utility uses value-at-risk to measure its shareholders’ 

exposure to these risks. The Utility’s value-at-risk was 

approximately $7 million and $2 million at December 31, 

2016 and 2015, respectively. During 2016, the Utility’s 

approximate high, low, and average values-at-risk were $7 

million, $1 million and $4 million, respectively. During 2015, 

the value-at-risk amounts were $2 million, $1 million and 

$2 million, respectively. (See Note 9 of the Notes to the 

Consolidated Financial Statements in Item 8 for further 

discussion of price risk management activities.)

Interest Rate Risk 

Interest rate risk sensitivity analysis is used to measure 

interest rate risk by computing estimated changes in 

cash flows as a result of assumed changes in market 

interest rates. At December 31, 2016 and 2015, if interest 

rates changed by 1% for all PG&E Corporation and Utility 

variable rate long-term debt, short-term debt, and cash 

investments, the impact on net income over the next 12 

months would be $13 million and $11 million, respectively, 

based on net variable rate debt and other interest ratesensitive instruments outstanding. (See Note 4 of the 

Notes to the Consolidated Financial Statements in Item 8 

for further discussion of interest rates.)

Energy Procurement Credit Risk

The Utility conducts business with counterparties mainly 

in the energy industry, including the CAISO market, other 

California investor-owned electric utilities, municipal 

utilities, energy trading companies, financial institutions, 

electricity generation companies, and oil and natural 

gas production companies located in the United States 

and Canada. If a counterparty fails to perform on its 

contractual obligation to deliver electricity or gas, then 

the Utility may find it necessary to procure electricity or 

gas at current market prices, which may be higher than 

the contract prices.

The Utility manages credit risk associated with its 

counterparties by assigning credit limits based on 

evaluations of their financial conditions, net worth, credit 

ratings, and other credit criteria as deemed appropriate. 

Credit limits and credit quality are monitored periodically. 

The Utility executes many energy contracts under master 

commodity enabling agreements that may require security 

(referred to as “Credit Collateral” in the table below). 

Credit collateral may be in the form of cash or letters of 

credit. The Utility may accept other forms of performance 

assurance in the form of corporate guarantees of acceptable 

credit quality or other eligible securities (as deemed 

appropriate by the Utility). Credit collateral or performance 

assurance may be required from counterparties when 

current net receivables and replacement cost exposure 

exceed contractually specified limits. 

The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties:

(in millions)

Gross Credit

Exposure

 Before Credit 

Collateral(1)

Credit 

Collateral 

Net Credit 

Exposure(2)

Number of

Wholesale

Customers or

 Counterparties

>10% 

Net Credit

 Exposure to

Wholesale

Customers or

 Counterparties

>10%

December 31, 2016 $69 $ (11) $58 3 39

December 31, 2015 64 $ (11) $53 4 39

(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, and net receivables 

(payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include 

adjustments for time value or liquidity.

(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters 

of credit posted by counterparties and held by the Utility). For purposes of this table, parental guarantees are not included 

as part of the calculation.

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Critical Accounting Policies

The preparation of the Consolidated Financial Statements 

in accordance with GAAP involves the use of estimates and 

assumptions that affect the recorded amounts of assets 

and liabilities as of the date of the financial statements and 

the reported amounts of revenues and expenses during the 

reporting period. The accounting policies described below 

are considered to be critical accounting policies due, in 

part, to their complexity and because their application is 

relevant and material to the financial position and results 

of operations of PG&E Corporation and the Utility, and 

because these policies require the use of material judgments 

and estimates. Actual results may differ materially from 

these estimates and assumptions. These accounting 

policies and their key characteristics are outlined below. 

Regulatory Accounting

As a regulated entity, the Utility records regulatory assets 

and liabilities for amounts that are deemed probable of 

recovery from, or refund to, customers. These amounts 

would otherwise be recorded to expense or income under 

GAAP. Refer to “Regulation and Regulated Operations” in 

Note 2 as well as Note 3 of the Notes to the Consolidated 

Financial Statements in Item 8. At December 31, 2016, PG&E 

Corporation and the Utility reported regulatory assets 

(including current regulatory balancing accounts receivable) 

of $9.9 billion and regulatory liabilities (including current 

regulatory balancing accounts payable) of $7.7 billion. 

Determining probability requires significant judgment 

by management and includes, but is not limited to, 

consideration of testimony presented in regulatory hearings, 

proposed regulatory decisions, final regulatory orders, 

and the strength or status of applications for rehearing 

or state court appeals. For some of the Utility’s regulatory 

assets, including utility retained generation, the Utility 

has determined that the costs are recoverable based on 

specific approval from the CPUC. The Utility also records a 

regulatory asset when a mechanism is in place to recover 

current expenditures and historical experience indicates 

that recovery of incurred costs is probable, such as the 

regulatory assets for pension benefits; deferred income 

tax; price risk management; and unamortized loss, net of 

gain, on reacquired debt. The CPUC has not denied the 

recovery of any material costs previously recognized by 

the Utility as regulatory assets for the periods presented. 

If the Utility determined that it is no longer probable that 

regulatory assets would be recovered or reflected in future 

rates, or if the Utility ceased to be subject to rate regulation, 

the regulatory assets would be charged against income 

in the period in which that determination was made. If 

regulatory accounting did not apply, the Utility’s future 

financial results could become more volatile as compared 

to historical financial results due to the differences in the 

timing of expense or revenue recognition.

In addition, regulatory accounting standards require 

recognition of a loss if it becomes probable that capital 

expenditures will be disallowed for ratemaking purposes 

and if a reasonable estimate of the amount of the 

disallowance can be made. Such assessments require 

significant judgment by management regarding probability 

of recovery, as described above, and the ultimate cost of 

construction of capital assets. The Utility records a loss 

to the extent capital costs are expected to exceed the 

amount to be recovered. The Utility records a provision 

based on its best estimate; to the extent there is a high 

degree of uncertainty in the Utility’s forecast, it will record 

a provision based on the lower end of the range of possible 

losses. The Utility’s capital forecasts involve a series of 

complex judgments regarding detailed project plans, 

estimates included in third-party contracts, historical cost 

experience for similar projects, permitting requirements, 

environmental compliance standards, and a variety of 

other factors. 

The Utility recorded charges of $283 million in 2016 for 

capital spending that was disallowed related to the Penalty 

Decision. The Utility incurred charges of $219 million in 

2016 for capital expenditures that will be disallowed based 

on the final phase two decision in its 2015 GT&S rate case. 

Additionally, the Utility would be required to record charges 

in future periods to the extent PSEP-related capital costs 

are higher than currently expected. (See “Enforcement 

and Litigation Matters” in Note 13 of the Notes to the 

Consolidated Financial Statements in Item 8.) 

Loss Contingencies

As discussed below, PG&E Corporation and the Utility have recorded material accruals for environmental remediation 

liabilities and for various enforcement and legal matters, and have recorded insurance receivables for third-party claims.

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Environmental Remediation Liabilities

The Utility is subject to loss contingencies pursuant to 

federal and California environmental laws and regulations 

that in the future may require the Utility to pay for 

environmental remediation at sites where it has been, or 

may be, a potentially responsible party. Such contingencies 

may exist for the remediation of hazardous substances 

at various potential sites, including former manufactured 

gas plant sites, power plant sites, gas compressor stations, 

and sites used by the Utility for the storage, recycling, or 

disposal of potentially hazardous materials, even if the 

Utility did not deposit those substances on the site.

The Utility generally commences the environmental 

remediation assessment process upon notification from 

federal or state agencies, or other parties, of a potential 

site requiring remedial action. (In some instances, the 

Utility may initiate action to determine its remediation 

liability for sites that it no longer owns in cooperation with 

regulatory agencies. For example, the Utility has begun a 

program related to certain former manufactured gas plant 

sites.) Based on such notification, the Utility completes an 

assessment of the potential site and evaluates whether it 

is probable that a remediation liability has been incurred. 

The Utility records an environmental remediation liability 

when site assessments indicate remediation is probable 

and it can reasonably estimate the loss or a range of 

possible losses. Given the complexities of the legal and 

regulatory environment and the inherent uncertainties 

involved in the early stages of a remediation project, the 

process for estimating remediation liabilities is subjective 

and requires significant judgment. Key factors evaluated 

in developing cost estimates include the extent and 

types of hazardous substances at a potential site, the 

range of technologies that can be used for remediation, 

the determination of the Utility’s liability in proportion to 

other responsible parties, and the extent to which such 

costs are recoverable from third parties. 

When possible, the Utility estimates costs using site-specific 

information, but also considers historical experience for 

costs incurred at similar sites depending on the level of 

information available. Estimated costs are composed 

of the direct costs of the remediation effort and the 

costs of compensation for employees who are expected 

to devote a significant amount of time directly to the 

remediation effort. These estimated costs include remedial 

site investigations, remediation actions, operations and 

maintenance activities, post remediation monitoring, and 

the costs of technologies that are expected to be approved 

to remediate the site. Remediation efforts for a particular 

site generally extend over a period of several years. During 

this period, the laws governing the remediation process 

may change, as well as site conditions, thereby possibly 

affecting the cost of the remediation effort.

At December 31, 2016 and 2015, the Utility’s accruals 

for undiscounted gross environmental liabilities were 

$958 million and $969 million, respectively. The Utility’s 

undiscounted future costs could increase to as much as 

$1.9 billion if the extent of contamination or necessary 

remediation is greater than anticipated or if the other 

potentially responsible parties are not financially able 

to contribute to these costs, and could increase further 

if the Utility chooses to remediate beyond regulatory 

requirements. Although the Utility has provided for known 

environmental obligations that are probable and reasonably 

estimable, estimated costs may vary significantly from 

actual costs, and the amount of additional future costs 

may be material to results of operations in the period in 

which they are recognized. 

Enforcement and Litigation Matters

PG&E Corporation and the Utility are subject to various 

laws and regulations and, in the normal course of business, 

are named as parties in a number of claims and lawsuits. 

In addition, penalties may be incurred for failure to comply 

with federal, state, or local laws and regulations. PG&E 

Corporation and the Utility record a provision for a loss 

contingency when it is both probable that a loss has been 

incurred and the amount of the loss can be reasonably 

estimated. PG&E Corporation and the Utility evaluate 

the range of reasonably estimated losses and record a 

provision based on the lower end of the range, unless an 

amount within the range is a better estimate than any other 

amount. The assessment of whether a loss is probable or 

reasonably possible, and whether the loss or a range of loss 

is estimable, often involves a series of complex judgments 

about future events. Loss contingencies are reviewed 

quarterly and estimates are adjusted to reflect the impact 

of all known information, such as negotiations, discovery, 

settlements and payments, rulings, advice of legal counsel, 

and other information and events pertaining to a particular 

matter. PG&E Corporation’s and the Utility’s policy is to 

exclude anticipated legal costs from the provision for 

loss and expense these costs as incurred. Management 

has made significant estimates and assumptions about 

accruals related to the Butte fire. At December 31, 2016, the 

Utility’s accrual for the Butte fire was $690 million. Actual 

results may differ materially from these estimates and 

assumptions. (See “Enforcement and Litigation Matters” 

in Note 13 of the Notes to the Consolidated Financial 

Statements in Item 8.) 

Insurance Receivable

The Utility has liability insurance from various insurers, 

which provides coverage for third party claims. The Utility 

records insurance recoveries only when a third party claim 

is recorded and it is deemed probable that a recovery 

of that claim will occur and the Utility can reasonably 

estimate the amount or its range. The assessment of 

whether recovery is probable or reasonably possible, 

and whether the recovery or a range of recoveries is 

estimable, often involves a series of complex judgments 

about future events. Insurance recoveries are reviewed 

quarterly and estimates are adjusted to reflect the impact of 

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all known information, including contractual liability 

insurance policy coverage, advice of legal counsel, past 

experience with similar events, discussions with insurers 

and other information and events pertaining to a particular 

matter. Management has made significant estimates and 

assumptions about insurance recoveries related to the 

Butte fire. (See “Enforcement and Litigation Matters” and 

“Legal and Regulatory Contingencies” in Note 13 of the 

Notes to the Consolidated Financial Statements in Item 8.)

Asset Retirement Obligations

PG&E Corporation and the Utility account for an ARO at 

fair value in the period during which the legal obligation 

is incurred if a reasonable estimate of fair value and its 

settlement date can be made. At the time of recording an 

ARO, the associated asset retirement costs are capitalized 

as part of the carrying amount of the related long-lived 

asset. The Utility recognizes a regulatory asset or liability for 

the timing differences between the recognition of expenses 

and costs recovered through the ratemaking process. (See 

Notes 2 and 3 of the Notes to the Consolidated Financial 

Statements in Item 8.)

To estimate its liability, the Utility uses a discounted 

cash flow model based upon significant estimates and 

assumptions about future decommissioning costs, inflation 

rates, and the estimated date of decommissioning. The 

estimated future cash flows are discounted using a creditadjusted risk-free rate that reflects the risk associated 

with the decommissioning obligation. 

At December 31, 2016, the Utility’s recorded ARO for the 

estimated cost of retiring these long-lived assets was 

$4.7 billion. Changes in these estimates and assumptions 

could materially affect the amount of the recorded ARO 

for these assets. For example, a premature shutdown of 

the nuclear facilities at Diablo Canyon would increase 

the likelihood of an earlier start to decommissioning and 

cause an increase in the ARO. If the inflation adjustment 

or discount rate increased 25 basis points, the result would 

be an immaterial impact to ARO. 

Pension and Other Postretirement Benefit Plans

PG&E Corporation and the Utility sponsor a noncontributory defined benefit pension plan for eligible 

employees as well as contributory postretirement health 

care and medical plans for eligible retirees and their 

eligible dependents, and non-contributory postretirement 

life insurance plans for eligible employees and retirees. 

Adjustments to the pension and other benefit obligation are 

based on the differences between actuarial assumptions 

and actual plan results. These amounts are deferred in 

accumulated other comprehensive income (loss) and 

amortized into income on a gradual basis. The differences 

between pension benefit expense recognized in accordance 

with GAAP and amounts recognized for ratemaking 

purposes are recorded as regulatory assets or liabilities as 

amounts are probable of recovery from customers. To the 

extent the other benefits are in an overfunded position, 

the Utility records a regulatory liability. (See Note 3 of the 

Notes to the Consolidated Financial Statements in Item 8.)

The pension and other postretirement benefit obligations 

are calculated using actuarial models as of the December 31 

measurement date. The significant actuarial assumptions used 

in determining pension and other benefit obligations include 

the discount rate, the average rate of future compensation 

increases, the health care cost trend rate and the expected 

return on plan assets. PG&E Corporation and the Utility review 

these assumptions on an annual basis and adjust them as 

necessary. While PG&E Corporation and the Utility believe that 

the assumptions used are appropriate, significant differences 

in actual experience, plan changes or amendments, or 

significant changes in assumptions may materially affect 

the recorded pension and other postretirement benefit 

obligations and future plan expenses. 

In establishing health care cost assumptions, PG&E 

Corporation and the Utility consider recent cost trends 

and projections from industry experts. This evaluation 

suggests that current rates of inflation are expected to 

continue in the near term. In recognition of continued 

high inflation in health care costs and given the design of 

PG&E Corporation’s plans, the assumed health care cost 

trend rate for 2017 is 7.2%, gradually decreasing to the 

ultimate trend rate of 4.5% in 2025 and beyond. 

Expected rates of return on plan assets were developed 

by estimating future stock and bond returns and then 

applying these returns to the target asset allocations 

of the employee benefit trusts, resulting in a weighted 

average rate of return on plan assets. Fixed-income returns 

were projected based on real maturity and credit spreads 

added to a long-term inflation rate. Equity returns were 

projected based on estimates of dividend yield and real 

earnings growth added to a long-term rate of inflation. 

For the Utility’s defined benefit pension plan, the assumed 

return of 5.3% compares to a ten-year actual return of 7.3%.

The rate used to discount pension benefits and other 

benefits was based on a yield curve developed from 

market data of approximately 696 Aa-grade non-callable 

bonds at December 31, 2016. This yield curve has discount 

rates that vary based on the duration of the obligations. 

The estimated future cash flows for the pension and 

other postretirement benefit obligations were matched 

to the corresponding rates on the yield curve to derive a 

weighted average discount rate.

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The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial 

assumptions:

(in millions)

Increase (Decrease) 

in Assumption 

Increase in 2016 

Pension Costs 

Increase in Projected 

Benefit Obligation at 

December 31, 2016

Discount rate (0.50)% $ 109 $ 1,319

Rate of return on plan assets (0.50)% 68 –

Rate of increase in compensation 0.50 % 59 306

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to 

changes in certain actuarial assumptions:

(in millions)

Increase (Decrease) 

in Assumption 

Increase in 2016

Other Postretirement

Benefit Costs 

Increase in Accumulated

Benefit Obligation at

December 31, 2016

Health care cost trend rate 0.50% $ 4 $ 58

Discount rate (0.50)% 4 134

Rate of return on plan assets (0.50)% 10 –

New Accounting Pronouncements

See Note 2 of the Notes to the Consolidated Financial Statements.

Forward-Looking Statements 

This report contains forward-looking statements that are 

necessarily subject to various risks and uncertainties. These 

statements reflect management’s judgment and opinions 

which are based on current estimates, expectations, and 

projections about future events and assumptions regarding 

these events and management’s knowledge of facts as of 

the date of this 2016 Form 10-K. These forward-looking 

statements relate to, among other matters, estimated 

losses, including penalties and fines, associated with 

various investigations and proceedings; forecasts of 

pipeline-related expenses that the Utility will not recover 

through rates; forecasts of capital expenditures; estimates 

and assumptions used in critical accounting policies, 

including those relating to regulatory assets and liabilities, 

environmental remediation, litigation, third-party claims, 

and other liabilities; and the level of future equity or debt 

issuances. These statements are also identified by words 

such as “assume,” “expect,” “intend,” “forecast,” “plan,” 

“project,” “believe,” “estimate,” “predict,” “anticipate,” 

“may,” “should,” “would,” “could,” “potential” and similar 

expressions. PG&E Corporation and the Utility are not able 

to predict all the factors that may affect future results. 

Some of the factors that could cause future results to 

differ materially from those expressed or implied by the 

forward-looking statements, or from historical results, 

include, but are not limited to: 

đ the timing and outcomes of the Butte fire litigation, 

and whether the Utility’s insurance is sufficient to cover 

the Utility’s liability resulting therefrom or whether 

insurance is otherwise available; and whether additional 

investigations and proceedings in connection with the 

Butte fire will be opened;

đ the timing and outcomes of the 2017 GRC, TO rate case, 

cost of capital proceeding, and other ratemaking and 

regulatory proceedings;

đ the terms of probation and the monitorship imposed 

in the sentencing phase of the Utility’s federal criminal 

trial on January 26, 2017, the timing and outcomes of 

the debarment proceeding and potential remedial and 

other measures that could be imposed on the Utility 

as a result of that proceeding, the SED’s unresolved 

enforcement matters relating to the Utility’s compliance 

with natural gas-related laws and regulations, and other 

investigations that have been or may be commenced 

relating to the Utility’s compliance with natural gasrelated laws and regulations, and the ultimate amount 

of fines, penalties, and remedial costs that the Utility 

may incur in connection with the outcomes;

đ the timing and outcomes of the CPUC’s investigation 

of communications between the Utility and the CPUC 

that may have violated the CPUC’s rules regarding ex 

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parte communications or are otherwise alleged to be 

improper, or of a potential settlement, and of the U.S. 

Attorney’s Office in San Francisco and the California 

Attorney General’s office investigations in connection 

with communications between the Utility’s personnel and 

CPUC officials, whether additional criminal or regulatory 

investigations or enforcement actions are commenced 

with respect to allegedly improper communications, and 

the extent to which such matters negatively affect the 

final decisions to be issued in the Utility’s ratemaking 

proceedings;

đ whether PG&E Corporation and the Utility are able 

to repair the harm to their reputations caused by the 

Utility’s conviction in the federal criminal trial, the state 

and federal investigations of natural gas incidents, 

matters relating to the criminal federal trial, improper 

communications between the CPUC and the Utility, and 

the Utility’s ongoing work to remove encroachments 

from transmission pipeline rights-of-way;

đ whether the Utility can control its costs within the 

authorized levels of spending, and successfully implement 

a streamlined organizational structure and achieve 

project savings, the extent to which the Utility incurs 

unrecoverable costs that are higher than the forecasts of 

such costs, and changes in cost forecasts or the scope 

and timing of planned work resulting from changes in 

customer demand for electricity and natural gas or 

other reasons;

đ the timing and outcome of the complaint filed by the 

CPUC and certain other parties with the FERC on 

February 2, 2017; the complaint requests that the Utility 

provide an open and transparent planning process for 

its capital transmission projects that do not go through 

the California ISO’s Transmission Planning Process in 

order to allow for participation and input from interested 

parties. The planning process that may result from 

come out of the proceeding may impact the scope and 

timing of capital transmission projects that the Utility 

will execute in the future;

đ the amount and timing of additional common stock 

and debt issuances by PG&E Corporation, including 

the dilutive impact of common stock issuances to fund 

PG&E Corporation’s equity contributions to the Utility 

as the Utility incurs charges and costs, including fines, 

that it cannot recover through rates;

đ the outcome of the CPUC’s investigation into the Utility’s 

safety culture, and future legislative or regulatory actions 

that may be taken to require the Utility to separate its 

electric and natural gas businesses, restructure into 

separate entities, undertake some other corporate 

restructuring, or implement corporate governance changes;

đ the outcomes of the SED’s investigations of potential 

violations identified through audits, investigations, or 

self-reports including in connection with the Utility’s 

February 2017 self-report related to its customer service 

representatives’ drug and alcohol testing program;

đ the outcome of future investigations or other enforcement 

proceedings that may be commenced relating to 

the Utility’s compliance with laws, rules, regulations, 

or orders applicable to its operations, including the 

construction, expansion or replacement of its electric 

and gas facilities, inspection and maintenance practices, 

customer billing and privacy, and physical and cyber 

security, environmental laws and regulations; 

đ the impact of environmental remediation laws, regulations, 

and orders; the ultimate amount of costs incurred to 

discharge the Utility’s known and unknown remediation 

obligations; and the extent to which the Utility is able 

to recover environmental costs in rates or from other 

sources;

đ the ultimate amount of unrecoverable environmental 

costs the Utility incurs associated with the Utility’s 

natural gas compressor station site located near Hinkley, 

California;

đ the impact of maintenance costs of the Utility electric 

transmission facilities;

đ the impact of new legislation or NRC regulations, 

recommendations, policies, decisions, or orders relating 

to the nuclear industry, including operations, seismic 

design, security, safety, relicensing, the storage of spent 

nuclear fuel, decommissioning, cooling water intake, 

or other issues; the impact of actions taken by state 

agencies that may affect the Utility’s ability to continue 

operating Diablo Canyon; whether the CPUC approves 

the joint proposal that will phase out the Utility’s Diablo 

Canyon nuclear units at the expiration of their licenses in 

2024 and 2025; whether the Utility obtains the approvals 

required to withdraw its NRC application to renew the 

two Diablo Canyon operating licenses; whether the State 

Lands Commission could be required to perform an 

environmental review of the new lands lease as a result 

of the WBA assertion that the State Lands Commission 

committed legal error when it determined that the short 

term lease extension for an existing facility was exempt 

from review under the California Environmental Quality 

Act; and whether the Utility will be able to successfully 

implement its retention and retraining and development 

programs for Diablo Canyon employees, and whether 

these programs will be recovered in rates;

đ whether the Utility is successful in ensuring physical 

security of its critical assets and whether the Utility’s 

information technology, operating systems and networks, 

including the advanced metering system infrastructure, 

customer billing, financial, records management, and 

other systems, can continue to function accurately 

while meeting regulatory requirements; whether the 

Utility and its third party vendors and contractors (who 

host, maintain, modify and update some of the Utility’s 

systems) are able to protect the Utility’s operating 

systems and networks from damage, disruption, or 

failure caused by cyber-attacks, computer viruses, or 

other hazards; whether the Utility’s security measures are 

sufficient to protect against unauthorized or inadvertent 

disclosure of information contained in such systems and 

networks, including confidential proprietary information 

and the personal information of customers; and whether 

the Utility can continue to rely on third-party vendors 

and contractors that maintain and support some of the 

Utility’s information technology and operating systems;

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

đ the impact of droughts or other weather-related 

conditions or events, wildfires (such as the Butte fire), 

climate change, natural disasters, acts of terrorism, war, 

vandalism (including cyber-attacks), and other events, 

that can cause unplanned outages, reduce generating 

output, disrupt the Utility’s service to customers, or 

damage or disrupt the facilities, operations, or information 

technology and systems owned by the Utility, its 

customers, or third parties on which the Utility relies; 

whether the Utility incurs liability to third parties for 

property damage or personal injury caused by such 

events; whether the Utility is subject to civil, criminal, 

or regulatory penalties in connection with such events; 

and whether the Utility’s insurance coverage is available 

for these types of claims and sufficient to cover the 

Utility’s liability;

đ how the CPUC and the CARB implement state 

environmental laws relating to GHG, renewable energy 

targets, energy efficiency standards, DERs, electric 

vehicles, and similar matters, including whether the Utility 

is able to continue recovering associated compliance 

costs, such as the cost of emission allowances and offsets 

under cap-and-trade regulations; and whether the Utility 

is able to timely recover its associated investment costs;

đ the impact of the SB 887 directing DOGGR and CARB 

to develop permanent regulations for gas storage facility 

operations in California to comply with new safety and 

reliability measures, as well the impact of the PHMSA 

rules effective January 18, 2017 regulating gas storage 

facilities at the federal level;

đ whether the Utility’s climate change adaptation strategies 

are successful;

đ the impact that reductions in customer demand for 

electricity and natural gas have on the Utility’s ability to 

make and recover its investments through rates and earn 

its authorized return on equity, and whether the Utility is 

successful in addressing the impact of growing distributed 

and renewable generation resources, changing customer 

demand for natural gas and electric services, and an 

increasing number of customers departing for CCAs;

đ the supply and price of electricity, natural gas, and 

nuclear fuel; the extent to which the Utility can manage 

and respond to the volatility of energy commodity 

prices; the ability of the Utility and its counterparties 

to post or return collateral in connection with price risk 

management activities; and whether the Utility is able 

to recover timely its electric generation and energy 

commodity costs through rates, including its renewable 

energy procurement costs;

đ the amount and timing of charges reflecting probable 

liabilities for third-party claims; the extent to which 

costs incurred in connection with third-party claims 

or litigation can be recovered through insurance, rates, 

or from other third parties; and whether the Utility can 

continue to obtain adequate insurance coverage for 

future losses or claims, especially following a major 

event that causes widespread third-party losses;

đ the ability of PG&E Corporation and the Utility to access 

capital markets and other sources of debt and equity 

financing in a timely manner on acceptable terms;

đ changes in credit ratings which could result in increased 

borrowing costs especially if PG&E Corporation or the 

Utility were to lose their investment grade credit ratings;

đ the impact of federal or state laws or regulations, or 

their interpretation, on energy policy and the regulation 

of utilities and their holding companies, including how 

the CPUC interprets and enforces the financial and 

other conditions imposed on PG&E Corporation when it 

became the Utility’s holding company, and whether the 

ultimate outcomes of the CPUC’s pending investigations, 

the jury’s verdict in the federal criminal trial of the Utility 

and its possible conviction, and other enforcement 

matters affect the Utility’s ability to make distributions 

to PG&E Corporation, and, in turn, PG&E Corporation’s 

ability to pay dividends;

đ the impact of the corporate tax reform considered by the 

new federal administration and the outcome of federal 

or state tax audits and the impact of any changes in 

federal or state tax laws, policies, regulations, or their 

interpretation; 

đ changes in the regulatory and economic environment, 

including potential changes affecting renewable energy 

sources and associated tax credits, as a result of the 

new federal administration; and

đ the impact of changes in GAAP, standards, rules, or 

policies, including those related to regulatory accounting, 

and the impact of changes in their interpretation or 

application.

For more information about the significant risks that could 

affect the outcome of the forward-looking statements 

and PG&E Corporation’s and the Utility’s future financial 

condition, results of operations, and cash flows, see Item. 

1A. Risk Factors above and our detailed discussion of these 

matters contained elsewhere in MD&A. PG&E Corporation 

and the Utility do not undertake any obligation to update 

forward-looking statements, whether in response to new 

information, future events, or otherwise.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and 

in Note 9: Derivatives and Note 10: Fair Value Measurements of the Notes to the Consolidated Financial Statements 

in Item 8.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

ITEM 8. Financial Statements and Supplementary Data

PG&E Corporation

CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)

Year ended December 31,

2016 2015 2014

Operating Revenues

Electric $13,864 $13,657 $13,658

Natural gas 3,802 3,176 3,432

Total operating revenues 17,666 16,833 17,090

Operating Expenses

Cost of electricity 4,765 5,099 5,615

Cost of natural gas 615 663 954

Operating and maintenance 7,354 6,951 5,638

Depreciation, amortization, and decommissioning 2,755 2,612 2,433

Total operating expenses 15,489 15,325 14,640

Operating Income 2,177 1,508 2,450

Interest income 23 9 9

Interest expense (829) (773) (734)

Other income, net 91 117 70

Income Before Income Taxes 1,462 861 1,795

Income tax provision (benefit) 55 (27) 345

Net Income 1,407 888 1,450

Preferred stock dividend requirement of subsidiary 14 14 14

Income Available for Common Shareholders $ 1,393 $ 874 $ 1,436

Weighted Average Common Shares Outstanding, Basic 499 484 468

Weighted Average Common Shares Outstanding, Diluted 501 487 470

Net Earnings Per Common Share, Basic $ 2.79 $ 1.81 $ 3.07

Net Earnings Per Common Share, Diluted $ 2.78 $ 1.79 $ 3.06

See accompanying Notes to the Consolidated Financial Statements.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

Year ended December 31,

2016 2015 2014

Net Income $1,407 $ 888 $1,450

Other Comprehensive Income 

Pension and other postretirement benefit plans obligations 

(net of taxes of $1, $0, and $10, at respective dates) (2) (1) (14)

Net change in investments 

(net of taxes of $0, $12, and $17 at respective dates) - (17) (25)

Total other comprehensive income (loss) (2) (18) (39)

Comprehensive Income 1,405 870 1,411

Preferred stock dividend requirement of subsidiary 14 14 14

Comprehensive Income Attributable to Common Shareholders $1,391 $ 856 $1,397

See accompanying Notes to the Consolidated Financial Statements.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions)

Balance at December 31,

2016 2015

ASSETS

Current Assets

Cash and cash equivalents $ 177 $ 123

Restricted cash 7 234

Accounts receivable

Customers (net of allowance for doubtful accounts of $58 and $54 

at respective dates) 1,252 1,106

Accrued unbilled revenue 1,098 855

Regulatory balancing accounts 1,500 1,760

Other 801 286

Regulatory assets 423 517

Inventories

Gas stored underground and fuel oil 117 126

Materials and supplies 346 313

Income taxes receivable 160 155

Other 283 338

Total current assets 6,164 5,813

Property, Plant, and Equipment

Electric 52,556 48,532

Gas 17,853 16,749

Construction work in progress 2,184 2,059

Other 2 2

Total property, plant, and equipment 72,595 67,342

Accumulated depreciation (22,014) (20,619)

Net property, plant, and equipment 50,581 46,723

Other Noncurrent Assets

Regulatory assets 7,951 7,029

Nuclear decommissioning trusts 2,606 2,470

Income taxes receivable 70 135

Other 1,226 1,064

Total other noncurrent assets 11,853 10,698

TOTAL ASSETS $ 68,598 $ 63,234

See accompanying Notes to the Consolidated Financial Statements.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

Balance at December 31,

2016 2015

LIABILITIES AND EQUITY

Current Liabilities

Short-term borrowings $ 1,516 $ 1,019

Long-term debt, classified as current 700 160

Accounts payable

Trade creditors 1,495 1,414

Regulatory balancing accounts 645 715

Other 433 398

Disputed claims and customer refunds 236 454

Interest payable 216 206

Other 2,323 1,997

Total current liabilities 7,564 6,363

Noncurrent Liabilities 

Long-term debt 16,220 15,925

Regulatory liabilities 6,805 6,321

Pension and other postretirement benefits 2,641 2,622

Asset retirement obligations 4,684 3,643

Deferred income taxes 10,213 9,206

Other 2,279 2,326

Total noncurrent liabilities 42,842 40,043

Commitments and Contingencies (Note 13)

Equity

Shareholders' Equity

Common stock, no par value, authorized 800,000,000 shares; 506,891,874 and 

492,025,443 shares outstanding at respective dates 12,198 11,282

Reinvested earnings 5,751 5,301

Accumulated other comprehensive loss (9) (7)

Total shareholders' equity 17,940 16,576

Noncontrolling Interest – Preferred Stock of Subsidiary 252 252

Total equity 18,192 16,828

TOTAL LIABILITIES AND EQUITY $ 68,598 $ 63,234

See accompanying Notes to the Consolidated Financial Statements.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

Year ended December 31,

2016 2015 2014

Cash Flows from Operating Activities

Net income $ 1,407 $ 888 $ 1,450

Adjustments to reconcile net income to net cash provided by 

operating activities:

Depreciation, amortization, and decommissioning 2,755 2,612 2,433

Allowance for equity funds used during construction (112) (107) (100)

Deferred income taxes and tax credits, net 1,030 693 690

Disallowed capital expenditures 507 407 116

Other 379 326 286

Effect of changes in operating assets and liabilities:

Accounts receivable (473) (177) 13

Butte-related insurance receivable (575) - -

Inventories (24) 37 (22)

Accounts payable 180 (55) (61)

Butte-related third-party claims 690 - -

Income taxes receivable/payable (5) 43 376

Other current assets and liabilities 83 (288) 218

Regulatory assets, liabilities, and balancing accounts, net (1,214) (244) (1,642)

Other noncurrent assets and liabilities (219) (355) (67)

Net cash provided by operating activities 4,409 3,780 3,690

Cash Flows from Investing Activities

Capital expenditures (5,709) (5,173) (4,833)

Decrease in restricted cash 227 64 3

Proceeds from sales and maturities of nuclear decommissioning 

trust investments 1,295 1,268 1,336

Purchases of nuclear decommissioning trust investments (1,352) (1,392) (1,334)

Other 13 22 114

Net cash used in investing activities (5,526) (5,211) (4,714)

Cash Flows from Financing Activities

Borrowings (repayments) under revolving credit facilities - - (260)

Net issuances (repayments) of commercial paper, net of discount 

of $6, $3, and $2 at respective dates (9) 683 (583)

Short-term debt financing 500 - 300

Short-term debt matured - (300) -

Proceeds from issuance of long-term debt, net of premium, discount 

and issuance costs of $17, $27 and $17 at respective dates 983 1,123 2,308

Repayments of long-term debt (160) - (889)

Common stock issued 822 780 802

Common stock dividends paid (921) (856) (828)

Other (44) (27) 29

Net cash provided by financing activities 1,171 1,403 879

Net change in cash and cash equivalents 54 (28) (145)

Cash and cash equivalents at January 1 123 151 296

Cash and cash equivalents at December 31 $ 177 $ 123 $ 151

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Year ended December 31,

2016 2015 2014

Supplemental disclosures of cash flow information

Cash received (paid) for: 

Interest, net of amounts capitalized $ (726) $ (684) $ (633)

Income taxes, net 231 77 501

Supplemental disclosures of noncash investing and financing 

activities

Common stock dividends declared but not yet paid $ 248 $ 224 $ 217

Capital expenditures financed through accounts payable 403 440 339

Noncash common stock issuances 20 21 21

Terminated capital leases 18 - 71

See accompanying Notes to the Consolidated Financial Statements.

PG&E Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)

Common 

Stock 

Shares

Common 

Stock 

Amount

Reinvested 

Earnings 

Accumulated 

Other 

Comprehensive 

Income (Loss)

Total 

Shareholders’ 

Equity

Non 

controlling 

Interest - 

Preferred 

Stock of 

Subsidiary

Total 

Equity

Balance at 

December 31, 2013 456,670,424 $ 9,550 $ 4,742 $ 50 $ 14,342 $ 252 $ 14,594

Net income - - 1,450 - 1,450 - 1,450

Other comprehensive 

income - - - (39) (39) - (39)

Common stock issued, net 19,242,980 823 - - 823 - 823

Stock-based compensation 

amortization - 65 - - 65 - 65

Common stock dividends 

declared - - (862) - (862) - (862)

Tax expense from employee 

stock plans - (17) - - (17) - (17)

Preferred stock dividend 

requirement of subsidiary - - (14) - (14) - (14)

Balance at 

December 31, 2014 475,913,404 $ 10,421 $ 5,316 $ 11 $ 15,748 $ 252 $ 16,000

Net income - - 888 - 888 - 888

Other comprehensive loss - - - (18) (18) - (18)

Common stock issued, net 16,112,039 801 - - 801 - 801

Stock-based compensation 

amortization - 66 - - 66 - 66

Common stock dividends 

declared - - (889) - (889) - (889)

Tax expense from employee 

stock plans - (6) - - (6) - (6)

Preferred stock dividend 

requirement of subsidiary - - (14) - (14) - (14)

Balance at 

December 31, 2015 492,025,443 $ 11,282 $ 5,301 $ (7) $ 16,576 $ 252 $ 16,828

Cumulative effect of change 

in accounting principle - - 29 - 29 - 29

Net income - - 1,407 - 1,407 - 1,407

Other comprehensive loss - - - (2) (2) - (2)

Common stock issued, net 14,866,431 842 - - 842 - 842

Stock-based compensation 

amortization - 74 - - 74 - 74

Common stock dividends 

declared - - (972) - (972) - (972)

Preferred stock dividend 

requirement of subsidiary - - (14) - (14) - (14)

Balance at 

December 31, 2016 506,891,874 $ 12,198 $ 5,751 $ (9) $ 17,940 $ 252 $ 18,192

See accompanying Notes to the Consolidated Financial Statements.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF INCOME

(in millions)

Year ended December 31,

2016 2015 2014

Operating Revenues 

Electric $13,865 $13,657 $13,656

Natural gas 3,802 3,176 3,432

Total operating revenues 17,667 16,833 17,088

Operating Expenses 

Cost of electricity 4,765 5,099 5,615

Cost of natural gas 615 663 954

Operating and maintenance 7,352 6,949 5,635

Depreciation, amortization, and decommissioning 2,754 2,611 2,432

Total operating expenses 15,486 15,322 14,636

Operating Income 2,181 1,511 2,452

Interest income 22 8 8

Interest expense (819) (763) (720)

Other income, net 88 87 77

Income Before Income Taxes 1,472 843 1,817

Income tax provision (benefit) 70 (19) 384

Net Income 1,402 862 1,433

Preferred stock dividend requirement 14 14 14

Income Available for Common Stock $ 1,388 $ 848 $ 1,419

See accompanying Notes to the Consolidated Financial Statements.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)

Year ended December 31,

2016 2015 2014

Net Income $1,402 $ 862 $1,433

Other Comprehensive Income 

Pension and other postretirement benefit plans obligations 

(net of taxes of $1, $1, and $6, at respective dates) (1) (2) (8)

Total other comprehensive income (loss) (1) (2) (8)

Comprehensive Income $1,401 $ 860 $1,425

See accompanying Notes to the Consolidated Financial Statements.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions)

Balance at December 31,

2016 2015

ASSETS

Current Assets

Cash and cash equivalents $ 71 $ 59

Restricted cash 7 234

Accounts receivable

Customers (net of allowance for doubtful accounts of $58 and $54 

at respective dates) 1,252 1,106

Accrued unbilled revenue 1,098 855

Regulatory balancing accounts 1,500 1,760

Other 801 284

Regulatory assets 423 517

Inventories

Gas stored underground and fuel oil 117 126

Materials and supplies 346 313

Income taxes receivable 159 130

Other 282 338

Total current assets 6,056 5,722

Property, Plant, and Equipment

Electric 52,556 48,532

Gas 17,853 16,749

Construction work in progress 2,184 2,059

Total property, plant, and equipment 72,593 67,340

Accumulated depreciation (22,012) (20,617)

Net property, plant, and equipment 50,581 46,723

Other Noncurrent Assets

Regulatory assets 7,951 7,029

Nuclear decommissioning trusts 2,606 2,470

Income taxes receivable 70 135

Other 1,110 958

Total other noncurrent assets 11,737 10,592

TOTAL ASSETS $ 68,374 $ 63,037

See accompanying Notes to the Consolidated Financial Statements.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pacific Gas and Electric Company

CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)

Balance at December 31,

2016 2015

LIABILITIES AND SHAREHOLDERS' EQUITY

Current Liabilities

Short-term borrowings $ 1,516 $ 1,019

Long-term debt, classified as current 700 160

Accounts payable

Trade creditors 1,494 1,414

Regulatory balancing accounts 645 715

Other 453 418

Disputed claims and customer refunds 236 454

Interest payable 214 203

Other 2,072 1,750

Total current liabilities 7,330 6,133

Noncurrent Liabilities 

Long-term debt 15,872 15,577

Regulatory liabilities 6,805 6,321

Pension and other postretirement benefits 2,548 2,534

Asset retirement obligations 4,684 3,643

Deferred income taxes 10,510 9,487

Other 2,230 2,282

Total noncurrent liabilities 42,649 39,844

Commitments and Contingencies (Note 13)

Shareholders' Equity

Preferred stock 258 258

Common stock, $5 par value, authorized 800,000,000 shares; 

264,374,809 shares outstanding at respective dates 1,322 1,322

Additional paid-in capital 8,050 7,215

Reinvested earnings 8,763 8,262

Accumulated other comprehensive income 2 3

Total shareholders' equity 18,395 17,060

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 68,374 $ 63,037

See accompanying Notes to the Consolidated Financial Statements.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

Year ended December 31,

2016 2015 2014

Cash Flows from Operating Activities 

Net income $ 1,402 $ 862 $ 1,433

Adjustments to reconcile net income to net cash provided 

by operating activities:

Depreciation, amortization, and decommissioning 2,754 2,611 2,432

Allowance for equity funds used during construction (112) (107) (100)

Deferred income taxes and tax credits, net 1,042 714 731

Disallowed capital expenditures 507 407 116

Other 306 263 226

Effect of changes in operating assets and liabilities:

Accounts receivable (475) (177) 16

Butte-related insurance receivable (575) - -

Inventories (24) 37 (22)

Accounts payable 179 (2) (55)

Butte-related third-party claims 690 - -

Income taxes receivable/payable (29) 38 395

Other current assets and liabilities 112 (315) 168

Regulatory assets, liabilities, and balancing accounts, net (1,214) (244) (1,642)

Other noncurrent assets and liabilities (219) (340) (66)

Net cash provided by operating activities 4,344 3,747 3,632

Cash Flows from Investing Activities 

Capital expenditures (5,709) (5,173) (4,833)

Decrease in restricted cash 227 64 3

Proceeds from sales and maturities of nuclear decommissioning 

trust investments 1,295 1,268 1,336

Purchases of nuclear decommissioning trust investments (1,352) (1,392) (1,334)

Other 13 22 29

Net cash used in investing activities (5,526) (5,211) (4,799)

Cash Flows from Financing Activities 

Net issuances (repayments) of commercial paper, net of discount 

of $6, $3, and $2 at respective dates (9) 683 (583)

Short-term debt financing 500 - 300

Short-term debt matured - (300) -

Proceeds from issuance of long-term debt, net of premium, discount 

and issuance costs of $17, $27, and $14 at respective dates 983 1,123 1,961

Repayments of long-term debt (160) - (539)

Preferred stock dividends paid (14) (14) (14)

Common stock dividends paid (911) (716) (716)

Equity contribution from PG&E Corporation 835 705 705

Other (30) (13) 43

Net cash provided by financing activities 1,194 1,468 1,157

Net change in cash and cash equivalents 12 4 (10)

Cash and cash equivalents at January 1 59 55 65

Cash and cash equivalents at December 31 $ 71 $ 59 $ 55

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Year ended December 31,

2016 2015 2014

Supplemental disclosures of cash flow information 

Cash received (paid) for: 

Interest, net of amounts capitalized $ (717) $ (675) $ (618)

Income taxes, net 244 77 500

Supplemental disclosures of noncash investing and financing 

activities

Capital expenditures financed through accounts payable $ 403 $ 440 $ 339

Terminated capital leases 18 - 71

See accompanying Notes to the Consolidated Financial Statements.

Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

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Pacific Gas and Electric Company

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)

Preferred 

Stock

Common 

Stock

Additional 

Paid-in 

Capital

Reinvested 

Earnings

Accumulated 

Other 

Comprehensive 

Income (Loss)

Total 

Shareholders’ 

Equity

Balance at December 31, 2013 $ 258 $ 1,322 $ 5,821 $ 7,427 $ 13 $ 14,841

Net income - - - 1,433 - 1,433

Other comprehensive income - - - - (8) (8)

Equity contribution - - 705 - - 705

Tax expense from employee 

stock plans - - (12) - - (12)

Common stock dividend - - - (716) - (716)

Preferred stock dividend - - - (14) - (14)

Balance at December 31, 2014 $ 258 $ 1,322 $ 6,514 $ 8,130 $ 5 $ 16,229

Net income - - - 862 - 862

Other comprehensive loss - - - - (2) (2)

Equity contribution - - 705 - - 705

Tax expense from employee 

stock plans - - (4) - - (4)

Common stock dividend - - - (716) - (716)

Preferred stock dividend - - - (14) - (14)

Balance at December 31, 2015 $ 258 $ 1,322 $ 7,215 $ 8,262 $ 3 $ 17,060

Cumulative effect of change 

in accounting principle - - - 24 - 24

Net income - - - 1,402 - 1,402

Other comprehensive loss - - - - (1) (1)

Equity contribution - - 835 - - 835

Common stock dividend - - - (911) - (911)

Preferred stock dividend - - - (14) - (14)

Balance at December 31, 2016 $ 258 $ 1,322 $ 8,050 $ 8,763 $ 2 $ 18,395

See accompanying Notes to the Consolidated Financial Statements.

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Notes to the Consolidated Financial Statements

NOTE 1: Organization and Basis of Presentation

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 is primarily regulated by the CPUC and the FERC. 

In addition, the NRC oversees the licensing, construction, 

operation, and decommissioning of the Utility’s nuclear 

generation facilities. 

This is a combined annual report of PG&E Corporation 

and the Utility. PG&E Corporation’s Consolidated Financial 

Statements include the accounts of PG&E Corporation, the 

Utility, and other wholly owned and controlled subsidiaries. 

The Utility’s Consolidated Financial Statements include 

the accounts of the Utility and its wholly owned and 

controlled subsidiaries. All intercompany transactions 

have been eliminated in consolidation. The Notes to the 

Consolidated Financial Statements apply to both PG&E 

Corporation and the Utility. PG&E Corporation and the 

Utility assess financial performance and allocate resources 

on a consolidated basis (i.e., the companies operate in 

one segment).

The accompanying Consolidated Financial Statements 

have been prepared in conformity with GAAP and in 

accordance with the reporting requirements of Form 10-K. 

The preparation of financial statements in conformity with 

GAAP requires the use of estimates and assumptions that 

affect the reported amounts of assets, liabilities, revenues 

and expenses and the disclosure of contingent assets and 

liabilities. Some of the more significant estimates and 

assumptions relate to the Utility’s regulatory assets and 

liabilities, legal and regulatory contingencies, environmental 

remediation liabilities, AROs, and pension and other 

postretirement benefit plans obligations. Management 

believes that its estimates and assumptions reflected in 

the Consolidated Financial Statements are appropriate 

and reasonable. A change in management’s estimates or 

assumptions could result in an adjustment that would have 

a material impact on PG&E Corporation’s and the Utility’s 

financial condition and results of operations and cash 

flows during the period in which such change occurred.

NOTE 2: Summary of Significant Accounting Policies

Regulation and Regulated Operations

The Utility follows accounting principles for rate-regulated 

entities and collects rates from customers to recover “revenue 

requirements” that have been authorized by the CPUC or 

the FERC based on the Utility’s cost of providing service. 

The Utility’s ability to recover a significant portion of its 

authorized revenue requirements through rates is generally 

independent, or “decoupled,” from the volume of the Utility’s 

electricity and natural gas sales. The Utility records assets and 

liabilities that result from the regulated ratemaking process 

that would not be recorded under GAAP for nonregulated 

entities. The Utility capitalizes and records, as regulatory 

assets, costs that would otherwise be charged to expense 

if it is probable that the incurred costs will be recovered in 

future rates. Regulatory assets are amortized over the future 

periods in which the costs are recovered. If costs expected 

to be incurred in the future are currently being recovered 

through rates, the Utility records those expected future 

costs as regulatory liabilities. Amounts that are probable 

of being credited or refunded to customers in the future 

are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account 

asset or liability for differences between customer billings 

and authorized revenue requirements that are probable 

of recovery or refund. In addition, the Utility records a 

regulatory balancing account asset or liability for differences 

between incurred costs and customer billings or authorized 

revenue meant to recover those costs, to the extent that 

these differences are probable of recovery or refund. These 

differences have no impact on net income. (See “Revenue 

Recognition” below.)

Management continues to believe the use of regulatory 

accounting is applicable and that all regulatory assets and 

liabilities are recoverable or refundable. To the extent that 

portions of the Utility’s operations cease to be subject to 

cost of service rate regulation, or recovery is no longer 

probable as a result of changes in regulation or other reasons, 

the related regulatory assets and liabilities are written off.

Revenue Recognition

The Utility recognizes revenues when electricity and natural 

gas services are delivered. The Utility records unbilled 

revenues for the estimated amount of energy delivered 

to customers but not yet billed at the end of the period. 

Unbilled revenues are included in accounts receivable 

on the Consolidated Balance Sheets. Rates charged to 

customers are based on CPUC and FERC authorized 

revenue requirements.

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The CPUC authorizes most of the Utility’s revenues in the 

Utility’s GRC and its GT&S rate cases, which generally 

occur every three or four years. The Utility’s ability to 

recover revenue requirements authorized by the CPUC in 

these rates cases is independent, or “decoupled” from the 

volume of the Utility’s sales of electricity and natural gas 

services. The Utility recognizes revenues that have been 

authorized for rate recovery, are objectively determinable 

and probable of recovery, and are expected to be collected 

within 24 months. Generally, revenue is recognized ratably 

over the year. 

The CPUC also has authorized the Utility to collect 

additional revenue requirements to recover costs that 

the Utility has been authorized to pass on to customers, 

including costs to purchase electricity and natural gas; 

and to fund public purpose, demand response, and 

customer energy efficiency programs. In general, the 

revenue recognition criteria for pass-through costs billed 

to customers are met at the time the costs are incurred.

The FERC authorizes the Utility’s revenue requirements in 

periodic (often annual) TO rate cases. The Utility’s ability 

to recover revenue requirements authorized by the FERC 

is dependent on the volume of the Utility’s electricity 

sales, and revenue is recognized only for amounts billed 

and unbilled.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, 

highly liquid investments with original maturities of three 

months or less. Cash equivalents are stated at fair value.

Restricted Cash

Prior to October 2016, restricted cash primarily consisted 

of the Utility’s cash held in escrow pending the resolution 

of the remaining disputed claims made by electricity 

suppliers in the Utility’s proceeding under Chapter 11 of 

the U.S. Bankruptcy Code. (See “Resolution of Remaining 

Chapter 11 Disputed Claims” in Note 13 below.)

Allowance for Doubtful Accounts Receivable

PG&E Corporation and the Utility recognize an allowance 

for doubtful accounts to record uncollectable customer 

accounts receivable at estimated net realizable value. 

The allowance is determined based upon a variety of 

factors, including historical write-off experience, aging of 

receivables, current economic conditions, and assessment 

of customer collectability.

Inventories

Inventories are carried at weighted-average cost and include 

natural gas stored underground as well as materials and 

supplies. Natural gas stored underground is recorded to 

inventory when injected and then expensed as the gas 

is withdrawn for distribution to customers or to be used 

as fuel for electric generation. Materials and supplies are 

recorded to inventory when purchased and expensed or 

capitalized to plant, as appropriate, when consumed or 

installed.

Emission Allowances

The Utility purchases GHG emission allowances to satisfy 

its compliance obligations. Associated costs are recorded 

as inventory and included in current assets – other and 

other noncurrent assets – other on the Consolidated 

Balance Sheets. Costs are carried at weighted-average 

and are recoverable through rates.

Property, Plant, and Equipment

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair 

value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The 

Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:

(in millions, except estimated useful lives)

Estimated Useful 

Lives (years)

Balance at December 31,

2016 2015

Electricity generating facilities(1) 5 to 100 $ 11,308 $ 9,860

Electricity distribution facilities 15 to 55 29,836 28,476

Electricity transmission facilities 15 to 75 11,412 10,196

Natural gas distribution facilities 5 to 60 11,362 10,397

Natural gas transmission and storage facilities 5 to 65 6,491 6,352

Construction work in progress 2,184 2,059

Total property, plant, and equipment 72,593 67,340

Accumulated depreciation (22,012) (20,617)

Net property, plant, and equipment $ 50,581 $ 46,723

(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in 

the reactor is expensed as it is used based on the amount of energy output. (See Note 13 below.)

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The Utility depreciates property, plant, and equipment 

using the composite, or group, method of depreciation, 

in which a single depreciation rate is applied to the gross 

investment balance in a particular class of property. 

This method approximates the straight line method of 

depreciation over the useful lives of property, plant, 

and equipment. The Utility’s composite depreciation 

rates were 3.73% in 2016, 3.80% in 2015, and 3.77% in 

2014. The useful lives of the Utility’s property, plant, and 

equipment are authorized by the CPUC and the FERC, 

and the depreciation expense is recovered through rates 

charged to customers. Depreciation expense includes a 

component for the original cost of assets and a component 

for estimated cost of future removal, net of any salvage 

value at retirement. Upon retirement, the original cost 

of the retired assets, net of salvage value, is charged 

against accumulated depreciation. The cost of repairs 

and maintenance, including planned major maintenance 

activities and minor replacements of property, is charged 

to operating and maintenance expense as incurred.

AFUDC

AFUDC represents the estimated costs of debt (i.e., 

interest) and equity funds used to finance regulated plant 

additions before they go into service and is capitalized 

as part of the cost of construction. AFUDC is recoverable 

from customers through rates over the life of the related 

property once the property is placed in service. AFUDC 

related to the cost of debt is recorded as a reduction to 

interest expense. AFUDC related to the cost of equity is 

recorded in other income. The Utility recorded AFUDC 

related to debt and equity, respectively, of $51 million 

and $112 million during 2016, $48 million and $107 

million during 2015, and $45 million and $100 million 

during 2014.

Asset Retirement Obligations

The following table summarizes the changes in ARO liability during 2016 and 2015, including nuclear decommissioning 

obligations:

(in millions) 2016 2015

ARO liability at beginning of year $ 3,643 $3,575

Revision in estimated cash flows 968 13

Accretion 194 169

Liabilities settled (121) (114)

ARO liability at end of year $ 4,684 $ 3,643

The Utility has not recorded a liability related to certain 

ARO’s for assets that are expected to operate in perpetuity. 

As the Utility cannot estimate a settlement date or range 

of potential settlement dates for these assets, reasonable 

estimates of fair value cannot be made. As such, ARO 

liabilities are not recorded for retirement activities 

associated with substations, photovoltaic facilities, and 

certain hydroelectric facilities; removal of lead-based paint 

in some facilities and certain communications equipment 

from leased property; and restoration or land to the 

conditions under certain agreements.

Nuclear Decommissioning Obligation

Detailed studies of the cost to decommission the Utility’s 

nuclear generation facilities are generally conducted 

every three years in conjunction with the Nuclear 

Decommissioning Cost Triennial Proceeding conducted by 

the CPUC. In March 2016, the Utility submitted its updated 

decommissioning cost estimate to the CPUC. As a result, 

the estimated undiscounted cost to decommission the 

Utility’s nuclear power plants increased by approximately 

$1.4 billion. The change in total estimated cost resulted in 

an $818 million adjustment to the ARO. The adjustment 

was a result of increased estimated costs related to spent 

fuel storage, staffing, and out-of-state waste disposal. 

The decommissioning cost estimates are based on the 

plant location and cost characteristics for the Utility’s 

nuclear power plants. Actual decommissioning costs 

may vary from these estimates as a result of changes in 

assumptions such as decommissioning dates; regulatory 

requirements; technology; and costs of labor, materials, and 

equipment. The Utility recovers its revenue requirements 

for decommissioning costs from customers through a 

non-bypassable charge that the Utility expects will continue 

until those costs are fully recovered. The Utility requested 

that the CPUC authorize the collection of increased annual 

revenue requirements beginning on January 1, 2017 based 

on these updated cost estimates.

On August 11, 2016, the Utility submitted an application to 

the CPUC to retire Diablo Canyon at the expiration of its 

current operating licenses in 2024 (Unit 1) and 2025 (Unit 2). 

The application includes a joint proposal between the Utility 

and certain interested parties, entered into on June 20, 

2016, which resulted in a $115 million increase to the ARO 

recognized on the Consolidated Balance Sheets in June 2016.

The Utility adjusts its nuclear decommissioning obligation to 

reflect changes in the estimated costs of decommissioning 

its nuclear power facilities and records this as an adjustment 

to the ARO liability on its Consolidated Balance Sheets. 

The total nuclear decommissioning obligation accrued 

was $3.5 billion and $2.5 billion at December 31, 2016 

and 2015, respectively. The estimated undiscounted nuclear 

decommissioning cost for the Utility’s nuclear power 

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and 2015 (or $7.3 billion in future dollars), respectively. These 

estimates are based on the 2016 decommissioning cost 

studies, prepared in accordance with CPUC requirements.

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when 

it is both probable that costs incurred or projected to 

be incurred for recently completed plant will not be 

recoverable through rates charged to customers and the 

amount of disallowance can be reasonably estimated. (See 

“Enforcement and Litigation Matters” in Note 13 below.)

Nuclear Decommissioning Trusts

The Utility’s nuclear generation facilities consist of two units 

at Diablo Canyon and one retired facility at Humboldt Bay. 

Nuclear decommissioning requires the safe removal of a 

nuclear generation facility from service and the reduction of 

residual radioactivity to a level that permits termination of the 

NRC license and release of the property for unrestricted use. 

The Utility’s nuclear decommissioning costs are recovered 

from customers through rates and are held in trusts until 

authorized for release by the CPUC. 

The Utility classifies its investments held in the nuclear 

decommissioning trusts as “available-for-sale.” Since the 

Utility’s nuclear decommissioning trust assets are managed 

by external investment managers, the Utility does not have 

the ability to sell its investments at its discretion. Therefore, 

all unrealized losses are considered other-than-temporary 

impairments. Gains or losses on the nuclear decommissioning 

trust investments are refundable or recoverable, respectively, 

from customers through rates. Therefore, trust earnings 

are deferred and included in the regulatory liability for 

recoveries in excess of the ARO. There is no impact on 

the Utility’s earnings or accumulated other comprehensive 

income. The cost of debt and equity securities sold by the 

trust is determined by specific identification.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at 

risk to finance its activities without additional subordinated 

financial support from other parties, or whose equity 

investors lack any characteristics of a controlling financial 

interest. An enterprise that has a controlling financial 

interest in a VIE is a primary beneficiary and is required 

to consolidate the VIE.

Some of the counterparties to the Utility’s power purchase 

agreements are considered VIEs. Each of these VIEs was 

designed to own a power plant that would generate 

electricity for sale to the Utility. To determine whether 

the Utility was the primary beneficiary of any of these 

VIEs at December 31, 2016, it assessed whether it absorbs 

any of the VIE’s expected losses or receives any portion 

of the VIE’s expected residual returns under the terms of 

the power purchase agreement, analyzed the variability 

in the VIE’s gross margin, and considered whether it had 

any decision-making rights associated with the activities 

that are most significant to the VIE’s performance, such as 

dispatch rights and operating and maintenance activities. 

The Utility’s financial obligation is limited to the amount 

the Utility pays for delivered electricity and capacity. The 

Utility did not have any decision-making rights associated 

with any of the activities that are most significant to the 

economic performance of any of these VIEs. Since the 

Utility was not the primary beneficiary of any of these VIEs 

at December 31, 2016, it did not consolidate any of them.

Other Accounting Policies

For other accounting policies impacting PG&E Corporation’s 

and the Utility’s consolidated financial statements, see 

“Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair 

Value Measurements” in Note 10, and “Contingencies and 

Commitments” in Note 13 herein.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year 

ended December 31, 2016 consisted of the following:

(in millions, net of income tax)

Pension 

Benefits

Other 

Benefits Total

Beginning balance $ (23) $ 16 $ (7)

Other comprehensive income before reclassifications: 

Unrecognized prior service cost (net of taxes of $37 and $15, respectively) 54 (21) 33

Unrecognized net actuarial loss (net of taxes of $45 and $15, respectively) (64) 21 (43)

Regulatory account transfer (net of taxes of $5 and $0, respectively) 7 - 7

Amounts reclassified from other comprehensive income:

Amortization of prior service cost (net of taxes of $3 and $6, respectively)(1) 5 9 14

Amortization of net actuarial loss (net of taxes of $10 and $2, respectively)(1) 14 2 16

Regulatory account transfer (net of taxes of $13 and $8, respectively)(1) (18) (11) (29)

Net current period other comprehensive loss (2) - (2)

Ending balance $ (25) $ 16 $ (9)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 

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The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year 

ended December 31, 2015 consisted of the following:

(in millions, net of income tax)

Pension 

Benefits

Other 

Benefits

Other 

Investments Total

Beginning balance $ (21) $ 15 $ 17 $ 11

Other comprehensive income before reclassifications: 

Unrecognized net actuarial loss 

(net of taxes of $51, $21, and $0, respectively) (76) (31) - (107)

Regulatory account transfer 

(net of taxes of $51, $21, and $0, respectively) 73 31 - 104

Amounts reclassified from other comprehensive income:

Amortization of prior service cost 

(net of taxes of $7, $8, and $0, respectively)(1) 8 11 - 19

Amortization of net actuarial loss 

(net of taxes of $4, $1, and $0, respectively)(1) 63 - 9

Regulatory account transfer 

(net of taxes of $10, $9, and $0, respectively)(1) (13) (13) - (26)

Realized gain on investments 

(net of taxes of $0, $0, and $12, respectively) - - (17) (17)

Net current period other comprehensive loss (2) 1 (17) (18)

Ending balance $ (23) $ 16 $ - $ (7)

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 

below for additional details.)

With the exception of other investments, there was no material difference between PG&E Corporation and the Utility 

for the information disclosed above.

Recently Adopted Accounting Guidance

Share-Based Payment Accounting

In March 2016, the FASB issued ASU No. 2016-09, 

Compensation – Stock Compensation (Topic 718), which 

amends the existing guidance relating to the accounting 

for share-based payment awards issued to employees, 

including the income tax consequences, classification 

of awards as either equity or liabilities, and classification 

on the statement of cash flows. PG&E Corporation and 

the Utility have adopted this standard as of the fourth 

quarter of 2016. 

ASU 2016-09 requires recognition of excess tax benefits 

and deficiencies in the income statement, which resulted 

in the recognition of $6.3 million in income tax benefit 

for PG&E Corporation and the Utility for the year ended 

December 31, 2016. Previously, these amounts were 

recognized in additional paid-in capital. Previously 

unrecognized excess tax benefits were reclassified via a 

cumulative-effect adjustment. ASU 2016-09 also requires 

excess tax benefits and deficiencies to be prospectively 

excluded from assumed future proceeds in the calculation 

of diluted shares when calculating diluted earnings per 

share utilizing the treasury stock method. The effect of this 

change on diluted EPS is immaterial. Additionally, excess 

income tax benefits from stock-based compensation 

arrangements are now classified as cash flows from 

operating activities rather than as cash flows from financing 

activities, which resulted in an increase to cash flows from 

operating activities of approximately $7.2 million for the 

year ended December 31, 2016. 

Furthermore, ASU 2016-09 requires, on a retrospective 

basis, that employee taxes paid for withheld shares be 

classified as cash flows from financing activities rather 

than as cash flows from operating activities. As such, 

the consolidated statements of cash flows for PG&E 

Corporation and the Utility for the prior periods presented 

were restated. This change resulted in an increase to cash 

flows from operating activities and a decrease to cash flows 

from financing activities of $34.6 million, $26.8 million, 

and $13.2 million for the years ended December 31, 2016, 

2015, and 2014, respectively.

PG&E Corporation and the Utility have elected to continue 

to estimate forfeitures expected to occur to determine the 

amount of compensation cost to be recognized in each 

period and have not changed their policy on statutory 

withholding requirements and will continue to allow 

the employee to withhold up to the minimum statutory 

withholding requirements.

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Fair Value Measurement

In May 2015, the FASB issued ASU No. 2015-07, Fair Value 

Measurement (Topic 820): Disclosures for Investments in 

Certain Entities That Calculate Net Asset Value per Share 

(or Its Equivalent), which standardizes reporting practices 

related to the fair value hierarchy for all investments 

for which fair value is measured using net asset value 

per share. PG&E Corporation and the Utility adopted 

this guidance effective January 1, 2016. The adoption 

of this standard did not have a material impact on their 

Consolidated Financial Statements. All prior periods 

presented in these Consolidated Financial Statements 

reflect the retrospective adoption of this guidance. (See 

Notes 10 and 11 below.)

Accounting for Fees Paid in a Cloud Computing 

Arrangement

In April 2015, the FASB issued ASU No. 2015-05, 

Intangibles – Goodwill and Other – Internal-Use Software 

(Subtopic 350-40): Customer’s Accounting for Fees Paid in 

a Cloud Computing Arrangement, which adds guidance to 

help entities evaluate the accounting treatment for cloud 

computing arrangements. PG&E Corporation and the 

Utility adopted this guidance effective January 1, 2016. The 

adoption of this guidance did not have a material impact 

on their Consolidated Financial Statements.

Presentation of Debt Issuance Costs

In April 2015, the FASB issued ASU No. 2015-03, Interest - 

Imputation of Interest (Subtopic 835-30): Simplifying the 

Presentation of Debt Issuance Costs, which amends the 

existing guidance relating to the presentation of debt 

issuance costs. The amendments in this ASU require that 

debt issuance costs related to a recognized debt liability 

be presented in the balance sheet as a direct deduction 

from the carrying amount of that debt liability, consistent 

with debt discounts. PG&E Corporation and the Utility 

adopted this guidance effective January 1, 2016 and 

applied the requirements retrospectively for all periods 

presented. The adoption of this guidance did not have a 

material impact on their Consolidated Financial Statements. 

PG&E Corporation and the Utility restated $105 million 

and $103 million, respectively, of debt issuance costs as of 

December 31, 2015 with no impact to net income or total 

shareholders’ equity previously reported. All prior periods 

presented in these Consolidated Financial Statements 

reflect the retrospective adoption of this guidance.

Accounting Standards Issued But Not 

Yet Adopted

Restricted Cash

In November 2016, the FASB issued ASU No. 2016-18, 

Statement of Cash Flows – Restricted Cash (Topic 230), 

which amends the existing guidance relating to the 

disclosure of restricted cash and restricted cash equivalents 

on the statement of cash flows. The ASU will be effective 

for PG&E Corporation and the Utility on January 1, 2018, 

with early adoption permitted. PG&E Corporation and the 

Utility are currently evaluating the impact the guidance 

will have on their Consolidated Statements of Cash Flows. 

Recognition of Lease Assets and Liabilities

In February 2016, the FASB issued ASU No. 2016-02, Leases 

(Topic 842), which amends the existing guidance relating 

to the recognition of lease assets and lease liabilities on the 

balance sheet and the disclosure of key information about 

leasing arrangements. Under the new standard, an entity 

must recognize an asset and liability for operating leases on 

the balance sheet, which were previously not recognized. 

The ASU will be effective for PG&E Corporation and the 

Utility on January 1, 2019 with retrospective application. 

PG&E Corporation and the Utility are currently evaluating 

the impact the guidance will have on their Consolidated 

Financial Statements and related disclosures.

Recognition and Measurement of Financial Assets 

and Financial Liabilities

In January 2016, the FASB issued ASU No. 2016-01, Financial 

Instruments—Overall (Subtopic 825-10): Recognition and 

Measurement of Financial Assets and Financial Liabilities,

which amends the existing guidance relating to the 

recognition and measurement of financial instruments. 

The ASU will be effective for PG&E Corporation and the 

Utility on January 1, 2018. PG&E Corporation and the 

Utility are currently evaluating the impact the guidance 

will have on their Consolidated Financial Statements and 

related disclosures.

Revenue Recognition Standard 

In May 2014, the FASB issued ASU No. 2014-09, Revenue 

from Contracts with Customers, which amends existing 

revenue recognition guidance, effective January 1, 

2018. The objective of the new standard is to provide a 

single, comprehensive revenue recognition model for all 

contracts with customers to improve comparability across 

entities, industries, jurisdiction, and capital markets and 

to provide more useful information to users of financial 

statements through improved disclosure requirements. 

PG&E Corporation and the Utility do not plan to early 

adopt the standard and are currently reviewing all revenue 

streams and evaluating the impact the guidance will have 

on their Consolidated Financial Statements and related 

disclosures. The Utility does not expect ASU 2014-09 to 

materially impact the timing or recognition of revenue 

generated through the sale and delivery of electricity and 

natural gas to customers. However, the Utility continues 

to consider the impacts of outstanding industry-related 

issues being addressed by the American Institute of CPAs’ 

Revenue Recognition Working Group and the FASB’s 

Transition Resource Group.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NOTE 3: Regulatory Assets, Liabilities, and Balancing Accounts

Regulatory Assets

Long-term regulatory assets are comprised of the following:

(in millions)

Balance at December 31, Recovery 

2016 2015 Period

Pension benefits(1) $ 2,429 $ 2,414 Indefinitely(3)

Deferred income taxes(1) 3,859 3,054 47 years

Utility retained generation(2) 364 411 9 years

Environmental compliance costs(1) 778 748 32 years

Price risk management(1) 92 138 10 years

Unamortized loss, net of gain, on reacquired debt(1) 76 94 26 years

Other 353 170 Various

Total long-term regulatory assets $ 7,951 $ 7,029

(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated 

other comprehensive income (loss) recognized in accordance with GAAP.

(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to 

resolve the Utility’s proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related 

to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over 

the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are 

recognized.

(3) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual 

requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, 

the Utility earns a return only on its regulatory assets for retained generation, and regulatory assets for unamortized 

loss, net of gain, on reacquired debt.

Regulatory Liabilities

Long-term regulatory liabilities are comprised of the following:

Balance at December 31,

(in millions) 2016 2015

Cost of removal obligations(1) $ 5,060 $ 4,605

Recoveries in excess of AROs(2) 626 631

Public purpose programs(3) 567 600

Other 552 485

Total long-term regulatory liabilities $ 6,805 $ 6,321

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected 

asset removal costs.

(2) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs 

related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts. This 

regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning 

trust investments. (See Note 10 below.)

(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond 

the next 12 months, primarily related to energy efficiency programs.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Regulatory Balancing Accounts

The Utility tracks (1) differences between the Utility’s 

authorized revenue requirement and customer billings, 

and (2) differences between incurred costs and customer 

billings. To the extent these differences are probable of 

recovery or refund over the next 12 months, the Utility 

records a current regulatory balancing account receivable 

or payable. Regulatory balancing accounts that the Utility 

expects to collect or refund over a period exceeding 

12 months are recorded as other noncurrent assets 

– regulatory assets or noncurrent liabilities – regulatory 

liabilities, respectively, in the Consolidated Balance Sheets. 

These differences do not have an impact on net income. 

Balancing accounts will fluctuate during the year based on 

seasonal electric and gas usage and the timing of when 

costs are incurred and customer revenues are collected.

Current regulatory balancing accounts receivable and payable are comprised of the following:

Receivable 

Balance at December 31,

(in millions) 2016 2015

Electric distribution $ 132 $ 380

Utility generation 48 122

Gas distribution and transmission 541 493

Energy procurement 132 262

Public purpose programs 106 155

Other 541 348

Total regulatory balancing accounts receivable $1,500 $1,760

Payable 

Balance at December 31,

(in millions) 2016 2015

Gas distribution and transmission $ 48 $ -

Energy procurement 13 112

Public purpose programs 264 244

Other 320 359

Total regulatory balancing accounts payable $ 645 $ 715

The electric distribution and utility generation accounts 

track the collection of revenue requirements approved 

in the GRC. The gas distribution and transmission accounts 

track the collection of revenue requirements approved in 

the GRC and the GT&S rate case. Energy procurement 

balancing accounts track recovery of costs related to the 

procurement of electricity, including any environmental 

compliance-related activities. Public purpose programs 

balancing accounts are primarily used to record and 

recover authorized revenue requirements for commissionmandated programs such as energy efficiency.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NOTE 4: Debt

Long-Term Debt

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

December 31,

(in millions) 2016 2015

PG&E Corporation

Senior notes:

Maturity Interest Rates

2019 2.40% $ 350 $ 350

Unamortized discount, net of premium and debt issuance costs (2) (2)

Total PG&E Corporation long-term debt 348 348

Utility

Senior notes:

Maturity Interest Rates

2017 5.625% 700 700

2018 8.25% 800 800

2020 3.50% 800 800

2021 3.25% to 4.25% 550 550

2022 through 2046 2.45% to 6.35% 12,775 11,775

Less: current portion (700) -

Unamortized discount, net of premium and debt issuance costs (161) (156)

Total senior notes, net of current portion 14,764 14,469

Pollution control bonds:

Maturity Interest Rates

Series 2004 A-D, due 2023(1) 4.75% 345 345

Series 2009 A-D, due 2026(2) variable rate(4) 149 309

Series 1996 C, E, F, 1997 B due 2026(3) variable rate(5) 614 614

Less: current portion - (160)

Total pollution control bonds 1,108 1,108

Total Utility long-term debt, net of current portion 15,872 15,577

Total consolidated long-term debt, net of current portion $ 16,220 $ 15,925

(1) The Utility has obtained credit support from an insurance company for these bonds.

(2) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility

may choose not to provide a credit facility without issuer consent. Series C and D pollution control bonds were redeemed on 

November 30, 2016.

(3) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended 

to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility 

extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation

of the series without a credit facility.

(4) At December 31, 2016, the interest rate on these bonds was 0.74%.

(5) At December 31, 2016, the interest rate on these bonds ranged from 0.72% - 0.73%.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Pollution Control Bonds

The California Pollution Control Financing Authority and the 

California Infrastructure and Economic Development Bank 

have issued various series of fixed rate and multi-modal 

tax-exempt pollution control bonds for the benefit of the 

Utility. Substantially all of the net proceeds of the pollution 

control bonds were used to finance or refinance pollution 

control and sewage and solid waste disposal facilities at the 

Geysers geothermal power plant or at the Utility’s Diablo 

Canyon nuclear power plant. In 1999, the Utility sold all bondfinanced facilities at the non-retired units of the Geysers 

geothermal power plant to Geysers Power Company, LLC 

pursuant to purchase and sales agreements stating that 

Geysers Power Company, LLC will use the bond-financed 

facilities solely as pollution control facilities for so long as 

any tax-exempt pollution control bonds issued to finance 

the Geysers project are outstanding. Except for components 

that may have been abandoned in place or disposed of as 

scrap or that are permanently non-operational, the Utility 

has no knowledge that Geysers Power Company, LLC 

intends to cease using the bond-financed facilities solely 

as pollution control facilities.

Repayment Schedule

PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2016 

are reflected in the table below:

(in millions, except interest rates) 2017 2018 2019 2020 2021 Thereafter Total

PG&E Corporation 

Average fixed interest rate - - 2.40% - - - 2.40%

Fixed rate obligations $ - $ - $ 350 $ - $ - $ - $ 350

Utility

Average fixed interest rate 5.625% 8.25% - 3.50% 3.80% 4.84% 4.94%

Fixed rate obligations $ 700 $ 800 $ - $ 800 $ 550 $13,120 $15,970

Variable interest rate 

as of December 31, 2016 - - 0.74% 0.73% - - 0.73%

Variable rate obligations(1) $ - $ - $ 149 $ 614 $ - $ - $ 763

Total consolidated debt $ 700 $ 800 $ 499 $ 1,414 $ 550 $ 13,120 $ 17,083

(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.

Short-term Borrowings

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving 

credit facilities and commercial paper programs at December 31, 2016:

(in millions)

Termination 

Date

Credit 

Facility 

Limit

Letters of 

Credit 

Outstanding

Commercial 

Paper 

Outstanding

Facility 

Availability

PG&E Corporation April 2021 $ 300(1) $ - $ - $ 300

Utility April 2021 3,000(2) 41 1,016 1,943

Total revolving credit facilities $ 3,300 $ 41 $ 1,016 $ 2,243

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans 

defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

For the year ended December 31, 2016, PG&E Corporation’s 

average outstanding commercial paper balance was 

$84 million and the maximum outstanding balance during 

the year was $176 million. For 2016, the Utility’s average 

outstanding commercial paper balance was $837 million 

and the maximum outstanding balance during the year 

was $1.4 billion. There were no bank borrowings for PG&E 

Corporation or the Utility in 2016. 

Revolving Credit Facilities

In June 2016, PG&E Corporation and the Utility each 

extended the termination dates of their existing revolving 

credit facilities by one year from April 27, 2020 to April 27, 

2021. PG&E Corporation’s and the Utility’s revolving credit 

facilities may be used for working capital, the repayment 

of commercial paper, and other corporate purposes. At 

PG&E Corporation’s and the Utility’s request and at the sole 

discretion of each lender, the facilities may be extended 

for one additional period. 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Borrowings under each credit agreement (other than 

swingline loans) will bear interest based, at each borrower’s 

election, on (1) a London Interbank Offered Rate (“LIBOR”) 

plus an applicable margin or (2) the base rate plus an 

applicable margin. The base rate will equal the higher of 

the following: the administrative agent’s announced base 

rate, 0.5% above the overnight federal funds rate, and the 

one-month LIBOR plus an applicable margin. The applicable 

margin for LIBOR loans will range between 0.9% and 1.475% 

under PG&E Corporation’s credit agreement and between 

0.8% and 1.275% under the Utility’s credit agreement. 

The applicable margin for base rate loans will range 

between 0% and 0.475% under PG&E Corporation’s 

credit agreement and between 0% and 0.275% under the 

Utility’s credit agreement. In addition, the facility fee under 

PG&E Corporation’s and the Utility’s credit agreements 

will range between 0.1% and 0.275% and between 0.075% 

and 0.225%, respectively. 

PG&E Corporation’s and the Utility’s revolving credit 

facilities include usual and customary provisions for 

revolving credit facilities of this type, including those 

regarding events of default and covenants limiting liens 

to those permitted under their senior note indentures, 

mergers, sales of all or substantially all of their assets, and 

other fundamental changes. In addition, the respective 

revolving credit facilities require that PG&E Corporation 

and the Utility maintain a ratio of total consolidated 

debt to total consolidated capitalization of at most 65% 

as of the end of each fiscal quarter. PG&E Corporation’s 

revolving credit facility agreement also requires that PG&E 

Corporation own, directly or indirectly, at least 80% of 

the outstanding common stock and at least 70% of the 

outstanding voting capital stock of the Utility. 

Commercial Paper Programs

The borrowings from PG&E Corporation’s and the Utility’s 

commercial paper programs are used primarily to fund 

temporary financing needs. PG&E Corporation and the 

Utility can issue commercial paper up to the maximum 

amounts of $300 million and $2.5 billion, respectively. PG&E 

Corporation and the Utility treat the amount of outstanding 

commercial paper as a reduction to the amount available 

under their respective revolving credit facilities. The 

commercial paper may have maturities up to 365 days and 

ranks equally with PG&E Corporation’s and the Utility’s other 

unsubordinated and unsecured indebtedness. Commercial 

paper notes are sold at an interest rate dictated by the 

market at the time of issuance. For 2016, the average yield 

on outstanding PG&E Corporation and Utility commercial 

paper was 0.63% and 0.64%, respectively.

Other Short-term Borrowings 

In March 2016, the Utility entered into a $250 million floating 

rate unsecured term loan that matures on February 2, 

2017. Additionally, in December 2016, the Utility issued 

a $250 million unsecured senior floating rate note that 

matures on November 30, 2017. The proceeds were used 

for general corporate purposes, including the repayment 

of a portion of the Utility’s outstanding commercial paper.

NOTE 5: Common Stock and Share-Based Compensation

PG&E Corporation had 506,891,874 shares of common 

stock outstanding at December 31, 2016. PG&E Corporation 

held all of the Utility’s outstanding common stock at 

December 31, 2016.

During 2016, PG&E Corporation sold 2.6 million shares of 

common stock under the February 2015 equity distribution 

agreement for cash proceeds of $149 million, net of 

commissions paid of $1.3 million. As of December 31, 2016, 

the remaining gross sales available under this agreement 

were $275 million. 

In August 2016, PG&E Corporation sold 4.9 million shares 

of its common stock in an underwritten public offering 

for net cash proceeds of $309 million.

In addition, during 2016, PG&E Corporation sold 7.4 million 

shares of common stock under its 401(k) plan, the Dividend 

Reinvestment and Stock Purchase Plan, and share-based 

compensation plans for total cash proceeds of $364 million.

Dividends

The Board of Directors of PG&E Corporation and the Utility 

declare dividends quarterly. Under the Utility’s Articles 

of Incorporation, the Utility cannot pay common stock 

dividends unless all cumulative preferred dividends on 

the Utility’s preferred stock have been paid. For the first 

quarter of 2016, the Board of Directors of PG&E Corporation 

declared a common stock dividend of $0.455 per share. 

In May 2016, the Board of Directors of PG&E Corporation 

adopted a new quarterly common stock dividend of $0.49 

per share. In 2016, total dividends were $1.925 per share.

Under their respective credit agreements, PG&E Corporation 

and the Utility are each required to maintain a ratio of 

consolidated total debt to consolidated capitalization of 

at most 65%. Additionally, the CPUC requires the Utility to 

maintain a capital structure composed of at least 52% equity 

on a weighted average over five years. At December 31, 

2016, the Utility had restricted net assets of $15.8 billion 

and was limited to $25 million of additional common stock 

dividends it could pay to PG&E Corporation.

Long-Term Incentive Plan 

The PG&E Corporation LTIP permits various forms of 

share-based incentive awards, including restricted stock 

awards, restricted stock units, performance shares, and 

other share-based awards, to eligible employees of PG&E 

Corporation and its subsidiaries. Non-employee directors 

of PG&E Corporation are also eligible to receive certain 

share-based awards. A maximum of 17 million shares of 

PG&E Corporation common stock (subject to certain 

adjustments) has been reserved for issuance under the 

2014 LTIP, of which 13,826,995 shares were available for 

future awards at December 31, 2016. Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation 

for share-based incentive awards for 2016, 2015, and 2014:

(in millions) 2016 2015 2014

Restricted stock units $ 53 $ 47 $ 42

Performance shares 55 46 36

Total compensation expense (pre-tax) $ 108 $ 93 $ 78

Total compensation expense (after-tax) $ 64 $ 55 $ 47

The amount of share-based compensation costs capitalized during 2016, 2015, and 2014 was immaterial. There was 

no material difference between PG&E Corporation and the Utility for the information disclosed above.

Restricted Stock Units

Prior to 2014, restricted stock units generally vested over 

four years in 20% increments on the first business day 

of March in year one, two, and three, with the remaining 

40% vesting on the first business day of March in year 

four. Restricted stock units granted after 2014 generally 

vest equally over three years. Vested restricted stock units 

are settled in shares of PG&E Corporation common stock 

accompanied by cash payments to settle any dividend 

equivalents associated with the vested restricted stock 

units. Compensation expense is generally recognized 

rateably over the vesting period based on grant-date 

fair value. The weighted average grant-date fair value 

for restricted stock units granted during 2016, 2015, and 

2014 was $56.68, $53.30, and $43.76, respectively. The 

total fair value of restricted stock units that vested during 

2016, 2015, and 2014 was $36 million, $57 million, and 

$34 million, respectively. The tax benefit from restricted 

stock units that vested during each period was not 

material. In general, forfeitures are recorded rateably 

over the vesting period, using historical averages and 

adjusted to actuals when vesting occurs. As of December 

31, 2016, $37 million of total unrecognized compensation 

costs related to nonvested restricted stock units was 

expected to be recognized over the remaining weighted 

average period of 1.22 years.

The following table summarizes restricted stock unit activity for 2016:

Number of Restricted 

Stock Units

Weighted Average Grant-Date 

Fair Value 

Nonvested at January 1 1,972,899 $ 47.33

Granted 776,312 $ 56.68

Vested (770,968) $ 46.79

Forfeited (55,233) $ 49.65

Nonvested at December 31 1,923,010 $ 51.26

Performance Shares

Performance shares generally will vest three years after the 

grant date. Upon vesting, performance shares are settled in 

shares of common stock based on either PG&E Corporation’s 

total shareholder return relative to a specified group of 

industry peer companies over a three-year performance 

period or, for a small number of awards, an internal PG&E 

Corporation metric. Dividend equivalents are paid in cash 

based on the amount of common stock to which the 

recipients are entitled. 

Compensation expense attributable to performance share 

is generally recognized rateably over the applicable threeyear period based on the grant-date fair value determined 

using a Monte Carlo simulation valuation model for the total 

shareholder return based awards or the grant-date market 

value of PG&E Corporation common stock for internal 

metric based awards. The weighted average grant-date fair 

value for performance shares granted during 2016, 2015, 

and 2014 was $53.61, $68.27, and $51.81 respectively. There 

was no tax benefit associated with performance shares 

during each of these periods. In general, forfeitures are 

recorded rateably over the vesting period, using historical 

averages and adjusted to actuals when vesting occurs. As 

of December 31, 2016, $40 million of total unrecognized 

compensation costs related to nonvested performance 

shares was expected to be recognized over the remaining 

weighted average period of 1.57 years.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following table summarizes activity for performance shares in 2016:

Number of Performance 

Shares

Weighted Average Grant-Date 

Fair Value

Nonvested at January 1 1,450,612 $ 59.24

Granted 1,233,884 53.61

Vested (777,719) 51.81

Forfeited(1) (67,922) 58.20

Nonvested at December 31 1,838,855 $ 58.65

(1) Includes performance shares that expired with zero value as performance targets were not met.

NOTE 6: Preferred Stock

PG&E Corporation has authorized 80 million shares of no 

par value preferred stock and 5 million shares of $100 par 

value preferred stock, which may be issued as redeemable 

or nonredeemable preferred stock. PG&E Corporation 

does not have any preferred stock outstanding.

The Utility has authorized 75 million shares of $25 par value 

preferred stock and 10 million shares of $100 par value 

preferred stock. At December 31, 2016 and December 31, 

2015, the Utility’s preferred stock outstanding included 

$145 million of shares with interest rates between 5% and 

6% designated as nonredeemable preferred stock and 

$113 million of shares with interest rates between 4.36% 

and 5% that are redeemable between $25.75 and $27.25 

per share. The Utility’s preferred stock outstanding are 

not subject to mandatory redemption. All outstanding 

preferred stock has a $25 par value.

At December 31, 2016, annual dividends on the Utility’s 

nonredeemable preferred stock ranged from $1.25 to 

$1.50 per share. The Utility’s redeemable preferred stock 

is subject to redemption at the Utility’s option, in whole 

or in part, if the Utility pays the specified redemption 

price plus accumulated and unpaid dividends through the 

redemption date. At December 31, 2016, annual dividends 

on redeemable preferred stock ranged from $1.09 to 

$1.25 per share.

Dividends on all Utility preferred stock are cumulative. 

All shares of preferred stock have voting rights and an 

equal preference in dividend and liquidation rights. Upon 

liquidation or dissolution of the Utility, holders of preferred 

stock would be entitled to the par value of such shares plus 

all accumulated and unpaid dividends, as specified for the 

class and series. The Utility paid $14 million of dividends 

on preferred stock in each of 2016, 2015, and 2014.

NOTE 7: Earnings Per Share

PG&E Corporation’s basic EPS is calculated by dividing 

the income available for common shareholders by the 

weighted average number of common shares outstanding. 

PG&E Corporation applies the treasury stock method of 

reflecting the dilutive effect of outstanding share-based 

compensation in the calculation of diluted EPS. The 

following is a reconciliation of PG&E Corporation’s income 

available for common shareholders and weighted average 

common shares outstanding for calculating diluted EPS 

for 2016, 2015, and 2014.

Year Ended December 31,

(in millions, except per share amounts) 2016 2015 2014

Income available for common shareholders $1,393 $ 874 $1,436

Weighted average common shares outstanding, basic 499 484 468

Add incremental shares from assumed conversions:

Employee share-based compensation 2 3 2

Weighted average common share outstanding, diluted 501 487 470

Total earnings per common share, diluted $ 2.78 $ 1.79 $ 3.06

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded 

an insignificant amount of options and securities that were antidilutive.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NOTE 8: Income Taxes

PG&E Corporation and the Utility use the asset and liability 

method of accounting for income taxes. The income tax 

provision includes current and deferred income taxes 

resulting from operations during the year. PG&E Corporation 

and the Utility estimate current period tax expense in 

addition to calculating deferred tax assets and liabilities. 

Deferred tax assets and liabilities result from temporary 

tax and accounting timing differences, such as those 

arising from depreciation expense.

PG&E Corporation and the Utility recognize a tax benefit 

if it is more likely than not that a tax position taken or 

expected to be taken in a tax return will be sustained upon 

examination by taxing authorities based on the merits of 

the position. The tax benefit recognized in the financial 

statements is measured based on the largest amount of 

benefit that is greater than 50% likely of being realized 

upon settlement. As such, the difference between a tax 

position taken or expected to be taken in a tax return in 

future periods and the benefit recognized and measured 

pursuant to this guidance in the financial statements 

represents an unrecognized tax benefit.

Investment tax credits are deferred and amortized 

to income over time. PG&E Corporation amortizes its 

investment tax credits over the projected investment 

recovery period. The Utility amortizes its investment tax 

credits over the life of the related property in accordance 

with regulatory treatment.

PG&E Corporation files a consolidated U.S. federal income 

tax return that includes the Utility and domestic subsidiaries 

in which its ownership is 80% or more. PG&E Corporation 

files a combined state income tax return in California. PG&E 

Corporation and the Utility are parties to a tax-sharing 

agreement under which the Utility determines its income 

tax provision (benefit) on a stand-alone basis.

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

PG&E Corporation Utility

Year Ended December 31,

(in millions) 2016 2015 2014 2016 2015 2014

Current:

Federal $(105) $ (89) $ (84) $(105) $ (88) $ (84)

State (70) 11 (41) (66) 6 (29)

Deferred:

Federal 218 131 396 229 136 426

State 16 (76) 78 16 (69) 75

Tax credits (4) (4) (4) (4) (4) (4)

Income tax provision (benefit) $ 55 $ (27) $ 345 $ 70 $ (19) $384

The following table describes net deferred income tax liabilities:

PG&E Corporation Utility

Year Ended December 31,

(in millions) 2016 2015 2016 2015

Deferred income tax assets:

Tax carryforwards 1,851 1,703 1,596 1,462

Other(1) 463 757 402 700

Total deferred income tax assets $ 2,314 $ 2,460 $ 1,998 $ 2,162

Deferred income tax liabilities:

Property related basis differences 10,429 9,656 10,411 9,638

Income tax regulatory asset(2) 1,572 1,244 1,572 1,245

Other(3) 526 766 525 766

Total deferred income tax liabilities $ 12,527 $ 11,666 $ 12,508 $11,649

Total net deferred income tax liabilities $ 10,213 $ 9,206 $ 10,510 $ 9,487

(1) Amounts include compensation and benefits, environmental reserve, and customer advances for construction.

(2) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking 

purposes and amounts recognized in accordance with GAAP. (See Note 3 of the Notes to the Consolidated Financial 

Statements in Item 8.)

(3) Amounts primarily relate to regulatory balancing accounts. Greenhouse gas allowances are temporary timing differences 

that reverse through regulatory balancing accounts. Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:

PG&E Corporation Utility

Year Ended December 31,

2016 2015 2014 2016 2015 2014

Federal statutory income 

tax rate 35.0% 35.0% 35.0% 35.0% 35.0% 35.0%

Increase (decrease) in income 

tax rate resulting from:

State income tax 

(net of federal benefit)(1) (2.5) (4.9) 1.4 (2.2) (4.8) 1.6

Effect of regulatory 

treatment of fixed asset 

differences(2) (23.7) (33.6) (15.0) (23.4) (33.7) (14.7)

Tax credits (0.8) (1.3) (0.7) (0.8) (1.3) (0.7)

Benefit of loss carryback (1.1) (1.5) (0.8) (1.1) (1.5) (0.8)

Non deductible penalties(3) 0.8 4.3 0.3 0.8 4.3 0.3

Other, net(4) (3.9) (1.1) (0.8) (3.5) (0.2) 0.4

Effective tax rate 3.8% (3.1)% 19.4% 4.8% (2.2)% 21.1%

(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts include an agreement with the 

IRS on a 2011 audit related to electric transmission and distribution repairs deductions.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 

2014 GRC decision in all periods presented and by the 2015 GT&S decision which impacts only 2016. All amounts are 

impacted by the level of income before income taxes. The 2014 GRC and 2015 GT&S rate case decisions authorized revenue 

requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and 

certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and 

the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. 

Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E 

Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts 

will be recovered from or returned to customers in future rates.

(3) Primarily represents the effects of non-tax deductible fines and penalties associated with the natural gas distribution 

facilities record-keeping decision for the year ended December 31, 2016 and the effects of the Penalty Decision for the year 

ended December 31, 2015. For more information about the Penalty Decision see “Enforcement and Litigation Matters” in 

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

(4) In 2016, the amount primarily represents the impact of tax audit settlements.

Unrecognized tax benefits

The following table reconciles the changes in unrecognized tax benefits:

PG&E Corporation Utility

(in millions) 2016 2015 2014 2016 2015 2014

Balance at beginning of year $468 $ 713 $666 $462 $ 707 $660

Additions for tax position taken 

during a prior year - 40 7 - 40 7

Reductions for tax position taken 

during a prior year (77) (349) (9) (77) (349) (9)

Additions for tax position taken 

during the current year 56 64 61 56 64 61

Settlements (59) - (12) (59) - (12)

Balance at end of year $ 388 $ 468 $ 713 $ 382 $ 462 $ 707

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The component of unrecognized tax benefits that, if 

recognized, would affect the effective tax rate at 

December 31, 2016 for PG&E Corporation and the Utility 

was $25 million.

PG&E Corporation’s and the Utility’s unrecognized tax 

benefits may change significantly within the next 12 months 

due to the resolution of several matters, including audits. 

As of December 31, 2016, it is reasonably possible that 

unrecognized tax benefits will decrease by approximately 

$70 million within the next 12 months. PG&E Corporation 

and the Utility believe that the majority of the decrease 

will not impact net income.

Interest income, interest expense and penalties associated 

with income taxes are reflected in income tax expense 

on the Consolidated Statements of Income. For the years 

ended December 31, 2016, 2015, and 2014, these amounts 

were immaterial.

IRS settlements

PG&E Corporation previously participated in the Compliance 

Assurance Process, a real-time IRS audit intended to 

expedite resolution of tax matters. The Compliance 

Assurance Process audit culminates with a letter from 

the IRS indicating its acceptance of the return. PG&E 

Corporation’s participation in the Compliance Assurance 

Process ended effective with the submission of its 2015 

tax return.

PG&E Corporation’s tax returns have been accepted 

through 2015 except for a few matters, the most significant 

of which relates to deductible repair costs. In March 2016, 

PG&E Corporation reached an agreement with the IRS on 

deductible electric transmission and distribution repair 

costs for the 2012 tax year. The agreement provided that 

the methodology used in determining the deductible 

amount should be followed for all subsequent periods, 

absent any material change in facts. Deductible repair 

costs for other lines of business will continue to be subject 

to examination by the IRS for subsequent years. The IRS 

is expected to issue guidance in 2017 that clarifies which 

repair costs are deductible for the natural gas transmission 

and distribution businesses.

Tax years after 2008 remain subject to examination by 

the state of California.

2015 Gas Transmission and Storage Rate Case

In comments to the proposed decision in phase two of 

the 2015 GT&S rate case, the Utility questioned whether 

the methodology employed to calculate the capital 

disallowance portion of the San Bruno penalty might 

constitute a normalization violation. In recognition of this 

concern, the CPUC, in the final phase two decision, provided 

the Utility an opportunity to submit a ruling to the IRS for 

guidance and establish a memorandum account to track 

the additional revenue that would be recoverable if the 

method is deemed to be a normalization violation. The 

Utility anticipates filing the ruling request in early 2017.

As a result of the final phase two decision, PG&E 

Corporation and the Utility applied flow through accounting 

to property-related timing differences for 2016 and 2015.

Carryforwards

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

December 31,

2016

Expiration

(in millions) Year

Federal:

Net operating loss carryforward $ 5,009 2029 - 2036

Tax credit carryforward 116 2029 - 2036

Charitable contribution loss carryforward 192 2017 - 2021

State:

Net operating loss carryforward $ - N/A

Tax credit carryforward 51 Various

Charitable contribution loss carryforward 112 2019 - 2021

PG&E Corporation believes it is more likely than not the 

tax benefits associated with the federal and California 

net operating losses, charitable contributions and tax 

credits can be realized within the carryforward periods, 

therefore no valuation allowance was recognized as of 

December 31, 2016 for these tax attributes.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NOTE 9: Derivatives

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result 

of its electricity and natural gas procurement activities. 

Procurement costs are recovered through customer 

rates. The Utility uses both derivative and non-derivative 

contracts to manage volatility in customer rates due to 

fluctuating commodity prices. Derivatives include forward 

contracts, swaps, futures, options, and CRRs.

Derivatives are presented in the Utility’s Consolidated 

Balance Sheets on a net basis in accordance with master 

netting arrangements for each counterparty. The fair 

value of derivative instruments is further offset by cash 

collateral paid or received where the right of offset and 

the intention to offset exist.

Price risk management activities that meet the definition of 

derivatives are recorded at fair value on the Consolidated 

Balance Sheets. These instruments are not held for 

speculative purposes and are subject to certain regulatory 

requirements. The Utility expects to fully recover in rates all 

costs related to derivatives under the applicable ratemaking 

mechanism in place as long as the Utility’s price risk 

management activities are carried out in accordance with 

CPUC directives. Therefore, all unrealized gains and losses 

associated with the change in fair value of these derivatives 

are deferred and recorded within the Utility’s regulatory 

assets and liabilities on the Consolidated Balance Sheets. 

Net realized gains or losses on commodity derivatives are 

recorded in the cost of electricity or the cost of natural gas 

with corresponding increases or decreases to regulatory 

balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception 

for eligible derivatives. Eligible derivatives are those that 

require physical delivery in quantities that are expected 

to be used by the Utility over a reasonable period in the 

normal course of business, and do not contain pricing 

provisions unrelated to the commodity delivered. These 

items are not reflected in the Consolidated Balance Sheets 

at fair value. Eligible derivatives are accounted for under 

the accrual method of accounting.

Volume of Derivative Activity

At December 31, 2016 and 2015, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

Contract Volume

Underlying Product Instruments 2016 2015

Natural Gas(1) (MMBtus(2)) Forwards and Swaps 323,301,331 333,091,813

Options 96,602,785 111,550,004

Electricity (Megawatt-hours) Forwards and Swaps 3,287,397 3,663,512

Congestion Revenue Rights(3) 278,143,281 216,383,389

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to 

transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

At December 31, 2016, the Utility’s outstanding derivative balances were as follows:

Commodity Risk

(in millions)

Gross Derivative 

Balance Netting Cash Collateral

Total Derivative 

Balance

Current assets – other $ 91 $(10) $ 1 $ 82

Other noncurrent assets – other 149 (9) - 140

Current liabilities – other (48) 10 - (38)

Noncurrent liabilities – other (101) 9 3 (89)

Total commodity risk $ 91 $ - $ 4 $ 95

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At December 31, 2015, the Utility’s outstanding derivative balances were as follows:

Commodity Risk

(in millions)

Gross Derivative 

Balance Netting Cash Collateral

Total Derivative 

Balance

Current assets – other $ 97 $ (4) $25 $ 118

Other noncurrent assets – other 172 (2) - 170

Current liabilities – other (102) 4 44 (54)

Noncurrent liabilities – other (140) 2 21 (117)

Total commodity risk $ 27 $ - $ 90 $ 117

Gains and losses associated with price risk management activities were recorded as follows:

Commodity Risk

For the year ended December 31,

(in millions) 2016 2015 2014

Unrealized gain/(loss) - regulatory assets and liabilities(1) $ 64 $ (6) $124

Realized loss - cost of electricity(2) (53) (14) (83)

Realized loss - cost of natural gas(2) (18) (10) (8)

Total commodity risk $ (7) $(30) $ 33

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, 

respectively, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of 

cash collateral postings.

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized 

amounts on these instruments.

Cash inflows and outflows associated with derivatives 

are included in operating cash flows on the Utility’s 

Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives contain collateral 

posting provisions tied to the Utility’s credit rating from 

each of the major credit rating agencies. At December 31, 

2016, the Utility’s credit rating was investment grade. If 

the Utility’s credit rating were to fall below investment 

grade, the Utility would be required to post additional 

cash immediately to fully collateralize some of its net 

liability derivative positions.

The additional cash collateral that the Utility would be 

required to post if the credit risk-related contingency 

features were triggered was as follows:

Balance at December 31,

(in millions) 2016 2015

Derivatives in a liability position with credit risk-related contingencies that are not fully 

collateralized $(24) $ (2)

Related derivatives in an asset position 19 -

Collateral posting in the normal course of business related to these derivatives 4 -

Net position of derivative contracts/additional collateral posting requirements(1) $ (1) $ (2)

(1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the 

Utility’s credit risk-related contingencies.

NOTE 10: Fair Value Measurements

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments 

at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used 

to measure fair value:

đ Level 1 – Observable inputs that reflect quoted prices 

(unadjusted) for identical assets or liabilities in active 

markets.

đ Level 2 – Other inputs that are directly or indirectly 

observable in the marketplace.

đ Level 3 – Unobservable inputs which are supported by 

little or no market activities.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable 

inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized 

below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

Fair Value Measurements

At December 31, 2016

(in millions) Level 1 Level 2 Level 3 Netting(1) Total

Assets:

Short-term investments $ 105 $ - $ - $ - $ 105

Nuclear decommissioning trusts

Short-term investments 9 - - - 9

Global equity securities 1,724 - - - 1,724

Fixed-income securities 665 527 - - 1,192

Assets measured at NAV ---- 14

Total nuclear decommissioning trusts(2) 2,398 527 - - 2,939

Price risk management instruments 

(Note 9)

Electricity 30 18 181 (18) 211

Gas - 11 - - 11

Total price risk management instruments 30 29 181 (18) 222

Rabbi trusts

Fixed-income securities - 61 - - 61

Life insurance contracts - 70 - - 70

Total rabbi trusts - 131 - - 131

Long-term disability trust

Short-term investments 8 - - - 8

Assets measured at NAV ---- 170

Total long-term disability trust 8 - - -178

TOTAL ASSETS $2,541 $ 687 $181 $(18) $ 3,575

Liabilities:

Price risk management instruments 

(Note 9)

Electricity $ 9 $ 12 $126 $(21) $ 126

Gas - 2 - (1) 1

TOTAL LIABILITIES $ 9 $ 14 $126 $(22) $ 127

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value.

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Fair Value Measurements

At December 31, 2015

(in millions) Level 1 Level 2 Level 3 Netting(1) Total

Assets:

Short-term investments $ 64 $ - $ - $ - $ 64

Nuclear decommissioning trusts

Short-term investments 36 - - - 36

Global equity securities 1,520 - - - 1,520

Fixed-income securities 694 521 - - 1,215

Assets measured at NAV - - - - 13

Total nuclear decommissioning trusts(2) 2,250 521 - - 2,784

Price risk management instruments 

(Note 9)

Electricity - 9 259 18 286

Gas - 1 - 1 2

Total price risk management instruments - 10 259 19 288

Rabbi trusts

Fixed-income securities - 57 - - 57

Life insurance contracts - 70 - - 70

Total rabbi trusts - 127 - - 127

Long-term disability trust

Short-term investments 7 - - - 7

Assets measured at NAV - - - - 158

Total long-term disability trust 7-- - 165

TOTAL ASSETS $2,321 $658 $259 $ 19 $3,428

Liabilities:

Price risk management instruments 

(Note 9)

Electricity $ 69 $ 1 $170 $(70) $ 170

Gas - 2 - (1) 1

TOTAL LIABILITIES $ 69 $ 3 $170 $(71) $ 171

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $314 million, primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

The following describes the valuation techniques used to 

measure the fair value of the assets and liabilities shown 

in the tables above. Equity investments valued at net 

asset value per share utilize investment strategies aimed 

at matching the performance of indexed funds. Transfers 

between levels in the fair value hierarchy are recognized 

as of the end of the reporting period. There were no 

material transfers between any levels for the years ended 

December 31, 2016 and 2015.

Trust Assets

In general, investments held in the trusts are exposed 

to various risks, such as interest rate, credit, and market 

volatility risks. Nuclear decommissioning trust assets 

and other trust assets are composed primarily of equity 

and fixed-income securities and also include short-term 

investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in 

common stock that are valued based on quoted prices 

in active markets and are classified as Level 1.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Fixed-income securities are primarily composed of U.S. 

government and agency securities, municipal securities, 

and other fixed-income securities, including corporate debt 

securities. U.S. government and agency securities primarily 

consist of U.S. Treasury securities that are classified as Level 

1 because the fair value is determined by observable market 

prices in active markets. A market approach is generally 

used to estimate the fair value of debt securities classified as 

Level 2 using evaluated pricing data such as broker quotes, 

for similar securities adjusted for observable differences. 

Significant inputs used in the valuation model generally 

include benchmark yield curves and issuer spreads. The 

external credit ratings, coupon rate, and maturity of each 

security are considered in the valuation model, as applicable.

On January 1, 2016, PG&E Corporation and the Utility 

adopted FASB ASU No. 2015-07, Fair Value Measurement 

(Topic 820): Disclosures for Investments in Certain Entities 

That Calculate Net Asset Value per Share (or Its Equivalent)

and applied it retrospectively for the periods presented in 

their Consolidated Financial Statements. (See Note 2 above.) 

In accordance with this guidance, investments in the nuclear 

decommissioning trusts and the long-term disability trust 

that are measured at fair value using the NAV per share 

practical expedient have not been classified in the fair value 

hierarchy tables above. The fair value amounts are included 

in the tables above in order to reconcile to the amounts 

presented in the Consolidated Balance Sheets. These 

investments include commingled funds that are composed 

of equity securities traded publicly on exchanges as well 

as fixed-income securities that are composed primarily of 

U.S. government securities and asset-backed securities. 

There are no restrictions on the terms and conditions upon 

which the investments may be redeemed.

Price Risk Management Instruments

Price risk management instruments include physical and 

financial derivative contracts, such as power purchase 

agreements, forwards, swaps, options, and CRRs that 

are traded either on an exchange or over-the-counter.

Power purchase agreements, forwards, and swaps are 

valued using a discounted cash flow model. Exchangetraded forwards and swaps that are valued using observable 

market forward prices for the underlying commodity are 

classified as Level 1. Over-the-counter forwards and swaps 

that are identical to exchange-traded forwards and swaps, 

or are valued using forward prices from broker quotes 

that are corroborated with market data are classified 

as Level 2. Exchange-traded options are valued using 

observable market data and market-corroborated data 

and are classified as Level 2.

Long-dated power purchase agreements that are valued 

using significant unobservable data are classified as 

Level 3. These Level 3 contracts are valued using either 

estimated basis adjustments from liquid trading points 

or techniques, including extrapolation from observable 

prices, when a contract term extends beyond a period 

for which market data is available. Market and credit risk 

management utilizes models to derive pricing inputs for 

the valuation of the Utility’s Level 3 instruments using 

pricing inputs from brokers and historical data.

The Utility holds CRRs to hedge the financial risk of 

CAISO-imposed congestion charges in the day-ahead 

market. Limited market data is available in the CAISO 

auction and between auction dates; therefore, the Utility 

utilizes historical prices to forecast forward prices. CRRs 

are classified as Level 3.

Level 3 Measurements and Sensitivity Analysis

The Utility’s market and credit risk management function, 

which reports to the Chief Financial Officer, is responsible 

for determining the fair value of the Utility’s price risk 

management derivatives. The Utility’s finance and risk 

management functions collaborate to determine the 

appropriate fair value methodologies and classification for 

each derivative. Inputs used and the fair value of Level 3 

instruments are reviewed period-over-period and compared 

with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs 

would result in a significantly higher or lower fair value, 

respectively. All reasonable costs related to Level 3 

instruments are expected to be recoverable through 

customer rates; therefore, there is no impact to net income 

resulting from changes in the fair value of these instruments. 

(See Note 9 above.)

(in millions)

Fair Value at 

At December 31, 2016

Valuation Technique

Unobservable 

Fair Value Measurement Assets Liabilities Range Input (1)

Congestion revenue rights $181 $35 Market approach CRR auction prices $(11.88) - 6.93

Power purchase agreements $ - $91 Discounted cash flow Forward prices $ 18.07 - 38.80

(1) Represents price per megawatt-hour

(in millions)

Fair Value at 

At December 31, 2015

Valuation Technique

Unobservable 

Fair Value Measurement Assets Liabilities Input Range(1)

Congestion revenue rights $259 $ 63 Market approach CRR auction prices $(161.36) - 8.76

Power purchase agreements $ - $107 Discounted cash flow Forward prices $ 15.08 - 37.27

(1) Represents price per megawatt-hour

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended 

December 31, 2016 and 2015, respectively:

Price Risk Management Instruments

(in millions) 2016 2015

Asset (liability) balance as of January 1 $ 89 $69

Net realized and unrealized gains:

Included in regulatory assets and liabilities or balancing accounts(1) (34) 20

Asset (liability) balance as of December 31 $ 55 $89

(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing 

account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains 

and losses are deferred in regulatory liabilities and assets.

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial 

instruments:

đ The fair values of cash, restricted cash, net accounts 

receivable, short-term borrowings, accounts payable, 

customer deposits, floating rate senior notes, and 

the Utility’s variable rate pollution control bond loan 

agreements approximate their carrying values at 

December 31, 2016 and 2015, as they are short-term in 

nature or have interest rates that reset daily.

đ The fair values of the Utility’s fixed-rate senior notes and 

fixed-rate pollution control bonds and PG&E Corporation’s 

fixed-rate senior notes were based on quoted market 

prices at December 31, 2016 and 2015.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table 

below excludes financial instruments with carrying values that approximate their fair values):

At December 31,

2016 2015

(in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value

Debt (Note 4)

PG&E Corporation $ 348 $ 352 $ 348 $ 354

Utility 15,813 17,790 14,818 16,422

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Available for Sale Investments

The following table provides a summary of available-for-sale investments:

(in millions)

Amortized 

Cost

Total 

Unrealized 

Gains

Total 

Unrealized 

Losses

Total Fair 

Value

As of December 31, 2016

Nuclear decommissioning trusts

Short-term investments $ 9 $ - $ - $ 9

Global equity securities 584 1,157 (3) 1,738

Fixed-income securities 1,156 48 (12) 1,192

TOTAL(1) $ 1,749 $1,205 $(15) $ 2,939

As of December 31, 2015

Nuclear decommissioning trusts

Short-term investments $ 36 $ - $ - $ 36

Global equity securities 508 1,034 (9) 1,533

Fixed-income securities 1,165 58 (8) 1,215

TOTAL(1) $ 1,709 $1,092 $(17) $ 2,784

(1) Represents amounts before deducting $333 million and $314 million at December 31, 2016 and 2015, respectively, 

primarily related to deferred taxes on appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows:

(in millions) As of December 31, 2016

Less than 1 year $ 13

1–5 years 419

5–10 years 255

More than 10 years 505

Total maturities of fixed-income securities $ 1,192

The following table provides a summary of activity for the fixed-income and equity securities:

(in millions) 2016 2015 2014

Proceeds from sales and maturities of nuclear decommissioning 

 investments $1,295 $1,268 $1,336

Gross realized gains on securities held as available-for-sale 18 55 118

Gross realized losses on securities held as available-for-sale (26) (37) (12)

NOTE 11: Employee Benefit Plans

Pension Plan and Postretirement Benefits 

Other than Pensions (“PBOP”) 

PG&E Corporation and the Utility sponsor a noncontributory defined benefit pension plan for eligible 

employees hired before December 31, 2012 and a cash 

balance plan for those eligible employees hired after 

this date or who made a one-time election to participate 

(“Pension Plan”). The trusts underlying certain of these 

plans are qualified trusts under the Internal Revenue 

Code of 1986, as amended. If certain conditions are met, 

PG&E Corporation and the Utility can deduct payments 

made to the qualified trusts, subject to certain limitations. 

PG&E Corporation’s and the Utility’s funding policy is 

to contribute tax-deductible amounts, consistent with 

applicable regulatory decisions and federal minimum 

funding requirements. Based upon current assumptions 

and available information, the Utility’s minimum funding 

requirements related to its pension plans is zero.

PG&E Corporation and the Utility also sponsor contributory 

postretirement medical plans for retirees and their eligible 

dependents, and non-contributory postretirement life 

insurance plans for eligible employees and retirees. 

PG&E Corporation and the Utility use a fiscal year-end 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Change in Plan Assets, Benefit Obligations, and Funded Status

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate 

funded status for pension benefits and other benefits for PG&E Corporation during 2016 and 2015:

Pension Plan

(in millions) 2016 2015

Change in plan assets:

Fair value of plan assets at beginning of year $13,745 $14,216

Actual return on plan assets 1,358 (176)

Company contributions 334 334

Benefits and expenses paid (708) (629)

Fair value of plan assets at end of year $14,729 $13,745

Change in benefit obligation:

Benefit obligation at beginning of year $16,299 $16,696

Service cost for benefits earned 453 479

Interest cost 715 673

Actuarial (gain) loss 637 (922)

Plan amendments (91) 1

Transitional costs - 1

Benefits and expenses paid (708) (629)

Benefit obligation at end of year(1) $17,305 $16,299

Funded Status:

Current liability $ (7) $ (6)

Noncurrent liability (2,569) (2,547)

Net liability at end of year $ (2,576) $ (2,553)

(1) PG&E Corporation’s accumulated benefit obligation was $15.6 billion and $14.7 billion at December 31, 2016 and 2015, 

respectively.

Postretirement Benefits Other than Pensions

(in millions) 2016 2015

Change in plan assets:

Fair value of plan assets at beginning of year $2,035 $ 2,092

Actual return on plan assets 167 (26)

Company contributions 52 61

Plan participant contribution 85 68

Benefits and expenses paid (166) (160)

Fair value of plan assets at end of year $2,173 $ 2,035

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

(in millions) 2016 2015

Change in benefit obligation:

Benefit obligation at beginning of year $1,766 $ 1,811

Service cost for benefits earned 52 55

Interest cost 76 71

Actuarial (gain) loss 11 (98)

Plan amendments 37 -

Transitional costs - 1

Benefits and expenses paid (153) (146)

Federal subsidy on benefits paid 3 4

Plan participant contributions 85 68

Benefit obligation at end of year $1,877 $ 1,766

Funded Status:(1)

Noncurrent asset $ 368 $ 344

Noncurrent liability (72) (75)

Net asset at end of year $ 296 $ 269

(1) At December 31, 2016 and 2015, the postretirement medical plan was in an overfunded position and the postretirement life 

insurance plan was in an underfunded position.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

Components of Net Periodic Benefit Cost

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

Pension Plan

(in millions) 2016 2015 2014

Service cost $ 453 $ 479 $ 383

Interest cost 715 673 695

Expected return on plan assets (828) (873) (807)

Amortization of prior service cost 8 15 20

Amortization of net actuarial loss 24 10 2

Net periodic benefit cost 372 304 293

Less: transfer to regulatory account(1) (34) 34 42

Total expense recognized $ 338 $ 338 $ 335

(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

Postretirement Benefits Other than Pensions

(in millions) 2016 2015 2014

Service cost $ 52 $ 55 $ 45

Interest cost 76 71 76

Expected return on plan assets (107) (112) (103)

Amortization of prior service cost 15 19 23

Amortization of net actuarial loss 44 2

Net periodic benefit cost $ 40 $ 37 $ 43

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Components of Accumulated Other 

Comprehensive Income

PG&E Corporation and the Utility record unrecognized prior 

service costs and unrecognized gains and losses related to 

pension and post-retirement benefits other than pension 

as components of accumulated other comprehensive 

income, net of tax. In addition, regulatory adjustments 

are recorded in the Consolidated Statements of Income 

and Consolidated Balance Sheets to reflect the difference 

between expense or income calculated in accordance with 

GAAP for accounting purposes and expense or income for 

ratemaking purposes, which is based on authorized plan 

contributions. For pension benefits, a regulatory asset or 

liability is recorded for amounts that would otherwise be 

recorded to accumulated other comprehensive income. 

For post-retirement benefits other than pension, the 

Utility generally records a regulatory liability for amounts 

that would otherwise be recorded to accumulated other 

comprehensive income. As the Utility is unable to record 

a regulatory asset for these other benefits, the charge 

remains in accumulated other comprehensive income (loss).

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2017 are as follows:

(in millions) Pension Plan PBOP Plans

Unrecognized prior service cost $ (7) $15

Unrecognized net loss 22 4

TOTAL $ 15 $19

There were no material differences between the estimated amounts that will be amortized into net periodic benefit 

costs for PG&E Corporation and the Utility.

Valuation Assumptions 

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic 

benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected 

benefit obligations and net benefit cost.

Pension Plan PBOP Plans

December 31, December 31,

2016 2015 2014 2016 2015 2014

Discount rate 4.11% 4.37% 4.00% 4.05 - 4.19% 4.27 - 4.48% 3.89 - 4.09%

Rate of future compensation 

 increases 4.00% 4.00% 4.00% - - -

Expected return on plan assets 5.30% 6.10% 6.20% 2.80 - 6.00% 3.20 - 6.60% 3.30 - 6.70%

The assumed health care cost trend rate as of December 31, 2016 was 7.2%, decreasing gradually to an ultimate trend 

rate in 2025 and beyond of approximately 4.5%. A one-percentage-point change in assumed health care cost trend 

rate would have the following effects:

(in millions)

One-Percentage-Point 

Increase 

One-Percentage-Point 

Decrease

Effect on postretirement benefit obligation $118 $(120)

Effect on service and interest cost 9 (10)

Expected rates of return on plan assets were developed 

by determining projected stock and bond returns and then 

applying these returns to the target asset allocations of 

the employee benefit plan trusts, resulting in a weighted 

average rate of return on plan assets. Returns on fixedincome debt investments were projected based on real 

maturity and credit spreads added to a long-term inflation 

rate. Returns on equity investments were estimated based 

on estimates of dividend yield and real earnings growth 

added to a long-term inflation rate. For the pension plan, 

the assumed return of 5.3% compares to a ten-year actual 

return of 7.3%. The rate used to discount pension benefits 

and other benefits was based on a yield curve developed 

from market data of over approximately 696 Aa-grade 

non-callable bonds at December 31, 2016. This yield curve 

has discount rates that vary based on the duration of the 

obligations. The estimated future cash flows for the pension 

benefits and other benefit obligations were matched to 

the corresponding rates on the yield curve to derive a 

weighted average discount rate.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Investment Policies and Strategies

The financial position of PG&E Corporation’s and the 

Utility’s funded status is the difference between the fair 

value of plan assets and projected benefit obligations. 

Volatility in funded status occurs when asset values 

change differently from liability values and can result in 

fluctuations in costs in financial reporting, as well as the 

amount of minimum contributions required under the 

Employee Retirement Income Security Act of 1974, as 

amended. PG&E Corporation’s and the Utility’s investment 

policies and strategies are designed to increase the ratio 

of trust assets to plan liabilities at an acceptable level of 

funded status volatility. 

The trusts’ asset allocations are meant to manage volatility, 

reduce costs, and diversify its holdings. Interest rate, 

credit, and equity risk are the key determinants of PG&E 

Corporation’s and the Utility’s funded status volatility. In 

addition to affecting the trusts’ fixed income portfolio 

market values, interest rate changes also influence liability 

valuations as discount rates move with current bond yields. 

To manage volatility, PG&E Corporation’s and the Utility’s 

trusts hold significant allocations in long maturity fixedincome investments. Although they contribute to funded 

status volatility, equity investments are held to reduce longterm funding costs due to their higher expected return. 

Real assets and absolute return investments are held to 

diversify the trust’s holdings in equity and fixed-income 

investments by exhibiting returns with low correlation to the 

direction of these markets. Real assets include commodities 

futures, global REITS, global listed infrastructure equities, 

and private real estate funds. Absolute return investments 

include hedge fund portfolios.

In the Pension Plan, target allocations for 2017 were updated 

to reflect a 2% increase in global equity investments 

and a 2% decrease in fixed income investments. Target 

allocations for PBOP Plans remain unchanged. Derivative 

instruments such as equity index futures are used to meet 

target equity exposure. Derivative instruments, such as 

equity index futures and U.S. treasury futures, are also 

used to rebalance the fixed income/equity allocation 

of the pension’s portfolio. Foreign currency exchange 

contracts are used to hedge a portion of the non U.S. 

dollar exposure of global equity investments.

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are 

as follows: 

Pension Plan PBOP Plans

2017 2016 2015 2017 2016 2015

Global equity 27% 25% 25% 32% 32% 31%

Absolute return 5% 5% 5% 3% 3% 3%

Real assets 10% 10% 10% 7% 7% 8%

Fixed income 58% 60% 60% 58% 58% 58%

TOTAL 100% 100% 100% 100% 100% 100%

PG&E Corporation and the Utility apply a risk management 

framework for managing the risks associated with employee 

benefit plan trust assets. The guiding principles of this risk 

management framework are the clear articulation of roles 

and responsibilities, appropriate delegation of authority, and 

proper accountability and documentation. Trust investment 

policies and investment manager guidelines include 

provisions designed to ensure prudent diversification, 

manage risk through appropriate use of physical direct 

asset holdings and derivative securities, and identify 

permitted and prohibited investments. 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Fair Value Measurements

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category 

at December 31, 2016 and 2015. 

Fair Value Measurements

At December 31,

2016 2015

(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total

Pension Plan:

Short-term investments $ 364 $ 369 $ - $ 733 $ 247 $ 375 $ - $ 622

Global equity 996 - - 996 903-- 903

Real assets 610 - - 610 581-- 581

Fixed-income 1,754 4,774 5 6,533 1,841 4,495 3 6,339

Assets measured at NAV - - - 5,950 --- 5,308

Total $ 3,724 $5,143 $5 $ 14,822 $ 3,572 $4,870 $ 3 $13,753

PBOP Plans:

Short-term investments $ 33 $ - $ - $ 33 $ 20 $ - $ - $ 20

Global equity 115 - - 115 104 - - 104

Real assets 70 - - 70 69 - - 69

Fixed-income 150 656 - 806 150 632 - 782

Assets measured at NAV - - - 1,153 --- 1,065

Total $ 368 $ 656 $ - $ 2,177 $ 343 $ 632 $ -$ 2,040

TOTAL PLAN ASSETS AT FAIR VALUE $ 16,999 $15,793

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $97 million

and $13 million at December 31, 2016 and 2015, respectively, comprised primarily of cash, accounts receivable, deferred 

taxes, and accounts payable.

Valuation Techniques 

The following describes the valuation techniques used to 

measure the fair value of the assets and liabilities shown 

in the table above. All investments that are valued using 

a net asset value per share can be redeemed quarterly 

with a notice not to exceed 90 days.

Short-Term Investments

Short-term investments consist primarily of commingled 

funds across government, credit, and asset-backed sectors. 

These securities are categorized as Level 1 and Level 2 assets. 

Global Equity

The global equity category includes investments in common 

stock and equity-index futures. Equity investments in 

common stock are actively traded on public exchanges 

and are therefore considered Level 1 assets. These equity 

investments are generally valued based on unadjusted 

prices in active markets for identical securities. Equity-index 

futures are valued based on unadjusted prices in active 

markets and are Level 1 assets. 

Real Assets

The real asset category includes portfolios of commodity 

futures, global REITS, global listed infrastructure equities, 

and private real estate funds. The commodity futures, 

global REITS, and global listed infrastructure equities are 

actively traded on a public exchange and are therefore 

considered Level 1 assets. 

Fixed-Income

Fixed-income securities are primarily composed of U.S. 

government and agency securities, municipal securities, 

and other fixed-income securities, including corporate 

debt securities. U.S. government and agency securities 

primarily consist of U.S. Treasury securities that are 

classified as Level 1 because the fair value is determined 

by observable market prices in active markets. A market 

approach is generally used to estimate the fair value of 

debt securities classified as Level 2 using evaluated pricing 

data such as broker quotes, for similar securities adjusted 

for observable differences. Significant inputs used in the 

valuation model generally include benchmark yield curves 

and issuer spreads. The external credit ratings, coupon 

rate, and maturity of each security are considered in the 

valuation model, as applicable.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Assets Measured at NAV

On January 1, 2016, PG&E Corporation and the Utility 

adopted FASB ASU No. 2015-07, Fair Value Measurement 

(Topic 820): Disclosures for Investments in Certain Entities 

That Calculate Net Asset Value per Share (or Its Equivalent)

and applied it retrospectively for the periods presented 

in their Consolidated Financial Statements. (See Note 2 

above.) In accordance with this guidance, investments 

in the pension and PBOP plans that are measured at 

fair value using the NAV per share practical expedient 

have not been classified in the fair value hierarchy tables 

above. The fair value amounts are included in the tables 

above in order to reconcile to the amounts presented 

in the Consolidated Balance Sheets. These investments 

include commingled funds that are composed of equity 

securities traded publicly on exchanges, hedge funds, 

private real estate funds, and fixed-income securities that 

are composed primarily of U.S. government securities and 

asset-backed securities.

Transfers Between Levels

Any transfers between levels in the fair value hierarchy 

are recognized as of the end of the reporting period. No 

material transfers between levels occurred in the years 

ended December 31, 2016 and 2015.

Level 3 Reconciliation 

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been 

classified as Level 3 for the years ended December 31, 2016 and 2015:

(in millions) Fixed-Income

For the year ended December 31, 2016

Balance at beginning of year $ 3

Actual return on plan assets:

Relating to assets still held at the reporting date 3

Relating to assets sold during the period -

Purchases, issuances, sales, and settlements:

Purchases -

Settlements (1)

Balance at end of year $ 5

(in millions) Fixed-Income

For the year ended December 31, 2015

Balance at beginning of year $12

Actual return on plan assets:

Relating to assets still held at the reporting date (3)

Relating to assets sold during the period 1

Purchases, issuances, sales, and settlements:

Purchases 2

Settlements (9)

Balance at end of year $ 3

There were no material transfers out of Level 3 in 2016 and 2015.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Cash Flow Information

Employer Contributions 

PG&E Corporation and the Utility contributed $334 million 

to the pension benefit plans and $52 million to the other 

benefit plans in 2016. These contributions are consistent 

with PG&E Corporation’s and the Utility’s funding policy, 

which is to contribute amounts that are tax-deductible 

and consistent with applicable regulatory decisions and 

federal minimum funding requirements. None of these 

pension or other benefits were subject to a minimum 

funding requirement requiring a cash contribution in 

2016. The Utility’s pension benefits met all the funding 

requirements under ERISA. PG&E Corporation and the 

Utility expect to make total contributions of approximately 

$327 million and $61 million to the pension plan and other 

postretirement benefit plans, respectively, for 2017. 

Benefits Payments and Receipts

As of December 31, 2016, the estimated benefits expected to be paid and the estimated federal subsidies expected 

to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows: 

(in millions) Pension Plan PBOP Plans Federal Subsidy

2017 $ 739 $ 87 $ (8)

2018 781 93 (9)

2019 821 97 (10)

2020 857 103 (10)

2021 892 108 (11)

Thereafter in the succeeding five years 4,879 592 (15)

There were no material differences between the estimated 

benefits expected to be paid by PG&E Corporation and 

paid by the Utility for the years presented above. There 

were also no material differences between the estimated 

subsidies expected to be received by PG&E Corporation 

and received by the Utility for the years presented above.

Retirement Savings Plan 

PG&E Corporation sponsors a retirement savings plan, 

which qualifies as a 401(k) defined contribution benefit plan 

under the Internal Revenue Code 1986, as amended. This 

plan permits eligible employees to make pre-tax and aftertax contributions into the plan, and provide for employer 

contributions to be made to eligible participants. Total 

expenses recognized for defined contribution benefit plans 

reflected in PG&E Corporation’s Consolidated Statements 

of Income were $97 million, $89 million, and $80 million 

in 2016, 2015, and 2014, respectively.

There were no material differences between the employer 

contribution expense for PG&E Corporation and the Utility 

for the years presented above.

NOTE 12: Related Party Agreements and Transactions

The Utility and other subsidiaries provide and receive 

various services to and from their parent, PG&E Corporation, 

and among themselves. The Utility and PG&E Corporation 

exchange administrative and professional services in 

support of operations. Services provided directly to 

PG&E Corporation by the Utility are priced at the higher 

of fully loaded cost (i.e., direct cost of good or service 

and allocation of overhead costs) or fair market value, 

depending on the nature of the services. Services provided 

directly to the Utility by PG&E Corporation are generally 

priced at the lower of fully loaded cost or fair market value, 

depending on the nature and value of the services. PG&E 

Corporation also allocates various corporate administrative 

and general costs to the Utility and other subsidiaries using 

agreed-upon allocation factors, including the number 

of employees, operating and maintenance expenses, 

total assets, and other cost allocation methodologies. 

Management believes that the methods used to allocate 

expenses are reasonable and meet the reporting and 

accounting requirements of its regulatory agencies.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The Utility’s significant related party transactions were:

Year Ended December 31,

(in millions) 2016 2015 2014

Utility revenues from:

Administrative services provided to PG&E Corporation $ 7 $ 6 $ 5

Utility expenses from:

Administrative services received from PG&E Corporation $74 $53 $54

Utility employee benefit due to PG&E Corporation 91 82 70

At December 31, 2016 and 2015, the Utility had receivables 

of $18 million and $22 million, respectively, from PG&E 

Corporation included in accounts receivable – other and 

other noncurrent assets – other on the Utility’s Consolidated 

Balance Sheets, and payables of $22 million and $21 

million, respectively, to PG&E Corporation included in 

accounts payable – other on the Utility’s Consolidated 

Balance Sheets.

NOTE 13: Contingencies and Commitments

PG&E Corporation and the Utility have significant 

contingencies arising from their operations, including 

contingencies related to enforcement and litigation matters 

and environmental remediation. A provision for a loss 

contingency is recorded when it is both probable that a 

loss has been incurred and the amount of the loss can be 

reasonably estimated. PG&E Corporation and the Utility 

evaluate the range of reasonably estimated losses and 

record a provision based on the lower end of the range, 

unless an amount within the range is a better estimate 

than any other amount. The assessment of whether a loss 

is probable or reasonably possible, and whether the loss 

or a range of loss is estimable, often involves a series of 

complex judgments about future events. Loss contingencies 

are reviewed quarterly and estimates are adjusted to reflect 

the impact of all known information, such as negotiations, 

discovery, settlements and payments, rulings, advice of 

legal counsel, and other information and events pertaining 

to a particular matter. PG&E Corporation’s and the Utility’s 

policy is to exclude anticipated legal costs from the 

provision for loss and expense these costs as incurred. 

The Utility also has substantial financial commitments in 

connection with agreements entered into to support its 

operating activities. See “Purchase Commitments” below. 

PG&E Corporation has financial commitments described 

in “Other Commitments” below. PG&E Corporation’s and 

the Utility’s financial condition, results of operations, and 

cash flows may be materially affected by the outcome of 

the following matters.

Enforcement and Litigation Matters

CPUC Matters

Order Instituting an Investigation into Compliance 

with Ex Parte Communication Rules 

During 2014 and 2015, the Utility filed several reports 

to notify the CPUC of communications that the Utility 

believes may have constituted or described ex parte 

communications that either should not have occurred or 

that should have been timely reported to the CPUC. Ex 

parte communications include communications between a 

decision maker or a commissioner’s advisor and interested 

persons concerning substantive issues in certain formal 

proceedings. Certain communications are prohibited and 

others are permissible with proper noticing and reporting.

On November 23, 2015, the CPUC issued an OII into 

whether the Utility should be sanctioned for violating 

rules pertaining to ex parte communications and Rule 1.1 

of the CPUC’s Rules of Practice and Procedure governing 

the conduct of those appearing before the CPUC. The OII 

cites some of the communications the Utility reported to 

the CPUC. The OII also cites the ex parte violations alleged 

in the City of San Bruno’s July 2014 motion, which it filed 

in CPUC investigations related to the Utility’s natural gas 

transmission pipeline operations and practices. 

On October 14, 2016, the Cities of San Bruno and San 

Carlos, ORA, the SED, TURN, and the Utility submitted a 

status report to the CPUC which proposed an update to 

the framework for resolving the proceeding. The revised 

framework includes a total of 164 communications in the 

scope of the proceeding. Throughout 2016, the parties 

jointly submitted stipulations on all of the communications, 

and on November 30, 2016, the parties began settlement 

discussions. In the event a settlement cannot be reached, 

the parties will brief the matter based upon the identified 

communications and some related discovery as well as 

factual stipulations and agreed upon issues of policy and 

law for CPUC resolution. The opening briefs are due on 

March 24, 2017, and reply briefs are due on April 14, 2017.

The Utility expects that the other parties may argue that 

the number of violations exceeds the 164 communications 

referenced in the October 14, 2016 joint status report either 

because a single communication may have violated more 

than one rule or because they believe some of the material 

provided during discovery constitutes impermissible ex 

parte communications. The Utility expects to contest many 

of these assertions. If the matter does not settle, the CPUC 

will determine which communications included within the 

scope of the proceeding were in violation of its rules. The 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CPUC will also determine whether to impose penalties or 

other remedies, as a result of a potential settlement or 

otherwise. The CPUC can impose fines up to $50,000 for 

each violation, and up to $50,000 per day if the CPUC 

determines that the violation was continuing. The CPUC 

has wide discretion to determine the amount of penalties 

based on the totality of the circumstances, including such 

factors as how many days each violation continued; 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 

is also required to consider the appropriateness of the 

amount of the penalty to the size of the entity charged. 

The CPUC has historically exercised broad discretion in 

determining whether violations are continuing and the 

amount of penalties to be imposed. 

PG&E Corporation and the Utility believe it is probable 

that the CPUC will impose penalties on the Utility in the 

OII. In light of recent CPUC decisions, such as the Penalty 

Decision and the decision in the 2015 GT&S rate case, the 

Utility expects that such penalties could include fines and 

future revenue requirement reductions. In accordance with 

accounting rules, revenue requirement reductions would 

be recorded in the period they are incurred and fines 

would be recorded when considered probable and their 

amount or range can be reasonably estimated. The Utility 

is unable to determine the form or amount of penalties 

or reasonably estimate the amount or range of future 

charges that could be incurred because it is uncertain 

how the CPUC will calculate the number of violations or 

the penalty for any violations.

Finally, 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 has cooperated with those 

investigations. It is uncertain whether any charges will be 

brought against the Utility.

CPUC Investigation Regarding Natural Gas 

Distribution Facilities Record-Keeping

On November 20, 2014, the CPUC began an investigation 

into whether the Utility violated applicable laws pertaining 

to record-keeping practices with respect to maintaining 

safe operation of its natural gas distribution service and 

facilities. The order also required the Utility to show cause 

why (1) the CPUC should not find that the Utility violated 

provisions of the California Public Utilities Code, CPUC 

general orders or decisions, other rules, or requirements, 

and/or engaged in unreasonable and/or imprudent 

practices related to these matters, and (2) the CPUC 

should not impose penalties, and/or any other forms of 

relief, if any violations are found. In particular, the order 

cited the SED’s investigative reports alleging that the 

Utility violated rules regarding safety record-keeping in 

connection with six natural gas distribution incidents, 

including the natural gas explosion that occurred in Carmel, 

California on March 3, 2014. 

On August 18, 2016, the CPUC approved a final decision 

in this investigation. The CPUC assessed a fine of $25.6 

million. With the $10.85 million citation previously paid 

in 2015 for the City of Carmel-by-the-Sea (“Carmel”) 

incident, the total fine imposed on the Utility was $36.5 

million. The remaining $25.6 million was paid in September 

2016. The decision denied the appeals previously filed by 

the SED and Carmel from the presiding officer’s decision, 

and closed this proceeding but allowed the parties an 

opportunity to request that this proceeding be reopened if 

needed to ensure proper implementation of a compliance 

plan to be developed by the parties. 

On September 26, 2016, the SED filed an application 

for rehearing of the CPUC’s decision. Specifically, the 

application indicates that the CPUC erred in certain of 

its determinations (including those related to maximum 

allowable operating pressure documentation that, if 

adopted, could result in an additional fine of $7 million), 

calculations (including those related to the missing De 

Anza records violations) and certain other findings, and 

requests that the CPUC adopt its recommendations. On 

October 11, 2016, the Utility submitted its response to 

the CPUC in which it opposed the SED’s application for 

rehearing arguing that the application failed to identify 

a legal error warranting rehearing by the CPUC. The 

Utility cannot predict when or if the CPUC will grant the 

rehearing or if it will adopt the SED’s recommendations. 

On October 24, 2016 and November 30, 2016, the Utility 

held meet and confer sessions with parties to develop 

remedial measures necessary to address the issues 

identified in the CPUC decision with the objective of 

establishing a compliance plan. On December 16, 2016, 

the Utility submitted its Initial Gas Distribution Records 

Compliance Plan that includes feasible and cost-effective 

measures necessary to improve natural gas distribution 

system record-keeping. 

Natural Gas Transmission Pipeline Rights-of-Way

In 2012, the Utility notified the CPUC and the SED that 

the Utility planned to complete a system-wide survey of 

its transmission pipelines in an effort to address a selfreported violation whereby the Utility did not properly 

identify encroachments (such as building structures and 

vegetation overgrowth) on the Utility’s pipeline rights-ofway.  The Utility also submitted a proposed compliance 

plan that set forth the scope and timing of remedial work to 

remove identified encroachments over a multi-year period 

and to pay penalties if the proposed milestones were not 

met.  In March 2014, the Utility informed the SED that the 

survey had been completed and that remediation work, 

including removal of the encroachments, was expected 

to continue for several years. The SED has not addressed 

the Utility’s proposed compliance plan, and it is reasonably 

possible that the SED will impose fines on the Utility in 

the future based on the Utility’s failure to continuously 

survey its system and remove encroachments. The Utility 

is unable to reasonably estimate the amount or range of 

future charges that could be incurred given the SED’s 

wide discretion and the number of factors that can be 

considered in determining penalties.

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 Potential Safety Citations

The SED periodically audits utility operating practices and 

conducts investigations of potential violations of laws and 

regulations applicable to the safety of the California utilities’ 

electric and natural gas facilities and operations. The CPUC 

has delegated authority to the SED to issue citations and 

impose penalties for violations identified through audits, 

investigations, or self-reports. Under both the gas and 

electric programs, 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. 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 

can consider the discretionary factors discussed above 

(see “Order Instituting an Investigation into Compliance 

with Ex Parte Communication Rules” above) in determining 

the number of violations and whether to impose daily fines 

for continuing violations. There is also an administrative 

limit of $8 million per citation issued. 

The SED has imposed fines on the Utility ranging from 

$50,000 to $16.8 million for violations of electric and 

natural gas laws and regulations. The Utility believes it 

is probable that the SED will impose penalties or take 

other enforcement action based on some of the Utility’s 

self-reported non-compliance with laws and regulations, 

based on the SED’s investigations of incidents reported to 

the CPUC, or based on allegations of non-compliance with 

such laws and regulations that are contained in some of 

the SED’s audits or investigations. The Utility is unable to 

reasonably estimate the amount or range of future charges 

that could be incurred for fines imposed by the SED with 

respect to these matters given the wide discretion the 

SED and other CPUC staff has in determining whether to 

bring enforcement action and the number of factors that 

can be considered in determining the amount of fines.

In September 2016, the Utility reported that it discovered in 

November 2015 that approximately 550,000 atmospheric 

corrosion inspections on above-ground gas distribution 

meters completed in 2014, which constituted 35% of such 

inspections in 2014, were performed by non-operator 

qualified personnel. The Utility did not provide timely 

notification of such non-compliance to the CPUC. On 

December 23, 2016, the SED issued the Utility a citation 

with a $5.45 million fine related to this self-report. The 

citation included a $5.05 million fine for not ensuring 

that contractor inspectors were operator-qualified, a 

$350,000 fine for not completing inspections within 39 

months from the previous inspections, and a $50,000 fine 

for not reporting the self-identified violations within ten 

days of discovery. The amount of the fine is conditioned 

upon the Utility implementing certain remedial measures. 

The Utility paid the fine in January 2017.

In February 2017, the Utility reported that it discovered 

in April 2014 that customer service representatives who 

handle gas emergency calls within the Utility’s call centers 

are not included in the drug and alcohol testing program 

as required by PHMSA regulations. The Utility did not 

provide timely notification of such non-compliance to 

the CPUC. The SED could impose fines on the Utility of 

$50,000 per violation, and also for failure to timely file a 

self-report in connection with the non-compliance. The 

SED has the authority to issue more than one citation 

for a series of related incidents and can impose daily 

fines for continuing violations, and the CPUC can issue 

an OII and possible additional fines even after the SED 

has issued a citation. The Utility is unable to reasonably 

estimate the amount or range of future charges that could 

be incurred for fines that could be imposed with respect 

to this self-report, for the reasons indicated above, or to 

predict whether the CPUC will open a formal proceeding. 

Federal Matters

Federal Criminal Trial 

On June 14, 2016, a federal criminal trial against the Utility 

began in the United States District Court for the Northern 

District of California, in San Francisco, on 12 felony counts 

alleging that the Utility knowingly and willfully violated 

minimum safety standards under the Natural Gas Pipeline 

Safety Act relating to record-keeping, pipeline integrity 

management, and identification of pipeline threats, and one 

felony count charging that the Utility obstructed the NTSB 

investigation into the cause of the San Bruno accident. On 

July 26, 2016, the court granted the government’s motion 

to dismiss one count alleging that the Utility knowingly 

and willfully failed to retain a strength test pressure record 

with respect to a distribution feeder main, thereby reducing 

the total number of counts from 13 to 12. 

On August 9, 2016, the jury returned its verdict. The 

jury acquitted the Utility on all six of the record-keeping 

allegations but found the Utility guilty on six felony counts 

that include 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 sentencing 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 Utility has 

decided not to appeal the convictions. 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 is required to retain a 

third-party monitor. The goal of the monitorship will be to 

prevent the criminal conduct with respect to gas pipeline 

transmission safety that gave rise to the conviction. To that 

end, the goal of the monitor will be to help ensure that the 

Utility takes reasonable and appropriate steps to maintain 

the safety of the gas transmission pipeline system, performs 

appropriate integrity management assessments on its gas 

transmission pipelines, and maintains an effective ethics 

and compliance program and safety related incentive 

program.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

After an initial assessment is conducted and an initial 

report is prepared by the monitor, the monitor will prepare 

reports on a semi-annual basis setting forth the monitor’s 

continued assessment and making recommendations 

consistent with the goals and scope of the monitorship. 

The Utility expects that the monitor will be retained before 

the end of the second quarter of 2017. 

At December 31, 2016, PG&E Corporation’s and the Utility’s 

Consolidated Balance Sheets include a $3 million accrual 

in connection with this matter. On February 1, 2017, the 

Utility paid the $3 million fine imposed by the court. The 

Utility could incur material costs, not recoverable through 

rates, in the event of non-compliance with the terms of 

probation and in connection with the monitorship (including 

but not limited to the monitor’s compensation or costs 

resulting from recommendations of the monitor). 

Other Federal Matters

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 has cooperated with those investigations. In 

addition, in October 2016, the Utility received a grand 

jury subpoena and letter from the U.S. Attorney for the 

Northern District of California advising that the Utility is a 

target of a federal investigation regarding possible criminal 

violations of the Migratory Bird Treaty Act and conspiracy 

to violate the act. The investigation involves a removal by 

the Utility of a hazardous tree that contained an osprey 

nest and egg in Inverness, California, on March 18, 2016. It 

is uncertain whether any charges will be brought against 

the Utility as a result of these investigations.

Other Matters

Butte Fire Litigation

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 a press release also issued on April 

28, 2016, Cal Fire indicated that it will seek to recover 

firefighting costs in excess of $90 million from the Utility.

On May 23, 2016, individual plaintiffs filed a master 

complaint against the Utility and its two vegetation 

management contractors in the Superior Court of California 

for Sacramento County.  Subrogation insurers also filed a 

separate master complaint on the same date.  The California 

Judicial Council had previously authorized the coordination 

of all cases in Sacramento County.  As of December 31, 2016, 

complaints have been filed against the Utility and its two 

vegetation management contractors in the Superior Court 

of California in the Counties of Calaveras, San Francisco, 

Sacramento, and Amador involving approximately 

1,950 individual plaintiffs representing approximately 

950 households and their insurance companies.  These 

complaints are part of or are in the process of being 

added to the two master complaints.  Plaintiffs seek to 

recover damages and other costs, principally based on 

inverse condemnation and negligence theories of liability. 

The number of individual complaints and plaintiffs may 

increase in the future. 

The Utility continues mediating and settling cases. The 

next case management conference is scheduled for 

March 2, 2017.

In connection with this matter, the Utility may be liable for 

property damages, interest, and attorneys’ fees without 

having been found negligent, through the theory 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. The Utility believes it was not negligent; 

however, there can be no assurance that a court or jury 

would agree with the Utility. The Utility believes that it is 

probable that it will incur a loss of at least $750 million 

for all potential damages described above. This amount is 

based on assumptions about the number, size, and type 

of structures damaged or destroyed, the contents of such 

structures, the number and types of trees damaged or 

destroyed, as well as assumptions about personal injury 

damages, attorneys’ fees, fire suppression costs, and 

other damages that the Utility could be liable for under 

the theories of inverse condemnation and/or negligence.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The following table presents changes in the third-party claims liability since December 31, 2015. The balance for the 

third-party claims liability is included in Other current liabilities in PG&E Corporation’s and the Utility’s Consolidated 

Balance Sheets:

Loss Accrual (in millions)

Balance at December 31, 2015 $ -

Accrued losses 750

Payments (60)

Balance at December 31, 2016 $ 690

In addition to the amounts reflected in the table above, 

the Utility has incurred cumulative legal expenses of $27 

million.

The Utility believes that it is reasonably possible that it 

will incur losses related to Butte fire claims in excess of 

$750 million accrued through December 31, 2016 but is 

currently unable to reasonably estimate the upper end 

of the range of losses because it is still in an early stage 

of the evaluation of claims, the mediation and settlement 

process, and discovery. The process for estimating costs 

associated with claims relating to the Butte fire requires 

management to exercise significant judgment based on a 

number of assumptions and subjective factors. As more 

information becomes known, including additional discovery 

from the plaintiffs and results from the ongoing mediation 

and settlement process, management estimates and 

assumptions regarding the financial impact of the Butte 

fire may result in material increases to the loss accrued. 

The Utility has liability insurance from various insurers, which 

provides coverage for third-party liability attributable to 

the Butte fire in an aggregate amount of approximately 

$900 million. The Utility records insurance recoveries 

when it is deemed probable that a recovery will occur 

and the Utility can reasonably estimate the amount or its 

range. The Utility has recorded $625 million for probable 

insurance recoveries in connection with losses related to 

the Butte fire. While the Utility plans to seek recovery of all 

insured losses, it is unable to predict the ultimate amount 

and timing of such insurance recoveries. In addition, the 

Utility is pursuing coverage under the insurance policies 

of its two vegetation management contractors, including 

under policies where the Utility is listed as an additional 

insured. Recoveries of any amounts under these policies 

are uncertain. 

The following table presents changes in the insurance receivable since December 31, 2015. The balance for the insurance 

receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)

Balance at December 31, 2015 $ -

Accrued insurance recoveries 625

Reimbursements (50)

Balance at December 31, 2016 $ 575

If the Utility records losses in connection with claims relating 

to the Butte fire that materially exceed the amount the 

Utility accrued for these liabilities, PG&E Corporation’s and 

the Utility’s financial condition, results of operations, or 

cash flows could be materially affected in the reporting 

periods during which additional charges are recorded, 

depending on whether the Utility is able to record or 

collect insurance recoveries in amounts sufficient to offset 

such additional accruals.

Other Contingencies 

PG&E Corporation and the Utility are subject to various 

claims, lawsuits and regulatory proceedings that separately 

are not considered material. Accruals for contingencies 

related to such matters (excluding amounts related to the 

contingencies discussed above under “Enforcement and 

Litigation Matters”) totaled $45 million at December 31, 

2016 and $63 million at December 31, 2015. These amounts 

are included in Other current liabilities in the Consolidated 

Balance Sheets. The resolution of these matters is not 

expected to have a material impact on PG&E Corporation’s 

and the Utility’s financial condition, results of operations, 

or cash flows. 

Disallowance of Plant Costs

PG&E Corporation and the Utility record a charge when 

it is both probable that costs incurred or projected to 

be incurred for recently completed plant will not be 

recoverable through rates and the amount of disallowance 

can be reasonably estimated. Capital disallowances are 

reflected in operating and maintenance expenses in the 

Consolidated Statements of Income. Disallowances as a 

result of the CPUC’s June 23, 2016 final phase one decision 

and December 1, 2016 final phase two decision in the 

Utility’s 2015 GT&S rate case, the April 9, 2015 Penalty 

Decision and the Utility’s Pipeline Safety Enhancement 

Plan are discussed below. 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

2015 GT&S Rate Case Disallowance of Capital 

Expenditures

On June 23, 2016, the CPUC approved a final phase one 

decision in the Utility’s 2015 GT&S rate case.  The decision 

permanently disallowed a portion of the 2011 through 2014 

capital spending in excess of the amount adopted and 

established various cost caps that will increase the risk 

of overspend over the current rate case cycle, including 

new one-way capital balancing accounts. As a result, 

in 2016, the Utility incurred charges of $219 million for 

capital expenditures that the Utility believes are probable 

of disallowance based on the decision. This included 

$134 million to the net plant balance for 2011 through 

2014 capital expenditures in excess of adopted amounts 

and $85 million for the Utility’s estimate of 2015 through 

2018 capital expenditures that are probable of exceeding 

authorized amounts. Additional charges may be required 

in the future based on the Utility’s ability to manage its 

capital spending and on the outcome of the CPUC’s audit 

of 2011 through 2014 capital spending.

Penalty Decision’s Disallowance of Natural Gas 

Capital Expenditures

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 “Penalty Decision”). In January 

2016, the CPUC closed the investigative proceedings. 

The total penalty includes (1) a $300 million fine, (2) a 

one-time $400 million bill credit to the Utility’s natural 

gas customers, (3) $850 million to fund pipeline safety 

projects and programs, and (4) remedial measures that 

the CPUC estimates will cost the Utility at least $50 million. 

On December 1, 2016, the CPUC approved a final phase 

two decision in the Utility’s 2015 GT&S rate case, which 

applies $689 million of the $850 million penalty to capital 

expenditures. The decision also approves the Utility’s list 

of programs and projects that meet the CPUC’s definition 

of “safety related,” the costs of which are to be funded 

through the $850 million penalty. 

For the twelve months ended December 31, 2016, the Utility recorded charges for disallowed capital spending of $283 

million as a result of the Penalty Decision. The cumulative charges at December 31, 2016, and the additional future 

charges that will be recognized in the first quarter of 2017 are shown in the following table:

(in millions)

Twelve Months

Ended 

December 31, 

2016

Cumulative

Charges

December 31,

2016

Future 

Charges

and 

Costs

Total 

Amount

Fine paid to the state $ - $ 300 $ - $ 300

Customer bill credit paid - 400 - 400

Charge for disallowed capital (1) 283 689 - 689

Disallowed revenue for pipeline safety expenses(2) 129 129 32 161

CPUC estimated cost of other remedies (3) --- 50

TOTAL PENALTY DECISION FINES AND REMEDIES $ 412 $1,518 $ 32 $ 1,600

(1) The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related 

projects and programs. On December 1, 2016, the CPUC approved a final phase two decision in the Utility’s 2015 GT&S rate 

case which allocates $689 million of the $850 million penalty to capital expenditures. 

(2) GT&S revenues have been reduced for these unrecovered expenses. The remaining charges will be recognized in the first 

quarter of 2017. 

(3) In the Penalty Decision, the CPUC estimated that the Utility would incur $50 million to comply with the remedies specified in 

the Penalty Decision. This table does not reflect the Utility’s remedy-related costs already incurred or the Utility’s estimated 

future remedy-related costs.

Capital Expenditures Relating to Pipeline Safety 

Enhancement Plan 

The CPUC has authorized the Utility to collect $766 million 

for recovery of PSEP capital costs. As of December 31, 2016, 

the Utility has spent $1.35 billion on PSEP-related capital 

costs, of which $665 million was expensed in previous 

years for costs that are expected to exceed the authorized 

amount. The Utility expects the remaining PSEP work 

to continue beyond 2017. The Utility would be required 

to record charges in future periods to the extent PSEPrelated capital costs are higher than currently expected.

Environmental Remediation Contingencies

Given the complexities of the legal and regulatory 

environment and the inherent uncertainties involved in 

the early stages of a remediation project, the process for 

estimating remediation liabilities is subjective and requires 

significant judgment.  The Utility records an environmental 

remediation liability when the site assessments indicate 

that remediation is probable and the Utility can reasonably 

estimate the loss or a range of probable amounts. The 

Utility records an environmental remediation liability based 

on the lower end of the range of estimated probable 

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

costs, unless an amount within the range is a better 

estimate than any other amount.  Amounts recorded 

are not discounted to their present value. The Utility’s 

environmental remediation liability is primarily included 

in non-current liabilities on the Consolidated Balance 

Sheets and is composed of the following:

Balance at

(in millions) December 31, 2016 December 31, 2015

Topock natural gas compressor station (1) $299 $300

Hinkley natural gas compressor station (1) 135 140

Former manufactured gas plant sites owned by the Utility 

 or third parties

285 271

Utility-owned generation facilities (other than fossil fuel- 

 fired), other facilities, and third-party disposal sites 131 164

Fossil fuel-fired generation facilities and sites 108 94

TOTAL ENVIRONMENTAL REMEDIATION LIABILITY $958 $969

(1) See “Natural Gas Compressor Station Sites” below.

The Utility’s gas compressor stations, former manufactured 

gas plant sites, power plant sites, gas gathering sites, 

and sites used by the Utility for the storage, recycling, 

and disposal of potentially hazardous substances are 

subject to requirements issued by the EPA under the 

federal Resource Conversation and Recovery Act as 

well as other state hazardous waste laws. The Utility has 

a comprehensive program in place designed to comply 

with federal, state, and local laws and regulations related 

to hazardous materials, waste, remediation activities, and 

other environmental requirements. The Utility assesses 

and monitors, on an ongoing basis, measures that may be 

necessary to comply with these laws and regulations and 

implements changes to its program as deemed appropriate. 

The Utility’s remediation activities are overseen by the 

DTSC, several California regional water quality control 

boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at 

December 31, 2016 reflects its best estimate of probable 

future costs associated with its final remediation plan. 

Future costs will depend on many factors, including the 

extent of work to implement final remediation plans and 

the Utility’s required time frame for remediation. Future 

changes in cost estimates and the assumptions on which 

they are based may have a material impact on future 

financial condition and cash flows. 

At December 31, 2016 the Utility expected to recover $671 

million of its environmental remediation liability through 

various ratemaking mechanisms authorized by the CPUC. 

One of these mechanisms allows the Utility rate recovery 

for 90% of its hazardous substance remediation costs 

for certain approved sites (including the Topock site) 

without a reasonableness review. The Utility may incur 

environmental remediation costs that it does not seek 

to recover in rates, such as the costs associated with the 

Hinkley site.

Natural Gas Compressor Station Sites

The Utility is legally responsible for remediating groundwater 

contamination caused by hexavalent chromium used in 

the past at the Utility’s natural gas compressor stations. 

One of these stations is located near Needles, California 

and is referred to below as the “Topock site.” Another 

station is located near Hinkley, California and is referred to 

below as the “Hinkley site.” The Utility is also required to 

take measures to abate the effects of the contamination 

on the environment.

Topock Site

The Utility’s remediation and abatement efforts at the 

Topock site are subject to the regulatory authority of the 

DTSC and the DOI. In November 2015, the Utility submitted 

its final remediation design to the agencies for approval. 

The Utility’s design proposes that the Utility construct 

an in-situ groundwater treatment system to convert 

hexavalent chromium into a non-toxic and non-soluble 

form of chromium. The DTSC conducted an additional 

environmental review of the proposed design and issued a 

draft environmental impact report for public comment in 

January 2017. After the DTSC considers public comments 

that may be made, the DTSC is expected to issue a final 

environmental impact report in mid-2017. After the Utility 

modifies its design in response to the final report, the 

Utility will seek approval to begin construction of the 

new in-situ treatment system in late 2017 or early 2018.

Hinkley Site

The Utility has been implementing interim remediation 

measures at the Hinkley site to reduce the mass of the 

chromium plume and to monitor and control movement 

of the plume. The Utility’s remediation and abatement 

efforts at the Hinkley site are subject to the regulatory 

authority of the Regional Board. In November 2015, the 

Regional Board adopted a final clean-up and abatement 

order to contain and remediate the underground plume 

of hexavalent chromium and the potential environmental 

impacts. The final order states that the Utility must continue 

and improve its remediation efforts, define the boundaries 

of the chromium plume, and take other action. Additionally, 

the final order requires setting plume capture requirements, 

requires establishing a monitoring and reporting program, 

and finalizes deadlines for the Utility to meet interim 

cleanup targets.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Reasonably Possible Environmental Contingencies

Although the Utility has provided for known environmental 

obligations that are probable and reasonably estimable, 

the Utility’s undiscounted future costs could increase to 

as much as $1.9 billion (including amounts related to the 

Topock and Hinkley sites described above) if the extent 

of contamination or necessary remediation is greater 

than anticipated or if the other potentially responsible 

parties are not financially able to contribute to these 

costs. The Utility may incur actual costs in the future that 

are materially different than this estimate and such costs 

could have a material impact on results of operations, 

financial condition and cash flows during the period in 

which they are recorded.

Nuclear Insurance 

The Utility is a member of NEIL, which is a mutual insurer 

owned by utilities with nuclear facilities. NEIL provides 

insurance coverage for property damages and business 

interruption losses incurred by the Utility if a nuclear event 

were to occur at the Utility’s two nuclear generating units 

at Diablo Canyon and the retired Humboldt Bay Unit 3. 

NEIL provides property damage and business interruption 

coverage of up to $3.2 billion per nuclear incident and 

$2.6 billion per non-nuclear incident for Diablo Canyon. 

Humboldt Bay Unit 3 has up to $131 million of coverage 

for nuclear and non-nuclear property damages.

NEIL also provides coverage for damages caused by acts of 

terrorism at nuclear power plants. Certain acts of terrorism 

may be “certified” by the Secretary of the Treasury. If 

damages are caused by certified acts of terrorism, NEIL 

can obtain compensation from the federal government 

and will provide up to its full policy limit of $3.2 billion 

for each insured loss. In contrast, NEIL would treat all 

non-certified terrorist acts occurring within a 12-month 

period against one or more commercial nuclear power 

plants insured by NEIL as one event and the owners of 

the affected plants would share the $3.2 billion policy 

limit amount. 

In addition to the nuclear insurance the Utility maintains 

through the NEIL, the Utility also is a member of the EMANI, 

which provides excess insurance coverage for property 

damages and business interruption losses incurred by the 

Utility if a nuclear or non-nuclear event were to occur at 

Diablo Canyon. 

If NEIL losses in any policy year exceed accumulated 

funds, the Utility could be subject to a retrospective 

assessment.  If NEIL were to exercise this assessment, as 

of December 31, 2016, the current maximum aggregate 

annual retrospective premium obligation for the Utility 

would be approximately $60 million.  EMANI provides 

$200 million for any one accident and in the annual 

aggregate excess of the combined amount recoverable 

under the Utility’s NEIL policies. If EMANI losses in any 

policy year exceed accumulated funds, the Utility could 

be subject to a retrospective assessment of approximately 

$2 million, as of December 31, 2016.   

Under the Price-Anderson Act, public liability claims that 

arise from nuclear incidents that occur at Diablo Canyon, 

and that occur during the transportation of material to 

and from Diablo Canyon are limited to $13.5 billion. The 

Utility purchased the maximum available public liability 

insurance of $375 million for Diablo Canyon. The balance 

of the $13.5 billion of liability protection is provided under 

a loss-sharing program among utilities owning nuclear 

reactors. The Utility may be assessed up to $255 million 

per nuclear incident under this program, with payments in 

each year limited to a maximum of $38 million per incident. 

Both the maximum assessment and the maximum yearly 

assessment are adjusted for inflation at least every five 

years. The next scheduled adjustment is due on or before 

September 10, 2018.

The Price-Anderson Act does not apply to claims that 

arise from nuclear incidents that occur during shipping 

of nuclear material from the nuclear fuel enricher to a fuel 

fabricator or that occur at the fuel fabricator’s facility. 

The Utility has a separate policy that provides coverage 

for claims arising from some of these incidents up to a 

maximum of $375 million per incident. In addition, the 

Utility has $53 million of liability insurance for Humboldt 

Bay Unit 3 and has a $500 million indemnification from 

the NRC for public liability arising from nuclear incidents, 

covering liabilities in excess of the liability insurance.

Resolution of Remaining Chapter 11 

Disputed Claims

Various electricity suppliers filed claims in the Utility’s 

proceeding filed under Chapter 11 of the U.S. Bankruptcy 

Code seeking payment for energy supplied to the Utility’s 

customers between May 2000 and June 2001.  While 

the FERC and judicial proceedings are pending, the 

Utility has pursued, and continues to pursue, settlements 

with electricity suppliers. The Utility has entered into a 

number of settlement agreements with various electricity 

suppliers to resolve some of these disputed claims and to 

resolve the Utility’s refund claims against these electricity 

suppliers. Under these settlement agreements, amounts 

payable by the parties are, in some instances, subject to 

adjustment based on the outcome of the various refund 

offset and interest issues being considered by the FERC. In 

connection with the CPUC approved settlement agreement, 

on April 12, 2004, the Utility deposited approximately 

$1.7 billion into escrow for the payment of certain disputed 

claims, previously collected from customers through 

rates. Generally, any net refunds, claim offsets, or other 

credits that the Utility receives from electricity suppliers 

either through settlement or through the conclusion of 

the various FERC and judicial proceedings are refunded 

to customers through rates in future periods.

On October 13, 2016, the Utility received approval from 

the bankruptcy court to release the remaining cash held 

in escrow to unrestricted cash for use by the Utility. The 

approval resulted in a $161 million reduction to the cash 

in escrow within the Restricted cash balance on the 

Consolidated Balance Sheets.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

On September 2, 2016, the Utility’s settlement became 

effective resolving, among other matters, the Utility’s 

claim against the CAISO for $165 million, which includes 

receivables and interest.  Additionally, the Utility agreed to 

release $66 million of cash from escrow to the California 

Power Exchange. The settlement resulted in a $231 million 

reduction to the Disputed claims and customer refunds 

balance on the Consolidated Balance Sheets. 

At December 31, 2016 and December 31, 2015, respectively, 

the Consolidated Balance Sheets reflected $236 million 

and $454 million in net claims within Disputed claims 

and customer refunds. The cash held in escrow within 

Restricted cash was zero as of December 31, 2016 and 

$228  million as of December 31, 2015. The Utility is uncertain 

when or how the remaining net disputed claims liability 

will be resolved. 

Purchase Commitments 

The following table shows the undiscounted future expected obligations under power purchase agreements that have 

been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected 

payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of 

December 31, 2016:

Power Purchase Agreements

(in millions)

Renewable

Energy

Conventional

Energy Other

Natural 

Gas

Nuclear

Fuel Total

2017 $ 2,233 $ 815 $ 369 $ 536 $ 97 $ 4,050

2018 2,108 716 284 169 93 3,370

2019 2,144 698 225 160 95 3,322

2020 2,139 677 179 148 130 3,273

2021 2,117 585 147 93 49 2,991

Thereafter 27,685 1,168 653 455 136 30,097

TOTAL PURCHASE COMMITMENTS $ 38,426 $ 4,659 $ 1,857 $1,561 $ 600 $ 47,103

Third-Party Power Purchase Agreements 

In the ordinary course of business, the Utility enters 

into various agreements, including renewable energy 

agreements, QF agreements, and other power purchase 

agreements to purchase power and electric capacity. The 

price of purchased power may be fixed or variable. Variable 

pricing is generally based on the current market price of 

either natural gas or electricity at the date of delivery.

Renewable Energy Power Purchase Agreements

In order to comply with California’s RPS requirements, 

the Utility is required to deliver renewable energy to its 

customers at a gradually increasing rate. The Utility has 

entered into various agreements to purchase renewable 

energy to help meet California’s requirement. The Utility’s 

obligations under a significant portion of these agreements 

are contingent on the third party’s construction of new 

generation facilities, which are expected to grow. As of 

December 31, 2016, renewable energy contracts expire at 

various dates between 2017 and 2043.

Conventional Energy Power Purchase Agreements

The Utility has entered into many power purchase 

agreements for conventional generation resources, 

which include tolling agreements and resource adequacy 

agreements. The Utility’s obligation under a portion of 

these agreements is contingent on the third parties’ 

development of new generation facilities to provide capacity 

and energy products to the Utility. As of December 31, 

2016, these power purchase agreements expire at various 

dates between 2017 and 2033.

Other Power Purchase Agreements

The Utility has entered into agreements to purchase 

energy and capacity with independent power producers 

that own generation facilities that meet the definition of 

a QF under federal law. Several of these agreements are 

treated as capital leases. At December 31, 2016 and 2015, net 

capital leases reflected in property, plant, and equipment 

on the Consolidated Balance Sheets were $35 million and 

$54 million including accumulated amortization of $148 

million and $147 million, respectively. The present value 

of the future minimum lease payments due under these 

agreements included $17 million and $19 million in Current 

Liabilities and $18 million and $35 million in Noncurrent 

Liabilities on the Consolidated Balance Sheet, respectively. 

As of December 31, 2016, QF contracts in operation expire 

at various dates between 2017 and 2028. In addition, the 

Utility has agreements with various irrigation districts and 

water agencies to purchase hydroelectric power.

The costs incurred for all power purchases and electric 

capacity amounted to $3.5 billion in 2016, $3.5 billion in 

2015, and $3.6 billion in 2014.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Natural Gas Supply, Transportation, and Storage 

Commitments 

The Utility purchases natural gas directly from producers 

and marketers in both Canada and the United States to 

serve its core customers and to fuel its owned-generation 

facilities. The Utility also contracts for natural gas 

transportation from the points at which the Utility takes 

delivery (typically in Canada, the US Rocky Mountain supply 

area, and the southwestern United States) to the points 

at which the Utility’s natural gas transportation system 

begins. These agreements expire at various dates between 

2017 and 2026. In addition, the Utility has contracted for 

natural gas storage services in northern California in order 

to more reliably meet customers’ loads.

Costs incurred for natural gas purchases, natural gas 

transportation services, and natural gas storage, which 

include contracts with terms of less than 1 year, amounted 

to $0.7 billion in 2016, $0.9 billion in 2015, and $1.4 billion 

in 2014.

Nuclear Fuel Agreements 

The Utility has entered into several purchase agreements 

for nuclear fuel. These agreements expire at various dates 

between 2017 and 2025 and are intended to ensure longterm nuclear fuel supply. The Utility relies on a number of 

international producers of nuclear fuel in order to diversify 

its sources and provide security of supply. Pricing terms 

are also diversified, ranging from market-based prices to 

base prices that are escalated using published indices. 

Payments for nuclear fuel amounted to $100 million in 

2016, $128 million in 2015, and $105 million in 2014.

Other Commitments 

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and 

land), which expire at various dates between 2017 and 2052. At December 31, 2016, the future minimum payments 

related to these commitments were as follows: 

(in millions) Operating Leases

2017 $ 44

2018 41

2019 39

2020 39

2021 36

Thereafter 168

TOTAL MINIMUM LEASE PAYMENTS $ 367

Payments for other commitments related to operating 

leases amounted to $43 million in 2016, $41 million in 2015, 

and $42 million in 2014. Certain leases on office facilities 

contain escalation clauses requiring annual increases in 

rent. The rentals payable under these leases may increase 

by a fixed amount each year, a percentage of increase 

over base year, or the consumer price index. Most leases 

contain extension operations ranging between one and 

five years.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

Quarter ended

(in millions, except per share amounts) December 31 September 30 June 30 March 31

2016

PG&E CORPORATION

Operating revenues(1) $ 4,713 $ 4,810 $ 4,169 $ 3,974

Operating income 1,041 640 401 95

Income tax provision (benefit)(2) 160 70 12 (187)

Net income(3) 696 391 210 110

Income available for common shareholders 692 388 206 107

Comprehensive income 694 391 210 110

Net earnings per common share, basic 1.37 0.77 0.41 0.22

Net earnings per common share, diluted 1.36 0.77 0.41 0.22

Common stock price per share:

High 62.12 65.39 63.92 59.72

Low 58.04 60.82 56.62 51.29

UTILITY

Operating revenues(1) $ 4,714 $ 4,809 $ 4,169 $ 3,975

Operating income 1,044 640 401 96

Income tax provision (benefit)(2) 169 73 13 (185)

Net income(3) 696 389 209 108

Income available for common stock 692 386 205 105

Comprehensive income 694 389 210 108

2015

PG&E CORPORATION

Operating revenues $ 4,167 $ 4,550 $ 4,217 $ 3,899

Operating income 205 545 687 71

Income tax (benefit) provision(4) (111) 67 110 (93)

Net income(5) 138 310 406 34

Income available for common shareholders 134 307 402 31

Comprehensive income 137 310 406 17

Net earnings per common share, basic 0.27 0.63 0.84 0.06

Net earnings per common share, diluted 0.27 0.63 0.83 0.06

Common stock price per share:

High 54.50 54.41 54.27 60.15

Low 51.65 47.60 49.10 51.38

UTILITY

Operating revenues $ 4,167 $ 4,550 $ 4,216 $ 3,900

Operating income 208 544 687 72

Income tax (benefit) provision(4) (114) 72 115 (92)

Net income(5) 147 305 406 4

Income available for common stock 143 302 402 1

Comprehensive income 145 305 406 4

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

(1) In the third and fourth quarters of 2016, the Utility recorded an increase in base revenues as authorized by the CPUC in the 

2015 GT&S rate case decision.

(2) In the first quarter of 2016, the Utility had an income tax benefit, primarily due to net loss before income taxes and various 

tax audit results.

(3) In the first, second, and third quarters of 2016, the Utility recorded charges for disallowed capital spending of $87 million, 

$148 million, and $51 million, respectively, as a result of the Penalty Decision. Additionally, in the second and fourth quarters 

of 2016, the Utility recorded charges of $190 million and $29 million for capital expenditures probable of disallowance 

related to the final decision in the 2015 GT&S rate case. Also, in the first quarter of 2016 the Utility recorded a $350 million 

charge related to Butte Fire litigation. In the second quarter of 2016, the Utility recorded $260 million for probable insurance 

recoveries in connection with recovery of losses related to the Butte fire. In the fourth quarter of 2016, the Utility recorded 

a $400 million charge related to the Butte fire litigation and an insurance receivable of $365 million for probable insurance 

recoveries in connection with the Butte fire. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

(4) In the first quarter of 2015, the Utility had an income tax benefit, primarily due to the impact of the Penalty Decision. (See 

footnote (4) below.) In the fourth quarter of 2015, the Utility had an income tax benefit, primarily due to lower income 

before taxes and an audit settlement received. 

(5) In the first quarter of 2015, the Utility recorded total charges of $553 million related to the Penalty Decision, including 

$53 million in estimated capital spending that is probable of disallowance. In the second, third, and fourth quarters of 2015, 

the Utility recorded $75 million, $142 million, and $137 million, respectively, in estimated capital spending that is probable of 

disallowance. (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8.)

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Report on Internal Control Over Financial Reporting

Management of PG&E Corporation and the Utility is responsible for establishing and maintaining adequate internal 

control over financial reporting.  PG&E Corporation’s and the Utility’s internal control over financial reporting is a process 

designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial 

statements for external purposes in accordance with generally accepted accounting principles, or GAAP.  Internal control 

over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, 

in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation 

and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of 

financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance 

with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable 

assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could 

have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, 

projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become 

inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may 

deteriorate.

Management assessed the effectiveness of internal control over financial reporting as of December 31, 2016, based 

on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring 

Organizations of the Treadway Commission.  Based on its assessment and those criteria, management has concluded that 

PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2016.

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s 

internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — 

Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company 

San Francisco, California

We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) 

and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2016, based on criteria 

established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of 

the Treadway Commission. The Company’s and the Utility’s management is responsible for maintaining effective internal 

control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, 

included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is 

to express an opinion on the Company’s and the Utility’s internal control over financial reporting based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board 

(United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about 

whether effective internal control over financial reporting was maintained in all material respects. Our audits included 

obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness 

exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 

and performing such other procedures as we considered necessary in the circumstances. We believe that our audits 

provide a reasonable basis for our opinion. 

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the 

company’s principal executive and principal financial officers, or persons performing similar functions, and effected by 

the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the 

reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 

generally accepted accounting principles. A company’s internal control over financial reporting includes those policies 

and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect 

the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are 

recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting 

principles, and that receipts and expenditures of the company are being made only in accordance with authorizations 

of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely 

detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect 

on the financial statements. 

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or 

improper management override of controls, material misstatements due to error or fraud may not be prevented or 

detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial 

reporting to future periods are subject to the risk that the controls may become inadequate because of changes in 

conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company and the Utility maintained, in all material respects, effective internal control over financial 

reporting as of December 31, 2016, based on the criteria established in Internal Control — Integrated Framework (2013)

issued by the Committee of Sponsoring Organizations of the Treadway Commission. 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United 

States), the consolidated financial statements as of and for the year ended December 31, 2016 of the Company and 

the Utility and our report dated February 16, 2017 expressed an unqualified opinion on those financial statements. 

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 16, 2017

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PART II

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company 

San Francisco, California

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) 

and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2016 and 2015, and the 

Company’s related consolidated statements of income, comprehensive income, equity, and cash flows and the Utility’s 

related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each 

of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the 

Company’s and the Utility’s management. Our responsibility is to express an opinion on these financial statements 

based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United 

States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether 

the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence 

supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting 

principles used and significant estimates made by management, as well as evaluating the overall financial statement 

presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of 

PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31, 

2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended 

December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United 

States), the Company’s and the Utility’s internal control over financial reporting as of December 31, 2016, based on 

the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring 

Organizations of the Treadway Commission and our report dated February 16, 2017 expressed an unqualified opinion 

on the Company’s and the Utility’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 16, 2017

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PART II

ITEM 9B.  OTHER INFORMATION

ITEM 9. Changes in and Disagreements with Accountants on 

Accounting and Financial Disclosure

Not applicable.

ITEM 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, 

2016, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have 

concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E 

Corporation and the Utility in reports that the companies file or submit under the 1934 Act is (i) recorded, processed, 

summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and 

communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s 

respective principal executive officers and principal financial officers, or persons performing similar functions, as 

appropriate to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control over Financial Reporting

Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial 

reporting.  Management’s report, together with the report of the independent registered public accounting firm, 

appears in Item 8 of this 2016 Form 10-K under the heading “Management’s Report on Internal Control Over Financial 

Reporting” and “Report of Independent Registered Public Accounting Firm.”

Registered Public Accounting Firm’s Report on Internal Control over Financial Reporting

Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s 

internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control — 

Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Internal Control Over Financial Reporting

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 

2016 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s 

internal control over financial reporting.

ITEM 9B. Other Information

Not applicable.

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PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Information regarding executive officers of PG&E 

Corporation and the Utility is set forth under “Executive 

Officers of the Registrants” at the end of Part I of this 2016 

Form 10-K. Other information regarding directors will be 

included under the heading “Nominees for Directors of 

PG&E Corporation and Pacific Gas and Electric Company” 

in the Joint Proxy Statement relating to the 2017 Annual 

Meetings of Shareholders, which information is incorporated 

herein by reference. Information regarding compliance with 

Section 16 of the Exchange Act will be included under the 

heading “Section 16(a) Beneficial Ownership Reporting 

Compliance” in the Joint Proxy Statement relating to the 

2017 Annual Meetings of Shareholders, which information 

is incorporated herein by reference.

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on the 

Corporate Governance section of PG&E Corporation’s 

website (www.pgecorp.com/aboutus/corp_gov) and on the 

Utility’s website (www.pge.com/about/company, under the 

Corporate Governance tab): (1) the PG&E Corporation and 

the Utility’s code of conduct (which meets the definition 

of “code of ethics” of Item 406(b) of the SEC Regulation 

S-K) adopted by PG&E Corporation and the Utility and 

applicable to their directors and employees, including 

their respective Chief Executive Officer and Presidents, 

as the case may be, Chief Financial Officers, Controllers 

and other executive officers, (2) PG&E Corporation’s and 

the Utility’s respective corporate governance guidelines, 

and (3) key Board committee charters, including charters 

for the companies’ Audit Committees and the PG&E 

Corporation Nominating and Governance Committee and 

Compensation Committee.

If any amendments are made to, or any waivers are granted 

with respect to, provisions of the code of conduct adopted 

by PG&E Corporation and the Utility and that apply to their 

respective Chief Executive Officer and Presidents, as the 

case may be, Chief Financial Officers, or Controllers, PG&E 

Corporation and the Utility will post the amended code 

of ethics on their websites and will disclose any waivers 

to the code of conduct in a Current Report on Form 8-K.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

Other than as noted below, there were no material changes 

to the procedures described in PG&E Corporation’s and the 

Utility’s Joint Proxy Statement relating to the 2016 Annual 

Meetings of Shareholders by which security holders may 

recommend nominees to PG&E Corporation’s or Pacific 

Gas and Electric Company’s Boards of Directors.

On December 16, 2016, the Boards of Directors of PG&E 

Corporation and the Utility each amended the applicable 

company’s respective Bylaw provisions regarding a 

shareholder’s right to (1) notify the company of the 

shareholder’s intent to introduce director nominees and 

other matters from the floor of the annual meeting of 

shareholders (“floor proposals”) or (2) call a special meeting 

of shareholders at which directors could be nominated 

or other business could be transacted.

In relevant part, PG&E Corporation’s and the Utility’s 

amended Bylaws (1) require that any “advance notice” 

of floor proposals be received between 90 and 120 days 

prior to the anniversary of the prior year’s annual meeting 

(previously, the deadline was 45 days prior to the mailing 

date of the proxy materials for the prior year’s annual 

meeting), (2) expand the information that must be included 

in a shareholder’s “advance notice” of a floor proposal, 

including requiring additional information regarding 

financial interests and intentions of the shareholder, as 

well as additional information relating to any director 

nominees, and (3) result in other procedural clarifications.

The amendments to PG&E Corporation’s Bylaws also 

establish deadlines, information requirements, and other 

processes relating to any PG&E Corporation shareholder’s 

request for a special meeting of the shareholders, including 

meetings at which director nominees will be presented 

for vote.

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PART III

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E 

Corporation and the Utility and the “audit committee 

financial experts” as defined by the SEC will be included 

under the headings “Corporate Governance – Board 

Committee Duties – Audit Committees” and “Corporate 

Governance – Committee Membership, Independence, and 

Qualifications” in the Joint Proxy Statement relating to the 

2017 Annual Meetings of Shareholders, which information 

is incorporated herein by reference.

ITEM 11. Executive Compensation

Information responding to Item 11, for each of PG&E 

Corporation and the Utility, will be included under the 

headings “Compensation Discussion and Analysis,” 

“Compensation Committee Report,” “Summary 

Compensation Table - 2016,” “Grants of Plan-Based 

Awards in 2016,” “Outstanding Equity Awards at Fiscal 

Year End - 2016,” “Option Exercises and Stock Vested 

During 2016,” “Pension Benefits – 2016,” “Non-Qualified 

Deferred Compensation – 2016,” “Potential Payments Upon 

Resignation, Retirement, Termination, Change in Control, 

Death, or Disability” and “Compensation of Non-Employee 

Directors – 2016 Director Compensation” in the Joint 

Proxy Statement relating to the 2017 Annual Meetings of 

Shareholders, which information is incorporated herein 

by reference.

ITEM 12. Security Ownership of Certain Beneficial Owners and

Management and Related Stockholder Matters

Information regarding the beneficial ownership of 

securities for each of PG&E Corporation and the Utility 

will be included under the headings “Share Ownership 

Information – Security Ownership of Management” and 

“Share Ownership Information – Principal Shareholders” 

in the Joint Proxy Statement relating to the 2017 Annual 

Meetings of Shareholders, which information is incorporated 

herein by reference.

Equity Compensation Plan Information 

The following table provides information as of December 31, 2016 concerning shares of PG&E Corporation common 

stock authorized for issuance under PG&E Corporation’s existing equity compensation plans.

(a) (b) (c)

Plan Category

Number of Securities to 

be Issued Upon Exercise 

of Outstanding Options, 

Warrants and Rights

Weighted Average 

Exercise Price of 

Outstanding Options, 

Warrants and Rights

Number of Securities 

Remaining Available for 

Future Issuance Under 

Equity Compensation 

Plans (Excluding Securities 

Reflected in Column (a))

Equity compensation plans 

approved by shareholders

6,962,072(1) $ 35.53(2) 13,826,995(3)

Equity compensation plans not 

approved by shareholders

-- -

Total equity compensation 

plans

6,962,072(1) $ 35.53(2) 13,826,995(3)

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PART III

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

(1) Includes 21,675 phantom stock units, 2,002,357 restricted stock units and 4,933,950 performance shares. The weighted 

average exercise price reported in column (b) does not take these awards into account. For performance shares, amounts 

reflected in this table assume payout in shares at 200% of target or, for performance shares granted in 2014, reflects the 

actual payout percentage of 160%. The actual number of shares issued can range from 0% to 200% of target depending on 

achievement of performance objectives. Also, restricted stock units and performance shares are generally settled in net 

shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, 

taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below 

maximum will be available again for issuance.

(2) This is the weighted average exercise price for the 4,090 options outstanding as of December 31, 2016.

(3) Represents the total number of shares available for issuance under all of PG&E Corporation’s equity compensation plans as 

of December 31, 2016. Stock-based awards granted under these plans include restricted stock units, performance shares 

and phantom stock units. The 2014 LTIP, which became effective on May 12, 2014, authorizes up to 17 million shares to 

be issued pursuant to awards granted under the 2014 LTIP, less approximately 2.7 million shares for awards granted under 

the 2006 LTIP from January 1, 2014 through May 11, 2014. In addition, if any awards outstanding under the 2006 LTIP at 

December 31, 2013 are cancelled, forfeited or expire without being settled in full, shares of stock allocable to the terminated 

portion of such awards shall again be available for issuance under the 2014 LTIP.

For more information, see Note 5 of the Notes to the Consolidated Financial Statements in Item 8.

ITEM 13. Certain Relationships and Related Transactions, 

and Director Independence

Information responding to Item 13, for each of PG&E Corporation and the Utility, will be included under the headings 

“Related Party Transactions” and “Corporate Governance – Board and Director General Independence and Qualifications” 

and “Corporate Governance – Committee Membership, Independence, and Qualifications” in the Joint Proxy Statement 

relating to the 2017 Annual Meetings of Shareholders, which information is incorporated herein by reference.

ITEM 14. Principal Accountant Fees and Services

Information responding to Item 14, for each of PG&E Corporation and the Utility, will be included under the heading 

“Information Regarding the Independent Auditor for PG&E Corporation and Pacific Gas and Electric Company” in 

the Joint Proxy Statement relating to the 2017 Annual Meetings of Shareholders, which information is incorporated 

herein by reference.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PART IV

ITEM 15. Exhibits and Financial Statement Schedules

a. The following documents are filed as a part of this report: 

1. The following consolidated financial statements, supplemental information and report of independent registered 

public accounting firm are filed as part of this report in Item 8:

đ Consolidated Statements of Income for the Years Ended December 31, 2016, 2015, and 2014 for each of PG&E 

Corporation and Pacific Gas and Electric Company.

đ Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2016, 2015, and 2014 for 

each of PG&E Corporation and Pacific Gas and Electric Company.

đ Consolidated Balance Sheets at December 31, 2016 and 2015 for each of PG&E Corporation and Pacific Gas and 

Electric Company.

đ Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015, and 2014 for each of PG&E 

Corporation and Pacific Gas and Electric Company.

đ Consolidated Statements of Equity for the Years Ended December 31, 2016, 2015, and 2014 for PG&E Corporation.

đ Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2016, 2015, and 2014 for 

Pacific Gas and Electric Company.

đ Notes to the Consolidated Financial Statements.

đ Quarterly Consolidated Financial Data (Unaudited).

đ Management’s Report on Internal Controls 

đ Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

2. The following financial statement schedules are filed as part of this report: 

đ Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

đ I—Condensed Financial Information of Parent as of December 31, 2016 and 2015 and for the Years Ended December 31, 

2016, 2015, and 2014.

đ II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric 

Company for the Years Ended December 31, 2016, 2015, and 2014.

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PART IV

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

3. Exhibits required by Item 601 of Regulation S-K 

Exhibit 

Number Exhibit Description

3.1 Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by 

reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), 

Exhibit 3.1)

3.2 Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 

(incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 

(File No. 1-12609), Exhibit 3.2)

3.3 Bylaws of PG&E Corporation amended as of December 16, 2016 

3.4 Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 

(incorporated by reference to Pacific Gas and Electric Company's Form 8-K dated April 12, 2004 

(File No. 1-2348), Exhibit 3)

3.5 Bylaws of Pacific Gas and Electric Company amended as of December 16, 2016 

4.1 Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, 

dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 

2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric 

Company and The Bank of New York Trust Company, N.A. (incorporated by reference to Pacific Gas and 

Electric Company's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-2348), Exhibit 4.1)

4.2 First Supplemental Indenture, dated as of March 13, 2007, relating to the issuance of $700,000,000 

principal amount of Pacific Gas and Electric Company’s 5.80% Senior Notes due March 1, 2037 

(incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 

(File No. 1-2348), Exhibit 4.1)

4.3 Second Supplemental Indenture, dated as of December 4, 2007, relating to the issuance of $500,000,000 

principal amount of Pacific Gas and Electric Company’s 5.625% Senior Notes due November 30, 2017 

(incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 

(File No. 1-2348), Exhibit 4.1)

4.4 Third Supplemental Indenture, dated as of March 3, 2008, relating to the issuance of $200,000,000 Pacific 

Gas and Electric Company’s 5.625% Senior Notes due November 30, 2017 and $400,000,000 of its 6.35% 

Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s 

Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)

4.5 Fourth Supplemental Indenture, dated as of October 21, 2008, relating to the issuance of $600,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 8.25% Senior Notes due October 15, 

2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 

(File No. 1-2348), Exhibit 4.1)

4.6 Fifth Supplemental Indenture, dated as of November 18, 2008, relating to the issuance of $400,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due December 1, 

2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by 

reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), 

Exhibit 4.1)

4.7 Sixth Supplemental Indenture, dated as of March 6, 2009, relating to the issuance of $550,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 

2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 

(File No. 1-2348), Exhibit 4.1)

4.8 Seventh Supplemental Indenture, dated as of June 11, 2009 (incorporated by reference to Pacific Gas and 

Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1)

4.9 Eighth Supplemental Indenture, dated as of November 18, 2009, relating to the issuance of $550,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 

(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 

(File No. 1-2348), Exhibit 4.1)

4.10 Ninth Supplemental Indenture, dated as of April 1, 2010, relating to the issuance of $250,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and 

$250,000,000 aggregate principal amount of its Senior Notes due March 1, 2037 (incorporated by reference 

to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

4.11 Tenth Supplemental Indenture, dated as of September 15, 2010, relating to the issuance of $550,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 

2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 

2010 (File No. 1-2348), Exhibit 4.1)

4.12 Twelfth Supplemental Indenture, dated as of November 18, 2010, relating to the issuance of $250,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 

2020 and $250,000,000 aggregate principal amount of its 5.40% Senior Notes due January 15, 2040 

(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 

(File No. 1-2348), Exhibit 4.1)

4.13 Thirteenth Supplemental Indenture, dated as of May 13, 2011, relating to the issuance of $300,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 

2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 

(File No. 1-2348), Exhibit 4.1)

4.14 Fourteenth Supplemental Indenture, dated as of September 12, 2011, relating to the issuance of 

$250,000,000 aggregate principal amount of Pacific Gas and Electric Company's 3.25% Senior Notes due 

September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated 

September 12, 2011 (File No. 1-2348), Exhibit 4.1)

4.15 Sixteenth Supplemental Indenture, dated as of December 1, 2011, relating to the issuance of $250,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 

2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 

(File No. 1-2348), Exhibit 4.1)

4.16 Seventeenth Supplemental Indenture, dated as of April 16, 2012, relating to the issuance of $400,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 

2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 

(File No. 1-2348), Exhibit 4.1)

4.17 Eighteenth Supplemental Indenture, dated as of August 16, 2012, relating to the issuance of $400,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 

2022 and $350,000,000 aggregate principal amount of its 3.75% Senior Notes due August 15, 2042 

(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 

(File No. 1-2348), Exhibit 4.1)

4.18 Nineteenth Supplemental Indenture, dated as of June 14, 2013, relating to the issuance of $375,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 

and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by 

reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)

4.19 Twentieth Supplemental Indenture, dated as of November 12, 2013, relating to the issuance of 

$300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes 

due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due 

November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated 

November 12, 2013 (File No. 1-2348), Exhibit 4.1)

4.20 Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of 

$450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due 

February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 

15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 

2014 (File No.1 2348), Exhibit 4.1)

4.21 Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of 

$350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due 

August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 

2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 

(File No. 1-2348), Exhibit 4.1)

4.22 Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of 

$500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes 

due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated 

November 6, 2014 (File No. 1-2348), Exhibit 4.1)

4.23 Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 

aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 

and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by 

reference to Pacific Gas and Electric Company’s Form 8-K dated June 12, 2015 (File No. 1-2348), Exhibit 4.1)

Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

4.24 Twenty-Sixth Supplemental Indenture, dated as of November 5, 2015, relating to the issuance of 

$200,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due 

June 15, 2025 and $450,000,000 aggregate principal amount of its 4.25% Senior Notes due March 15, 2046 

(incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 5, 2015 

(File No. 1-2348), Exhibit 4.1)

4.25 Twenty-Seventh Supplemental Indenture, dated as of March 1, 2016, relating to the issuance of 

$600,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.95% Senior Notes 

due March 1, 2026 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated 

March 1, 2016 (File No. 1-2348), Exhibit 4.1)

4.26 Twenty-Eighth Supplemental Indenture, dated as of December 1, 2016, relating to the issuance of 

$250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior 

Notes due November 30, 2017 and $400,000,000 aggregate principal amount of its 4.00% Senior Notes 

due December 1, 2046 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated 

December 1, 2016 (File No. 1-2348), Exhibit 4.1)

4.27 Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National 

Association (incorporated by reference to PG&E Corporation’s Form S-3 (File No. 333-193880), Exhibit 4.1)

4.28 First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 

aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by 

reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)

10.1 Second Amended and Restated Credit Agreement, dated as of April 27, 2015, among (1) PG&E 

Corporation, as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) Merrill 

Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and 

Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan 

Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association, as 

documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, 

Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank 

of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank, National 

Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York 

Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s 

Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)

10.2 Second Amended and Restated Credit Agreement dated as of April 27, 2015, among (1) Pacific Gas 

and Electric Company, as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill 

Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, 

and Wells Fargo Securities LLC, as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. 

and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National 

Association, as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, 

BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, 

Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank 

National Association, MUFG Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New 

York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and 

Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)

10.3 Term Loan Agreement, dated as of March 2, 2016, between Pacific Gas and Electric Company and The 

Bank of Tokyo-Mitsubishi UFJ, Ltd. (incorporated by reference to Pacific Gas and Electric Company’s Form 

8-K dated March 2, 2016 (File No. 1-2348), Exhibit 10.1)

10.4 Settlement Agreement among the California Public Utilities Commission, Pacific Gas and Electric Company 

and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by 

reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K dated December 22, 

2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99) 

10.5 Transmission Control Agreement among the California Independent System Operator (CAISO) and 

the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of 

March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E 

Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 

(File No. 1-12609 and File No. 1-2348), Exhibit 10.8)

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

10.6 * Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated 

August 8, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended 

September 30, 2011 (File No. 1-12609), Exhibit 10.1)

10.7 * Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2016 grant 

under the PG&E Corporation 2014 Long-Term Incentive Plan 

10.8 * Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2015 grant 

under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.7) 

10.9 * Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant 

under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.4) 

10.10 * Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant 

under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.5)

10.11 * Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant 

under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.3)

10.12 * Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E 

Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

10.13 * Performance Share Agreement subject to financial goals between Anthony F. Earley, Jr. and PG&E 

Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated 

by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), 

Exhibit 10.8) 

10.14 * Performance Share Agreement subject to safety and customer affordability goals between Anthony 

F. Earley, Jr. and PG&E Corporation for 2016 grant under the PG&E Corporation 2014 Long-Term 

Incentive Plan

10.15 * Performance Share Agreement subject to safety and customer affordability goals between Anthony F. 

Earley, Jr. and PG&E Corporation for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive 

Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2015 

(File No. 1-12609), Exhibit 10.9) 

10.16 * Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant under 

the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's 

Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.5)

 10.17 * Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under 

the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's 

Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.6)

10.18 * Restricted Stock Unit Agreement between Nickolas Stavropoulos and PG&E Corporation for additional 

2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to 

PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 

2015 (File No. 1-2609 and File No. 1-2348), Exhibit 10.16)

10.19 * Restricted Stock Unit Agreement between Geisha J. Williams and PG&E Corporation for additional 2015 

grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 

(File No. 1-2609 and File No. 1-2348), Exhibit 10.17)

10.20 * Restricted Stock Unit Agreement between John R. Simon and PG&E Corporation for additional 2015 

grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2015 

(File No. 1-2609 and File No. 1-2348), Exhibit 10.18)

10.21 * Letter regarding Compensation Agreement between PG&E Corporation and Julie M. Kane dated March 11, 

2015 for employment starting May 18, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q 

for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.4)

10.22 * Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 

2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to 

PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 (File No. 1-2348), Exhibit 10.5)

Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

10.23 * Non-Annual Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 

2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 

(File No. 1-2348), Exhibit 10.6)

10.24 * Performance Share Agreement subject to financial goals between Julie M. Kane and PG&E Corporation 

dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan 

(incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2015 

(File No. 1-2348), Exhibit 10.7)

10.25 * Performance Share Agreement subject to safety and customer affordability goals between Julie M. Kane 

and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 

30, 2015 (File No. 1-2348), Exhibit 10.8)

10.26 * Restricted Stock Unit Agreement between Dinyar Mistry and PG&E Corporation dated February 23, 2016 

(incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for 

the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.27 * Separation agreement between Pacific Gas and Electric Company and Greg Kiraly dated February 18, 

2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q 

for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), Exhibit 10.3)

10.28 * Letter regarding Compensation Agreement between Pacific Gas and Electric Company and David 

Thomason dated May 24, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas 

and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and 

File No. 1-2348), Exhibit 10.2)

10.29 * Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason 

dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric 

Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and File No. 1-2348), 

Exhibit 10.1)

10.30 * Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E 

Corporation dated August 8, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas 

and Electric Company's Form 10-Q for the quarter ended September 30, 2016 (File No. 1-12609 and 

File No. 1-2348), Exhibit 10.2)

10.31 * Performance Share Award Agreement subject to safety and customer affordability goals between 

David S. Thomason and PG&E Corporation dated August 8, 2016 (incorporated by reference to PG&E 

Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended September 30, 2016 

(File No. 1-12609 and File No. 1-2348), Exhibit 10.3)

10.32 * Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and Edward D. Halpin 

dated November 28, 2016

10.33 * Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. 

dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the 

quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2)

10.34 * Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. 

Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific 

Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21)

10.35 * PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, 

and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the 

year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)

10.36 * PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 15, 2015 

(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 

(File No. 1-12609), Exhibit 10.3)

10.37 * PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of 

January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective 

as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended 

December 31, 2008 (File No. 1-12609), Exhibit 10.24)

10.38 * PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated 

effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter 

ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)

Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

10.39 * Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective 

January 1, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s 

Form 8-K dated February 16, 2016 (File No. 1-12609 and File No. 1-2348)

10.40 * Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective 

January 1, 2015 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended 

March 31, 2015 (File No. 1-12609), Exhibit 10.3)

10.41 * Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective 

January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) 

(incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 

(File No. 1-12609), Exhibit 10.27)

10.42 * Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus 

Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A 

regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year 

ended December 31, 2008 (File No. 1-2348), Exhibit 10.28) 

10.43 * PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013 

(incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 

(File No. 1-12609, Exhibit 10.31)

10.44 * PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective 

September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended 

September 30, 2013 (File No. 1-12609), Exhibit 10.2)

10.45 * Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference 

to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended 

December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.38)

10.46 * Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective 

February 16, 2016 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric 

Company's Form 10-Q for the quarter ended March 31, 2016 (File No. 1-12609 and File No. 1-2348), 

Exhibit 10.4)

10.47 * Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective 

February 6, 2015 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended 

December 31, 2014) (File No. 1-12609), Exhibit 10.37)

10.48 * Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, as amended and restated on 

February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the 

quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)

10.49 * PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation 

Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to 

PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 

2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)

10.50 * PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 

1, 2016 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 

10-K for the year ended December 31, 2015 (File No. 1-12609 and File No. 1-2348), Exhibit 10.42)

10.51 * PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013 (incorporated 

by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2012 (File No. 1-12609), 

Exhibit 10.40)

10.52 * PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and 

Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's 

Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)

10.53 * Form of Restricted Stock Unit Agreement for 2016 grants to non-employee directors under the PG&E 

Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation and Pacific 

Gas and Electric Company's Form 10-Q for the quarter ended June 30, 2016 (File No. 1-12609 and 

File No. 1-2348), Exhibit 10.1)

10.54 * Form of Restricted Stock Unit Agreement for 2015 grants to non-employee directors under the PG&E 

Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q 

for the quarter ended June 30, 2015 (File No. 1-12609), Exhibit 10.3)

10.55 * Form of Restricted Stock Unit Agreement for 2016 grants under the PG&E Corporation 2014 Long-Term 

Incentive Plan

Case: 19-30088 Doc# 2306-2 Filed: 05/31/19 Entered: 05/31/19 13:27:55 Page

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

10.56 * Form of Restricted Stock Unit Agreement for 2015 grants under the PG&E Corporation 2014 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 

2015 (File No. 1-12609), Exhibit 10.4)

10.57 * Form of Restricted Stock Unit Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 

2014 (File No. 1-12609), Exhibit 10.2)

10.58 * Form of Restricted Stock Unit Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 

2013 (File No. 1-12609), Exhibit 10.3)

10.59 * Form of Restricted Stock Unit Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 

2012 (File No. 1-12609), Exhibit 10.1)

10.60 * Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive 

Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 

8-K dated January 6, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99.1)

10.61 * Form of Performance Share Agreement subject to financial goals for 2016 grants under the PG&E 

Corporation 2014 Long-Term Incentive Plan 

10.62 * Form of Performance Share Agreement subject to financial goals for 2015 grants under the PG&E 

Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q 

for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.5)

10.63 * Form of Performance Share Agreement subject to safety and customer affordability goals for 2016 grants 

under the PG&E Corporation 2014 Long-Term Incentive Plan 

10.64 * Form of Performance Share Agreement subject to safety and customer affordability goals for 2015 

grants under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E 

Corporation's Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.6)

10.65 * Form of Performance Share Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 

2014 (File No. 1-12609), Exhibit 10.3)

10.66 * Form of Performance Share Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term 

Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended 

March 31, 2013 (File No. 1-12609), Exhibit 10.4)

10.67 * PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective 

January 1, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended 

September 30, 2010 (File No. 1-12609), Exhibit 10.3)

10.68 * PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 

2010 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 

2010 (File No. 1-12609), Exhibit 10.2)

10.69 * PG&E Corporation 2012 Officer Severance Policy, as amended effective as of May 12, 2014 (incorporated 

by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No. 1-12609), 

Exhibit 10.2)

10.70 * PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated 

by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), 

Exhibit 10.49)

10.71 * Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 

(amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference 

to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)

10.72 * Amended and Restated PG&E Corporation Director Grantor Trust Agreement dated October 1, 2015 

(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 

(File No. 1-12609), Exhibit 10.1) 

10.73 * Amended and Restated PG&E Corporation Officer Grantor Trust Agreement dated October 1, 2015 

(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2015 

(File No. 1-12609), Exhibit 10.2)

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Exhibit 

Number Exhibit Description

10.74 * PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment 

Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation's Form 10-K for 

the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)

10.75 * Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and 

directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the 

year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)

10.76 * Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification 

of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric 

Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)

12.1 Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company

12.2 Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific 

Gas and Electric Company

12.3 Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

21 Subsidiaries of the Registrant

23 Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)

24 Powers of Attorney

31.1 Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required 

by Section 302 of the Sarbanes-Oxley Act of 2002

31.2 Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric 

Company required by Section 302 of the Sarbanes-Oxley Act of 2002

32.1 ** Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required 

by Section 906 of the Sarbanes-Oxley Act of 2002

32.2 ** Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric 

Company required by Section 906 of the Sarbanes-Oxley Act of 2002

101.INS XBRL Instance Document

101.SCH XBRL Taxonomy Extension Schema Document

101.CAL XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB XBRL Taxonomy Extension Labels Linkbase Document

101.PRE XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF XBRL Taxonomy Extension Definition Linkbase Document

*Management contract or compensatory agreement.

**  Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly 

caused this Annual Report on Form 10-K for the year ended December 31, 2016 to be signed on their behalf by the 

undersigned, thereunto duly authorized.

PG&E CORPORATION PACIFIC GAS AND ELECTRIC COMPANY

 (Registrant) (Registrant)

ANTHONY F. EARLEY, JR. NICKOLAS STAVROPOULOS

Anthony F. Earley, Jr. Nickolas Stavropoulos

   

By: Chairman of the Board, Chief Executive Officer, and President By: President, Gas

Date: February 16, 2017 Date: February 16, 2017

    GEISHA J. WILLIAMS

    Geisha J. Williams

    By: President, Electric

    Date: February 16, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following 

persons on behalf of the registrants and in the capacities and on the dates indicated.

Signature Title Date

A. PRINCIPAL EXECUTIVE OFFICERS

ANTHONY F. EARLEY, JR. Chairman of the Board, Chief Executive Officer, and 

President (PG&E Corporation) February 16, 2017 Anthony F. Earley, Jr.

NICKOLAS STAVROPOULOS

President, Gas (Pacific Gas and Electric Company) February 16, 2017 Nickolas Stavropoulos

GEISHA J. WILLIAMS President, Electric (Pacific Gas and Electric Company) February 16, 2017 Geisha J. Williams

B. PRINCIPAL FINANCIAL OFFICERS

JASON P. WELLS Senior Vice President and Chief Financial Officer 

(PG&E Corporation) February 16, 2017 Jason P. Wells

DAVID S. THOMASON Vice President, Chief Financial Officer, and Controller 

David S. Thomason (Pacific Gas and Electric Company) February 16, 2017

C. PRINCIPAL ACCOUNTING OFFICER

DAVID S. THOMASON Vice President and Controller (PG&E Corporation)

Vice President, Chief Financial Officer, and Controller

(Pacific Gas and Electric Company)

David S. Thomason February 16, 2017

D. DIRECTORS

* LEWIS CHEW

Director February 16, 2017 Lewis Chew

* ANTHONY F. EARLEY, JR.

Director February 16, 2017 Anthony F. Earley, Jr.

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Signature Title Date

* FRED J. FOWLER

Director February 16, 2017 Fred J. Fowler

* MARYELLEN C. HERRINGER

Director February 16, 2017 Maryellen C. Herringer

* RICHARD C. KELLY

Director February 16, 2017 Richard C. Kelly

* ROGER H. KIMMEL

Director February 16, 2017 Roger H. Kimmel

* RICHARD A. MESERVE

Director February 16, 2017 Richard A. Meserve

* FORREST E. MILLER

Director February 16, 2017 Forrest E. Miller

* ERIC D. MULLINS

Director February 16, 2017 Eric D. Mullins

* ROSENDO G. PARRA

Director February 16, 2017 Rosendo G. Parra

* BARBARA L. RAMBO

Director February 16, 2017 Barbara L. Rambo

* ANNE SHEN SMITH

Director February 16, 2017 Anne Shen Smith

* NICKOLAS STAVROPOULOS

Director (Pacific Gas and Electric Company only) February 16, 2017 Nickolas Stavropoulos

* BARRY LAWSON WILLIAMS

Director February 16, 2017 Barry Lawson Williams

* GEISHA J. WILLIAMS

Director (Pacific Gas and Electric Company only) February 16, 2017 Geisha J. Williams

*By: HYUN PARK

HYUN PARK, Attorney-in-Fact

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of PG&E Corporation and Pacific Gas and Electric Company 

San Francisco, California 

We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the “Company”) and 

Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2016 and 2015, and for each of the 

three years in the period ended December 31, 2016, and the Company’s and the Utility’s internal control over financial 

reporting as of December 31, 2016, and have issued our reports thereon dated February 16, 2017; such consolidated 

financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated 

financial statement schedules of the Company and the Utility listed in Item 15. These consolidated financial statement 

schedules are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an 

opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in 

relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the 

information set forth therein.

/s/ DELOITTE & TOUCHE LLP

San Francisco, California

February 16, 2017

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PG&E CORPORATION 

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT 

CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Years Ended December 31,

(in millions, except per share amounts) 2016 2015 2014

Administrative service revenue $ 70 $ 51 $ 51

Operating expenses (73) (53) (53)

Interest income 1 1 1

Interest expense (10) (10) (14)

Other income (expense) 2 30 (1)

Equity in earnings of subsidiaries 1,388 852 1,413

Income before income taxes 1,378 871 1,397

Income tax benefit 15 3 39

Net income $1,393 $ 874 $1,436

Other Comprehensive Income 

Pension and other postretirement benefit plans obligations 

(net of taxes of $1, $0, and $10, at respective dates) 

$ (2) $ (1) $ (14)

Net change in investments (net of taxes of $0, $12, and $17, 

at respective dates)

 - (17) (25)

Total other comprehensive income (loss) (2) (18) (39)

Comprehensive Income $1,391 $ 856 $1,397

Weighted Average Common Shares Outstanding, Basic 499 484 468

Weighted Average Common Shares Outstanding, Diluted 501 487 470

Net earnings per common share, basic $ 2.79 $1.81 $ 3.07

Net earnings per common share, diluted $ 2.78 $1.79 $ 3.06

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PG&E CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED BALANCE SHEETS

Balance at December 31,

(in millions) 2016 2015 

ASSETS 

Current Assets 

Cash and cash equivalents $ 106 $ 64

Advances to affiliates 24 22

Income taxes receivable 25 24

Other - 1

Total current assets 155 111

Noncurrent Assets 

Equipment 2 2

Accumulated depreciation (2) (2)

Net equipment - -

Investments in subsidiaries 18,172 16,837

Other investments 133 130

Deferred income taxes 267 250

Total noncurrent assets 18,572 17,217

TOTAL ASSETS $ 18,727 $ 17,328

LIABILITIES AND SHAREHOLDERS’ EQUITY 

Current Liabilities 

Accounts payable – other 7 3

Other 274 246

Total current liabilities 281 249

Noncurrent Liabilities 

Long-term debt 348 348

Other 158 155

Total noncurrent liabilities 506 503

Common Shareholders’ Equity 

Common stock 12,198 11,282

Reinvested earnings 5,751 5,301

Accumulated other comprehensive income (loss) (9) (7)

Total common shareholders’ equity 17,940 16,576

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 18,727 $ 17,328

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PG&E CORPORATION 

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued) 

CONDENSED STATEMENTS OF CASH FLOWS

Year ended December 31,

(in millions) 2016 2015 2014

Cash Flows from Operating Activities: 

Net income $ 1,393 $ 874 $ 1,436

 Adjustments to reconcile net income to net cash provided by 

operating activities:

Stock-based compensation amortization 74 66 65

Equity in earnings of subsidiaries (1,388) (852) (1,413)

Deferred income taxes and tax credits-net 11 10 (72)

Noncurrent income taxes receivable/payable - - 5

Current income taxes receivable/payable (1) 5 (16) 

Other (24) (70) 43

Net cash provided by operating activities 65 33 48

Cash Flows From Investing Activities: 

Investment in subsidiaries (835) (705) (978)

Dividends received from subsidiaries(1) 911 716 716

Proceeds from tax equity investments - - 368

Net cash provided by (used in) investing activities 76 11 106

Cash Flows From Financing Activities: 

Borrowings (repayments) under revolving credit facilities - - (260)

 Proceeds from issuance of long-term debt, net of discount and 

issuance costs of $3

- - 347

Repayments of long-term debt - - (350)

Common stock issued 822 780 802

Common stock dividends paid(2) (921) (856) (828)

Net cash provided by (used in) financing activities (99) (76) (289) 

Net change in cash and cash equivalents 42 (32) (135) 

Cash and cash equivalents at January 1 64 96 231

Cash and cash equivalents at December 31 $ 106 $ 64 $ 96

Supplemental disclosure of cash flow information 

Cash received (paid) for: 

Interest, net of amounts capitalized $ (9) $ (9) $ (15)

Income taxes, net (13) - 1

Supplemental disclosure of noncash investing and financing activities 

Noncash common stock issuances $ 20 $ 21 $ 21

Common stock dividends declared but not yet paid 248 224 217

(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries as an 

investing cash flow.

(2) In January of 2016, PG&E Corporation paid a quarterly common stock dividend of $0.455 per share.

 In April, July and October of 2016, respectively, PG&E Corporation paid quarterly common stock dividends of $0.49 per share. 

 In January, April, July, and October of 2015 and 2014, respectively, PG&E Corporation paid quarterly common stock 

dividends of $0.455 per share.

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 

For the Years Ended December 31, 2016, 2015, and 2014

(in millions) Additions

Description

Balance at 

Beginning of 

Period 

Charged to 

Costs and 

Expenses 

Charged 

to Other 

Accounts Deductions(2)

Balance 

at End of 

Period

Valuation and qualifying 

accounts deducted from 

assets:

 

2016: 

 Allowance for 

uncollectible accounts(1)

$ 54 $ 50 $ - $ 46 $ 58

2015: 

Allowance for 

uncollectible accounts(1)

$ 66 $ 43 $ - $ 55 $ 54

2014: 

Allowance for 

uncollectible accounts(1)

$ 80 $ 41 $ - $ 55 $ 66

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

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ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Pacific Gas and Electric Company 

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS 

For the Years Ended December 31, 2016, 2015, and 2014

(in millions) Additions

Description

Balance at 

Beginning of 

Period 

Charged to 

Costs and 

Expenses 

Charged 

to Other 

Accounts Deductions(2)

Balance 

at End of 

Period

Valuation and qualifying 

accounts deducted from 

assets:

 

2016: 

Allowance for 

uncollectible accounts(1)

$ 54 $ 50 $ - $ 46 $ 58

2015: 

Allowance for 

uncollectible accounts(1)

$ 66 $ 43 $ - $ 55 $ 54

2014: 

Allowance for 

uncollectible accounts(1)

$ 80 $ 41 $ - $ 55 $ 66

(1) Allowance for uncollectible accounts is deducted from “Accounts receivable - Customers.”

(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.

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Boards of Directors of PG&E Corporation and Pacific Gas 

and Electric Company

LEWIS CHEW

Executive Vice President and Chief Financial Officer of 

Dolby Laboratories, Inc.

ANTHONY F. EARLEY, JR.

Executive Chair of the Board of PG&E Corporation

FRED J. FOWLER

Retired Chairman of the Board of Spectra Energy 

Partners, LP

MARYELLEN C. HERRINGER

Retired Executive Vice President, General Counsel, 

and Secretary of APL Limited

RICHARD C. KELLY

Retired Chairman and Chief Executive Officer of 

Xcel Energy Inc.

ROGER H. KIMMEL

Vice Chairman of Rothschild Inc.

RICHARD A. MESERVE

President Emeritus, Carnegie Institution of Washington

FORREST E. MILLER

Retired Group President-Corporate Strategy and 

Development of AT&T Inc.

ERIC D. MULLINS

Managing Director and Co-Chief Executive Officer of 

Lime Rock Resources, L.P.

ROSENDO G. PARRA

Retired executive of Dell Inc. and Co-Founder and 

Partner of Daylight Partners

BARBARA L. RAMBO

Chief Executive Officer of Taconic Management Services

ANNE SHEN SMITH

Retired Chairman and Chief Executive Officer of 

Southern California Gas Company

NICKOLAS STAVROPOULOS(1)

President and Chief Operating Officer of 

Pacific Gas and Electric Company

BARRY LAWSON WILLIAMS(2)

Retired Managing General Partner and 

President of Williams Pacific Ventures, Inc.

GEISHA J. WILLIAMS(1)

Chief Executive Officer and President of 

PG&E Corporation 

(1) Nickolas Stavropoulos and Geisha J. Williams are directors of Pacific Gas and Electric Company only.

(2) Barry Lawson Williams is the lead director of PG&E Corporation and the non-executive Chairman of the Board of Pacific Gas and 

Electric Company.

PG&E Corporation Officers

ANTHONY F. EARLEY, JR.

Executive Chair of the Board

GEISHA J. WILLIAMS

Chief Executive Officer and President

JOHN R. SIMON

Executive Vice President and General Counsel

JULIE M. KANE

Senior Vice President, Chief Ethics and Compliance 

Officer, and Deputy General Counsel

STEVEN E. MALNIGHT

Senior Vice President, Strategy and Policy

DINYAR B. MISTRY

Senior Vice President, Human Resources and 

Chief Diversity Officer

HYUN PARK

Senior Vice President and Special Counsel to 

the Chairman

JASON P. WELLS

Senior Vice President and Chief Financial Officer

MALLIKARJUN ANGALAKUDATI

Vice President, Corporate Strategy

NICHOLAS M. BIJUR

Vice President and Treasurer

STEPHEN J. CAIRNS

Vice President, Internal Audit and Chief Risk Officer

MARK T. CARON

Vice President, Tax

LINDA Y.H. CHENG

Vice President, Corporate Governance and 

Corporate Secretary

MELISSA A. LAVINSON

Vice President, Federal Affairs and Policy and 

Chief Sustainability Officer

DAVID S. THOMASON

Vice President and Controller

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Pacific Gas and Electric Company Officers

BARRY LAWSON WILLIAMS

Non-executive Chairman of the Board

NICKOLAS STAVROPOULOS

President and Chief Operating Officer

KAREN A. AUSTIN

Senior Vice President and Chief Information Officer

LORAINE M. GIAMMONA

Senior Vice President and Chief Customer Officer

EDWARD D. HALPIN

Senior Vice President, Generation and Chief Nuclear Officer

PATRICK M. HOGAN

Senior Vice President, Electric Operations

JULIE M. KANE

Senior Vice President, Chief Ethics and Compliance 

Officer, and Deputy General Counsel

STEVEN E. MALNIGHT

Senior Vice President, Strategy and Policy

DINYAR B. MISTRY

Senior Vice President, Human Resources and 

Chief Diversity Officer

JESUS SOTO, JR.

Senior Vice President, Gas Operations

FONG WAN

Senior Vice President, Energy Policy and Procurement

DEBORAH T. AFFONSA

Vice President, Customer Service

BARRY D. ANDERSON

Vice President, Electric Distribution

WILLIAM D. ARNDT

Vice President, Electric Business and 

Performance Management

VALERIE J. BELL

Vice President, Information Technology Operations

NICHOLAS M. BIJUR

Vice President and Treasurer

STEPHEN J. CAIRNS

Vice President, Internal Audit and Chief Risk Officer

MARK T. CARON

Vice President, Tax

LINDA Y.H. CHENG

Vice President, Corporate Governance and 

Corporate Secretary

BERNARD A. COWENS

Vice President and Chief Security Officer

KEVIN J. DASSO

Vice President, Electric Asset Management

TIMOTHY FITZPATRICK

Vice President, Corporate Relations and 

Chief Communications Officer

JON A. FRANKE

Vice President, Generation Technical Services

DEANN HAPNER

Vice President, FERC and ISO Relations

JOHN C. HIGGINS

Vice President, Safety and Health

AARON J. JOHNSON

Vice President, Customer Energy Solutions

KATHLEEN B. KAY

Vice President, Business Technology

ROBERT S. KENNEY

Vice President, Regulatory Affairs

MARY K. KING

Vice President, Human Resources

TRAVIS T. KIYOTA

Vice President, California External Affairs

ROY M. KUGA

Vice President, Grid Integration and Innovation

GREGG L. LEMLER

Vice President, Electric Transmission Operations

JANET C. LODUCA

Vice President and Deputy General Counsel

SCOTT T. SANFORD

Vice President, Customer Operations

GUN S. SHIM

Vice President, Supply Chain Management

SUMEET SINGH

Vice President, Gas Asset and Risk Management

DAVID S. THOMASON

Vice President, Chief Financial Officer, and Controller

ROLANDO I. TREVINO

Vice President, Gas Engineering and Design

JAMES M. WELSCH

Vice President, Nuclear Generation

ANDREW K. WILLIAMS

Vice President, Land and Environmental Management

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Shareholder Information

For financial and other information about PG&E Corporation and Pacific Gas and Electric Company, please visit 

our websites, www.pgecorp.com and www.pge.com, respectively. PG&E Corporation is the holder of all issued and 

outstanding shares of Pacific Gas and Electric Company common stock.

If you have questions about your PG&E Corporation common stock account or Pacific Gas and Electric Company 

preferred stock account, please contact our transfer agent, Wells Fargo Shareowner Services (“WFSS”).

Wells Fargo Shareowner Services

P. O. Box 64874

St. Paul, MN 55164-0874

Toll-free telephone services: 1-888-489-4689 (Representatives are available from 7:00 a.m. CT to 7:00 p.m. CT) 

Website: www.shareowneronline.com

PG&E Corporation Dividend Reinvestment and Stock Purchase Plan (“DRSPP”)

If you hold PG&E Corporation or Pacific Gas and Electric Company stock in your own name, rather than through a 

broker, you may automatically reinvest dividend payments from common and/or preferred stock in shares of PG&E 

Corporation common stock through the DRSPP. You may obtain a DRSPP prospectus and enroll by contacting WFSS.

Replacement of Dividend Checks

If you hold stock in your own name and you do not receive your dividend check within 10 days after the payment 

date, or if a check is lost or destroyed, you should notify WFSS so that payment can be stopped on the check and a 

replacement can be mailed.

Lost or Stolen Stock Certificates

If you hold stock in your own name and your stock certificate has been lost, stolen, or in some way destroyed, you 

should immediately notify WFSS.

Stock Held in Brokerage Accounts (“Street Name”)

When you purchase your stock and it is held for you by your broker, the shares are listed with WFSS in the broker’s 

name, or street name. WFSS does not know the identity of the individual shareholders who hold their shares in 

this manner. If you hold your stock in a street name account, you receive all tax forms, publications, and proxy 

materials through your broker. If you are receiving unwanted duplicate mailings, you should contact your broker to 

eliminate the duplications.

2017 Dividend Payment Dates 

PG&E Corporation 

January 15 

April 15 

July 15 

October 15 

Pacific Gas and Electric Company 

February 15 

May 15 

August 15 

November 15 

Stock Exchange Listings

PG&E Corporation’s common stock is listed on the New York Stock Exchange under the symbol “PCG.”

Pacific Gas and Electric Company has eight issues of first preferred cumulative stock, par value $25 per share, all of 

which are listed on NYSE MKT.

Non-Redeemable:

Issue Symbol

6.00% PCG-PA

5.50% PCG-PB

5.00% PCG-PC

Redeemable:

Issue Symbol

5.00% PCG-PD

5.00% Series A PCG-PE

4.80% PCG-PG

4.50% PCG-PH

4.36% PCG-PI

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If you have general questions about PG&E Corporation or Pacific Gas and Electric Company, please contact the 

Corporate Secretary’s Office.

Vice President, Corporate Governance and Corporate Secretary

Linda Y.H. Cheng

PG&E Corporation

Pacific Gas and Electric Company

P. O. Box 770000

San Francisco, CA 94177

415-973-8200

Fax: 415-973-8719

Email: CorporateSecretary@pge.com

Securities analysts, portfolio managers, or other representatives of the investment community should contact the 

Investor Relations Office.

Senior Director, Investor Relations 

Ann H. Kim

PG&E Corporation 

P. O. Box 770000

San Francisco, CA 94177

415-972-7080

Email: invrel@pge-corp.com

PG&E Corporation

General Information

415-973-1000

Pacific Gas and Electric Company

General Information

415-973-7000

PG&E CORPORATION AND PACIFIC GAS AND ELECTRIC COMPANY 

ANNUAL MEETINGS OF SHAREHOLDERS

Date: May 30, 2017

Time: 10:00 a.m.

Location: PG&E Corporation and 

Pacific Gas and Electric Company Headquarters 

77 Beale Street 

San Francisco, CA 94105

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Designed and Published by Labrador-company.com

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BAKER 

&

HOSTE TL E R L LP ATTOR NE YS AT LAW

SAN FRANCISCO

EXHIBIT C 

2017 JOINT ANNUAL REPORT TO SHAREHOLDERS, PG&E CORPORATION AND 

PACIFIC GAS AND ELECTRIC COMPANY 

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2017 Joint Annual 

Report to Shareholders

PG&E Corporation

Pacific Gas and Electric Company

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Table of Contents

A Letter from the Chief Executive Officer and President ����������������������������������������������������������������������������������� ii

Financial Highlights��������������������������������������������������������������������������������������������������������������������������������������������������iv

Comparison of Five-Year Cumulative Total Shareholder Return ������������������������������������������������������������vi

Form 10-K Cover Page���������������������������������������������������������������������������������������������������������������������������������������������x

Form 10-K Table of Contents���������������������������������������������������������������������������������������������������������������������������������x

PG&E Corporation and Pacific Gas and Electric Company Boards of Directors�������������������������������x

Officers of PG&E Corporation and Pacific Gas and Electric Company�������������������������������������������������x

Shareholder Information �����������������������������������������������������������������������������������������������������������������������������������������x

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iii

For PG&E Corporation, 2017 was a year of both great successes and unprecedented challenges.

Our subsidiary, Pacific Gas and Electric Company, reached a number of key goals – most notably in safety 

improvements, the advancement of California’s energy policy aims, and the implementation of one of the industry’s 

largest capital investment programs. We also made significant progress in running our business more efficiently, 

exceeding our cost-reduction target of $300 million.

PG&E’s leadership in clean energy and corporate 

responsibility drew wide recognition for both entities; 

honors that included being named to the prestigious Dow 

Jones Sustainability Index, which lists North American 

firms that lead their industries in economic, environmental 

and social performance.

Those achievements, however, were abruptly overshadowed 

by the uncertainties surrounding the October wildfires 

– the most destructive and costly in California history. 

Hundreds of thousands of acres burned. Nearly 9,000 

homes and buildings were lost, along with many lives.

In response, PG&E mobilized our biggest emergency 

restoration since the 1989 Loma Prieta earthquake, with 

more than 4,300 men and women – some of whom had 

their own homes go up in flames – working around the 

clock. Our efforts in the months since have focused on 

helping our customers and communities recover from the 

damage, while supporting projects to bolster California’s 

resilience to the potential consequences of climate change.

The causes of these fires have not yet been determined. However, under existing state law, PG&E could face 

substantial liability if company assets are found to be involved – even if all of our practices and processes met 

the applicable requirements. 

Meanwhile, the repercussions for California, its citizens, and the energy industry continue to mount. Homeowners in 

fire-prone areas are facing fewer and more expensive options for renewing their insurance coverage. For the state’s 

investor-owned utilities, a steep decline in equity value claimed as much as $20 billion in market capitalization – 

magnified, in PG&E’s case, by the necessary suspension of stock dividends. 

Securing a comprehensive resolution to these issues is a top priority for 2018. We are engaged across the legal, 

regulatory and legislative fronts in pursuit of solutions, along with our fellow California utilities, labor unions and 

many others. Addressing the flawed policy that effectively makes companies like ours the default insurers for 

wildfire risk will be essential to our clean-energy progress – not just for PG&E, but also the technology pioneers, 

resource developers, and customers who have a stake in our mutual success.

In the meantime, the companies’ core operations and performance are sound. We remain focused on our longrange business plan, which aims to capitalize on the prevailing trends in our industry and California’s constructive 

energy agenda.

With that promising future in mind, we introduced a new framework for defining PG&E’s mission, vision, and the 

central pillars of our culture that are crucial to our success. These statements affirm who we are, what we do 

and what we aspire to. They define the beliefs, attitudes and behaviors that are vital to moving us forward. Most 

importantly, they guide our decisions and actions. 

Our 2017 performance included major accomplishments in each of those areas.

Our Mission

To safely and reliably deliver 

affordable and clean energy 

to our customers and 

communities every single 

day, while building the 

energy network of tomorrow.

Our Vision

With a sustainable energy 

future as our North Star, 

we will meet the challenge 

of climate change while 

providing affordable energy 

for all customers.

Our Culture

We put safety first.

We are accountable. We act with integrity, transparency and humility.

We are here to serve our customers.

We embrace change, innovation and continuous improvement.

We value diversity and inclusion. We speak up, listen up and follow up.

We succeed through collaboration and partnership. We are one team.

Together, Building

a Better California

A Letter from the Chief Executive Officer and President

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iv

Our Mission

In accordance with our mission to safely and reliably deliver clean and affordable energy to our customers and 

communities, we created a five-year safety action plan to further improve public, employee and contractor safety. 

The conditions we experienced throughout 2017 drove home the need for vigilance, as our crews responded to 

severe weather by working an additional 1 million hours – nearly two times our original forecast.

Those efforts won acclaim from the Edison Electric Institute for outstanding recovery in the face of continuous 

storms that descended on our service area last winter, as well as the emergency assistance PG&E provided in 

Florida to restore power following Hurricane Irma.

In preparation for the increased frequency of such extreme events, as well as California’s changing climate, 

we invested extensive work in improving the reliability of our system, including vegetation management, asset 

replacement, circuit upgrades, and preventive identification of potential failures.

Our Vision

Reflecting our vision of enabling a sustainable energy future, 2017 saw PG&E deliver electricity that is among the 

cleanest in the nation. Nearly 80 percent now comes from resources that produce no greenhouse gas – including 

33 percent from renewables such as solar and wind, a threshhold PG&E reached three years ahead of California’s 

2020 target.

We likewise reached key milestones in the joint proposal to close the Diablo Canyon Power Plant at the expiration 

of its current operating licenses, laying the groundwork that enabled approval early this year of our plan to replace 

its output with a combination of renewables and energy efficiency. And we helped secure legislation extending 

California’s cap-and-trade program, keeping the state at the forefront of market mechanisms for reducing carbon 

emissions.

Our customers, too, continued to lead the way in the rapid adoption of clean-energy alternatives. Private rooftop 

solar connections to PG&E’s grid surpassed 340,000 in 2017, a total that accounts for one of every five solar 

households in the United States. That same ratio holds true for the number of electric vehicles that charge in our 

service terrority, which surged above 140,000 cars.

PG&E’s ability to manage the interplay of such distributed energy resources also allowed us to get approval for 

the Oakland Clean Energy Initiative, a first-of-its-kind project in the city of Oakland that would retire an aging 

fossil-fuel power plant, owned by a third party, in favor of affordable carbon-free alternatives.

Our Culture

Of course, no company can accomplish its objectives without an effective corporate culture. To help ensure that 

ours is up to the task, we completed development of an Enterprise Corrective Action Program, giving all employees 

an outlet to “speak up” and voice concerns, as well as ideas for how we can do things better. 

For our natural gas business, we opened a new state-of the-art Gas Safety Academy and a Center for Gas Safety 

and Innovation. And we began construction of a new substation training facility for our electric operations teams 

to complement an existing center for line workers.

PG&E’s commitment to an inclusive workforce was spotlighted by DiversityInc with a No. 3 ranking among all 

utilities in the nation, while Corporate Responsibilty magazine named us the No. 1 gas and electric provider on its 

list of 100 Best Corporate Citizens.

That’s the PG&E I know, and the one that inspires me every day. I am grateful to all of our 23,000 employees, as 

well as the multitude of stakeholders who join us in charting the road ahead. Their talents and dedication are 

indispensible.

A Letter from the Chief Executive Officer and President (continued)

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v

Our Future

Even with all we’ve done, there’s still more work to do. Ultimately, California’s energy policy and climate goals – as 

well as PG&E’s own vision – require that we achieve further deep reductions in carbon emissions, bringing them 

40 percent below 1990 levels by 2030. Our ability to deliver that result – and fulfill our mission – will depend in 

no small part on how California addresses the poor and inconisisent application of its strict liability interpretation.

That uncertainty aside, opportunities abound for PG&E to thrive in the new energy landscape. We look forward to 

expanding our capabilities as the most effective grid planner and operator as we enable our customers to make 

new energy choices. We look forward to helping to decarbonize the transportation sector by providing clean 

fuels. And we look forward to driving the growth of the energy storage market while taking a leadership position 

in the capacity of our own system.

Most of all, we look forward to continuing our shared project of together, building a better California. Thank you 

for following our progress on that exciting journey. 

Sincerely,

Geisha J. Williams

Chief Executive Officer and President

PG&E Corporation

A Letter from the Chief Executive Officer and President (continued)

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vi

Financial Highlights(1)

PG&E Corporation

(unaudited, in millions, except share and per share amounts) 2017 2016

Operating Revenues $ 17,135 $ 17,666

Income Available for Common Shareholders

PG&E Corporation’s Earnings on a GAAP basis 1,646 1,393

Less items impacting comparability:(2)

Tax Cuts and Jobs Act transition impact(3) 147 -

Northern California wildfire-related costs(4) 49 -

Butte fire-related costs, net of insurance(5) 36 137

Pipeline related expenses(6) 52 67

Legal and regulatory related expenses(7) 6 43

Fines and penalties(8) 47 307

Diablo Canyon settlement-related disallowance(9) 32 -

GT&S revenue timing impact(10) (88) (193)

Net benefit from derivative litigation settlement(11) (38) -

GT&S capital disallowance - 130

PG&E Corporation’s Earnings from Operations(12) 1,889 1,884

Income Per Common Share, diluted 

PG&E Corporation’s earnings per common share on a GAAP basis 3.21 2.78

Less items impacting comparability:(2)

Tax Cuts and Jobs Act transition impact(3) 0.29 -

Northern California wildfire-related costs(4) 0.09 -

Butte fire-related costs, net of insurance(5) 0.07 0.27

Pipeline related expenses (6) 0.10 0.13

Legal and regulatory related expenses(7) 0.01 0.09

Fines and penalties(8) 0.09 0.61

Diablo Canyon settlement-related disallowance(9) 0.06 -

GT&S revenue timing impact(10) (0.17) (0.38)

Net benefit from derivative litigation settlement(11) (0.07) -

GT&S capital disallowance - 0.26

PG&E Corporation’s earnings per common share on earnings from operations(12) 3.68 3.76

Dividends Declared Per Common Share 1.55 1.93 

Total Assets at December 31 $ 68,012 $ 68,598 

Number of common shares outstanding at December 31 514,755,845 506,891,874 

(1) This is a combined annual report of PG&E Corporation and Pacific Gas and Electric Company (the “Utility”). PG&E 

Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and subsidiaries, 

and have been prepared in accordance with Generally Accepted Accounting Principles (“GAAP”). All amounts presented in 

the table above are tax-adjusted at PG&E Corporation’s tax rate of 40.75% except for fines, which are not tax deductible.

(2) “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. Items impacting comparability reconcile earnings 

from operations with consolidated income available for common shareholders as reported in accordance with GAAP.

(3) PG&E Corporation, on a consolidated basis, incurred a one-time charge of $147 million during the three and twelve months 

ended December 31, 2017, as a result of the Tax Cuts and Jobs Act, which was signed into law on December 22, 2017. The 

Utility’s charge of $64 million was related to deferred tax assets not reflected in authorized revenue requirements, such as 

deferred tax assets associated with disallowed plant, and PG&E Corporation’s charge of $83 million was primarily related to 

net operating loss carryforwards and compensation-related deferred tax assets.

(4) The Utility incurred costs of $82 million (before the tax impact of $33 million) during the three and twelve months ended 

December 31, 2017, associated with the Northern California wildfires. This includes charges of $64 million (before the 

tax impact of $26 million) for the three and twelve months ended December 31, 2017, for the reinstatement of liability 

insurance coverage and $18 million (before the tax impact of $7 million) during the three and twelve months ended 

December 31, 2017, for legal and other expenses.

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vii

(5) The Utility incurred costs, net of insurance, of $15 million (before the tax impact of $6 million) and $60 million (before the 

tax impact of $24 million) during the three and twelve months ended December 31, 2017, respectively, associated with the 

Butte fire. This includes accrued charges of $350 million (before the tax impact of $143 million) during the twelve months 

ended December 31, 2017, related to estimated third-party claims. The Utility also incurred charges of $15 million (before 

the tax impact of $6 million) and $60 million (before the tax impact of $25 million) during the three and twelve months 

ended December 31, 2017, respectively, for legal costs. These costs were partially offset by $350 million (before the tax 

impact of $143 million) recorded during the twelve months ended December 31, 2017, for expected insurance recoveries.

(6) The Utility incurred costs of $12 million (before the tax impact of $5 million) and $89 million (before the tax impact of 

$37 million) during the three and twelve months ended December 31, 2017, respectively, for pipeline related expenses 

incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline 

rights-of-way.

(7) The Utility incurred costs of $2 million (before the tax impact of $1 million) and $10 million (before the tax impact of 

$4 million) during the three and twelve months ended December 31, 2017, respectively, for legal and regulatory related 

expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters 

and regulatory communications.

(8) The Utility incurred costs of $71 million (before the tax impact of $24 million) during the twelve months ended 

December 31, 2017, for fines and penalties. This includes costs of $32 million (before the tax impact of $13 million) during 

the twelve months ended December 31, 2017, associated with safety-related cost disallowances imposed by the California 

Public Utilities Commission (the “CPUC”) in its April 9, 2015 San Bruno Penalty Decision in the gas transmission pipeline 

investigations. The Utility also recorded $15 million (before the tax impact of $6 million) during the twelve months ended 

December 31, 2017, for penalty imposed by the CPUC in its final phase two decision of the 2015 Gas Transmission and 

Storage (“GT&S”) rate case for prohibited ex parte communications. In addition, the Utility recorded $24 million (before the 

tax impact of $5 million) during the twelve months ended December 31, 2017, in connection with the proposed decision 

in the order instituting investigation into Compliance with Ex Parte Communication Rules. 

(9) Consistent with the CPUC decision adopted on January 11, 2018 in connection with the retirement of the Diablo Canyon 

Power Plant, the Utility recorded a disallowance of $47 million (before the tax impact of $15 million) during the twelve 

months ended December 31, 2017, comprised of cancelled projects of $24 million (before the tax impact of $6 million) and 

disallowed license renewal costs of $23 million (before the tax impact of $9 million).

(10) As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the twelve months ended 

December 31, 2017, the Utility recorded revenues of $150 million (before the tax impact of $62 million) in excess of the 

2017 authorized revenue requirement, which includes the final component of under-collected revenues retroactive to 

January 1, 2015.

(11) PG&E Corporation recorded proceeds from insurance, net of plaintiff payments, of $65 million (before the tax impact of 

$27 million) during the twelve months ended December 31, 2017, associated with the settlement agreement in connection 

with the shareholder derivative litigation that was approved by the court on July 18, 2017. This includes $90 million (before 

the tax impact of $37 million) for insurance recoveries partially offset by $25 million (before the tax impact of $10 million) 

for plaintiff legal fees paid in connection with the settlement during the twelve months ended December 31, 2017.

(12) “Earnings from operations” is a non-GAAP financial measure and is calculated as consolidated income available for common 

shareholders less “Items impacting comparability” as described in Note (2) above. 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.

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viii

Comparison of Five-Year Cumulative Total Shareholder Return(1)

PG&E Corporation common stock is traded on the New York Stock Exchange under the symbol “PCG.”

This graph compares the cumulative total return on PG&E Corporation common stock (equal to dividends plus stock 

price appreciation) during the past five fiscal years with that of the Standard & Poor’s 500 Stock Index and the Dow 

Jones Utilities Index.

2012 2013 2014 2015 2016 2017

PG&E Corporation Dow Jones Utilities Index S&P 500 Index

Comparison of 5-Year Cumulative Total Returns

$0

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104.63

143.71

148.68

175.30

132.33

191.17

112.68 147.22

142.71

168.66

132.37

150.48 152.55

170.79

208.05

(1) Assumes $100 invested on December 31, 2012 in PG&E Corporation common stock, the Standard & Poor’s 500 Stock Index, and 

the Dow Jones Utilities Index, and assumes quarterly reinvestment of dividends. The total shareholder returns shown are not 

necessarily indicative of future returns.

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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) 

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3 

Contents 

UNITS OF MEASUREMENT ........................................................................................................................................................ 5

GLOSSARY .................................................................................................................................................................................... 6

PART I

ITEM 1. BUSINESS

Regulatory and Enforcement Environment ................................................................................................................................ 8

Ratemaking Mechanisms .......................................................................................................................................................... 11

Electric Utility Operations ........................................................................................................................................................ 14

Natural Gas Utility Operations ................................................................................................................................................. 19

Competition .............................................................................................................................................................................. 21

Environmental Regulation ........................................................................................................................................................ 22

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 ............................................................................................................. 46

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 ............................................................................................................................................................................. 51

RESULTS OF OPERATIONS ................................................................................................................................................. 58

LIQUIDITY AND FINANCIAL RESOURCES ...................................................................................................................... 62

CONTRACTUAL COMMITMENTS ...................................................................................................................................... 67

ENFORCEMENT AND LITIGATION MATTERS ................................................................................................................ 67

REGULATORY MATTERS ................................................................................................................................................... 68

LEGISLATIVE AND REGULATORY INITIATIVES .......................................................................................................... 75

ENVIRONMENTAL MATTERS ............................................................................................................................................ 77

RISK MANAGEMENT ACTIVITIES .................................................................................................................................... 77

CRITICAL ACCOUNTING POLICIES .................................................................................................................................. 79

NEW ACCOUNTING PRONOUNCEMENTS ....................................................................................................................... 82

FORWARD-LOOKING STATEMENTS ................................................................................................................................ 82

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E Corporation ........................................................................................................................................................................ 88

CONSOLIDATED STATEMENTS OF INCOME .................................................................................................................. 88

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ............................................................................... 89

CONSOLIDATED BALANCE SHEETS ................................................................................................................................ 90

CONSOLIDATED STATEMENTS OF CASH FLOWS ........................................................................................................ 92

CONSOLIDATED STATEMENTS OF EQUITY ................................................................................................................... 94

Pacific Gas and Electric Company ................................................................................................................................................ 95

CONSOLIDATED STATEMENTS OF INCOME .................................................................................................................. 95

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ............................................................................... 96

CONSOLIDATED BALANCE SHEETS ................................................................................................................................ 97

CONSOLIDATED STATEMENTS OF CASH FLOWS ........................................................................................................ 99

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY ............................................................................... 101

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS ........................................................................................ 102

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION ........................................................................................ 102

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES .............................................................................. 102

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS .................................................... 108

NOTE 4: DEBT ...................................................................................................................................................................... 111

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION .......................................................................... 113

NOTE 6: PREFERRED STOCK ............................................................................................................................................ 115

NOTE 7: EARNINGS PER SHARE ...................................................................................................................................... 116

NOTE 8: INCOME TAXES ................................................................................................................................................... 116

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4 

NOTE 9: DERIVATIVES ...................................................................................................................................................... 120

NOTE 10: FAIR VALUE MEASUREMENTS ..................................................................................................................... 122

NOTE 11: EMPLOYEE BENEFIT PLANS .......................................................................................................................... 128

NOTE 12: RELATED PARTY AGREEMENTS AND TRANSACTIONS .......................................................................... 135

NOTE 13: CONTINGENCIES AND COMMITMENTS ...................................................................................................... 136

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 ....................................................................................................................................................................... 170

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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 

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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 

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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 

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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 “ForwardLooking 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. 

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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. 

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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.) 

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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 í2017 General Rate Case” and “Regulatory Matters 

í2020 General Rate Case” in Item 7. MD&A.) 

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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 CPUC. The CPUC may disallow costs associated 

with electricity purchases if the costs were not incurred in compliance with the CPUC-approved plan or if the CPUC determines 

that the utility failed to follow the principles of least-cost dispatch. Additionally, the CPUC may disallow the cost of replacement 

power procured due to unplanned outages at Utility-owned generation facilities. 

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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. 

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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 costeffective 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. 

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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%). 

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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. 

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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. 

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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. 

 

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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. 

 

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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.) 

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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. 

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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 generationrelated 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 selfgenerating 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.

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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), mononitrogen 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 changerelated 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. 

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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. 

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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

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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.

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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. 

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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.) 

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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 

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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.) 

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 

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matters, and other ongoing state and federal investigations and requests for information. The 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. 

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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

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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 selfgeneration 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 nonbypassable 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. 

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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 programs. PG&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. 

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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 8. The 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. 

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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: 

x 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; 

x 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; 

x 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; 

x 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; 

x 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; 

x the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act; 

x 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; 

x 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); 

x 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; 

x operator or other human error; 

x an ineffective records management program that results in the failure to construct, operate and maintain 

a utility system safely and prudently; 

x 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; 

x 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 

x attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war. 

 

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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 

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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. 

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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

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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 SmartMeterTM 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 

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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. 

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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. 

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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.)

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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. 

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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 oncethrough 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. 

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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 

 

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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 

 

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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.

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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, 2017. 

PG&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. 

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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. 

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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. 

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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 remeasurement 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 operations. Additionally, 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.

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 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 wildfirerelated 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 

litigation settlement (10) - - - - (38) - (0.07) - 

GT&S capital disallowance - 17 - 0.04 - 130 - 0.26

PG&E Corporation’s 

Earnings from Operations (11) $ 327 $ 675 $ 0.63 $ 1.33 $ 1,889 $ 1,884 $ 3.68 $ 3.76 

All amounts presented in the table above are tax adjusted at PG&E Corporation’s statutory tax rate of 40.75 percent, except as indicated below.

(1) “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. 

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(2) PG&E Corporation, on a consolidated basis, incurred a one-time charge of $147 million during the three and twelve months ended December 31, 2017, as 

a result of the Tax Cuts and Jobs Act, which was signed into law on December 22, 2017. The Utility’s charge of $64 million was related to deferred tax 

assets not reflected in authorized revenue requirements, such as deferred tax assets associated with disallowed plant, and PG&E Corporation’s charge of 

$83 million was primarily related to net operating loss carryforwards and compensation-related deferred tax assets.

(3) The Utility incurred costs of $82 million (before the tax impact of $33 million) during the three and twelve months ended December 31, 2017, associated 

with the Northern California wildfires. This includes charges of $64 million (before the tax impact of $26 million) for the three and twelve months ended 

December 31, 2017, for the reinstatement of liability insurance coverage and $18 million (before the tax impact of $7 million) during the three and twelve 

months ended December 31, 2017, for legal and other expenses.

(4) The Utility incurred costs, net of insurance, of $15 million (before the tax impact of $6 million) and $60 million (before the tax impact of $24 million) 

during the three and twelve months ended December 31, 2017, respectively, associated with the Butte fire. This includes accrued charges of $350 million 

(before the tax impact of $143 million) during the twelve months ended December 31, 2017, related to estimated third-party claims. The Utility also 

incurred charges of $15 million (before the tax impact of $6 million) and $60 million (before the tax impact of $25 million) during the three and twelve 

months ended December 31, 2017, respectively, for legal costs. These costs were partially offset by $350 million (before the tax impact of $143 million) 

recorded during the twelve months ended December 31, 2017, for expected insurance recoveries.

(5) The Utility incurred costs of $12 million (before the tax impact of $5 million) and $89 million (before the tax impact of $37 million) during the three and 

twelve months ended December 31, 2017, respectively, for pipeline related expenses incurred in connection with the multi-year effort to identify and 

remove encroachments from transmission pipeline rights-of-way.

(6) The Utility incurred costs of $2 million (before the tax impact of $1 million) and $10 million (before the tax impact of $4 million) during the three and 

twelve months ended December 31, 2017, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, 

regulatory, and litigation activities regarding natural gas matters and regulatory communications. 

(7) The Utility incurred costs of $71 million (before the tax impact of $24 million) during the twelve months ended December 31, 2017, for fines and 

penalties. This includes costs of $32 million (before the tax impact of $13 million) during the twelve months ended December 31, 2017, associated with 

safety-related cost disallowances imposed by the CPUC in its April 9, 2015 San Bruno Penalty Decision in the gas transmission pipeline investigations. 

The Utility also recorded $15 million (before the tax impact of $6 million) during the twelve months ended December 31, 2017, for penalty imposed by 

the CPUC in its final phase two decision of the 2015 GT&S rate case for prohibited ex parte communications. In addition, the Utility recorded $24 

million (before the tax impact of $5 million) during the twelve months ended December 31, 2017, in connection with the PD in the OII into Compliance 

with Ex Parte Communication Rules. 

(8) Consistent with the CPUC decision adopted on January 11, 2018 in connection with the retirement of the Diablo Canyon Power Plant, the Utility recorded 

a disallowance of $47 million (before the tax impact of $15 million) during the twelve months ended December 31, 2017, comprised of cancelled projects 

of $24 million (before the tax impact of $6 million) and disallowed license renewal costs of $23 million (before the tax impact of $9 million). 

(9) As a result of the CPUC’s final phase two decision in the 2015 GT&S rate case, during the twelve months ended December 31, 2017, the Utility recorded 

revenues of $150 million (before the tax impact of $62 million) in excess of the 2017 authorized revenue requirement, which includes the final component 

of under-collected revenues retroactive to January 1, 2015. 

(10) PG&E Corporation recorded proceeds from insurance, net of plaintiff payments, of $65 million (before the tax impact of $27 million) during the twelve 

months ended December 31, 2017, associated with the settlement agreement in connection with the shareholder derivative litigation that was approved by 

the court on July 18, 2017. This includes $90 million (before the tax impact of $37 million) for insurance recoveries partially offset by $25 million 

(before the tax impact of $10 million) for plaintiff legal fees paid in connection with the settlement during the twelve months ended December 31, 2017.

 (11) “Earnings from operations” is a non-GAAP financial measure. 

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Reconciliation of Key Drivers of PG&E Corporation’s EPS from Operations (Non-GAAP): 

Three Months Ended December 31, Twelve Months Ended December 31, 

Earnings per Earnings per 

 Common Share Common Share

(in millions, except per share amounts) Earnings (Diluted) Earnings (Diluted) 

2016 Earnings from Operations (1) $ 675 $ 1.33 $ 1,884 $ 3.76

Timing of 2015 GT&S revenue impact (2) (172) (0.33) - -

Timing of taxes (3) (90) (0.18) - -

Impact of 2017 GRC decision (4) (47) (0.09) (139) (0.27)

Timing of operational spend (5) (31) (0.06) - -

CEE Incentive Award (6) (10) (0.02) (10) (0.02)

Increase in shares outstanding - (0.02) - (0.08)

Tax benefit on stock compensation (7) - - 31 0.06

Miscellaneous (23) (0.05) 20 0.03

Growth in rate base earnings (8) 25 0.05 103 0.20

2017 Earnings from Operations (1) $ 327 $ 0.63 $ 1,889 $ 3.68

(1) See first table above for a reconciliation of EPS on a GAAP basis to EPS from Operations. All amounts presented in the table above are tax adjusted at 

PG&E Corporation’s statutory tax rate of 40.75 percent, except for tax benefits on stock compensation. See Footnote 3 below. 

(2) Represents the impact in 2016 of the delay in the Utility’s 2015 GT&S rate case. The CPUC issued its final phase two decision on December 1, 2016, 

delaying recognition of the full 2016 revenue increase until the fourth quarter of 2016.

(3) Represents the timing of taxes reportable in quarterly statements in accordance with ASC 740 and results from variances in the percentage of quarterly 

earnings to annual earnings.

(4) Represents the impact of lower tax repair benefits as a result of the CPUC’s final decision in the 2017 GRC proceeding.

(5) Represents timing of operational expense spending during the three months ended December 31, 2017 as compared to the same period in 2016.

(6) Represents the Customer Energy Efficiency (“CEE”) incentive award received during the fourth quarter of 2016, with no similar amount in 2017. The 

2017 award of $21.9 million was fully offset by the reduction approved by the CPUC related to the rehearing of the 2006 – 2008 CEE incentive awards.

(7) Represents the excess tax benefit related to share-based compensation awards that vested during the twelve months ended December 31, 2017. Pursuant 

to ASU 2016-09, Compensation – Stock Compensation (Topic 718), which PG&E Corporation and the Utility adopted in 2016, excess tax benefits 

associated with vested awards are reflected in net income.

(8) Represents the impact of the increase in rate base authorized in various rate cases, including the 2017 GRC, during the three and twelve months ended 

December 31, 2017 as compared to the same periods in 2016. 

Key Factors Affecting Financial Results

PG&E Corporation and the Utility believe that their financial condition, results of operations, liquidity, and cash flows may be 

materially affected by the following factors: 

x The Impact of the Northern California 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. The Utility incurred costs of $219 million for service restoration and repairs to the Utility’s

facilities (including an estimated $97 million in capital expenditures) in connection with these fires. PG&E Corporation’s 

and 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 through CEMA. 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 damages, interest, and attorneys’ fees without having been found negligent, which 

liability, in the aggregate, could be substantial. In addition to such claims, as well as claims under other theories of 

liability, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury 

damages, and other damages if the Utility were found to have been negligent, which liability, in the aggregate, could be 

substantial and have a material effect on PG&E Corporation and the Utility. Further, the Utility also could be subject to 

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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. If 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 the principles discussed in Note 13 to Notes to the Consolidated Financial Statements in Item 8. To the 

extent not offset by insurance recoveries, the liability would affect the balance sheet equity of PG&E Corporation and the 

Utility. (See “Enforcement and Litigation Matters” in Note 13 to Notes to the Consolidated Financial Statements in Item 

8 and Item 1A. Risk Factors.) 

x The Applicability of the Doctrine of Inverse Condemnation in PG&E Corporation and the Utility’s Wildfire Litigation. 

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 shareholder liabilities from such litigation and materially affect PG&E 

Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. Although the 

imposition of liability is premised on the assumption that utilities have the ability to recover these costs from their 

customers, there can be no guarantee that the CPUC would authorize cost recovery even if a court decision imposes 

liability 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. 

(See “Enforcement and Litigation Matters” in Note 13 to Notes to the Consolidated Financial Statements in Item 8 and 

Item 1A. Risk Factors.) 

x The Tax Cut and Jobs Act. 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 eliminates bonus depreciation for utilities. As a result of the Tax Act, 

beginning in 2018, PG&E Corporation and the Utility anticipate a reduction in revenues, lower effective income tax rates 

and lower income tax expense. In addition, the Utility expects a rate base increase primarily due to the elimination of 

bonus depreciation. (See “The Tax Cuts and Job Act of 2017” and “Regulatory Matters” in this Item 7. MD&A and Note 

3 and Note 8 in the Notes to the Consolidated Financial Statements.) 

x The Outcome of Enforcement, Litigation, and Regulatory Matters. The Utility’s financial results may continue to be 

impacted by the outcome of current and future enforcement, litigation, and regulatory matters, including the impact of the 

Northern California wildfires, the Butte fire, the safety culture OII and any related fines, penalties, or other ratemaking 

tools that could be imposed by the CPUC, including as a result of the phase two of the proceeding, the ex parte OII and 

the related proposed decision, the potential recommendations that the third-party monitor (retained by the Utility in the 

first quarter of 2017 as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal 

conviction) may make, and potential penalties in connection with the Utility’s safety and other self-reports. (See 

“Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8, Item 3. 

Legal Proceedings, and Item 1A. Risk Factors.) 

x The Timing and Outcome of Ratemaking Proceedings. The Utility’s financial results may be impacted by the timing and 

outcome of its 2019 GT&S rate case, and FERC TO18 and TO19 rate cases, as well as the recent remand decision by the 

Ninth Circuit regarding an ROE adder for transmission facilities. (See “Regulatory Matters – 2019 Gas Transmission and 

Storage Rate Case” and “Regulatory Matters í FERC Transmission Owner Rate Cases” below for more information.) 

The outcome of regulatory proceedings can be affected by many factors, including intervening parties’ testimonies, 

potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors. 

x The Ability of the Utility to Control and Recover Operating Costs and Capital Expenditures. In any given year the 

Utility’s ability to earn its authorized rate of return depends on its ability to manage costs within the amounts authorized 

in rate case decisions. The Utility forecasts that in 2018 it will incur unrecovered pipeline-related expenses ranging from 

$35 million to $60 million which primarily relate to costs to identify and remove encroachments from transmission 

pipeline rights-of-way. Also, the CPUC decision in the Utility’s 2015 GT&S rate case established various cost caps that 

will increase the risk of overspend over the rate case cycle through 2018. (See “Disallowance of Plant Costs” in Note 13 

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

x The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation’s and the Utility’s ability to access the 

capital markets, ability to borrow under its loan financing arrangements and the terms and rates of future financings could 

be materially affected by the outcome of, or market perception of, the matters discussed in Note 13 of the Notes to the 

Consolidated Financial Statements, including liabilities, if any, incurred in relation to the Northern California wildfires, 

adverse effects on PG&E Corporation’s and the Utility’s ability to comply with consolidated debt to total capitalization 

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ratio covenants in their financing arrangements and regulatory capital structure requirements resulting therefrom, adverse 

changes in their respective credit ratings, general economic and market conditions, and other factors. PG&E Corporation 

contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. In 2017, PG&E 

Corporation issued $416 million of common stock and made equity contributions of $455 million to the Utility. PG&E 

Corporation forecasts that it will need to continue to issue a material amount of equity in future years, primarily to support 

the Utility’s capital expenditures. PG&E Corporation may seek to issue additional equity to fund unrecoverable pipelinerelated expenses and to pay claims, losses, fines, and penalties that may be required by the outcome of litigation and 

enforcement matters. Additional issuances of equity, if any, could have a material dilutive impact on PG&E 

Corporation’s EPS. 

x Changes in the Utility Industry. The Utility is committed to delivering safe, reliable, sustainable, and affordable electric 

and gas services to its customers. Increasing demands from state laws and policies relating to increased renewable energy 

resources, the reduction of GHG emissions, the expansion of energy efficiency programs, the development and 

widespread deployment of distributed generation and self-generation resources, and the development of energy storage 

technologies have increased pressure on the Utility to achieve efficiencies in its operations while continuing to provide 

customers with safe, reliable, and affordable service. The utility industry is also 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 policy makers notwithstanding a recent change in the federal approach to such matters. 

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). The Utility forecasts over $1 billion in grid investments 

through 2020, which would include increased remote control and sensor technology of the grid, integration investments in 

connection with DER bi-directional energy flows and voltage fluctuations, advanced grid data analytics, grid storage that 

enables renewable integration, expanded infrastructure for light, medium, and heavy-duty EVs, transmission integration 

for renewables, and energy efficiency and demand response programs. In addition, these changes brought about by 

technological advancements and climate policy may cause a reduction in natural gas usage and increase natural gas costs. 

The combination of reduced natural gas load and increased costs could result in higher natural gas customer bills and 

potential cost recovery risk. 

For more information about the factors and risks that could affect PG&E Corporation’s and the Utility’s financial condition, results 

of operations, liquidity, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk 

Factors. In addition, this 2017 Form 10-K contains forward-looking statements that are necessarily subject to various risks and 

uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and 

projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this 

2017 Form 10-K. See the section entitled “Forward-Looking Statements” below for a list of some of the factors that may cause 

actual results to differ materially. PG&E Corporation and the Utility are not able to predict all the factors that may affect future 

results and do not undertake an obligation to update forward-looking statements, whether in response to new information, future

events, or otherwise.

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RESULTS OF OPERATIONS 

The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2017, 2016, and 2015. See “Key 

Factors Affecting Financial Results” above for further discussion about factors that could affect future results of operations.

PG&E Corporation 

The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section 

below. The following table provides a summary of net income available for common shareholders: 

(in millions) 2017 2016 2015 

Consolidated Total $ 1,646 $ 1,393 $ 874 

PG&E Corporation (31) 5 26 

Utility $ 1,677 $ 1,388 $ 848 

 

PG&E Corporation’s net income consists primarily of income taxes, interest expense on long-term debt, and other income from 

investments. The decrease in PG&E Corporation’s net income for 2017, as compared to 2016, is primarily due to the impact of the 

Tax Act and interest expense, partially offset by the impact of the San Bruno Derivative Litigation. Results include approximately 

$30 million of realized gains and associated tax benefits related to an investment in SolarCity Corporation recognized in 2015,

with no corresponding gains in 2016 or 2017. 

Utility 

The table below shows certain items from the Utility’s Consolidated Statements of Income for 2017, 2016, and 2015. The table 

separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses 

the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs 

to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs, do not

impact earnings. In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the 

corresponding revenues the Utility is authorized to collect to recover such costs, do not impact earnings. 

 

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s 

costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. 

Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets. 

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2017 2016 2015 

Revenues and Costs: Revenues and Costs: Revenues and Costs: 

(in millions) 

That 

Impacted 

Earnings 

That Did 

Not Impact 

Earnings 

Total 

Utility 

That 

Impacted 

Earnings 

That Did 

Not Impact 

Earnings 

Total 

Utility 

That 

Impacted 

Earnings 

That Did 

Not Impact 

Earnings 

Total 

Utility 

Electric operating revenues $ 7,897 $ 5,230 $ 13,127 $ 7,955 $ 5,910 $ 13,865 $ 7,442 $ 6,215 $ 13,657 

Natural gas operating revenues 2,969 1,042 4,011 2,767 1,035 3,802 2,082 1,094 3,176 

Total operating revenues 10,866 6,272 17,138 10,722 6,945 17,667 9,524 7,309 16,833 

Cost of electricity - 4,309 4,309 - 4,765 4,765 - 5,099 5,099 

Cost of natural gas - 746 746 - 615 615 - 663 663 

Operating and maintenance 5,112 1,217 6,329 5,787 1,565 7,352 5,402 1,547 6,949 

Depreciation, amortization, and 

decommissioning 2,854 - 2,854 2,754 - 2,754 2,611 - 2,611 

Total operating expenses 7,966 6,272 14,238 8,541 6,945 15,486 8,013 7,309 15,322 

Operating income 2,900 - 2,900 2,181 - 2,181 1,511 - 1,511 

Interest income (1) 30 22 8 

Interest expense (1) (877) (819) (763) 

Other income, net (1) 65 88 87 

Income before income taxes 2,118 1,472 843 

Income tax provision (benefit) (1) 427 70 (19) 

Net income 1,691 1,402 862 

Preferred stock dividend requirement (1) 14 14 14 

Income Available for Common Stock $ 1,677 $ 1,388 $ 848 

 (1) These items impacted earnings. 

Utility Revenues and Costs that Impacted Earnings 

The following discussion presents the Utility’s operating results for 2017, 2016, and 2015, focusing on revenues and expenses that 

impacted earnings for these periods. 

Operating Revenues 

The Utility’s electric and natural gas operating revenues that impacted earnings increased $144 million, or 1% in 2017 compared

to 2016, primarily due to higher electric transmission revenues. 

The Utility’s electric and natural gas operating revenues that impacted earnings increased $1.2 billion or 13% in 2016 compared to 

2015, primarily as a result of approximately $700 million of incremental revenues authorized in the 2015 GT&S rate case and 

approximately $425 million of additional base revenues as authorized by the CPUC in the 2014 GRC decision and by the FERC in 

the TO17 rate case. 

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Operating and Maintenance 

The Utility’s operating and maintenance expenses that impacted earnings decreased $675 million, or 12%, in 2017 compared to 

2016. In 2017, the Utility incurred $455 million less in disallowed charges (the Utility recorded a $47 million disallowance related 

to the Diablo Canyon settlement in 2017 as compared to $502 million of disallowed capital charges related to the San Bruno 

Penalty Decision and 2015 GT&S rate case decision in 2016) and $447 million less in charges related to the Butte fire (the Utility 

recorded $410 million in charges in 2017 as compared to $857 million in 2016). These decreases were partially offset by 

insurance recoveries related to the Butte fire decreasing by approximately $275 million (the Utility recorded $350 million in 

insurance recoveries in 2017 as compared to approximately $625 million in 2016). (See Note 13 of the Notes to the Consolidated

Financial Statements in Item 8.) 

The Utility’s operating and maintenance expenses that impacted earnings increased $385 million, or 7%, in 2016 compared to 

2015, primarily due to $857 million in charges for third-party claims, Utility clean-up, repair, and legal costs related to the Butte 

fire, $219 million in permanently disallowed capital spending, $34 million in charges recorded in connection with the final CPUC 

decision related to the natural gas distribution facilities record-keeping investigation, the federal criminal trial, and the atmospheric 

corrosion inspection self-report, $24 million in higher pipeline-related expenses and legal and regulatory related expenses during 

2016, an escalation related to labor, benefits, and service contracts, and accelerated transmission and distribution project work. 

These increases were partially offset by $500 million in charges associated with the San Bruno Penalty Decision for customer 

refunds and fines incurred in 2015 with no corresponding charges in 2016 and approximately $125 million in lower disallowed 

capital charges associated with the San Bruno Penalty Decision in 2016. Additionally, the Utility recorded approximately $576 

million more in insurance recoveries (in 2016, the Utility recorded $625 million in insurance recoveries related to the Butte fire as 

compared to $49 million of insurance recoveries for third-party claims related to the San Bruno accident in 2015). 

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 and any additional charges associated with costs related to the Butte 

fire. (See Item 1A. Risk Factors above and Note 13 of the Notes to the Consolidated Financial Statements in Item 8.) 

Depreciation, Amortization, and Decommissioning

The Utility’s depreciation, amortization, and decommissioning expenses increased $100 million, or 4% in 2017 compared to 2016 

and $143 million, or 5% in 2016 compared to 2015. In 2017, the increase was primarily due to the impact of capital additions and 

higher depreciation rates as authorized by the CPUC in the 2017 GRC. In 2016, the increase was primarily due to the impact of 

capital additions. 

Interest Expense

The Utility’s interest expenses increased by $58 million, or 7% in 2017 compared to 2016, primarily due to the issuance of 

additional long-term debt. The Utility’s interest expenses increased by $56 million, or 7% in 2016 compared to 2015, primarily

due to the issuance of additional long-term debt. 

Interest Income and Other Income, Net 

There were no material changes to interest income and other income, net for the periods presented. 

Income Tax Provision 

The Utility’s income tax provision increased $357 million in 2017 compared to 2016. The increase in the tax provision was 

primarily the result of the statutory tax effect of higher pre-tax income in 2017 compared to 2016 and an adjustment required to 

record the change in deferred tax balances due to tax reform in 2017 with no comparable adjustment in 2016. (For more 

information see “Tax Reform” below and Note 8 of the Consolidated Financial Statements.) 

The Utility’s income tax provision increased $89 million in 2016 compared to 2015. The increase in the tax provision was 

primarily the result of the statutory tax effect of higher pre-tax income in 2016 compared to 2015, partially offset by higher tax 

benefits from property-related timing differences in 2016 compared to 2015. The higher effective tax rate was driven by higher

pre-tax earnings in 2016, partially offset by rate impact from property-related timing differences. 

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The following table reconciles the income tax expense at the federal statutory rate to the income tax provision: 

2017 2016 2015 

Federal statutory income tax rate 35.0 % 35.0 % 35.0 %

Increase (decrease) in income tax rate resulting from: 

State income tax (net of federal benefit) (1) 1.6 (2.2) (4.8)

Effect of regulatory treatment of fixed asset differences (2) (16.8) (23.4) (33.7) 

Tax credits (1.1) (0.8) (1.3)

Benefit of loss carryback - (1.1) (1.5)

Non-deductible penalties (3) 0.4 0.8 4.3 

Tax Reform Adjustment (4) 3.0 - - 

Other, net (5) (2.0) (3.5) (0.2)

Effective tax rate 20.1 % 4.8 % (2.2)%

(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts reflect an agreement with the IRS on a 2011 audit related to electric 

transmission and distribution repairs deductions. The 2017 amount reflects an agreement with the IRS on a 2013 audit related to generation repairs deductions. 

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods 

presented and by the 2015 GT&S decision which impacted 2016 and 2017. All amounts are impacted by the level of income before income taxes. The 2014 

GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences 

attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the 

Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the 

Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory 

assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. 

(3) Primarily represents the effects of a non-tax deductible penalty associated with the Butte fire for 2017, non-tax deductible fines and penalties associated with the 

natural gas distribution facilities record-keeping decision for 2016 and the effects of the San Bruno Penalty Decision for 2015. (4) Represents the required adjustment to deferred tax balances, due to the federal income tax rate being lowered from 35% to 21% beginning in 2018 as a result of 

the enactment of the Tax Act. 

(5) These amounts primarily represent the impact of tax audit settlements. 

Utility Revenues and Costs that did not Impact Earnings 

Fluctuations in revenues that did not impact earnings are primarily driven by procurement costs (see below for more detail). 

Cost of Electricity 

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), 

transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to 

comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 9 of 

the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s total purchased power is driven by customer demand, 

the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the costeffectiveness of each source of electricity. 

(in millions) 2017 2016 2015 

Cost of purchased power $ 4,039 $ 4,510 $ 4,805 

Fuel used in own generation facilities 270 255 294 

Total cost of electricity $ 4,309 $ 4,765 $ 5,099 

Average cost of purchased power per kWh (1) $ 0.140 $ 0.109 $ 0.100 

Total purchased power (in millions of kWh) (2) 28,750 41,324 48,175 

(1) Average cost of purchased power was impacted primarily by lower Utility electric customer demand due to their departure to CCAs or direct access providers 

and a larger percentage of higher cost renewable energy resources being allocated to fewer remaining Utility electric customers. See further discussion in Item 

7. MD&A, “Legislative and Regulatory Initiatives - Power Charge Indifference Adjustment OIR”, below. 

(2) The decrease in purchased power for 2017 compared to 2016 was primarily due to lower Utility electric customer demand and an increase in generation from 

hydroelectric facilities. 

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Cost of Natural Gas 

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with 

California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 9 of the Notes to 

the Consolidated Financial Statements in Item 8.) The Utility’s cost of natural gas is impacted by the market price of natural gas, 

changes in the cost of storage and transportation, and changes in customer demand. 

(in millions) 2017 2016 2015 

Cost of natural gas sold $ 627 $ 481 $ 518 

Transportation cost of natural gas sold 119 134 145 

Total cost of natural gas $ 746 $ 615 $ 663 

Average cost per Mcf (1) of natural gas sold $ 2.97 $ 2.45 $ 2.74 

Total natural gas sold (in millions of Mcf) (2) 211 196 189 

(1) One thousand cubic feet 

(2) The increase in natural gas sold for 2017 compared to 2016 was primarily due to cooler temperatures and resulted in additional customer heating demand.

Operating and Maintenance Expenses 

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as 

incurred such as pension contributions and public purpose programs costs. If the Utility were to spend more than authorized 

amounts, these expenses could have an impact to earnings. For 2017, 2016, and 2015, no material amounts were incurred above 

authorized amounts.

LIQUIDITY AND FINANCIAL RESOURCES 

Overview 

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both 

PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, 

beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities 

associated with the Northern California wildfires. (See Item 1A. Risk Factors and Note 13 of the Notes to the Consolidated 

Financial Statements in Item 8.) 

The Utility’s ability to fund operations, finance capital expenditures, and make distributions to PG&E Corporation depends on the 

levels of its operating cash flows and access to the capital and credit markets. The CPUC authorizes the Utility’s capital structure, 

the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able 

to collect to recover its cost of capital. The Utility generally utilizes equity contributions from PG&E Corporation and long-term 

senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and 

preferred stock. (See “Regulatory Matters” in Item 7. MD&A.) The Utility relies on short-term debt, including commercial paper, 

to fund temporary financing needs. 

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the

Utility, and declare and pay dividends primarily depends on the level of cash distributions received from the Utility and PG&E 

Corporation’s access to the capital and credit markets. PG&E Corporation’s equity contributions to the Utility are funded 

primarily through common stock issuances. PG&E Corporation has material stand-alone cash flows related to the issuance of 

equity and long-term debt, and issuances and repayments under its revolving credit facility and commercial paper program. PG&E

Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs. 

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PG&E Corporation’s and the Utility’s credit ratings may be affected by the ultimate outcome of pending enforcement and 

litigation matters, including the outcome of the uncertainties and potential liabilities associated with the Northern California 

wildfires. Credit rating downgrades may increase the cost and availability of short-term borrowing, including commercial paper, 

the costs associated with credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain 

collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. In December 2017, 

following PG&E Corporation’s announcement that it was suspending its dividend due to the uncertainty related to the causes and 

potential liabilities associated with the Northern California wildfires, all of the ratings of PG&E Corporation and the Utility were 

placed under review for downgrade by Moody’s Investor Services. Additionally, in December 2017, Standard & Poor’s Global 

Ratings lowered the Utility’s preferred stock credit rating and placed all of the ratings of PG&E Corporation and the Utility on 

CreditWatch with negative implications. If the Utility’s credit rating were to fall below investment grade, the Utility would be 

required to post additional cash immediately to fully collateralize some of its net liability positions. (See Notes 9 and 13 of the 

Notes to the Consolidated Financial Statements in Item 8.) 

PG&E Corporation’s and the Utility’s equity needs could increase materially and its liquidity and cash flows could be materially 

affected by potential costs and other liabilities in connection with the Northern California wildfires. The Utility’s equity needs will 

also continue to be affected by the timing and amount of disallowed capital expenditures, and by fines, penalties and claims that 

may be imposed in connection with the matters described in “Enforcement and Litigation Matters” in Note 13 of the Notes to the 

Consolidated Financial Statements in Item 8. In addition, PG&E Corporation’s and the Utility’s ability to access the capital 

markets in a manner consistent with its past practices, if at all, could be adversely affected by such matters. (See Item 1A. Risk 

Factors.) 

As a result of the Tax Act, the Utility anticipates an annual reduction to revenue requirements of approximately $500 million 

starting in 2018. In addition to this reduction in future revenue requirements, the Tax Act’s other provisions, in particular the 

elimination of bonus depreciation, are expected to accelerate when PG&E Corporation resumes paying federal taxes; although 

future taxes will 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 operations. Additionally, 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. 

Cash and Cash Equivalents 

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or

less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. 

Financial Resources 

Debt Financings 

In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid. 

Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan maturing on February 22, 

2018. 

In March 2017, the Utility issued $400 million principal amount of 3.30% senior notes due March 15, 2027 and $200 million 

principal amount of 4.00% senior notes due December 1, 2046. The proceeds were used for general corporate purposes, including 

the repayment of a portion of the Utility’s outstanding commercial paper. 

In November 2017, the Utility issued $1,150 million principal amount of 3.30% senior notes due December 1, 2027 and $850 

million principal amount of 3.95% senior notes due December 1, 2047. The proceeds were used to repay all of the $700 million 

outstanding principal amount of its 5.63% senior notes due November 30, 2017, all of the $250 million floating rate unsecured 

term loan maturing February 22, 2018 and $400 million of the 8.25% senior notes due October 15, 2018, and the balance, for 

general corporate purposes. 

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In November 2017, the Utility issued $500 million of floating rate senior notes due November 28, 2018. The proceeds were used 

towards repayment of the $250 million unsecured floating rate notes due November 30, 2017 and the balance was used to support 

the Northern California wildfire response efforts. 

On January 9, 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% 

senior notes due October 15, 2018 on February 18, 2018. On January 31, 2018, the Utility deposited with the trustee funds 

sufficient to effect the early redemption of these bonds and satisfy and discharge its remaining obligation of $400 million. 

Equity Financings 

In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common 

stock having an aggregate gross price of up to $275 million. During the twelve months ended December 31, 2017, PG&E 

Corporation sold 0.4 million shares of its common stock under the February 2017 EDA for cash proceeds of $28.4 million, net of 

commissions paid of $0.2 million. There were no issuances under the February 2017 EDA for the three months ended December 

31, 2017. As of December 31, 2017, the remaining gross sales available under this agreement were $246.3 million. 

PG&E Corporation also issued common stock under the PG&E Corporation 401(k) plan, the Dividend Reinvestment and Stock 

Purchase Plan, and share-based compensation plans. During 2017, 7.4 million shares were issued for cash proceeds of $366.4 

million under these plans. 

The proceeds from these sales were used for general corporate purposes, including the contribution of equity to the Utility. For the 

year ended December 31, 2017, PG&E Corporation made equity contributions to the Utility of $455 million. 

Pollution Control Bonds 

In June 2017, the Utility repurchased and retired $345 million principal amount of pollution control bonds Series 2004 A through 

D. Additionally, in June 2017, the Utility remarketed three series of pollution control bonds, previously held in treasury, totaling 

$145 million in principal amount. Series 2008 F and 2010 E bear interest at 1.75% per annum. Although the stated maturity date 

for Series 2008 F and 2010 E is November 1, 2026, these bonds have a mandatory redemption date of May 30, 2022. Series 2008 

G bears interest at 1.05% per annum and matures on December 1, 2018. 

Revolving Credit Facilities and Commercial Paper Programs 

In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by 

one year from April 27, 2021 to April 27, 2022. At December 31, 2017, PG&E Corporation and the Utility had $168 million and 

$2.9 billion available under their respective $300 million and $3.0 billion revolving credit facilities. (See Note 4 of the Notes to 

the Consolidated Financial Statements in Item 8.) 

PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, 

respectively. For the year ended December 31, 2017, PG&E Corporation and the Utility had an average outstanding commercial 

paper balance of $81 million and $469 million, and a maximum outstanding balance of $161 million and $1.1 billion, respectively. 

At December 31, 2017, PG&E Corporation and the Utility had outstanding commercial paper balances of $132 million and $50 

million, respectively. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.) 

The revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total 

consolidated capitalization of at most 65% as of the end of each fiscal quarter. At December 31, 2017, PG&E Corporation’s and 

the Utility’s total consolidated debt to total consolidated capitalization was 50% and 49%, respectively. PG&E Corporation’s 

revolving credit facility agreement also requires that PG&E Corporation owns, directly or indirectly, at least 80% of the common 

stock and at least 70% of the voting capital stock of the Utility. In addition, the revolving credit facilities include usual and 

customary provisions regarding events of default and covenants including covenants limiting liens to those permitted under PG&E

Corporation’s and the Utility’s senior note indentures, mergers, and imposing conditions on the sale of all or substantially all of 

PG&E Corporation’s and the Utility’s assets and other fundamental changes. At December 31, 2017, PG&E Corporation and the 

Utility were in compliance with all covenants under their respective revolving credit facilities. 

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Dividends 

The Board of Directors of PG&E Corporation and the Utility each has the authority to declare dividends on PG&E Corporation’s 

common stock and the Utility’s common and preferred stock, respectively. Dividends are not payable unless and until declared by 

the applicable Board of Directors. Each Board of Directors retains authority to change the respective common or preferred stock

dividend policy and dividend payout ratio or rate at any time, especially if unexpected events occur that would change their view 

as to the prudent level of cash conservation. 

PG&E Corporation 

For the first quarter of 2017, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.49 per share. 

In May 2017, the Board of Directors of PG&E Corporation approved a new annual common stock dividend of $2.12 per share. As 

a result, for the second and third quarters of 2017, the Board of Directors of PG&E Corporation declared a common stock dividend 

of $0.53 per share. In 2017, total dividends declared were $1.55 per share. For the first quarter of 2016, the Board of Directors of 

PG&E Corporation declared a common stock dividend of $0.455 per share. For each of the second, third and fourth quarters of 

2016, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.49 per share. In 2016, total dividends

declared were $1.925 per share. For each of the quarters in 2015, the Board of Directors of PG&E Corporation declared a 

common stock dividend of $0.455 per share, for annual dividends of $1.82 per share. Dividends paid to common shareholders by 

PG&E Corporation were $1.0 billion in 2017, $921 million in 2016, and $856 million in 2015. 

Utility 

For the first quarter of 2017, the Board of Directors of the Utility declared a common stock dividend of $244 million to PG&E 

Corporation. For the second and third quarter of 2017, the Board of Directors of the Utility declared common stock dividends of 

$270 million to PG&E Corporation. In 2017, total dividends paid by the Utility to PG&E Corporation were $784 million. For the

first quarter of 2016, the Board of Directors of the Utility declared a common stock dividend of $179 million to PG&E 

Corporation. For each of the second, third and fourth quarters of 2016, the Board of Directors of the Utility declared common 

stock dividends of $244 million to PG&E Corporation. In 2016, total dividends paid by the Utility to PG&E Corporation were 

$911 million. For each of the quarters in 2015, the Board of Directors of the Utility declared common stock dividends of $179 

million to PG&E Corporation for annual dividends paid of $716 million. In addition, the Utility paid $14 million of dividends on 

preferred stock in each of 2017, 2016, and 2015. The Utility’s preferred stock is cumulative and any dividends in arrears must be 

paid before the Utility may pay any common stock dividends. 

Utility Cash Flows 

The Utility’s cash flows were as follows: 

Year Ended December 31, 

 (in millions) 2017 2016 2015 

Net cash provided by operating activities $ 5,916 $ 4,344 $ 3,747 

Net cash used in investing activities (5,650) (5,526) (5,211) 

Net cash provided by financing activities 110 1,194 1,468 

Net change in cash and cash equivalents $ 376 $ 12 $ 4 

Operating Activities 

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating 

expenses, other than expenses such as depreciation that do not require the use of cash. During 2017, net cash provided by 

operating activities increased by $1.6 billion compared to 2016. This increase was primarily due to additional electric and natural 

gas operating revenues collected as authorized by the CPUC in the 2015 GT&S rate case, the $400 million refund to natural gas 

customers in the second quarter of 2016, as required by the San Bruno Penalty Decision (with no corresponding activity in 2017), 

and the receipt of approximately $300 million of insurance recoveries related to the Butte fire in 2017 as compared to $50 million 

of insurance recoveries related to the Butte fire during 2016. 

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During 2016, net cash provided by operating activities increased by $597 million compared to 2015. This increase was partially

due to the Utility receiving an additional $170 million in tax refunds in 2016 as compared to 2015. The remaining increase was

primarily due to fluctuations in activities within the normal course of business such as timing and amount of customer billings and 

vendor billings and payments. 

Future cash flow from operating activities will be affected by various factors, including: 

x the timing and amount of costs in connection with the Northern California wildfires, as well as potential liabilities in 

connection with third-party claims and fines or penalties that could be imposed on the Utility 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; 

x the timing and amounts of costs, including fines and penalties, that may be incurred in connection with the current and 

future enforcement, litigation, and regulatory matters, including the impact of the Butte fire and the timing and amount of 

related insurance recoveries, the safety culture OII, including other ratemaking tools that could be imposed by the CPUC 

as a result of the phase two of the proceeding, the ex parte OII and the related proposed decision, costs associated with 

potential recommendations that the third-party monitor may make related to the Utility’s conviction in the federal 

criminal trial, and potential penalties in connection with the Utility’s safety and other self-reports; 

x the Tax Act, which is expected to accelerate the timing of federal tax payments and reduce revenue requirements, 

resulting in lower operating cash flows; 

x the timing and outcomes of the 2019 GT&S, TO18, and TO19 rate cases and other ratemaking and regulatory 

proceedings; 

x the timing and amount of costs the Utility incurs, but does not recover, associated with its electric and natural gas 

systems; and 

x the timing of the resolution of the Chapter 11 disputed claims and the amount of principal and interest on these claims 

that the Utility will be required to pay. 

Investing Activities 

Net cash used in investing activities increased by $124 million during 2017 as compared to 2016 primarily due to an increase in

capital expenditures. Net cash used in investing activities increased by $315 million during 2016 as compared to 2015 primarily 

due to an increase of approximately $440 million in capital expenditures, partially offset by an increase in restricted cash released 

from escrow by approximately $160 million. 

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility 

estimates that it will incur approximately $6.3 billion in capital expenditures in 2018 and $6.0 billion in 2019. 

Financing Activities 

During 2017, net cash provided by financing activities decreased by $1.1 billion as compared to 2016. This decrease was 

primarily due to net commercial repayments of $972 million in 2017 as compared to net repayments of $9 million in 2016. During

2016, net cash provided by financing activities decreased by $274 million as compared to 2015. Cash provided by or used in 

financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating 

activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date 

of existing debt instruments. The Utility generally utilizes long-term debt issuances and equity contributions from PG&E 

Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

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CONTRACTUAL COMMITMENTS 

The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 

2017: 

Payment due by period 

Less Than 1-3 3-5 More Than 

(in millions) 1 Year Years Years 5 Years Total 

Utility 

Long-term debt (1): $ 1,253 $ 3,117 $ 2,523 $ 25,114 $ 32,007 

Purchase obligations (2): 

Power purchase agreements: 3,148 6,169 5,539 27,188 42,044 

Natural gas supply, transportation, and 

storage 388 315 186 357 1,246 

Nuclear fuel agreements 96 245 130 151 622 

Pension and other benefits (3) 351 701 701 351 2,104 

Operating leases (2) 44 81 63 138 326 

Preferred dividends (4) 14 28 28 - 70 

PG&E Corporation 

Long-term debt (1): 8 354 - - 362 

Total Contractual Commitments $ 5,302 $ 11,010 $ 9,170 $ 53,299 $ 78,781 

(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2017 and outstanding principal for 

each instrument with the terms ending at each instrument’s maturity. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.) 

(2) See “Purchase Commitments” and “Other Commitments” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8.

(3) See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. Payments into the pension and other benefits plans are based on annual 

contribution requirements. As these annual requirements continue indefinitely into the future, the amount shown in the column entitled “more than 5 years” 

represents only 1 year of contributions for the Utility’s pension and other benefit plans. 

(4) Beginning with the three-month period ending January 31, 2018, quarterly cash dividends on the Utility’s preferred stock were suspended. While the timing of 

cumulative dividend payments is uncertain, it is assumed for the table above to be payable within a fixed period of five years based on historical 

performance. (See Note 6 of the Consolidated Financial Statements in Item 8.) 

The contractual commitments table above excludes potential payments associated with unrecognized tax positions. Due to the 

uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amounts and periods 

of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject 

to examination are discussed in Note 8 of the Notes to the Consolidated Financial Statements in Item 8. 

Off-Balance Sheet Arrangements 

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, 

a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of 

operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 13 of the Notes to the 

Consolidated Financial Statements (the Utility’s commodity purchase agreements) in Item 8. 

ENFORCEMENT AND LITIGATION MATTERS 

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to 

the enforcement and litigation matters described in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 and

Legal Proceedings in Item 3. The outcome of these matters, individually or in the aggregate, could have a material effect on 

PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. 

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REGULATORY MATTERS 

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC, and other federal and state regulatory agencies. 

The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s financial condition, results of 

operations, and cash flows. 

The Utility is still analyzing the impact of the Tax Act on revenue requirements and rate base for the 2017 GRC, the 2015 GT&S 

Rate Case, the recently submitted 2019 GT&S Rate Case, and the pending TO19 rate case. However, on an aggregate basis, the 

Utility currently 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. 

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. As discussed below, the 2017 GRC final 

decision established a tax memorandum account to track revenue differences resulting from tax law changes, among other items, 

for disposition in the 2020 GRC. The March filings will accelerate that timing. (See “Tax Cuts and Jobs Act of 2017” in Item 7. 

MD&A and Note 3 and Note 8 in the Notes to the Consolidated Financial Statements.) 

2017 General Rate Case 

On May 11, 2017, the CPUC issued a final decision in the Utility’s 2017 GRC, which determined the annual amount of base 

revenues (or “revenue requirements”) that the Utility is authorized to collect from customers from 2017 through 2019 to recover its 

anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an 

opportunity to earn its authorized rate of return. The final decision approved, with certain modifications, the settlement agreement 

that the Utility, the ORA, TURN, and 12 other intervening parties jointly submitted to the CPUC on August 3, 2016 (the 

“settlement agreement”). Modifications from the settlement agreement to the final decision included a tax memorandum account 

and approval of a stand-alone application with the CPUC or a filing in the CPUC’s ongoing residential rate reform proceeding to

recover customer outreach and other costs incurred as a result of residential rate reform implementation. The new tax 

memorandum account will track any revenue differences resulting from changes in income tax expense caused by net revenue 

changes, mandatory or elective tax law changes, tax accounting changes, tax procedural changes, or tax policy changes during the 

2017 through 2019 GRC period. The account will remain open and the balance in the account will be reviewed in every 

subsequent GRC proceeding until a CPUC decision closes the account. 

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The final decision approved a revenue requirement increase of $88 million for 2017, with additional increases of $444 million in 

2018 and $361 million in 2019, in line with the amounts proposed in the settlement agreement. The following table shows the 

revenue requirement amounts approved in the final decision based on line of business and cost category as well as the differences 

between the 2016 authorized revenue requirements and the amounts approved in the final decision: 

 Increase/ 

 Amounts (Decrease) 

(in millions) Approved in 2016 vs. 

Line of Business: Final Decision (1) Final Decision 

Electric distribution $ 4,151 $ (62) 

Gas distribution 1,738 (3) 

Electric generation 2,115 153 

Total revenue requirements $ 8,004 $ 88 

 

(in millions) 

Cost Category: 

Operations and maintenance $ 1,794 $ 131 

Customer services 334 15 

Administrative and general 912 (99) 

Less: Revenue credits (152) (21) 

Franchise fees, taxes other than income, and other adjustments 170 132 

Depreciation (including costs of asset removal), return, and 

 income taxes 4,946 (70) 

Total revenue requirements $ 8,004 $ 88 

(1) Amounts approved in the final decision are the same as the amounts that were proposed in the settlement agreement.

As required by the final decision, the Utility has submitted a variety of compliance filings, including filings on June 12, 2017, 

which provides accounting for the January 2017 $300 million expense reduction announcement and on July 10, 2017, providing an 

update of the cost effectiveness study for the SmartMeterTM Upgrade project. On February 8, 2018, the CPUC extended the 

statutory deadline for the 2017 GRC from February 8, 2018 to August 9, 2018, in order to allow for comments and CPUC action 

on any PD on the SmartMeterTM Upgrade cost effectiveness study, as well as one other remaining GRC compliance item. 

2020 General Rate Case 

The Utility expects to file the 2020 GRC by September 1, 2018. On November 30, 2017, the Utility filed its first RAMP submittal

to the CPUC in advance of its 2020 GRC filing. The RAMP is a new CPUC requirement directing each large energy utility to 

submit a report describing how it assesses its risks and how it plans to mitigate and minimize such risks in advance of the utility’s 

GRC application. The objective of this filing is to inform the CPUC of the Utility’s top safety-related risks, risk assessment

procedures, and proposed mitigations of those risks for 2020-2022. 

The SED is expected to submit a report on the Utility’s RAMP submittal and hold a workshop on the report, after which parties 

will have the opportunity to file comments. The RAMP results will be incorporated in the Utility’s 2020 GRC. 

2015 Gas Transmission and Storage Rate Case 

During 2016, the CPUC issued final decisions in phase one and phase two of the Utility’s 2015 GT&S rate case. The phase one 

decision adopted the revenue requirements that the Utility is authorized to collect through rates beginning August 1, 2016, to 

recover its costs of gas transmission and storage services for the 2015 GT&S rate case period (2015 through 2018). The phase two 

decision determined the allocation of the $850 million penalty assessed in the San Bruno Penalty Decision and the revenue 

requirement reduction for the five-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this 

proceeding. 

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The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount 

adopted. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject 

to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. A draft of 

the audit report is expected in the first quarter of 2018. The decision established new one-way balancing accounts to track costs as 

well as various cost caps that will increase the risk of disallowance over the current rate case cycle. The Utility would be required 

to take a charge in the future if the CPUC’s audit of 2011 through 2014 capital spending resulted in additional permanent 

disallowance. 

In August 2016 and January 2017, TURN, ORA and Indicated Shippers filed applications for rehearing of the phase one and phase 

two decisions, respectively. The Utility cannot predict when or if the CPUC will grant the rehearings or if it will adopt the parties’ 

recommendations. Additionally, in June 2017, the Utility filed a PFM of the phase one decision to eliminate the requirement that 

the Utility install new cathodic protection systems in 2018 because the Utility is not in a position to identify the optimal location 

for such new systems in 2018. Instead, the Utility requested to be allowed to continue its current cathodic protection program. As 

directed by the CPUC, on August 23, 2017, the Utility provided supplemental information to the CPUC regarding the PFM. The 

Utility is unable to predict if and when the CPUC would adopt the PFM. In the event the PFM is not adopted and the Utility fails 

to perform the mandated new cathodic protection systems, the Utility could incur fines and penalties, the amount of which the 

Utility is unable to predict. 

2019 Gas Transmission and Storage Rate Case 

On November 17, 2017, the Utility filed its 2019 GT&S rate case application with the CPUC, covering the years 2019 through 

2021. While the Utility has not formally proposed a fourth year for this rate case, it provided a revenue requirement and rates for 

2022, in the event the CPUC adopts an additional year. 

In its application, the Utility requested that the CPUC authorize a 2019 revenue requirement of $1.59 billion to recover anticipated 

costs of providing natural gas transmission and storage services beginning on January 1, 2019. This corresponds to an increase of 

$289 million over the Utility’s 2018 authorized revenue requirement of $1.30 billion. The Utility’s request also includes proposed 

revenue requirements of $1.73 billion for 2020, $1.91 billion for 2021, and $1.91 billion for 2022 if the CPUC orders a fourth year 

for the rate case period. 

The requested rate base for 2019 is $4.66 billion, which corresponds to an increase of $0.95 billion over the 2018 authorized rate 

base of $3.71 billion. These rate base amounts exclude approximately $576 million of capital spending subject to audit by the 

CPUC related to 2011 through 2014 expenditures in excess of amounts adopted in the 2011 GT&S rate case. The Utility is unable 

to predict whether the $576 million, or a portion thereof, will ultimately be authorized by the CPUC and included in the Utility’s 

future rate base. The Utility’s request also excludes rate base adjustments that the Utility requested with the CPUC on November 

14, 2017, resulting from the IRS’s October 5, 2017 private letter ruling issued in connection with the CPUC’s final phase two 

decision in the 2015 GT&S rate case. The Utility’s request is based on capital expenditure forecasts of $971 million for 2019,

$963 million for 2020, and $804 million for 2021 (which exclude common capital allocations).

The increase in revenue requirement is largely attributable to increased infrastructure investment and costs related to new natural 

gas storage safety and environmental regulations. Such new regulations were issued by: (1) the DOGGR, which issued six new 

safety and reliability natural gas storage measures in 2016 in response to the 2015 Southern California natural gas storage leak in 

Aliso Canyon; (2) the PHMSA, which issued interim final rules, effective January 18, 2017, that address pipeline safety issues and 

mandate certain reporting requirements for operators of underground natural gas storage facilities; and (3) the CPUC, which issued 

General Order 112-F that became effective on January 1, 2017, and requires additional expenditures in the areas of gas leak repair, 

leak survey, and high consequence area identification, among other things.

In addition, DOGGR is planning to complete its final rulemaking on new gas storage safety rules. The draft rules, that were 

released for comments on May 19, 2017, include a requirement for natural gas storage operators to perform well integrity 

assessments every two years and to eliminate possible single points of failure from natural gas storage wells. The implementation 

timeframe and requirements under the PHMSA’s proposed regulations currently are being challenged in federal courts. In its 

application, the Utility proposes a new two-way Gas Storage Balancing Account to address uncertainty around the anticipated 

DOGGR regulations, and also proposes a new memorandum account to track costs related to other anticipated new regulations. 

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As a result of the existing and anticipated gas storage safety requirements, the Utility developed and proposed 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. The discontinuation is expected to reduce long-term costs for customers and to reduce safety and environmental 

risks.

In addition to costs related to new natural gas storage safety and environmental regulations, the Utility proposed increased 

infrastructure investments over the 2019 to 2021 period to continue its efforts to improve overall system safety by: (1) making

approximately 1,100 miles of transmission pipelines capable of in-line inspection; (2) performing in-line inspections of over 2,100 

miles of transmission pipeline, or approximately one-third of total miles; (3) testing or replacing all pipeline without a test record 

(or with a test record that does not meet the Utility’s documentation requirements) by 2027; (4) replacing vintage pipeline for other 

safety or reliability issues; and (5) automating valves in areas where there is a significant potential impact.

A prehearing conference took place on January 4, 2018, and established a procedural schedule. Testimony will be served near the

end of second quarter of 2018 and evidentiary hearings, if needed, will begin in the third quarter of 2018. As stated above, the 

Utility expects to file an update of its revenue requirement forecast to reflect the Tax Act by the end of March 2018. 

Transmission Owner Rate Cases 

Transmission Owner Rate Case for 2017 (the “TO18 rate case”) 

On July 29, 2016, the Utility filed its TO18 rate case at the FERC requesting a 2017 retail electric transmission revenue 

requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network 

transmission rate base for 2017 is $6.7 billion. The Utility is also seeking a return on equity of 10.9%, which includes an incentive 

component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it will 

make investments of $1.30 billion in 2017 in various capital projects. 

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and set it for hearing, but held the 

hearing procedures in abeyance for settlement procedures. The order set an effective date for rates of March 1, 2017, and made the 

rates subject to refund following resolution of the case. On March 17, 2017, the FERC chief judge issued an order terminating the 

settlement procedures due to an impasse in the settlement negotiations reported by the parties. 

On August 22, 2017, the FERC trial staff submitted testimony. The table below summarizes the differences between the amount 

of revenue requirement increases included in the Utility’s request and the testimony submitted by the FERC trial staff: 

 Amounts Amounts 

 requested by proposed by the 

(in millions) the Utility FERC trial staff 

Revenue Requirement $ 1,718 $ 1,353 

Return on Equity 10.90 % 8.46 %

Composite Depreciation Rate 3.26 % 2.08 %

Additionally, intervenors provided testimony on July 5, 2017 and the Utility submitted rebuttal testimony on October 9, 2017. 

Hearings in this proceeding took place January 9 through January 30, 2018, and an initial decision is expected on or before June 1, 

2018. 

Also, on March 31, 2017, several of the parties that had already intervened in the TO18 rate case filed a complaint at the FERC, 

and requested that the complaint be consolidated with the rate case. The complaint asserts that the Utility’s revenue requirement 

request in TO18 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO18 is 

that the Utility’s revenue requirement should be set at a lower level than the revenue requirement from the TO17 settlement, that 

the FERC order refunds to that lower level determined in TO18 litigation. On April 20, 2017, the Utility answered the complaint, 

requesting that FERC dismiss it. On November 16, 2017, FERC dismissed the complaint as the Utility had requested. On 

December 18, 2017, the complainants filed a request for rehearing of that order, and on January 16, 2018, FERC issued an order 

granting rehearing for further consideration. That order does not address the merits of the complaint; it simply gives FERC more 

time to reconsider its prior order dismissing the complaint. The Utility is unable to predict when FERC may issue an order on the 

merits of the complaint. 

 

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Transmission Owner Rate Case for 2018 (the “TO19 rate case”) 

On July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue 

requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted 

network transmission rate base for 2018 is $6.9 billion. The Utility is also seeking an ROE of 10.75%, which includes an incentive 

component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital 

expenditures of approximately $1.4 billion. On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 

filing, subject to hearing and refund, and established March 1, 2018, as the effective date for rate changes. The next settlement 

conference is scheduled for May 16, 2018. FERC also ordered that the hearings will be held in abeyance pending settlement 

discussion among the parties. 

On September 29, 2017, several of the parties that have intervened in the TO19 rate case filed a complaint at the FERC, and 

requested that the complaint be consolidated with the TO19 rate case. The complaint asserts that the Utility’s revenue requirement 

request in TO19 is unreasonably high and should be reduced. The complaint asks that, if the outcome of the litigation in TO19 is 

that the Utility’s revenue requirement should be set at a lower level than the settled revenue requirement approved by FERC in 

TO17, FERC order refunds to that lower level determined in the TO18 litigation. On October 17, 2017, the Utility answered the 

complaint, requesting that FERC dismiss it. The Utility is unable to predict when and how the FERC will respond to the 

complaint. 

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases) 

On January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion reversing FERC’s decisions in the TO16 and TO17 rate 

cases to grant the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO. The decision has been 

remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion. If FERC makes findings consistent with 

the Ninth Circuit Court of Appeals’ opinion, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 

and TO17, respectively. Alternatively, if FERC again concludes that the Utility should receive the 50 basis point ROE incentive

adder and provides the additional explanation that the Ninth Circuit found the FERC’s prior decisions lacked, then the Utility 

would not owe any refunds for this issue for TO16 or TO17. The Utility is unable to predict the outcome and timing of FERC’s 

response to this opinion. 

Diablo Canyon Nuclear Power Plant 

Joint Proposal for Plant Retirement

On August 11, 2016, the Utility submitted an application to the CPUC to retire Diablo Canyon at the expiration of its current 

operating licenses in 2024 and 2025 and replace it with a portfolio of energy efficiency and GHG-free resources. The application 

implements a joint proposal between the Utility and the Friends of the Earth, Natural Resources Defense Council, Environment 

California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, and Alliance

for Nuclear Responsibility (together, the “Joint Parties”). 

On January 11, 2018, the CPUC issued a final decision in the Utility’s proposal to retire Diablo Canyon Unit 1 by 2024 and Unit 2 

by 2025. The CPUC also: 

x deferred consideration of replacement resources to the CPUC’s Integrated Resource Planning proceeding; 

x authorized rate recovery for up to $211.3 million (compared with the $352.1 million requested by the Utility) for an 

employee retention program; 

x authorized rate recovery for an employee retraining program of $11.3 million requested by the Utility; 

x rejected rate recovery of the proposed $85 million for the community impacts mitigation program on the ground that rate 

recovery for such a program requires legislative authorization; 

x authorized rate recovery of $18.6 million of the total Diablo Canyon license renewal cost of $53 million and rate 

recovery of cancelled project costs equal to 100% of direct costs incurred prior to June 30, 2016, and 25% of direct costs 

incurred after June 30, 2016, based on a settlement agreement among the Utility, the Joint Parties, and certain other 

parties that the Utility filed with the CPUC in May 2017; and 

x approved the amortization of the book value for Diablo Canyon consistent with the Diablo Canyon closure schedule. 

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During the year ended December 31, 2017, the Utility incurred pre-tax charges of $47 million related to the retirement of Diablo 

Canyon including $24 million for cancelled projects and $23 million for disallowed license renewal costs. The Utility does not

expect to incur additional charges as a result of the CPUC’s final decision, other than additional project cancellation costs that the 

Utility does not expect to be material. 

The Joint Parties determined that they will not seek a rehearing on the CPUC final decision. In accepting the CPUC’s decision to 

retire Diablo Canyon, the Utility will withdraw its license renewal application at the NRC. 

California State Lands Commission Lands Lease 

On June 28, 2016, the California State Lands Commission approved a new lands lease for the intake and discharge structures at 

Diablo Canyon to run concurrently with Diablo Canyon’s current operating licenses, until Diablo Canyon Unit 2 ceases operations

in August 2025. The Utility believes that the approval of the new lease will ensure sufficient time for the Utility to identify and 

bring online a portfolio of GHG-free replacement resources. The Utility will submit a future lease extension request to address the 

period of time required for plant decommissioning, which under NRC regulations can take as long as 60 years. On August 28, 

2016, the World Business Academy filed a writ in the Los Angeles Superior Court asserting that the State Lands Commission 

committed legal error when it determined that the short term lease extension for an existing facility was exempt from review under 

the California Environmental Quality Act and alleging that the State Lands Commission should be required to perform an 

environmental review of the new lands lease. The trial took place on July 11, 2017, in Los Angeles Superior Court and the judge 

dismissed the petition on all grounds, ruling that the State Lands Commission properly determined the short term lease extension 

was subject to the existing facilities exemption under the California Environmental Quality Act. The World Business Academy 

appealed this decision and the matter is currently before the California Court of Appeals in Los Angeles, Second District. The trial 

date has not been set. 

Asset Retirement Obligations 

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating 

licenses. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in 

conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions 

such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility 

recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility 

expects will continue until those costs are fully recovered. 

While the NDCTP forecast includes employee severance program estimates, it does not include estimated costs related to the final 

decision’s employee retention and retraining and development programs, and the San Luis Obispo County community mitigation 

program described above. The Utility intends to conduct a site-specific decommissioning study to update the 2015 NDCTP 

forecast and to submit the study to the CPUC by mid-2019. 

The Utility expects to file its 2018 NDCTP application in late 2018 or early 2019. (See “Asset Retirement Obligations” in Note 2 

to the Consolidated Financial Statements in Item 8.) 

CPUC Cost of Capital

On July 13, 2017, the CPUC issued a final decision adopting, with no modifications to it, the PFM filed in February 2017 by San

Diego Gas & Electric Company, Southern California Gas Company, Southern California Edison, the ORA, TURN, and the Utility. 

The final decision extends the Utility’s next cost of capital application filing deadline by two years to April 22, 2019, for the year 

2020. The final decision also reduces the Utility’s authorized ROE from 10.40% to 10.25%, effective January 1, 2018, and resets 

the Utility’s authorized cost of long-term debt and preferred stock effective January 1, 2018. In addition, the decision suspends the 

cost of capital adjustment mechanism to adjust cost of capital for 2018, but allows the adjustment mechanism to operate for 2019 if 

triggered. If the mechanism is activated for 2019, the Utility’s cost of capital, including its new ROE of 10.25%, will be adjusted 

according to the existing terms of the mechanism. The Utility’s current capital structure of 52% common equity, 47% long-term 

debt, and 1% preferred equity remains unchanged. 

 

The final decision also leaves the proceeding open to facilitate gathering of information to inform the next cost of capital 

proceeding, as well as to provide a possible venue in which to consider whether the Utility’s ROE should be reduced until any 

recommendations that the CPUC may adopt in the second phase of its safety culture investigation are implemented, as described in 

the May 8, 2017 scoping memo and ruling issued in the Safety Culture OII. 

 

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On September 29, 2017, the Utility submitted an advice letter to the CPUC, updating its cost of capital and the estimated revenue 

requirement impacts with an effective date of January 1, 2018. The long-term debt cost, reset to 4.89%, reflects actual embedded 

costs as of the end of August 2017 and forecasted interest rates for the new long-term debt expected to be issued for the remainder 

of 2017 and all of 2018. Changes in market interest rates may have material effects on the cost of the Utility’s future financings, 

but will not affect the authorized cost of capital in 2018. 

The Utility expects to file its next cost of capital application in 2019. 

Application to Establish a Wildfire Expense Memorandum Account 

On July 26, 2017, the Utility filed an application with the CPUC requesting to establish a WEMA to track wildfire expenses and to 

preserve the opportunity for the Utility to request recovery of wildfire costs in excess of insurance at a future date. Concurrently 

with this application, the Utility also submitted a motion to the CPUC requesting that the WEMA be deemed effective as of July 

26, 2017, such that the Utility may begin recording costs to the account while the application is pending before the CPUC. 

Under the WEMA as proposed, the Utility would record costs related to wildfires, including: (1) payments to satisfy wildfire 

claims, including any deductibles, co-insurance and other insurance expense paid by the Utility but excluding costs that have 

already been authorized in the Utility’s GRC; (2) outside legal costs incurred in the defense of wildfire claims; (3) premium costs 

not in rates; and (4) the cost of financing these amounts. Insurance proceeds, as well as any payments received from third parties, 

would be credited to the WEMA as they are received. The WEMA would not include the Utility’s costs for fire response and 

infrastructure costs which are tracked in CEMA. The Utility would be required to file an application to seek approval to recover 

costs tracked in WEMA. A prehearing conference was held on December 8, 2017, and a scoping memo was issued on January 11, 

2018. The Utility filed opening briefs with the CPUC on January 25, 2018 and other parties’ briefs are expected to be filed in

February 2018. The Utility cannot predict the outcome of this proceeding. 

Catastrophic Event Memorandum Account Applications 

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events through a CEMA. The 

CEMA tariff authorizes the utilities to recover costs incurred in connection with a catastrophic event that has been declared a

disaster or state of emergency by competent federal or state authorities. In 2014, the CPUC directed the Utility to perform 

additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated

with this work were tracked in the CEMA. While the Utility believes such costs are recoverable through CEMA, its CEMA 

applications are subject to CPUC approval. 

In 2016, the Utility submitted a request to the CPUC to authorize recovery under the CEMA tariff revenue requirement of 

approximately $146 million for recorded capital and expense costs related to drought mitigation and emergency response activities 

for declared disasters that occurred from December 2012 through March 2016. On January 4, 2018, ORA, TURN, and the Utility 

filed an all-party motion with the CPUC seeking approval of a settlement agreement these parties have entered into. The 

settlement agreement proposes that the Utility’s total CEMA tariff revenue requirement request be reduced by $29 million, from 

$146 million to $117 million. The Utility has requested that these costs be recovered through rates in 2018 and 2019. PG&E 

Corporation and the Utility are unable to predict the outcome of this proceeding. 

The Utility expects to submit its 2018 CEMA application to the CPUC in the second quarter of 2018. 

Other Regulatory Proceedings and Initiatives 

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed DRP for approval by the CPUC. The Utility’s plan 

identifies optimal locations on its electric distribution system for deployment of DERs. The Utility’s proposal is designed to allow 

energy technologies to be integrated into the larger grid while continuing to provide customers with safe, reliable, and affordable 

electric service. 

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On February 27, 2017, the CPUC issued a ruling that seeks the development of a process for incorporating DER forecasts into the

DRP that takes into consideration the coordination with other statewide planning and forecasting processes such as the CEC’s 

Integrated Energy Policy Report. This ruling mandated the Utility, along with the other California IOUs, to develop a draft joint 

proposal for the CPUC and stakeholder consideration on the process for developing DER forecasts. On June 9, 2017, the IOUs 

submitted a draft joint proposal for CPUC and stakeholder consideration. The CPUC issued a PD on December 8, 2017, requiring 

the IOUs to use the CEC’s DER forecast for the 2018-2019 distribution planning cycle. The Utility has historically used the CEC 

forecast for planning and will have the opportunity to adjust forecasts for EV, photovoltaic, and energy storage during the 

intermediate years. The PD also requires the IOUs to develop an alternate planning forecast scenario in 2018 to establish a method 

for calculating costs and benefits for DER grid integration to better inform DER sourcing policies. Workshops to discuss the joint 

proposal will continue in early 2018 and a final decision is expected from the CPUC by the end of the first quarter of 2018. 

On June 30, 2017, the CPUC issued another ruling soliciting stakeholder responses on questions set forth in a CPUC staff white 

paper on proposing a DIDF. The DIDF aims to establish a process for identifying distribution deferral opportunities for DERs. 

Stakeholder comments on DIDF were submitted on August 7, 2017, with reply comments submitted on August 18, 2017. On 

December 8, 2017, the CPUC issued a PD requiring an annual grid needs assessment and an annual distribution deferral 

opportunity report, as part of the annual DRP for greater transparency on infrastructure investments. The grid needs assessment 

report will identify critical overload areas on the grid. The distribution deferral opportunity report will document the Utility’s 

proposed distribution needs and identify DER deferral opportunities to be reviewed by the Distribution Planning Advisory Group 

for prioritizing DER deferral projects. The PD proposes to adopt the regulatory incentive mechanism being piloted in the 

Integrated Distributed Energy Resources Proceeding where the Utility can earn a 4% pre-tax incentive on the annual payments for

DER deferral contracts. The Utility expects a final decision from the CPUC in the first quarter of 2018. 

Integrated Distributed Energy Resources Proceeding – Regulatory Incentives Pilot Program 

On April 4, 2016, the CPUC issued a ruling proposing to establish, on a pilot basis, an interim program offering regulatory 

incentives to the Utility and the other two large California IOUs for the deployment of cost-effective DERs. The ruling stated that 

it did not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities. On 

December 22, 2016, the CPUC issued a final decision in the proceeding which authorizes a pilot to test a regulatory incentive 

mechanism through which the Utility will earn a 4% pre-tax incentive on annual payments for DERs, as well as test a regulatory 

process that will allow the Utility to competitively solicit DER services to defer distribution infrastructure. Each IOU is required 

to conduct at least one pilot, but may conduct up to three additional pilots. 

In June 2017, the Utility submitted a pilot project proposal to the CPUC for approval to begin solicitations. The pilot aims to 

evaluate the effectiveness of an earnings opportunity in motivating utilities to source DERs. On October 27, 2017, the CPUC 

issued a draft resolution that proposed modifications to the Utility’s pilot program. On December 14, 2017, the CPUC granted the 

Utility’s November 20, 2017 request to cancel the current pilot project proposal due to the damage of the Utility’s facilities in the 

area of the Northern California wildfires and propose a new pilot program location by May 1, 2018. 

2015 – 2016 Energy Efficiency Incentive Awards 

On December 14, 2017, the CPUC approved a final 2015 – 2016 energy savings performance incentive award of $21.9 million, 

compared to the Utility’s request of $24.7 million. The award was fully offset by a portion of the remaining reduction approved in 

the settlement agreement related to the rehearing of the 2006 – 2008 risk/reward incentive mechanism. The settlement agreement

requires the Utility to reduce future energy efficiency shareholder incentives by a total of $29.1 million, of which $5.8 million was 

used to offset the 2014 – 2015 award. The remaining settlement reduction of $1.3 million will be offset against future energy 

saving performance incentive awards.

LEGISLATIVE AND REGULATORY INITIATIVES 

 

The California Legislature and the CPUC have adopted requirements, policies, and decisions to implement new state law 

requirements applicable to natural gas storage facilities, accommodate the growth in distributed electric generation resources 

(including solar installations), increase the amount of renewable energy delivered to customers, improve fire safety regulations, 

and foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles. In 

addition, the CPUC continues to implement state law requirements to reform electric rates to more closely reflect the utilities’ 

actual costs of service, and reduce cross-subsidization among customer rate classes. CPUC proceedings related to some of these

matters are discussed below. 

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The Utility’s ability to recover its costs, including investments associated with legislative and regulatory initiatives, as well as its 

electricity procurement and other operating costs, will, in large part, depend on the final form of legislative or regulatory 

requirements, and whether the associated ratemaking mechanisms can be timely adjusted to reflect changes in customer demand 

for the Utility’s electricity and natural gas service. 

Power Charge Indifference Adjustment OIR 

On April 25, 2017, the Utility, along with Southern California Edison Company and San Diego Gas & Electric Company, filed a 

joint application with the CPUC on how to allocate costs associated with long-term power commitments in a manner that ensures 

all customers are treated equally. At issue is how customers within communities that choose to implement CCA power 

arrangements and those served under direct access pay for their share of the costs. The utilities believe that these customers are 

not paying their full share of costs associated with the long-term commitments, which results in other customers paying more, 

which is inconsistent with state law. The Utility is committed to helping create a cost allocation method that treats all customers 

fairly and equally, whether they continue to receive service from the Utility or choose a CCA or direct access provider. The Utility 

projects that more than half of its customers will purchase electricity from a CCA or direct access provider by 2020. Without 

changes to the current cost allocation system, a portion of the contract and facilities costs will be shifted to customers who remain 

with the Utility or live in areas that do not have access to alternative electricity providers. The utilities’ joint proposed approach 

would replace the current system, which is known as the PCIA, with an updated system known as the Portfolio Allocation 

Methodology. 

On June 29, 2017, the CPUC dismissed the Utility’s joint Portfolio Allocation Methodology application without prejudice and 

instead approved an OIR to review, revise, and consider alternatives to the PCIA. The OIR will focus on PCIA within the larger

context of consumer choice in energy services, and should not be considered a follow-up to the CPUC and Energy Commission 

Joint En Banc on Customer Choice in California. On September 25, 2017, the CPUC issued a scoping memo and ruling 

establishing a procedural schedule and a new overall goal to mitigate cost increases for both bundled and departing load customers. 

Testimony is scheduled for the first quarter of 2018. Evidentiary hearings, if needed, are scheduled for the second quarter of 2018 

and a proposed decision is expected by the third quarter of 2018. 

Customer Choice 

On May 19, 2017, California energy companies, along with other stakeholders discussed customer choice and the future of 

California’s electric industry at a CPUC “en banc” meeting. Specifically, the goal of the meeting 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. 

On October 11, 2017, the CPUC announced the formation of the California Customer Choice Project to examine the issues and 

produce a report evaluating regulatory framework options in early 2018. The CPUC held an informal public workshop on October 

31, 2017, to gather stakeholder input on global and national electric market choice models, including California’s 2020 market. 

The project may produce a white paper that will provide a framework to evaluate customer choice models based on affordability, 

decarbonization, and reliability. The white paper will not present a recommendation nor is it intended to provide the basis for 

instituting a rulemaking. 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.

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Electric Vehicle (EV) Infrastructure Development

In December 2014, the CPUC issued a decision adopting a policy to expand the California utilities’ role in developing EV 

charging infrastructure to support California’s climate goals. On February 9, 2015, the Utility filed an application requesting that 

the CPUC approve the Utility’s proposal to deploy, own, and maintain EV charging stations and the associated infrastructure. On 

December 15, 2016, the CPUC issued a final decision establishing a three-year EV program of $130 million (approximately $109 

million in capital expenditures) to deploy up to 7,500 charging stations. Further deployment of light-duty EV infrastructure will be 

considered in a second phase of the proceeding. 

Transportation Electrification (TE) 

California Law (SB 350) requires the CPUC, in consultation with the CARB and the CEC, to direct electrical corporations to file

applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the 

other large IOUs to file TE applications which include both short-term projects (of up to $20 million in total) and two- to five-year 

programs with a requested revenue requirement determined by the Utility. On January 20, 2017, the Utility filed its TE application 

with the CPUC requesting a total of up to $253 million (approximately $211 million in capital expenditures) in program funding 

over five years (2018 - 2022) related to make-ready infrastructure for TE in medium to heavy-duty vehicle sectors, fast charging 

stations, and short-term projects which includes a series of TE demonstration projects and pilot programs. On January 11, 2018, 

the CPUC approved, with modifications, four out of the five short-term projects proposed by the Utility for a total of 

approximately $8 million. The CPUC may issue a proposed decision on the make-ready infrastructure proposals in the first or 

second quarter of 2018. 

Fire Safety OIR 

On December 14, 2017, the CPUC approved new regulations to enhance the fire safety of overhead electric transmission and 

distribution lines located in high fire-threat areas. This is the culmination of a decade-long effort to improve the fire safety of 

overhead utility and communication infrastructure across California. The SED conferred with Cal Fire, California IOUs, and fire

safety professionals, to develop and adopt a statewide fire-threat map. This map, in conjunction with a United States Forest Service 

and Cal Fire map of tree mortality high hazard zones, will dictate the application of the new fire safety regulations. On January 19, 

2018, the CPUC approved the final fire safety map associated with the new regulations. 

The new regulations include increased patrol frequency for overhead facilities, expanded vegetation clearances around powerlines, 

and give the utilities increased authority to de-energize lines on private property for the removal of trees that pose an immediate 

threat to fire safety. The costs associated with the implementation of these new regulations will be tracked in a fire hazard 

prevention memorandum account and requested for recovery through rates. 

ENVIRONMENTAL MATTERS 

The Utility’s operations are subject to extensive federal, state, and local laws and permits 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 the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of CO2 and other GHG 

emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas 

storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Item 1A. Risk Factors,

“Environmental Regulation” in Item 1. and “Environmental Remediation Contingencies” in Note 13 of the Notes to the 

Consolidated Financial Statements in Item 8.) 

RISK MANAGEMENT ACTIVITIES 

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse 

changes in commodity prices, interest rates, and counterparty credit. 

The Utility actively manages market risk through risk management programs designed to support business objectives, discourage 

unauthorized risk-taking, reduce commodity cost volatility, and manage cash flows. The Utility uses derivative instruments only 

for non-trading purposes (i.e. risk mitigation) and not for speculative purposes. The Utility’s risk management activities include 

the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and 

agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. 

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Commodity Price Risk 

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the 

procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. 

As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and 

natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings. Such fluctuations, 

however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully 

recoverable through a ratemaking mechanism. 

The Utility’s current authorized revenue requirement for natural gas transportation and storage service to non-core customers is not 

balancing account protected. The Utility recovers these costs in its gas transmission and storage rate cases through fixed 

reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk. The Utility uses 

value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $8 million and $7 

million at December 31, 2017 and 2016, respectively. During 2017, the Utility’s approximate high, low, and average values-atrisk were $8 million, $7 million and $7 million, respectively. During 2016, the value-at-risk amounts were $7 million, $1 million 

and $4 million, respectively. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of 

price risk management activities.) 

Interest Rate Risk 

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result 

of assumed changes in market interest rates. At December 31, 2017 and 2016, if interest rates changed by 1% for all PG&E 

Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the impact on net income over the next 

12 months would be $12 million and $13 million, respectively, based on net variable rate debt and other interest rate-sensitive

instruments outstanding. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of

interest rates.) 

Energy Procurement Credit Risk 

The Utility conducts business with counterparties mainly in the energy industry, including the CAISO market, other California 

investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, electricity generation 

companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to 

perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas 

at current market prices, which may be higher than the contract prices. 

The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial 

conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored 

periodically. The Utility executes many energy contracts under master commodity enabling agreements that may require security 

(referred to as “Credit Collateral” in the table below). Credit collateral may be in the form of cash or letters of credit. The Utility 

may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible 

securities (as deemed appropriate by the Utility). Credit collateral or performance assurance may be required from counterparties 

when current net receivables and replacement cost exposure exceed contractually specified limits. 

 

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The following table summarizes the Utility’s energy procurement credit risk exposure to its counterparties: 

 Net Credit 

 Number of Exposure to 

Gross Credit Wholesale Wholesale 

Exposure Customers or Customers or 

 Before Credit Credit Net Credit Counterparties Counterparties

(in millions) Collateral (1) Collateral Exposure (2) >10% >10% 

December 31, 2017 $ 40 $ (16) $ 24 2 12 

December 31, 2016 $ 69 $ (11) $ 58 3 39 

 (1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, and net receivables (payables) where netting is contractually 

allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity. 

(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit posted by counterparties and 

held by the Utility). For purposes of this table, parental guarantees are not included as part of the calculation.

CRITICAL ACCOUNTING POLICIES 

The preparation of the Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions 

that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of 

revenues and expenses during the reporting period. The accounting policies described below are considered to be critical 

accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position 

and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments

and estimates. Actual results may differ materially from these estimates and assumptions. These accounting policies and their key 

characteristics are outlined below. 

Regulatory Accounting 

As a regulated entity, the Utility records regulatory assets and liabilities for amounts that are deemed probable of recovery from, or 

refund to, customers. These amounts would otherwise be recorded to expense or income under GAAP. Refer to “Regulation and 

Regulated Operations” in Note 2 as well as Note 3 of the Notes to the Consolidated Financial Statements in Item 8. At December

31, 2017, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts 

receivable) of $5.6 billion and regulatory liabilities (including current regulatory balancing accounts payable) of $9.9 billion. 

Determining probability requires significant judgment by management and includes, but is not limited to, consideration of 

testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of 

applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including utility retained generation, 

the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a

regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of 

incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and

unamortized loss, net of gain, on reacquired debt. The CPUC has not denied the recovery of any material costs previously 

recognized by the Utility as regulatory assets for the periods presented. If the Utility determined that it is no longer probable that 

regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the 

regulatory assets would be charged against income in the period in which that determination was made. If regulatory accounting

did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the 

differences in the timing of expense or revenue recognition. 

 

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In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be 

disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments

require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of 

construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be 

recovered. The Utility records a provision based on its best estimate; to the extent there is a high degree of uncertainty in the 

Utility’s forecast, it will record a provision based on the lower end of the range of possible losses. The Utility’s capital forecasts 

involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost 

experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. 

In 2017, the Utility recorded charges of $47 million for capital expenditures related to cancelled projects and disallowed license 

renewal costs as part of the Diablo Canyon settlement agreement. In 2016, the Utility incurred charges of $283 million and $219 

million for capital spending that was disallowed related to the San Bruno Penalty Decision and for capital expenditures disallowed 

based on the final phase two decision in its 2015 GT&S rate case, respectively. In 2015, the Utility incurred charges of $407 

million for capital spending that were disallowed related to the San Bruno Penalty Decision. The Utility would be required to 

record charges in future periods to the extent there are additional capital disallowances. (See “Enforcement and Litigation 

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

Loss Contingencies 

As discussed below, PG&E Corporation and the Utility have recorded material accruals for various enforcement and legal matters 

and environmental remediation liabilities. PG&E Corporation and the Utility have also recorded insurance receivables for thirdparty claims. 

Enforcement and Litigation Matters 

PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as 

parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local 

laws and regulations. PG&E Corporation and the Utility record a provision for a loss contingency when it is both probable that a 

loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the 

range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range 

is a better estimate than any other amount. The assessment of whether a loss is probable or reasonably possible, and whether the 

loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are

reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, 

settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. 

PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as 

incurred. Actual results may differ materially from these estimates and assumptions. (See “Enforcement and Litigation Matters” 

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

Environmental Remediation Liabilities 

The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future 

may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. 

Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former 

manufactured gas plant sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or 

disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site. 

The Utility generally commences the environmental remediation assessment process upon notification from federal or state 

agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to 

determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility 

has begun a program related to certain former manufactured gas plant sites.) Based on such notification, the Utility completes an 

assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility 

records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably 

estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent 

uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective 

and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous 

substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability 

in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. 

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When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs 

incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the 

remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to 

the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and 

maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate 

the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws 

governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation 

effort. 

At December 31, 2017 and 2016, the Utility’s accruals for undiscounted gross environmental liabilities were $1 billion and $958

million, respectively. The Utility’s undiscounted future costs could increase to as much as $2.1 billion if the extent of 

contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially 

able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. 

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs 

may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the 

period in which they are recognized. 

Insurance Receivable 

The Utility has liability insurance from various insurers, which provides coverage for third party claims. The Utility records

insurance recoveries only when a third party claim is recorded and it is deemed probable that a recovery of that claim will occur 

and the Utility can reasonably estimate the amount or its range. The assessment of whether recovery is probable or reasonably

possible, and whether the recovery or a range of recoveries is estimable, often involves a series of complex judgments about future 

events. Insurance recoveries are reviewed quarterly and estimates are adjusted to reflect the impact of all known information,

including contractual liability insurance policy coverage, advice of legal counsel, past experience with similar events, discussions 

with insurers and other information and events pertaining to a particular matter. (See “Enforcement and Litigation Matters” in

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

Asset Retirement Obligations 

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a 

reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset 

retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory 

asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking 

process. (See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8.) 

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about

future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are 

discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. 

At December 31, 2017, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was $4.9 billion. 

Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. 

Pension and Other Postretirement Benefit Plans 

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as 

contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory 

postretirement life insurance plans for eligible employees and retirees. Adjustments to the pension and other benefit obligation are 

based on the differences between actuarial assumptions and actual plan results. These amounts are deferred in accumulated other 

comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense 

recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or 

liabilities as amounts are probable of recovery from customers. To the extent the other benefits are in an overfunded position, the 

Utility records a regulatory liability. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) 

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The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement 

date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the 

average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets. PG&E 

Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation 

and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or 

amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit 

obligations and future plan expenses. 

In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from

industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition 

of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost

trend rate for 2018 is 6.8%, gradually decreasing to the ultimate trend rate of 4.5% in 2027 and beyond. 

Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns 

to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixedincome returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were 

projected based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility’s 

defined benefit pension plan, the assumed return of 6.2% compares to a ten-year actual return of 7.8%. 

The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of 

approximately 623 Aa-grade non-callable bonds at December 31, 2017. This yield curve has discount rates that vary based on the

duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were

matched to the corresponding rates on the yield curve to derive a weighted average discount rate. 

The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions: 

Increase Increase in Projected 

(Decrease) in Increase in 2017 Pension Benefit Obligation at 

 (in millions) Assumption Costs December 31, 2017 

Discount rate (0.50) % $ 111 $ 1,485 

Rate of return on plan assets (0.50) % 73 - 

Rate of increase in compensation 0.50 % 61 348 

The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain 

actuarial assumptions: 

Increase Increase in 2017 Increase in Accumulated 

(Decrease) in Other Postretirement Benefit Obligation at 

 (in millions) Assumption Benefit Costs December 31, 2017 

Health care cost trend rate 0.50 % $ 4 $ 63 

Discount rate (0.50) % 4 142 

Rate of return on plan assets (0.50) % 10 - 

NEW ACCOUNTING PRONOUNCEMENTS 

See Note 2 of the Notes to the Consolidated Financial Statements. 

FORWARD-LOOKING STATEMENTS 

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements 

reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future 

events and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forwardlooking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various 

investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of 

capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets 

and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt 

issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” 

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“believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E 

Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause 

future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, 

include, but are not limited to: 

x the impact of the Northern California wildfires, including the costs of restoration of service to customers and repairs to 

the Utility’s facilities, and whether the Utility is able to recover such costs through CEMA; the timing and outcome of the 

wildfire investigations, including into the causes of the wildfires; whether the Utility may have liability associated with 

these fires; if liable for one or more fires, whether the Utility would be able to recover all or part of such costs through 

insurance or through regulatory mechanisms, to the extent insurance is not available or exhausted; and potential liabilities 

in connection with fines or penalties that could be imposed on the Utility 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; 

x the impact of the Tax Act, and the timing and outcome of the CPUC decision related to the Utility’s future filings in 

connection with the impact of the Tax Act on the Utility’s rate cases and its implementation plan; 

 

x the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within the 

authorized levels of spending and timely recover its costs through rates, and the extent to which the Utility incurs 

unrecoverable costs that are higher than the forecasts of such costs; 

x the timing and outcomes of the 2019 GT&S rate case, TO18 and TO19 rate cases and other ratemaking and regulatory 

proceedings; 

x the timing and outcome of the Butte fire litigation, the timing and outcome of any proceeding to recover costs in excess of 

insurance from customers, if any; the effect, if any, that the SED’s $8.3 million citations issued in connection with the 

Butte fire may have on the Butte fire litigation; and whether additional investigations and proceedings in connection with 

the Butte fire will be opened and any additional fines or penalties imposed on the Utility; 

x whether the CPUC approves the Utility’s application to establish a WEMA to track wildfire expenses and to preserve the 

opportunity for the Utility to request recovery of wildfire costs in excess of insurance at a future date, and the outcome of 

any potential request to recover such costs; 

x the outcome of the probation and the monitorship imposed by the federal court after the Utility’s conviction in the federal 

criminal trial in 2017, the timing and outcomes of the debarment proceeding, the SED’s unresolved enforcement matters 

relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been 

or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, ex 

parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in 

connection with the outcomes; 

x the timing and outcomes of investigations by the U.S. Attorney’s Office in San Francisco and the California Attorney 

General’s office related to communications between the Utility’s personnel and CPUC officials, whether additional 

criminal or regulatory investigations or enforcement actions are commenced with respect to allegedly improper 

communications, and the extent to which such matters negatively affect the final decisions to be issued in the Utility’s 

ratemaking proceedings; 

x the effects on PG&E Corporation and the Utility’s reputations caused by the Utility’s conviction in the federal criminal 

trial in 2017, the state and federal investigations of natural gas incidents and the Northern California wildfires, improper 

communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from 

transmission pipeline rights-of-way; 

x whether the Utility can control its costs within the authorized levels of spending, and successfully implement a 

streamlined organizational structure and achieve project savings, the extent to which the Utility incurs unrecoverable 

costs that are higher than the forecasts of such costs, and changes in cost forecasts or the scope and timing of planned 

work resulting from changes in customer demand for electricity and natural gas or other reasons; 

x whether the Utility is able to successfully adapt its business model to significant change that the electric industry is 

undergoing and the impact such change will have on the natural gas industry; 

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x the impact of increased costs to comply with natural gas regulations, including the SB 887 directing DOGGR and CARB 

to develop permanent regulations for gas storage facility operations in California to comply with new safety and 

reliability measures, the PHMSA rules effective January 18, 2017 regulating gas storage facilities at the federal level; and 

the CPUC General Order 112-F that went into effect on January 1, 2017, that requires additional expenditures in the areas 

of gas leak repair, leak survey, high consequences area identification, and operator qualifications, and could impact the 

Utility’s ability to timely recover such costs; 

x whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and 

information technology systems from cyber- and physical attacks, or other internal or external hazards; 

x the timing and outcome of the complaint filed by the CPUC and certain other parties with the FERC on February 2, 2017 

that requests that the Utility provide an open and transparent planning process for its capital transmission projects that do 

not go through the CAISO’s Transmission Planning Process to allow for greater participation and input from interested 

parties; and the timing and ultimate outcome of the Ninth Circuit Court of Appeals decision on January 8, 2018, to 

reverse FERC’s decision granting PG&E a 50 basis point ROE incentive adder for continued participation in the CAISO 

and remanding the case to FERC for further proceedings; 

x the amount and timing of additional common stock and debt issuances by PG&E Corporation, including the dilutive 

impact of common stock issuances to fund PG&E Corporation’s equity contributions to the Utility as the Utility incurs 

charges and costs, including fines, that it cannot recover through rates; 

x the outcome of the safety culture OII, including its phase two proceeding opened on May 8, 2017, and future legislative or 

regulatory actions that may be taken, such as requiring the Utility to separate its electric and natural gas businesses, or 

restructure into separate entities, or undertake some other corporate restructuring, or implement corporate governance 

changes; 

x the outcome of current and future self-reports, investigations or other enforcement proceedings that could be commenced 

or notices of violation that could be issued relating to the Utility’s compliance with laws, rules, regulations, or orders 

applicable to its operations, including the construction, expansion or replacement of its electric and gas facilities, electric

grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cyber security, 

environmental laws and regulations; and the outcome of notices of violations in connection with the Yuba City incident; 

x the outcomes of the CPUC’s data requests and future PDs, including in connection with the Utility’s SmartMeterTM 

Upgrade cost-benefit analysis, and of the Utility’s PFMs, including in connection with the installation of new cathodic 

protection systems in 2018; 

x the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge 

the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover 

environmental costs in rates or from other sources; 

x the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas 

compressor station site located near Hinkley, California; 

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x the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear 

industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, 

decommissioning, cooling water intake, or other issues; the impact of actions taken by state agencies that may affect the 

Utility’s ability to continue operating Diablo Canyon; whether the Utility will be able to successfully implement its 

retention and retraining and development programs for Diablo Canyon employees as a result of its planned retirement by 

2024 and 2025; 

x the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, 

acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, and other events, that can cause 

unplanned outages, reduce generating output, disrupt the Utility’s service to customers, or damage or disrupt the facilities, 

operations, or information technology and systems owned by the Utility, its customers, or third parties on which the 

Utility relies, and the reparation and other costs that the Utility may incur in connection with such conditions or events; 

the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for 

property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory 

penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of 

claims and sufficient to cover the Utility’s liability; 

x the breakdown or failure of equipment that can cause fires and unplanned outages; and whether the Utility will be subject 

to investigations, penalties, and other costs in connection with such events; 

x how the CPUC and the CARB implement state environmental laws relating to GHG, renewable energy targets, energy 

efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering 

associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and 

whether the Utility is able to timely recover its associated investment costs; 

x whether the Utility’s climate change adaptation strategies are successful; 

x the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and 

recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in 

addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural 

gas and electric services, and an increasing number of customers departing the Utility’s procurement service for CCAs; 

x the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to 

the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in 

connection with price risk management activities; and whether the Utility is able to recover timely its electric generation 

and energy commodity costs through rates, including its renewable energy procurement costs; 

x whether, as a result of Westinghouse’s Chapter 11 proceeding and its planned purchase by Brookfield Business Partners 

L.P., the Utility will experience issues with nuclear fuel supply, nuclear fuel inventory, and related services and products 

that Westinghouse supplies, and whether such proceeding will affect the Utility’s contracts with Westinghouse; 

x the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred 

in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; 

and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially 

following a major event that causes widespread third-party losses; 

x the ability of PG&E Corporation and the Utility to access capital markets and other sources of debt and equity financing 

in a timely manner on acceptable terms; 

x changes in credit ratings which could, among other things, result in higher borrowing costs and fewer financing options, 

especially if PG&E Corporation or the Utility were to lose their investment grade credit ratings; 

x the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities 

and their holding companies, including how the CPUC interprets and enforces the financial and other conditions imposed 

on PG&E Corporation when it became the Utility’s holding company, and whether the ultimate outcomes of the CPUC’s 

pending investigations, the Utility’s conviction in the federal criminal trial, and other enforcement matters will impact the 

Utility’s ability to make distributions to PG&E Corporation, and, in turn, PG&E Corporation’s ability to pay dividends; 

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x the outcome of federal or state tax audits and the impact of any changes in federal or state tax laws, policies, regulations, 

or their interpretation; 

x changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and 

associated tax credits, as a result of the new federal administration; and 

x the impact of changes in GAAP, standards, rules, or policies, including those related to regulatory accounting, and the 

impact of changes in their interpretation or application. 

For more information about the significant risks that could affect the outcome of the forward-looking statements and PG&E 

Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see Item 1A. Risk Factors below 

and a detailed discussion of these matters contained elsewhere in MD&A. PG&E Corporation and the Utility do not undertake any 

obligation to update forward-looking statements, whether in response to new information, future events, or otherwise. 

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. 

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 

Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in Item 7. MD&A and in Note 9: 

Derivatives and Note 10: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8. 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 

PG&E Corporation 

CONSOLIDATED STATEMENTS OF INCOME 

(in millions, except per share amounts) 

Year ended December 31, 

2017 2016 2015 

Operating Revenues 

Electric $ 13,124 $ 13,864 $ 13,657 

Natural gas 4,011 3,802 3,176 

Total operating revenues 17,135 17,666 16,833 

Operating Expenses 

Cost of electricity 4,309 4,765 5,099 

Cost of natural gas 746 615 663 

Operating and maintenance 6,270 7,354 6,951 

Depreciation, amortization, and decommissioning 2,854 2,755 2,612 

Total operating expenses 14,179 15,489 15,325 

Operating Income 2,956 2,177 1,508 

Interest income 31 23 9 

Interest expense (888) (829) (773) 

Other income, net 72 91 117 

Income Before Income Taxes 2,171 1,462 861 

Income tax provision (benefit) 511 55 (27) 

Net Income 1,660 1,407 888 

Preferred stock dividend requirement of subsidiary 14 14 14 

Income Available for Common Shareholders $ 1,646 $ 1,393 $ 874 

Weighted Average Common Shares Outstanding, Basic 512 499 484 

Weighted Average Common Shares Outstanding, Diluted 513 501 487 

Net Earnings Per Common Share, Basic $ 3.21 $ 2.79 $ 1.81 

Net Earnings Per Common Share, Diluted $ 3.21 $ 2.78 $ 1.79 

 

See accompanying Notes to the Consolidated Financial Statements. 

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PG&E Corporation 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 

(in millions) 

Year ended December 31, 

2017 2016 2015 

Net Income $ 1,660 $ 1,407 $ 888 

Other Comprehensive Income 

Pension and other postretirement benefit plans obligations 

 (net of taxes of $0, $1, and $0, at respective dates) 1 (2) (1) 

Net change in investments 

 (net of taxes of $0, $0, and $12 at respective dates) - - (17) 

Total other comprehensive income (loss) 1 (2) (18) 

Comprehensive Income 1,661 1,405 870 

Preferred stock dividend requirement of subsidiary 14 14 14 

Comprehensive Income Attributable to Common Shareholders $ 1,647 $ 1,391 $ 856 

 

See accompanying Notes to the Consolidated Financial Statements. 

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PG&E Corporation 

CONSOLIDATED BALANCE SHEETS 

(in millions) 

Balance at December 31, 

2017 2016 

ASSETS 

Current Assets 

Cash and cash equivalents $ 449 $ 177 

Accounts receivable 

Customers (net of allowance for doubtful accounts of $64 and $58 

at respective dates) 1,243 1,252 

Accrued unbilled revenue 946 1,098 

Regulatory balancing accounts 1,222 1,500 

Other 861 801 

Regulatory assets 615 423 

Inventories 

Gas stored underground and fuel oil 115 117 

Materials and supplies 366 346 

Income taxes receivable - 160 

Other 464 290 

Total current assets 6,281 6,164 

Property, Plant, and Equipment 

Electric 55,133 52,556 

Gas 19,641 17,853 

Construction work in progress 2,471 2,184 

Other 3 2 

Total property, plant, and equipment 77,248 72,595 

Accumulated depreciation (23,459) (22,014) 

Net property, plant, and equipment 53,789 50,581 

Other Noncurrent Assets 

Regulatory assets 3,793 7,951 

Nuclear decommissioning trusts 2,863 2,606 

Income taxes receivable 65 70 

Other 1,221 1,226 

Total other noncurrent assets 7,942 11,853 

TOTAL ASSETS $ 68,012 $ 68,598 

 

See accompanying Notes to the Consolidated Financial Statements. 

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PG&E Corporation 

CONSOLIDATED BALANCE SHEETS 

(in millions, except share amounts) 

Balance at December 31, 

2017 2016 

LIABILITIES AND EQUITY 

Current Liabilities 

Short-term borrowings $ 931 $ 1,516 

Long-term debt, classified as current 445 700 

Accounts payable 

Trade creditors 1,646 1,495 

Regulatory balancing accounts 1,120 645 

Other 517 433 

Disputed claims and customer refunds 243 236 

Interest payable 217 216 

Other 2,010 2,323 

Total current liabilities 7,129 7,564 

Noncurrent Liabilities 

Long-term debt 17,753 16,220 

Regulatory liabilities 8,679 6,805 

Pension and other postretirement benefits 2,128 2,641 

Asset retirement obligations 4,899 4,684 

Deferred income taxes 5,822 10,213 

Other 2,130 2,279 

Total noncurrent liabilities 41,411 42,842 

Commitments and Contingencies (Note 13) 

Equity 

Shareholders' Equity 

Common stock, no par value, authorized 800,000,000 shares; 

514,755,845 and 506,891,874 shares outstanding at respective dates 12,632 12,198 

Reinvested earnings 6,596 5,751 

Accumulated other comprehensive loss (8) (9)

Total shareholders' equity 19,220 17,940 

Noncontrolling Interest - Preferred Stock of Subsidiary 252 252 

Total equity 19,472 18,192 

TOTAL LIABILITIES AND EQUITY $ 68,012 $ 68,598 

See accompanying Notes to the Consolidated Financial Statements. 

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PG&E Corporation 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(in millions) 

Year ended December 31, 

2017 2016 2015 

Cash Flows from Operating Activities 

Net income $ 1,660 $ 1,407 $ 888 

Adjustments to reconcile net income to net cash provided by 

operating activities: 

Depreciation, amortization, and decommissioning 2,854 2,755 2,612 

Allowance for equity funds used during construction (89) (112) (107) 

Deferred income taxes and tax credits, net 1,254 1,030 693 

Disallowed capital expenditures 47 507 407 

Other 307 379 326 

Effect of changes in operating assets and liabilities: 

Accounts receivable 67 (473) (177) 

Butte-related insurance receivable (21) (575) - 

Inventories (18) (24) 37 

Accounts payable 173 180 (55) 

Butte-related third-party claims (129) 690 - 

Income taxes receivable/payable 160 (5) 43 

Other current assets and liabilities 42 83 (288) 

Regulatory assets, liabilities, and balancing accounts, net (387) (1,214) (244) 

Other noncurrent assets and liabilities 57 (219) (355) 

Net cash provided by operating activities 5,977 4,409 3,780 

Cash Flows from Investing Activities 

Capital expenditures (5,641) (5,709) (5,173) 

Decrease in restricted cash - 227 64 

Proceeds from sales and maturities of nuclear decommissioning 

trust investments 1,291 1,295 1,268 

Purchases of nuclear decommissioning trust investments (1,323) (1,352) (1,392) 

Other 23 13 22 

Net cash used in investing activities (5,650) (5,526) (5,211) 

Cash Flows from Financing Activities 

Net issuances (repayments) of commercial paper, net of discount 

of $5, $6, and $3 at respective dates (840) (9) 683 

Short-term debt financing 750 500 - 

Short-term debt matured (500) - (300) 

Proceeds from issuance of long-term debt, net of premium, discount and 

issuance costs of $32, $17 and $27 at respective dates 2,713 983 1,123 

Long-term debt matured or repurchased (1,445) (160) - 

Common stock issued 395 822 780 

Common stock dividends paid (1,021) (921) (856) 

Other (107) (44) (27) 

Net cash provided by financing activities (55) 1,171 1,403 

Net change in cash and cash equivalents 272 54 (28) 

Cash and cash equivalents at January 1 177 123 151 

Cash and cash equivalents at December 31 $ 449 $ 177 $ 123 

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Supplemental disclosures of cash flow information 

Cash received (paid) for: 

Interest, net of amounts capitalized $ (790) $ (726) $ (684) 

Income taxes, net 162 231 77 

Supplemental disclosures of noncash investing and financing activities 

Common stock dividends declared but not yet paid $ - $ 248 $ 224 

Capital expenditures financed through accounts payable 501 403 440 

Noncash common stock issuances 21 20 21 

Terminated capital leases 23 18 - 

 

See accompanying Notes to the Consolidated Financial Statements. 

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PG&E Corporation 

CONSOLIDATED STATEMENTS OF EQUITY 

(in millions, except share amounts) 

 Non 

 Accumulated controlling 

 Other Interest - 

Common Common Comprehensive Total Preferred 

 Stock Stock Reinvested Income Shareholders' Stock of Total 

 Shares Amount Earnings (Loss) Equity Subsidiary Equity 

Balance at December 31, 2014 475,913,404 $ 10,421 $ 5,316 $ 11 $ 15,748 $ 252 $ 16,000 

Net income - - 888 - 888 - 888 

Other comprehensive loss - - - (18) (18) - (18) 

Common stock issued, net 16,112,039 801 - - 801 - 801 

Stock-based compensation amortization - 66 - - 66 - 66 

Common stock dividends declared - - (889) - (889) - (889) 

Tax expense from employee stock plans - (6) - - (6) - (6) 

Preferred stock dividend requirement of 

subsidiary - - (14) - (14) - (14) 

Balance at December 31, 2015 492,025,443 $ 11,282 $ 5,301 $ (7) $ 16,576 $ 252 $ 16,828 

Cumulative effect of change 

in accounting principle - - 29 - 29 - 29 

Net income - - 1,407 - 1,407 - 1,407 

Other comprehensive loss - - - (2) (2) - (2) 

Common stock issued, net 14,866,431 842 - - 842 - 842 

Stock-based compensation amortization - 74 - - 74 - 74 

Common stock dividends declared - - (972) - (972) - (972) 

Preferred stock dividend requirement of 

subsidiary - - (14) - (14) - (14) 

Balance at December 31, 2016 506,891,874 $ 12,198 $ 5,751 $ (9) $ 17,940 $ 252 $ 18,192 

Net income - - 1,660 - 1,660 - 1,660 

Other comprehensive income - - - 1 1 - 1 

Common stock issued, net 7,863,971 416 - - 416 - 416 

Stock-based compensation amortization - 18 - - 18 - 18 

Common stock dividends declared - - (801) - (801) - (801) 

Preferred stock dividend requirement of 

subsidiary - - (14) - (14) - (14) 

Balance at December 31, 2017 514,755,845 $ 12,632 $ 6,596 $ (8) $ 19,220 $ 252 $ 19,472 

 

See accompanying Notes to the Consolidated Financial Statements. 

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95 

Pacific Gas and Electric Company 

CONSOLIDATED STATEMENTS OF INCOME 

(in millions) 

Year ended December 31, 

2017 2016 2015 

Operating Revenues 

Electric $ 13,127 $ 13,865 $ 13,657 

Natural gas 4,011 3,802 3,176 

Total operating revenues 17,138 17,667 16,833 

Operating Expenses 

Cost of electricity 4,309 4,765 5,099 

Cost of natural gas 746 615 663 

Operating and maintenance 6,329 7,352 6,949 

Depreciation, amortization, and decommissioning 2,854 2,754 2,611 

Total operating expenses 14,238 15,486 15,322 

Operating Income 2,900 2,181 1,511 

Interest income 30 22 8 

Interest expense (877) (819) (763) 

Other income, net 65 88 87 

Income Before Income Taxes 2,118 1,472 843 

Income tax provision (benefit) 427 70 (19) 

Net Income 1,691 1,402 862 

Preferred stock dividend requirement 14 14 14 

Income Available for Common Stock $ 1,677 $ 1,388 $ 848 

 

See accompanying Notes to the Consolidated Financial Statements. 

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Pacific Gas and Electric Company 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME 

(in millions) 

Year ended December 31, 

2017 2016 2015 

Net Income $ 1,691 $ 1,402 $ 862 

Other Comprehensive Income 

Pension and other postretirement benefit plans obligations 

(net of taxes of $3, $1, and $1, at respective dates) 4 (1) (2) 

Total other comprehensive income (loss) 4 (1) (2) 

Comprehensive Income $ 1,695 $ 1,401 $ 860 

     

See accompanying Notes to the Consolidated Financial Statements. 

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Pacific Gas and Electric Company 

CONSOLIDATED BALANCE SHEETS 

(in millions) 

Balance at December 31, 

2017 2016 

ASSETS 

Current Assets 

Cash and cash equivalents $ 447 $ 71 

Accounts receivable 

Customers (net of allowance for doubtful accounts of $64 and $58 

at respective dates) 1,243 1,252 

Accrued unbilled revenue 946 1,098 

Regulatory balancing accounts 1,222 1,500 

Other 862 801 

Regulatory assets 615 423 

Inventories 

Gas stored underground and fuel oil 115 117 

Materials and supplies 366 346 

Income taxes receivable - 159 

Other 465 289 

Total current assets 6,281 6,056 

Property, Plant, and Equipment 

Electric 55,133 52,556 

Gas 19,641 17,853 

Construction work in progress 2,471 2,184 

Total property, plant, and equipment 77,245 72,593 

Accumulated depreciation (23,456) (22,012) 

Net property, plant, and equipment 53,789 50,581 

Other Noncurrent Assets 

Regulatory assets 3,793 7,951 

Nuclear decommissioning trusts 2,863 2,606 

Income taxes receivable 64 70 

Other 1,094 1,110 

Total other noncurrent assets 7,814 11,737 

TOTAL ASSETS $ 67,884 $ 68,374 

 

See accompanying Notes to the Consolidated Financial Statements. 

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Pacific Gas and Electric Company 

CONSOLIDATED BALANCE SHEETS 

(in millions, except share amounts) 

Balance at December 31, 

2017 2016 

LIABILITIES AND SHAREHOLDERS' EQUITY 

Current Liabilities 

Short-term borrowings $ 799 $ 1,516 

Long-term debt, classified as current 445 700 

Accounts payable 

Trade creditors 1,644 1,494 

Regulatory balancing accounts 1,120 645 

Other 538 453 

Disputed claims and customer refunds 243 236 

Interest payable 214 214 

Other 2,018 2,072 

Total current liabilities 7,021 7,330 

Noncurrent Liabilities 

Long-term debt 17,403 15,872 

Regulatory liabilities 8,679 6,805 

Pension and other postretirement benefits 2,026 2,548 

Asset retirement obligations 4,899 4,684 

Deferred income taxes 5,963 10,510 

Other 2,146 2,230 

Total noncurrent liabilities 41,116 42,649 

Commitments and Contingencies (Note 13) 

Shareholders' Equity 

Preferred stock 258 258 

Common stock, $5 par value, authorized 800,000,000 shares; 

264,374,809 shares outstanding at respective dates 1,322 1,322 

Additional paid-in capital 8,505 8,050 

Reinvested earnings 9,656 8,763 

Accumulated other comprehensive income 6 2 

Total shareholders' equity 19,747 18,395 

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 67,884 $ 68,374 

 

See accompanying Notes to the Consolidated Financial Statements. 

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Pacific Gas and Electric Company 

CONSOLIDATED STATEMENTS OF CASH FLOWS 

(in millions) 

Year ended December 31, 

2017 2016 2015 

Cash Flows from Operating Activities 

Net income $ 1,691 $ 1,402 $ 862 

Adjustments to reconcile net income to net cash provided by 

operating activities: 

Depreciation, amortization, and decommissioning 2,854 2,754 2,611 

Allowance for equity funds used during construction (89) (112) (107) 

Deferred income taxes and tax credits, net 1,103 1,042 714 

Disallowed capital expenditures 47 507 407 

 Other 283 306 263 

Effect of changes in operating assets and liabilities: 

Accounts receivable 66 (475) (177) 

Butte-related insurance receivable (21) (575) - 

Inventories (18) (24) 37 

Accounts payable 173 179 (2) 

Butte-related third-party claims (129) 690 - 

Income taxes receivable/payable 159 (29) 38 

Other current assets and liabilities 59 112 (315) 

Regulatory assets, liabilities, and balancing accounts, net (390) (1,214) (244) 

 Other noncurrent assets and liabilities 128 (219) (340) 

Net cash provided by operating activities 5,916 4,344 3,747 

Cash Flows from Investing Activities 

Capital expenditures (5,641) (5,709) (5,173) 

Decrease in restricted cash - 227 64 

Proceeds from sales and maturities of nuclear decommissioning 

trust investments 1,291 1,295 1,268 

Purchases of nuclear decommissioning trust investments (1,323) (1,352) (1,392) 

Other 23 13 22 

Net cash used in investing activities (5,650) (5,526) (5,211) 

Cash Flows from Financing Activities 

Net issuances (repayments) of commercial paper, net of discount 

of $5, $6, and $3 at respective dates (972) (9) 683 

Short-term debt financing 750 500 - 

Short-term debt matured (500) - (300) 

Proceeds from issuance of long-term debt, net of premium, discount and 

issuance costs of $32, $17, and $27 at respective dates 2,713 983 1,123 

Repayments of long-term debt (1,445) (160) - 

Preferred stock dividends paid (14) (14) (14) 

Common stock dividends paid (784) (911) (716) 

Equity contribution from PG&E Corporation 455 835 705 

Other (93) (30) (13) 

Net cash provided by financing activities 110 1,194 1,468 

Net change in cash and cash equivalents 376 12 4 

Cash and cash equivalents at January 1 71 59 55 

Cash and cash equivalents at December 31 $ 447 $ 71 $ 59 

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Supplemental disclosures of cash flow information 

Cash received (paid) for: 

Interest, net of amounts capitalized $ (781) $ (717) $ (675) 

Income taxes, net 162 244 77 

Supplemental disclosures of noncash investing and financing activities 

Capital expenditures financed through accounts payable $ 501 $ 403 $ 440 

Terminated capital leases 23 18 - 

 

See accompanying Notes to the Consolidated Financial Statements. 

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Pacific Gas and Electric Company 

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY 

(in millions) 

 Accumulated 

Additional Other Total 

Preferred Common Paid-in Reinvested Comprehensive Shareholders' 

Stock Stock Capital Earnings Income (Loss) Equity 

Balance at December 31, 2014 $ 258 $ 1,322 $ 6,514 $ 8,130 $ 5 $ 16,229 

Net income - - - 862 - 862 

Other comprehensive loss - - - - (2) (2) 

Equity contribution - - 705 - - 705 

Tax expense from employee stock plans - - (4) - - (4) 

Common stock dividend - - - (716) - (716) 

Preferred stock dividend - - - (14) - (14) 

Balance at December 31, 2015 $ 258 $ 1,322 $ 7,215 $ 8,262 $ 3 $ 17,060 

Cumulative effect of change 

in accounting principle - - - 24 - 24 

Net income - - - 1,402 - 1,402 

Other comprehensive loss - - - - (1) (1) 

Equity contribution - - 835 - - 835 

Common stock dividend - - - (911) - (911) 

Preferred stock dividend - - - (14) - (14) 

Balance at December 31, 2016 $ 258 $ 1,322 $ 8,050 $ 8,763 $ 2 $ 18,395 

Net income - - - 1,691 - 1,691 

Other comprehensive income - - - - 4 4 

Equity contribution - - 455 - - 455 

Common stock dividend - - - (784) - (784) 

Preferred stock dividend - - - (14) - (14) 

Balance at December 31, 2017 $ 258 $ 1,322 $ 8,505 $ 9,656 $ 6 $ 19,747 

 

See accompanying Notes to the Consolidated Financial Statements. 

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION 

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 is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the 

licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. 

This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements 

include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s 

Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All 

intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to 

both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on 

a consolidated basis (i.e., the companies operate in one segment). 

The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the 

reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of 

estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of 

contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets 

and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, and pension and other 

postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated

Financial Statements are appropriate and reasonable. 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 and results of operations 

and cash flows during the period in which such change occurred. 

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. See “Northern California Wildfires” in Note 

13 below. 

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 

Regulation and Regulated Operations 

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue 

requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility 

also records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for

nonregulated entities. The Utility capitalizes and records as regulatory assets, costs that would otherwise be charged to expense if 

it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in 

which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility 

records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers 

in the future are also recorded as regulatory liabilities. 

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are 

recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate

regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and 

liabilities are written off. 

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Revenue Recognition 

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for 

the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included 

in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized 

revenue requirements. 

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three 

or four years. The Utility’s ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or 

“decoupled” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that 

have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected

within 24 months. Generally, revenue is recognized ratably over the year. The Utility records a balancing account asset or 

liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. 

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been 

authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand

response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to 

customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for 

differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these 

differences are probable of recovery or refund. These differences have no impact on net income. 

The FERC authorizes the Utility’s revenue requirements in periodic (often annual) TO rate cases. The Utility’s ability to recover 

revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized 

only for amounts billed and unbilled, net of revenues subject to refund. 

Cash and Cash Equivalents 

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or

less. Cash equivalents are stated at fair value. 

Allowance for Doubtful Accounts Receivable 

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts 

receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical 

write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability. 

Inventories 

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. 

Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution 

to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and 

expensed or capitalized to plant, as appropriate, when consumed or installed. 

Emission Allowances 

The Utility purchases GHG emission allowances to satisfy its compliance obligations. Associated costs are recorded as inventory 

and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. Costs are carried at 

weighted-average and are recoverable through rates. 

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Estimated Useful Balance at December 31, 

(in millions, except estimated useful lives) Lives (years) 2017 2016 

Electricity generating facilities (1) 5 to 120 $ 11,843 $ 11,308 

Electricity distribution facilities 15 to 65 31,110 29,836 

Electricity transmission facilities 15 to 75 12,180 11,412 

Natural gas distribution facilities 5 to 60 12,312 11,362 

Natural gas transmission and storage facilities 5 to 62 7,329 6,491 

Construction work in progress 2,471 2,184 

Total property, plant, and equipment 77,245 72,593 

Accumulated depreciation (23,456) (22,012) 

Net property, plant, and equipment $ 53,789 $ 50,581 

 (1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as used based 

on the amount of energy output. (See Note 13 below.) 

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single

depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight 

line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates 

were 3.83% in 2017, 3.73% in 2016, and 3.80% in 2015. The useful lives of the Utility’s property, plant, and equipment are 

authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. 

Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal,

net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged 

against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor 

replacements of property, is charged to operating and maintenance expense as incurred. 

AFUDC 

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they 

go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the 

life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to 

interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt

and equity, respectively, of $38 million and $89 million during 2017, $51 million and $112 million during 2016, and $48 million

and $107 million during 2015. 

Asset Retirement Obligations 

The following table summarizes the changes in ARO liability during 2017 and 2016, including nuclear decommissioning 

obligations: 

(in millions) 2017 2016 

ARO liability at beginning of year $ 4,684 $ 3,643

Revision in estimated cash flows 128 968

Accretion 207 194

Liabilities settled (120) (121)

ARO liability at end of year $ 4,899 $ 4,684

The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility 

cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot 

be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and 

certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased 

property; and restoration of land to specified conditions under certain agreements. 

Property, Plant, and Equipment 

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. 

Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total 

estimated useful lives and balances of its property, plant, and equipment were as follows: 

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Nuclear Decommissioning Obligation 

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in 

conjunction with the NDCTP. On May 25, 2017, the CPUC issued a final decision in the 2015 NDCTP adopting a nuclear 

decommissioning cost estimate of $1.1 billion for Humboldt Bay, corresponding to the Utility’s request, and $2.4 billion for 

Diablo Canyon, representing 64% of the Utility’s request of $3.8 billion. On an aggregate basis, the final decision adopted a $3.5 

billion total nuclear decommissioning cost estimate, compared to $4.8 billion requested by the Utility. Compared to the Utility’s 

estimated cost to decommission Diablo Canyon, the final decision adopts assumptions which lower costs for large component 

removal, site security, decommissioning contractor staff, spent nuclear fuel storage, and waste disposal. The Utility can seek

recovery of these costs in the 2018 NDCTP. The CPUC’s final decision resulted in a $66 million reduction to the ARO on the 

Consolidated Balance Sheets related to the assumed length of the wet cooling period of spent nuclear fuel after plant shut down. 

PG&E Corporation and the Utility recorded an increase of $92 million to the ARO recognized on the Consolidated Balance Sheets, 

to align the decommissioning cost estimate with the CPUC’s final decision on the Utility’s application to retire Diablo Canyon 

Unit 1 by 2024 and Unit 2 by 2025. 

The estimated nuclear decommissioning cost is discounted for GAAP purposes and recognized as an ARO on the Consolidated 

Balance Sheets. The total nuclear decommissioning obligation accrued was $3.5 billion at both December 31, 2017 and 2016. 

The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $4.1 billion at December 31,

2017 (or $7 billion in future dollars). These estimates are based on the 2017 decommissioning cost studies, prepared in accordance 

with CPUC requirements. 

Disallowance of Plant Costs 

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for 

recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be 

reasonably estimated. (See “Enforcement and Litigation Matters” in Note 13 below.) 

Nuclear Decommissioning Trusts 

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear 

decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity 

to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear

decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC. 

The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.” Since the Utility’s nuclear 

decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its 

investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on 

the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. 

Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no 

impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the

trust is determined by specific identification. 

Variable Interest Entities 

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial 

support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that 

has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE. 

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to 

own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary 

beneficiary of any of these VIEs at December 31, 2017, it assessed whether it absorbs any of the VIE’s expected losses or receives 

any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the 

VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most 

significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial 

obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decisionmaking rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. 

Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2017, it did not consolidate any of them. 

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Other Accounting Policies 

For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income 

Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in 

Note 13 herein. 

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended 

December 31, 2017 consisted of the following: 

Pension Other 

(in millions, net of income tax) Benefits Benefits Total 

Beginning balance $ (25) $ 16 $ (9) 

Other comprehensive income before reclassifications: 

Unrecognized prior service cost 

(net of taxes of $4 and $0, respectively) (6) - (6) 

Unrecognized net actuarial loss 

(net of taxes of $229 and $97, respectively) 333 141 474 

Regulatory account transfer 

(net of taxes of $225 and $97, respectively) (327) (141) (468) 

Amounts reclassified from other comprehensive income: 

Amortization of prior service cost 

(net of taxes of $3 and $6, respectively) (1) (4) 9 5 

Amortization of net actuarial loss 

(net of taxes of $9 and $2, respectively) (1) 13 2 15 

Regulatory account transfer 

(net of taxes of $6 and $8, respectively) (1) (9) (10) (19) 

Net current period other comprehensive loss - 1 1 

Ending balance $ (25) $ 17 $ (8) 

 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) 

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The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended 

December 31, 2016 consisted of the following: 

Pension Other 

(in millions, net of income tax) Benefits Benefits Total 

Beginning balance $ (23) $ 16 $ (7) 

Other comprehensive income before reclassifications: 

Unrecognized prior service cost 

(net of taxes of $37 and $15, respectively) 54 (21) 33 

Unrecognized net actuarial loss 

(net of taxes of $45 and $15, respectively) (64) 21 (43) 

Regulatory account transfer 

(net of taxes of $5 and $0, respectively) 7 - 7 

Amounts reclassified from other comprehensive income: 

Amortization of prior service cost 

(net of taxes of $3 and $6, respectively) (1) 5 9 14 

Amortization of net actuarial loss 

(net of taxes of $10 and $2, respectively) (1) 14 2 16 

Regulatory account transfer 

(net of taxes of $13 and $8, respectively) (1) (18) (11) (29) 

Net current period other comprehensive loss (2) - (2) 

Ending balance $ (25) $ 16 $ (9) 

 (1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.) 

With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the 

information disclosed above. 

Accounting Standards Issued But Not Yet Adopted 

Presentation of Net Periodic Pension Cost 

In March 2017, the FASB issued ASU 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the existing 

guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs. On a 

retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net

benefit cost and provides explicit guidance on how to present the service cost component and other components in the income 

statement. In addition, on a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service 

costs. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018. The FERC has allowed and the 

Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes. In January 2018, the CPUC 

approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the 

service cost component determined by a plan’s actuaries. The change in capitalization of retirement benefits will not have a 

material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements. 

Recognition of Lease Assets and Liabilities 

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the existing guidance relating to the 

definition of a lease, recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information 

about leasing arrangements. In November, 2017, the FASB tentatively decided to amend the new leasing guidance such that 

entities may elect not to restate their comparative periods in the period of adoption. Under the new standard, all lessees must 

recognize an asset and liability on the balance sheet. Operating leases were previously not recognized on the balance sheet. The 

ASU will be effective for PG&E Corporation and the Utility on January 1, 2019, with early adoption permitted. PG&E 

Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility expect this 

standard to increase lease assets and lease liabilities on the Consolidated Balance Sheets and do not expect the guidance will have 

a material impact on the Consolidated Statements of Income, Statements of Cash Flows and lease disclosures. 

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Recognition and Measurement of Financial Assets and Financial Liabilities 

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and 

Measurement of Financial Assets and Financial Liabilities, which amends the existing guidance relating to the recognition, 

measurement, presentation, and disclosure of financial instruments. The amendments require equity investments (excluding those

accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value 

recognized in net income. The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear 

decommissioning trusts. These investments are classified as “available-for-sale” and gains or losses are refundable, or 

recoverable, from customers through rates. The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 

and will not have a material impact on the Consolidated Financial Statements and related disclosures. 

Revenue Recognition Standard 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which amends existing 

revenue recognition guidance. The objective of the new standard is to provide a single, comprehensive revenue recognition model 

for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to 

provide more useful information to users of financial statements through improved and expanded disclosure requirements. The 

ASU became effective for PG&E Corporation and the Utility on January 1, 2018. This standard will be adopted for related 

disclosures in the first quarter of 2018 and will not have a material impact on the Consolidated Financial Statements. Upon 

adoption of ASU 2014-09, the Utility plans to disclose revenues from contracts with customers separately from regulatory 

balancing account revenue and disaggregate customer contract revenue by customer class. 

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS 

Regulatory Assets 

Current Regulatory Assets 

At December 31, 2017 and 2016, the Utility had current regulatory assets of $615 million and $423 million, respectively. At 

December 31, 2017 and 2016, the current regulatory assets included $426 million and $223 million, respectively, of costs related 

to CEMA fire prevention and vegetation management. Current regulatory assets are included within the current assets in the 

Consolidated Balance Sheets. 

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Long-Term Regulatory Assets 

Long-term regulatory assets are comprised of the following: 

Balance at December 31, Recovery 

(in millions) 2017 2016 Period 

Pension benefits (1) $ 1,954 $ 2,429 Indefinitely (3)

Deferred income taxes (1)(4) - 3,859 

Utility retained generation (2) 319 364 9 years

Environmental compliance costs (1) 837 778 32 years

Price risk management (1) 65 92 10 years

Unamortized loss, net of gain, on reacquired debt (1) 79 76 25 years

Other 539 353 Various

Total long-term regulatory assets $ 3,793 $ 7,951 

(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) 

recognized in accordance with GAAP. 

(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under 

Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of 

these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related 

revenues are recognized. 

(3) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the 

future, the Utility expects to continuously recover pension benefits. 

(4) The change in the balance from a regulatory asset as of December 31, 2016 to a regulatory liability as of December 31, 2017 reflects the impact of changes in net 

deferred tax liabilities associated with a lower federal income tax rate as a result of the Tax Act. (See “Regulatory Liabilities” below and Note 8.) 

At December 31, 2017 and 2016, other long-term regulatory assets included $274 million and $70 million, respectively, of costs 

related to CEMA events from 2014 through 2017 that the Utility believes are recoverable based on historical experience in 

recovering costs for these types of events. 

In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility 

earns a return only on its regulatory assets for retained generation, and unamortized loss, net of gain, on reacquired debt. 

Regulatory Liabilities 

Long-Term Regulatory Liabilities 

Long-term regulatory liabilities are comprised of the following: 

Balance at December 31, 

(in millions) 2017 2016 

Cost of removal obligations (1) $ 5,547 $ 5,060 

Deferred income taxes (2) 1,021 - 

Recoveries in excess of AROs (3) 624 626 

Public purpose programs (4) 590 567 

Other 897 552 

Total long-term regulatory liabilities $ 8,679 $ 6,805 

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs. 

(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of 

deferred taxes subject to flow-through treatment. (See Note 8 below.) 

(3) Represents the cumulative differences between ARO expenses and amounts collected in rates. Decommissioning costs related to the Utility’s nuclear facilities 

are recovered through rates and are placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized 

gains and losses on these nuclear decommissioning trust investments. (See Note 10 below.) 

(4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related 

to energy efficiency programs. 

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Regulatory Balancing Accounts 

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences 

between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 

months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the 

Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets 

or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets. These differences do not have an 

impact on net income. Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing 

of when costs are incurred and customer revenues are collected. 

Current regulatory balancing accounts receivable and payable are comprised of the following: 

Receivable 

Balance at December 31, 

(in millions) 2017 2016 

Electric distribution $ - $ 132 

Electric transmission 139 244 

Utility generation - 48 

Gas distribution and transmission 486 541 

Energy procurement 71 132 

Public purpose programs 103 106 

Other 423 297 

Total regulatory balancing accounts receivable $ 1,222 $ 1,500 

Payable 

Balance at December 31, 

(in millions) 2017 2016 

Electric distribution $ 72 $ - 

Electric transmission 120 99 

Utility generation 14 - 

Gas distribution and transmission - 48 

Energy procurement 149 13 

Public purpose programs 452 264 

Other 313 221 

Total regulatory balancing accounts payable $ 1,120 $ 645 

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The

electric transmission accounts track recovery of costs related to the transmission of electricity. The gas distribution and 

transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case. Energy 

procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental 

compliance-related activities. Public purpose programs balancing accounts are primarily used to record and recover authorized 

revenue requirements for commission-mandated programs such as energy efficiency. 

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NOTE 4: DEBT 

Long-Term Debt 

 The following table summarizes PG&E Corporation’s and the Utility’s long-term debt: 

 December 31, 

(in millions) 2017 2016 

PG&E Corporation 

Senior notes: 

Maturity Interest Rates 

2019 2.40% $ 350 $ 350 

Unamortized discount, net of premium and debt issuance - (2) 

Total PG&E Corporation long-term debt 350 348 

Utility 

Senior notes: 

Maturity Interest Rates 

2017 5.63% - 700 

2018 8.25% 400 800 

2020 3.50% 800 800 

2021 3.25% to 4.25% 550 550 

2022 2.45% 400 400 

2023 through 2047 2.95% to 6.35% 14,975 12,375 

Less: current portion (1) (400) (700) 

Unamortized discount, net of premium and debt issuance (185) (161) 

Total senior notes, net of current portion 16,540 14,764 

Pollution control bonds: 

Maturity Interest Rates 

Series 2004 A-D due 2023 (2) 4.75% - 345 

Series 2008 F and 2010 E, due 2026 (3) 1.75% 100 - 

Series 2008 G, due 2018 (4) 1.05% 45 - 

Series 2009 A-B, due 2026 (5) 1.78% 149 149 

Series 1996 C, E, F, 1997 B due 2026 (6) variable rate (7) 614 614 

Less: current portion (45) - 

Total pollution control bonds 863 1,108 

Total Utility long-term debt, net of current portion 17,403 15,872 

Total consolidated long-term debt, net of current portion $ 17,753 $ 16,220 

(1) On January 19, 2018, the Utility sent a notice of redemption to redeem all $400 million aggregate principal amount of the 8.25% senior notes due October 15, 

2018 on February 18, 2018. On January 31, 2018, the Utility deposited with the trustee funds sufficient to effect the early redemption of these bonds and satisfy 

and discharge its remaining obligation of $400 million.

(2) In June 2017, the Utility repurchased and retired $345 million principal amount of Pollution Control Bonds series 2004 A-D. 

(3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these 

bonds have a mandatory redemption date of May 30, 2022. 

(4) Pollution Control Bonds series 2008G were remarketed and issued in June 2017 and mature on December 1, 2018.

(5) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit 

facility without issuer consent. 

(6) Each series of these bonds is supported by a separate letter of credit. In December 2015, the letters of credit were extended to December 1, 2020. Although the 

stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains 

consent from the issuer to the continuation of the series without a credit facility. 

(7) At December 31, 2017, the interest rate on these bonds ranged from 1.45% - 1.70%. 

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Pollution Control Bonds 

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have 

issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially 

all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid

waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the 

Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, 

LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities 

solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are 

outstanding. Except for components that may have been abandoned in place or disposed of as scrap or that are permanently nonoperational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities 

solely as pollution control facilities. 

Repayment Schedule 

PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2017 are reflected 

in the table below: 

(in millions, 

except interest rates) 2018 2019 2020 2021 2022 Thereafter Total 

PG&E Corporation 

Average fixed interest rate - 2.40% - - - - 2.40% 

Fixed rate obligations $ - $ 350 $ - $ - $ - $ - $ 350 

Utility 

Average fixed interest rate 7.52% - 3.50% 3.80% 2.31% 4.68% 4.61% 

Fixed rate obligations $ 445 $ - $ 800 $ 550 $ 500 (2) $ 14,975 $ 17,270 

Variable interest rate 

 as of December 31, 2017 - 1.78% 1.59% - - - 1.63% 

Variable rate obligations (1) $ - $ 149 $ 614 $ - $ - $ - $ 763 

Total consolidated debt $ 445 $ 499 $ 1,414 $ 550 $ 500 $ 14,975 $ 18,383 

(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020. 

(2) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017. Although the stated maturity date for both series is 2026, these 

bonds have a mandatory redemption date of May 30, 2022. 

Short-term Borrowings 

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit 

facilities and commercial paper programs at December 31, 2017: 

 Credit Letters of Commercial 

Termination Facility Credit Paper Facility 

(in millions) Date Limit Outstanding Outstanding Availability 

PG&E Corporation April 2022 $ 300 (1) $ - $ 132 $ 168 

Utility April 2022 3,000 (2) 49 50 2,901 

Total revolving credit facilities $ 3,300 $ 49 $ 182 $ 3,069 

(1) Includes a $50 million lender commitment to the letter of credit sublimit and a $100 million commitment for swingline loans defined as loans that are made 

available on a same-day basis and are repayable in full within 7 days. 

(2) Includes a $500 million lender commitment to the letter of credit sublimit and a $75 million commitment for swingline loans. 

For the year ended December 31, 2017, PG&E Corporation’s average outstanding commercial paper balance was $81 million and 

the maximum outstanding balance during the year was $161 million. For 2017, the Utility’s average outstanding commercial 

paper balance was $469 million and the maximum outstanding balance during the year was $1.1 billion. There were no bank 

borrowings for PG&E Corporation or the Utility in 2017. 

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Revolving Credit Facilities 

In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by 

one year from April 27, 2021 to April 27, 2022. PG&E Corporation's and the Utility's revolving credit facilities may be used for 

working capital, the repayment of commercial paper, and other corporate purposes. 

Borrowings under each credit agreement (other than swingline loans) will bear interest based on the borrower’s credit rating and 

on each borrower’s election of either (1) a London Interbank Offered Rate (“LIBOR”) plus an applicable margin or (2) the base 

rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 

0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin. The borrower’s credit rating at 

the time of borrowing will determine the applicable rate within the following ranges. The applicable margin for LIBOR loans will 

range between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s 

credit agreement. The applicable margin for base rate loans will range between 0% and 0.475% under PG&E Corporation’s credit 

agreement and between 0% and 0.275% under the Utility’s credit agreement. In addition, the facility fee under PG&E 

Corporation’s and the Utility’s credit agreements will range between 0.1% and 0.275% and between 0.075% and 0.225%, 

respectively. 

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit 

facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior 

note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the respective 

revolving credit facilities require that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total 

consolidated capitalization of at most 65% as of the end of each fiscal quarter. PG&E Corporation’s revolving credit facility 

agreement also requires that PG&E Corporation owns, directly or indirectly, at least 80% of the outstanding common stock and at

least 70% of the outstanding voting capital stock of the Utility. 

Commercial Paper Programs 

The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs are used primarily to fund temporary 

financing needs. PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and 

$2.5 billion, respectively. PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to 

the amount available under their respective revolving credit facilities. The commercial paper may have maturities up to 365 days 

and ranks equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness. Commercial 

paper notes are sold at an interest rate dictated by the market at the time of issuance. For 2017, the average yield on outstanding 

PG&E Corporation and Utility commercial paper was 1.29% and 1.11%, respectively. 

Other Short-term Borrowings 

In February 2017, the Utility’s $250 million floating rate unsecured term loan, issued in March 2016, matured and was repaid. 

Additionally, in February 2017, the Utility entered into a $250 million floating rate unsecured term loan maturing on February 22, 

2018. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding

commercial paper. 

In November 2017, the Utility issued $500 million in unsecured floating rate senior notes that mature on November 28, 2018. The 

proceeds were used towards repayment of the $250 million unsecured floating rate senior notes due November 30, 2017 and the 

balance was used to support the Northern California wildfire response efforts. 

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION 

PG&E Corporation had 514,755,845 shares of common stock outstanding at December 31, 2017. PG&E Corporation held all of 

the Utility’s outstanding common stock at December 31, 2017. 

In February 2017, PG&E Corporation amended its February 2015 EDA providing for the sale of PG&E Corporation common 

stock having an aggregate price of up to $275 million. During 2017, PG&E Corporation sold 0.4 million shares of its common 

stock under the February 2017 EDA for cash proceeds of $28.4 million, net of commissions paid of $0.2 million. There were no 

issuances under the February 2017 EDA for the three months ended December 31, 2017. As of December 31, 2017, the remaining 

sales available under this agreement were $246.3 million. 

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In addition, during 2017, PG&E Corporation sold 7.4 million shares of common stock under its 401(k) plan, the Dividend 

Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $366.4 million. 

Dividends 

Ordinarily, the Board of Directors of PG&E Corporation and the Utility declare dividends quarterly. Under the Utility’s Articles 

of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s 

preferred stock have been paid. Under their respective credit agreements, PG&E Corporation and the Utility are each required to 

maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. Based on the calculation of this ratio for 

each company, no amount of PG&E Corporation’s retained earnings and $218 million of the Utility’s retained earnings was 

subject to this restriction at December 31, 2017. Additionally, the Utility’s net assets, and therefore its ability to pay dividends, are 

restricted by the CPUC-authorized capital structure, which requires the Utility to maintain, on average, at least 52% equity. Based 

on the calculation of this ratio, $14.3 billion of the Utility’s net assets were restricted at December 31, 2017. Additionally, as a 

result of this requirement, the Utility’s ability to pay dividends in the future could be impacted by future potential liabilities. On 

December 20, 2017, the Board of Directors of PG&E Corporation suspended quarterly cash dividends on PG&E Corporation’s 

common stock, beginning with the fourth quarter of 2017 due to uncertainty related to the causes of and potential liabilities 

associated with the Northern California wildfires. (See “Northern California Wildfires” in Note 13 below.) 

For the first quarter of 2017, the Board of Directors of PG&E Corporation declared a common stock dividend of $0.49 per share 

quarterly. In May 2017, the Board of Directors of PG&E Corporation approved a new annual common stock cash dividend of 

$0.53 per share quarterly. In 2017, total dividends declared were $1.55 per share. 

Long-Term Incentive Plan 

The PG&E Corporation LTIP permits various forms of share-based incentive awards, including restricted stock awards, restricted 

stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. 

Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. A maximum of 17 million 

shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, 

of which 14,327,157 shares were available for future awards at December 31, 2017. 

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for sharebased incentive awards for 2017, 2016, and 2015: 

(in millions) 2017 2016 2015 

Restricted stock units $ 40 $ 53 $ 47 

Performance shares 45 55 46 

Total compensation expense (pre-tax) $ 85 $ 108 $ 93 

Total compensation expense (after-tax) $ 50 $ 64 $ 55

The amount of share-based compensation costs capitalized during 2017, 2016, and 2015 was immaterial. There was no material 

difference between PG&E Corporation and the Utility for the information disclosed above. 

Restricted Stock Units 

Restricted stock units generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E 

Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted 

stock units. Compensation expense is generally recognized rateably over the vesting period based on grant-date fair value. The 

weighted average grant-date fair value for restricted stock units granted during 2017, 2016, and 2015 was $66.95, $56.68, and 

$53.30, respectively. The total fair value of restricted stock units that vested during 2017, 2016, and 2015 was $57 million, $36 

million, and $57 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. 

In general, forfeitures are recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting 

occurs. As of December 31, 2017, $33 million of total unrecognized compensation costs related to nonvested restricted stock units 

was expected to be recognized over the remaining weighted average period of 1.46 years. 

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The following table summarizes restricted stock unit activity for 2017: 

Number of Weighted Average GrantRestricted Stock Units Date Fair Value 

Nonvested at January 1 1,923,010 $ 51.26 

Granted 658,395 66.95 

Vested (1,172,194) 48.44 

Forfeited (29,976) 61.07 

Nonvested at December 31 1,379,235 $ 60.93 

Performance Shares 

Performance shares generally will vest three years after the grant date. Upon vesting, performance shares are settled in shares of 

common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer 

companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric. 

Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled. 

Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period 

based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return 

based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards. The weighted 

average grant-date fair value for performance shares granted during 2017, 2016, and 2015 was $77.00, $53.61, and $68.27, 

respectively. There was no tax benefit associated with performance shares during each of these periods. In general, forfeitures are 

recorded rateably over the vesting period, using historical averages and adjusted to actuals when vesting occurs. As of December 

31, 2017, $46 million of total unrecognized compensation costs related to nonvested performance shares was expected to be 

recognized over the remaining weighted average period of 1.42 years. 

The following table summarizes activity for performance shares in 2017: 

Number of Weighted Average GrantPerformance Shares Date Fair Value 

Nonvested at January 1 1,838,855 $ 58.65 

Granted 745,724 77.00 

Vested (81,501) 53.74 

Forfeited (1) (755,050) 66.30 

Nonvested at December 31 1,748,028 $ 63.40 

 

(1) Includes performance shares that expired with zero value as performance targets were not met. 

NOTE 6: PREFERRED STOCK 

PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value 

preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any 

preferred stock outstanding. 

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred

stock. At December 31, 2017 and December 31, 2016, the Utility’s preferred stock outstanding included $145 million of shares 

with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates 

between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are 

not subject to mandatory redemption. All outstanding preferred stock has a $25 par value. 

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At December 31, 2017, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. 

The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the 

specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2017, annual 

dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share. 

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility determined to suspend quarterly cash 

dividends on the Utility’s preferred stock, beginning with the three-month period ending January 31, 2018, due to uncertainty 

related to causes and potential liabilities associated with the October 2017 Northern California wildfires. See “Northern California 

Wildfires” in Note 13 below.)

Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in 

dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the 

par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $14 

million of dividends on preferred stock in each of 2017, 2016, and 2015. 

NOTE 7: EARNINGS PER SHARE 

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average 

number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of 

outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s 

income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 

2017, 2016, and 2015. 

Year Ended December 31, 

(in millions, except per share amounts) 2017 2016 2015 

Income available for common shareholders $ 1,646 $ 1,393 $ 874 

Weighted average common shares outstanding, basic 512 499 484 

Add incremental shares from assumed conversions: 

Employee share-based compensation 1 2 3 

Weighted average common share outstanding, diluted 513 501 487 

Total earnings per common share, diluted $ 3.21 $ 2.78 $ 1.79 

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant 

amount of options and securities that were antidilutive. 

 NOTE 8: INCOME TAXES

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes. The income tax provision 

includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate 

current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result 

from temporary tax and accounting timing differences, such as those arising from depreciation expense. 

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be 

taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit 

recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being 

realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future 

periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized 

tax benefit. 

Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits 

over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property 

in accordance with regulatory treatment. 

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which 

its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and 

the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a standalone basis. 

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The significant components of income tax provision (benefit) by taxing jurisdiction were as follows: 

PG&E Corporation Utility 

Year Ended December 31, 

(in millions) 2017 2016 2015 2017 2016 2015 

Current: 

Federal $ (10) $ (105) $ (89) $ 61 $ (105) $ (88) 

State 48 (70) 11 50 (66) 6 

Deferred: 

Federal 481 218 131 326 229 136 

State 6 16 (76) 4 16 (69) 

Tax credits (14) (4) (4) (14) (4) (4) 

Income tax provision (benefit) $ 511 $ 55 $ (27) $ 427 $ 70 $ (19) 

The following table describes net deferred income tax liabilities: 

PG&E Corporation Utility 

Year Ended December 31, 

(in millions) 2017 2016 2017 2016 

Deferred income tax assets: 

Tax carryforwards 830 1,851 736 1,596 

Compensation 274 277 205 199 

Income tax regulatory liability (1) 286 - 286 - 

Other (2) 185 186 194 203 

Total deferred income tax assets $ 1,575 $ 2,314 $ 1,421 $ 1,998 

Deferred income tax liabilities: 

Property related basis differences 7,269 10,429 7,256 10,411 

Income tax regulatory asset (1) - 1,572 - 1,572 

Other (3) 128 526 128 525 

Total deferred income tax liabilities $ 7,397 $ 12,527 $ 7,384 $ 12,508 

Total net deferred income tax liabilities $ 5,822 $ 10,213 $ 5,963 $ 10,510 

(1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and 

amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act. 

(For more information see Note 3 above and “Tax Cuts and Jobs Act of 2017” below.)

(2) Amounts include benefits, environmental reserve, and customer advances for construction. 

(3) Amounts primarily relate to regulatory balancing accounts. 

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The following table reconciles income tax expense at the federal statutory rate to the income tax provision: 

PG&E Corporation Utility 

Year Ended December 31, 

2017 2016 2015 2017 2016 2015 

Federal statutory income tax rate 35.0 % 35.0 % 35.0 % 35.0 % 35.0 % 35.0 %

Increase (decrease) in income 

tax rate resulting from: 

State income tax (net of 

federal benefit) (1) 1.5 (2.5) (4.9) 1.6 (2.2) (4.8)

Effect of regulatory treatment 

of fixed asset differences (2) (16.5) (23.7) (33.6) (16.8) (23.4) (33.7) 

Tax credits (1.1) (0.8) (1.3) (1.1) (0.8) (1.3)

Benefit of loss carryback - (1.1) (1.5) - (1.1) (1.5) 

Non deductible penalties (3) 0.4 0.8 4.3 0.4 0.8 4.3 

Tax Reform Adjustment (4) 6.8 - - 3.0 - - 

Other, net (5) (2.5) (3.9) (1.1) (2.0) (3.5) (0.2)

Effective tax rate 23.6 % 3.8 % (3.1) % 20.1 % 4.8 % (2.2) %

(1) Includes the effect of state flow-through ratemaking treatment. In 2016 and 2015, amounts reflect an agreement with the IRS on a 2011 audit related to electric 

transmission and distribution repairs deductions. The 2017 amount reflects an agreement with the IRS on a 2013 audit related to generation repairs deductions. 

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision in all periods 

presented and by the 2015 GT&S decision which impacted 2016 and 2017. All amounts are impacted by the level of income before income taxes. The 2014 

GRC and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences 

attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary tax differences, PG&E Corporation and the 

Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities. Therefore, PG&E Corporation’s and the 

Utility’s effective tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory 

assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. 

(3) Primarily represents the effects of a non-tax deductible penalty associated with the Butte fire for 2017, non-tax deductible fines and penalties associated with the 

natural gas distribution facilities record-keeping decision for 2016 and the effects of the San Bruno Penalty Decision for 2015. (4) Represents the required adjustment to deferred tax balances, due to the federal income tax rate being lowered from 35% to 21% beginning in 2018 as a result of 

the enactment of the Tax Act. 

(5) These amounts primarily represent the impact of tax audit settlements. 

 

Unrecognized Tax Benefits 

The following table reconciles the changes in unrecognized tax benefits: 

 

PG&E Corporation Utility 

(in millions) 2017 2016 2015 2017 2016 2015 

Balance at beginning of year $ 388 $ 468 $ 713 $ 382 $ 462 $ 707 

Additions for tax position taken 

during a prior year - - 40 - - 40 

Reductions for tax position 

taken during a prior year (71) (77) (349) (71) (77) (349) 

Additions for tax position 

taken during the current year 48 56 64 48 56 64 

Settlements (14) (59) - (8) (59) - 

Expiration of statute (3) - - (3) - - 

Balance at end of year $ 349 $ 388 $ 468 $ 349 $ 382 $ 462 

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The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2017 for 

PG&E Corporation and the Utility was $21 million. 

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the 

resolution of several matters, including audits. As of December 31, 2017, it is reasonably possible that unrecognized tax benefits 

will decrease by approximately $20 million within the next 12 months. 

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the 

Consolidated Statements of Income. For the years ended December 31, 2017, 2016, and 2015, these amounts were immaterial. 

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 required PG&E Corporation and the Utility to re-measure all existing 

deferred income tax assets and liabilities to reflect the reduction in the federal tax rate. PG&E Corporation and the Utility have 

made reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued 

by the SEC in Staff Accounting Bulletin No. 118, for the re-measurement of deferred tax balances as of December 31, 2017. 

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 carryforwards 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 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 differ from the above recorded amounts, possibly materially, due to, among other 

things, 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. In addition, while PG&E Corporation and the Utility were able to make 

reasonable estimates of the impact of the reduction in federal tax rate and the elimination of bonus depreciation due to the 

enactment of the Tax Act; changes in interpretations, guidance on legislative intent, and any changes in accounting standards for 

income taxes in response to the Tax Act could impact the recorded amounts. PG&E Corporation and the Utility will finalize and 

record any adjustments related to the Tax Act within the one year measurement period provided under Staff Accounting Bulletin 

No. 118. 

Tax Settlements

PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relates 

to deductible repair costs for gas transmission and distribution lines of business. In February 2017, the Joint Committee of 

Taxation approved PG&E Corporation’s settlement with the IRS related to deductible electric transmission and distribution repairs 

for the 2011 and 2012 tax years. The agreement provided that the methodology used in determining the deductible amount should 

be followed for all subsequent periods, absent any material change in facts. In November 2017, PG&E Corporation reached an 

agreement with the IRS on deductible generation repairs for the 2013 and 2014 tax years. The IRS may issue guidance in 2018 

that clarifies which repair costs are deductible for the natural gas transmission and distribution lines of business. 

Tax years after 2008 remain subject to examination by the state of California. 

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2015 Gas Transmission and Storage Rate Case 

The final phase two decision reduced rate base by the full amount of the disallowed capital expenditures but did not remove the

associated deferred taxes, which the Utility believes constitutes a normalization violation. In the final decision, the CPUC 

authorized the Utility to establish a Tax Normalization Memorandum Account to track relevant costs and clarified that it is the

CPUC’s intention that the Utility comply with normalization rules and avoid the potential adverse consequences of a normalization 

violation. The CPUC allowed the Utility to seek a ruling from the IRS and the Utility filed the ruling request with the IRS on

April 10, 2017. On October 5, 2017, the IRS issued a private letter ruling indicating the final decision rate base reduction was 

inconsistent with the IRS tax normalization requirements. As a result of the IRS private letter ruling, the Utility filed an advice 

letter with the CPUC on December 11, 2017, requesting a rate base adjustment of $7 million, $28 million, $49 million, and $61 

million, in 2015, 2016, 2017, and 2018, respectively. 

Carryforwards 

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances: 

December 31, Expiration 

(in millions) 2017 Year 

Federal: 

Net operating loss carryforward $ 4,233 2031 - 2036 

Tax credit carryforward 103 2029 - 2036 

Charitable contribution loss carryforward 2019 - 2021 93

State: 

Net operating loss carryforward $ - N/A 

Tax credit carryforward Various 13

Charitable contribution loss carryforward 24 2020 - 2021 

PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating 

losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance 

was recognized as of December 31, 2017 for these tax attributes. 

NOTE 9: DERIVATIVES 

Use of Derivative Instruments 

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement 

costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in 

customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, 

futures, swaps, options, and CRRs. 

Derivatives are presented in the Utility’s Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with 

master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid 

or received where the right of offset and the intention to offset exist. 

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance

Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility 

expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the 

Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and 

losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets 

and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost 

of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery 

from or refund to customers. 

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require 

physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, 

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and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Consolidated 

Balance Sheets at fair value. Eligible derivatives are accounted for under the accrual method of accounting. 

Volume of Derivative Activity 

At December 31, 2017 and 2016, respectively, the volumes of the Utility’s outstanding derivatives were as follows: 

 Contract Volume 

Underlying Product Instruments 2017 2016 

Natural Gas(1) (MMBtus(2)) Forwards and Swaps 228,768,745 323,301,331

 Options 60,736,806 96,602,785

Electricity (Megawatt-hours) Forwards and Swaps 2,872,013 3,287,397

 Congestion Revenue Rights(3) 312,272,177 278,143,281

 (1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units. 

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements 

At December 31, 2017, the Utility’s outstanding derivative balances were as follows: 

Commodity Risk 

Gross Derivative Total Derivative 

(in millions) Balance Netting Cash Collateral Balance 

Current assets – other $ 30 $ (3) $ 10 $ 37 

Other noncurrent assets – other 103 (1) - 102 

Current liabilities – other (47) 3 13 (31) 

Noncurrent liabilities – other (66) 1 8 (57) 

Total commodity risk $ 20 $ - $ 31 $ 51 

At December 31, 2016, the Utility’s outstanding derivative balances were as follows: 

Commodity Risk 

Gross Derivative Total Derivative 

(in millions) Balance Netting Cash Collateral Balance 

Current assets – other $ 91 $ (10) $ 1 $ 82 

Other noncurrent assets – other 149 (9) - 140 

Current liabilities – other (48) 10 - (38) 

Noncurrent liabilities – other (101) 9 3 (89) 

Total commodity risk $ 91 $ - $ 4 $ 95 

Gains and losses associated with price risk management activities were recorded as follows: 

Commodity Risk 

For the year ended December 31, 

(in millions) 2017 2016 2015 

Unrealized gain/(loss) - regulatory assets and liabilities(1) $ (71) $ 64 $ (6) 

Realized loss - cost of electricity(2) (27) (53) (14) 

Realized loss - cost of natural gas(2) (5) (18) (10) 

Total commodity risk $ (103) $ (7) $ (30) 

(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory liabilities or assets, respectively, rather than being 

recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings. 

(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments. 

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Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated 

Statements of Cash Flows. 

The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the 

major credit rating agencies. At December 31, 2017, the Utility’s credit rating was investment grade. If the Utility’s credit rating 

were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some 

of its net liability derivative positions. 

The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were 

triggered was as follows: 

Balance at December 31, 

(in millions) 2017 2016 

Derivatives in a liability position with credit risk-related 

 contingencies that are not fully collateralized $ (1) $ (24) 

Related derivatives in an asset position - 19

Collateral posting in the normal course of business related to 

these derivatives - 4 

Net position of derivative contracts/additional collateral 

posting requirements(1) $ $ (1) (1)

 (1) This calculation excludes the impact of closed but unpaid positions, as their settlement is not impacted by any of the Utility’s credit risk-related contingencies. 

NOTE 10: FAIR VALUE MEASUREMENTS 

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value. 

A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value: 

x Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets. 

x Level 2 – Other inputs that are directly or indirectly observable in the marketplace. 

x Level 3 – Unobservable inputs which are supported by little or no market activities. 

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs 

when measuring fair value. 

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Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. 

Assets held in rabbi trusts are held by PG&E Corporation and not the Utility. 

Fair Value Measurements 

At December 31, 2017 

(in millions) Level 1 Level 2 Level 3 Netting (1) Total 

Assets: 

Short-term investments $ 385 $ - $ - $ - $ 385 

Nuclear decommissioning trusts 

Short-term investments 23 - - - 23 

Global equity securities 1,967 - - - 1,967 

Fixed-income securities 733 562 - - 1,295 

Assets measured at NAV - - - - 18 

Total nuclear decommissioning trusts (2) 2,723 562 - - 3,303 

Price risk management instruments 

(Note 9) 

Electricity - 3 129 6 138 

Gas - 1 - - 1 

Total price risk management - 4 129 6 139 

instruments 

Rabbi trusts 

Fixed-income securities - 72 - - 72 

Life insurance contracts - 71 - - 71 

Total rabbi trusts - 143 - - 143 

Long-term disability trust 

Short-term investments 8 - - - 8 

Assets measured at NAV - - - - 167 

Total long-term disability trust 8 - - - 175 

TOTAL ASSETS $ 3,116 $ 709 $ 129 $ 6 $ 4,145 

Liabilities: 

Price risk management instruments 

(Note 9) 

Electricity $ 10 $ 15 $ 87 $ (25) $ 87 

Gas - 1 - - 1 

TOTAL LIABILITIES $ 10 $ 16 $ 87 $ (25) $ 88 

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value. 

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Fair Value Measurements 

At December 31, 2016 

(in millions) Level 1 Level 2 Level 3 Netting (1) Total 

Assets: 

Short-term investments $ 105 $ - $ - $ - $ 105 

Nuclear decommissioning trusts 

Short-term investments 9 - - - 9 

Global equity securities 1,724 - - - 1,724 

Fixed-income securities 665 527 - - 1,192 

Assets measured at NAV - - - - 14 

Total nuclear decommissioning trusts (2) 2,398 527 - - 2,939 

Price risk management instruments 

(Note 9) 

Electricity 30 18 181 (18) 211 

Gas - 11 - - 11 

Total price risk management 

instruments 30 29 181 (18) 222 

Rabbi trusts 

Fixed-income securities - 61 - - 61 

Life insurance contracts - 70 - - 70 

Total rabbi trusts - 131 - - 131 

Long-term disability trust 

Short-term investments 8 - - - 8 

Assets measured at NAV - - - - 170 

Total long-term disability trust 8 - - - 178 

TOTAL ASSETS $ 2,541 $ 687 $ 181 $ (18) $ 3,575 

Liabilities: 

Price risk management instruments 

(Note 9) 

Electricity $ 9 $ 12 $ 126 $ (21) $ 126 

Gas - 2 - (1) 1 

TOTAL LIABILITIES $ 9 $ 14 $ 126 $ (22) $ 127 

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $333 million, primarily related to deferred taxes on appreciation of investment value. 

Valuation Techniques 

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables 

above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. 

Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material 

transfers between any levels for the years ended December 31, 2017 and 2016. 

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Trust Assets 

Assets Measured at Fair Value 

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. 

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also 

include short-term investments that are money market funds valued at Level 1. 

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets

and are classified as Level 1. 

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixedincome securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury 

securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A 

market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing 

data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation 

model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each 

security are considered in the valuation model, as applicable. 

Assets Measured at NAV Using Practical Expedient 

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV 

per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included 

in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include 

commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are 

composed primarily of U.S. government securities and asset-backed securities. 

Price Risk Management Instruments 

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, 

forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model. Exchange-traded futures that 

are valued using observable market forward prices for the underlying commodity are classified as Level 1. Over-the-counter 

forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are 

corroborated with market data are classified as Level 2. Exchange-traded and over-the-counter options are valued using 

observable market data and market-corroborated data and are classified as Level 2. 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3. These Level 

3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation 

from observable prices, when a contract term extends beyond a period for which market data is available. Market and credit risk 

management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from 

brokers and historical data. 

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited 

market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast 

forward prices. CRRs are classified as Level 3. 

Level 3 Measurements and Sensitivity Analysis 

The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, is responsible for 

determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions 

collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair 

value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness. 

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Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All 

reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact 

to net income resulting from changes in the fair value of these instruments. (See Note 9 above.) 

 Fair Value at 

(in millions) At December 31, 2017 Valuation Unobservable 

Fair Value Measurement Assets Liabilities Technique Input Range (1)

Congestion revenue rights $ 129 $ 24 Market approach 

CRR auction 

prices $ (16.03) - 11.99 

Power purchase agreements $ - $ 63 

Discounted cash 

flow Forward prices $ 18.81 - 38.80 

(1) Represents price per megawatt-hour 

 Fair Value at 

(in millions) At December 31, 2016 Valuation Unobservable 

Fair Value Measurement Assets Liabilities Technique Input Range (1)

Congestion revenue rights $ 181 $ 35 Market approach CRR auction prices $ (11.88) - 6.93 

Power purchase agreements $ - $ 91 Discounted cash flow Forward prices $ 18.07 - 38.80 

(1) Represents price per megawatt-hour 

Level 3 Reconciliation 

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 

2017 and 2016, respectively: 

Price Risk Management Instruments 

(in millions) 2017 2016 

Asset (liability) balance as of January 1 $ 55 $ 89 

Net realized and unrealized gains: 

Included in regulatory assets and liabilities or balancing accounts (1) (13) (34) 

Asset (liability) balance as of December 31 $ 42 $ 55 

(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in 

regulatory liabilities and assets and net income is not impacted.

Financial Instruments 

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: 

x The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer 

deposits, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate 

their carrying values at December 31, 2017 and 2016, as they are short-term in nature or have interest rates that reset 

daily. 

x The fair values of the Utility’s fixed-rate senior notes and fixed-rate pollution control bonds and PG&E Corporation’s 

fixed-rate senior notes were based on quoted market prices at December 31, 2017 and 2016. 

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The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below 

excludes financial instruments with carrying values that approximate their fair values): 

At December 31, 

2017 2016 

(in millions) Carrying Amount Level 2 Fair Value Carrying Amount Level 2 Fair Value 

Debt (Note 4) 

PG&E Corporation $ 350 $ 350 $ 348 $ 352 

Utility 17,090 19,128 15,813 17,790 

Available for Sale Investments 

The following table provides a summary of available-for-sale investments: 

 Total Total 

Amortized Unrealized Unrealized Total Fair 

(in millions) Cost Gains Losses Value 

As of December 31, 2017 

Nuclear decommissioning trusts 

 Short-term investments $ 23 $ - $ - $ 23 

 Global equity securities 524 1,463 (2) 1,985 

 Fixed-income securities 1,252 51 (8) 1,295 

Total (1) $ 1,799 $ 1,514 $ (10) $ 3,303 

As of December 31, 2016 

Nuclear decommissioning trusts 

 Short-term investments $ 9 $ - $ - $ 9 

 Global equity securities 584 1,157 (3) 1,738 

 Fixed-income securities 1,156 48 (12) 1,192 

Total (1) $ 1,749 $ 1,205 $ (15) $ 2,939 

 (1) Represents amounts before deducting $440 million and $333 million at December 31, 2017 and 2016, respectively, primarily related to deferred taxes on 

appreciation of investment value.

The fair value of fixed-income securities by contractual maturity is as follows: 

As of 

(in millions) December 31, 2017 

Less than 1 year $ 41 

1–5 years 414 

5–10 years 352 

More than 10 years 488 

Total maturities of fixed-income securities $ 1,295 

The following table provides a summary of activity for the fixed-income and equity securities: 

2017 2016 2015 

(in millions) 

Proceeds from sales and maturities of nuclear decommissioning 

investments $ 1,291 $ 1,295 $ 1,268 

Gross realized gains on securities held as available-for-sale 53 18 55 

Gross realized losses on securities held as available-for-sale (11) (26) (37) 

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NOTE 11: EMPLOYEE BENEFIT PLANS 

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”) 

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before 

December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to

participate (“Pension Plan”). The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 

1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified 

trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, 

consistent with applicable regulatory decisions and federal minimum funding requirements. Based upon current assumptions and 

available information, the Utility’s minimum funding requirements related to its pension plans is zero. 

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible 

dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and

the Utility use a fiscal year-end measurement date for all plans. 

Change in Plan Assets, Benefit Obligations, and Funded Status 

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status 

for pension benefits and other benefits for PG&E Corporation during 2017 and 2016: 

Pension Plan 

(in millions) 2017 2016 

Change in plan assets: 

Fair value of plan assets at beginning of year $ 14,729 $ 13,745 

Actual return on plan assets 2,380 1,358 

Company contributions 335 334 

Benefits and expenses paid (792) (708) 

Fair value of plan assets at end of year $ 16,652 $ 14,729 

 

Change in benefit obligation: 

Benefit obligation at beginning of year $ 17,305 $ 16,299 

Service cost for benefits earned 472 453 

Interest cost 714 715 

Actuarial (gain) loss 1,048 637 

Plan amendments 10 (91) 

Benefits and expenses paid (792) (708) 

Benefit obligation at end of year (1) $ 18,757 $ 17,305 

Funded Status: 

Current liability $ (7) $ (7) 

Noncurrent liability (2,098) (2,569) 

Net liability at end of year $ (2,105) $ (2,576) 

 (1) PG&E Corporation’s accumulated benefit obligation was $16.8 billion and $15.6 billion at December 31, 2017 and 2016, respectively. 

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Postretirement Benefits Other than Pensions 

(in millions) 2017 2016 

Change in plan assets: 

Fair value of plan assets at beginning of year $ 2,173 $ 2,035 

Actual return on plan assets 298 167 

Company contributions 33 52 

Plan participant contribution 87 85 

Benefits and expenses paid (171) (166) 

Fair value of plan assets at end of year $ 2,420 $ 2,173 

Change in benefit obligation: 

Benefit obligation at beginning of year $ 1,877 $ 1,766 

Service cost for benefits earned 59 52 

Interest cost 77 76 

Actuarial (gain) loss (49) 11 

Plan amendments - 37 

Benefits and expenses paid (157) (153) 

Federal subsidy on benefits paid 3 3 

Plan participant contributions 87 85 

Benefit obligation at end of year $ 1,897 $ 1,877 

 

Funded Status: (1)

Noncurrent asset $ 553 $ 368 

Noncurrent liability (30) (72) 

Net asset at end of year $ 523 $ 296 

 (1) At December 31, 2017 and 2016, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an 

underfunded position. 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above. 

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Components of Net Periodic Benefit Cost 

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows: 

Pension Plan 

(in millions) 2017 2016 2015 

Service cost $ 472 $ 453 $ 479 

Interest cost 714 715 673 

Expected return on plan assets (770) (828) (873) 

Amortization of prior service cost (7) 8 15 

Amortization of net actuarial loss 22 24 10 

Net periodic benefit cost 431 372 304 

Less: transfer to regulatory account (1) (92) (34) 34 

Total expense recognized $ 339 $ 338 $ 338 

 (1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates. 

Postretirement Benefits Other than Pensions 

(in millions) 2017 2016 2015 

Service cost $ 59 $ 52 $ 55 

Interest cost 77 76 71 

Expected return on plan assets (97) (107) (112) 

Amortization of prior service cost 15 15 19 

Amortization of net actuarial loss 4 4 4 

Net periodic benefit cost $ 58 $ 40 $ 37 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above. 

Components of Accumulated Other Comprehensive Income 

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension 

and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In 

addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect 

the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income 

for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is 

recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits 

other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated 

other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in 

accumulated other comprehensive income (loss). 

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2018 are as follows: 

 

(in millions) Pension Plan PBOP Plans 

Unrecognized prior service cost $ (6) $ 14 

Unrecognized net loss 5 (5) 

Total $ (1) $ 9 

There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E 

Corporation and the Utility. 

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Valuation Assumptions 

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. 

The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net 

benefit cost. 

Pension Plan PBOP Plans 

December 31, December 31, 

2017 2016 2015 2017 2016 2015 

Discount rate 3.64 % 4.11 % 4.37 % 3.60- 3.67 % 4.05 - 4.19 % 4.27 - 4.48 %

Rate of future compensation 

increases 3.90 % 4.00 % 4.00 % - - - 

Expected return on plan 

assets 6.20 % 5.30 % 6.10 % 3.30 - 7.10 % 2.80 - 6.00 % 3.20 - 6.60 %

The assumed health care cost trend rate as of December 31, 2017 was 6.8%, decreasing gradually to an ultimate trend rate in 2025 

and beyond of approximately 4.5%. A one-percentage-point change in assumed health care cost trend rate would have the 

following effects: 

One-Percentage-Point One-Percentage-Point 

(in millions) Increase Decrease 

Effect on postretirement benefit obligation $ 128 $ (129) 

Effect on service and interest cost 9 (10) 

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these 

returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan 

assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term

inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added 

to a long-term inflation rate. For the pension plan, the assumed return of 6.2% compares to a ten-year actual return of 7.8%. The 

rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over 

approximately 623 Aa-grade non-callable bonds at December 31, 2017. This yield curve has discount rates that vary based on the

duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to 

the corresponding rates on the yield curve to derive a weighted average discount rate. 

Investment Policies and Strategies 

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets 

and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and 

can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the 

Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and 

strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility. 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity 

risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’ 

fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current 

bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixedincome investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding 

costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in 

equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets 

include commodities futures, global REITS, and global listed infrastructure equities. Absolute return investments include hedge 

fund portfolios. 

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Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity 

index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s 

portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity 

investments. 

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows: 

Pension Plan PBOP Plans 

2018 2017 2016 2018 2017 2016 

Global equity 29 % 27 % 25 % 33 % 32 % 32 %

Absolute return 5 % 5 % 5 % 3 % 3 % 3 %

Real assets 8 % 10 % 10 % 6 % 7 % 7 %

Fixed income 58 % 58 % 60 % 58 % 58 % 58 %

Total 100 % 100 % 100 % 100 % 100 % 100 %

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit 

plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, 

appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment 

manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical 

direct asset holdings and derivative securities, and identify permitted and prohibited investments. 

Fair Value Measurements 

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 

31, 2017 and 2016. 

 Fair Value Measurements 

At December 31, 

 2017 2016 

(in millions) Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total 

Pension Plan: 

Short-term investments $ 287 $ 424 $ - $ 711 $ 364 $ 369 $ - $ 733 

Global equity 1,292 - - 1,292 996 - - 996 

Real assets 499 - - 499 610 - - 610 

Fixed-income 1,916 5,520 4 7,440 1,754 4,774 5 6,533 

Assets measured at NAV - - - 6,818 - - - 5,950 

Total $ 3,994 $ 5,944 $ 4 $ 16,760 $ 3,724 $ 5,143 $ 5 $ 14,822 

PBOP Plans: 

Short-term investments $ 31 $ - $ - $ 31 $ 33 $ - $ - $ 33 

Global equity 141 - - 141 115 - - 115 

Real assets 55 - - 55 70 - - 70 

Fixed-income 163 757 - 920 150 656 - 806 

Assets measured at NAV - - - 1,281 - - - 1,153 

Total $ 390 $ 757 $ - $ 2,428 $ 368 $ 656 $ - $ 2,177 

Total plan assets at fair value $ 19,188 $ 16,999 

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $116 million and $97 

million at December 31, 2017 and 2016, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and 

accounts payable. 

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 Valuation Techniques 

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table 

above. All investments that are valued using a NAV per share can be redeemed quarterly with a notice not to exceed 90 days. 

Short-Term Investments 

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These 

securities are categorized as Level 1 and Level 2 assets. 

Global Equity 

The global equity category includes investments in common stock and equity-index futures. Equity investments in common stock 

are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued 

based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in 

active markets and are Level 1 assets. 

Real Assets 

The real asset category includes portfolios of commodity futures, global REITS and global listed infrastructure equities. The 

commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are 

therefore considered Level 1 assets. 

Fixed-Income 

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixedincome securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury 

securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A 

market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data 

such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model 

generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each 

security are considered in the valuation model, as applicable. 

Assets Measured at NAV Using Practical Expedient 

Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the 

fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts 

presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity 

securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government 

securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which 

the investments may be redeemed. 

Transfers Between Levels 

Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers 

between levels occurred in the years ended December 31, 2017 and 2016. 

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