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PG&E Corp - Quarter Report: 2016 September (Form 10-Q)

 


 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549
FORM 10-Q

(Mark One)

 

[X]

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

 

For the quarterly period ended September 30,2016

OR

 

 

[  ]

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
______________


IRS Employer
Identification
Number
___________

 

 

 

 

1-12609

PG&E Corporation

California 

94-3234914

1-2348

Pacific Gas and Electric Company

California 

94-0742640

 

PG&E Corporation
77 Beale Street
P.O. Box 770000
San Francisco, California 94177
________________________________________

Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000
San Francisco, California94177

______________________________________

Address of principal executive offices, including zip code

 

PG&E Corporation
(415) 973-1000
________________________________________

Pacific Gas and Electric Company
(415) 973-7000
______________________________________

Registrant's telephone number, including area code

 

Indicate by check mark whether each 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) have been subject to such filing requirements for the past 90 days.  [X] 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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

PG&E Corporation:

[X] Yes [  ] No

Pacific Gas and Electric Company:

[X] Yes [  ] No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definitions of “large accelerated filer”, “accelerated filer”, and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

PG&E Corporation:

[X] Large accelerated filer

[  ] Accelerated filer

 

[  ] Non-accelerated filer

[  ] Smaller reporting company

Pacific Gas and Electric Company:

[  ] Large accelerated filer

[  ] Accelerated filer

 

[X] 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 [X] No

Pacific Gas and Electric Company:

[  ] Yes [X] No

 

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date.

Common stock outstanding as of October 24,2016:

 

PG&E Corporation:

505,666,694

Pacific Gas and Electric Company:

264,374,809


 


PG&E CORPORATION AND
PACIFIC GAS AND ELECTRIC COMPANY
FORM 10-Q

FOR THE QUARTERLY PERIOD ENDEDSEPTEMBER 30,2016

 

TABLE OF CONTENTS

 

GLOSSARY

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONDENSED CONSOLIDATED BALANCE SHEETS

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

CONDENSED CONSOLIDATED BALANCE SHEETS

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

NOTE 4: DEBT

NOTE 5: EQUITY

NOTE 6: EARNINGS PER SHARE

NOTE 7: DERIVATIVES

NOTE 8: FAIR VALUE MEASUREMENTS

NOTE 9: CONTINGENCIES AND COMMITMENTS

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

OVERVIEW

RESULTS OF OPERATIONS

LIQUIDITY AND FINANCIAL RESOURCES

ENFORCEMENT AND LITIGATION MATTERS

REGULATORY MATTERS

LEGISLATIVE AND REGULATORY INITIATIVES

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

FORWARD-LOOKING STATEMENTS

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

ITEM 4. CONTROLS AND PROCEDURES

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

ITEM 1A. RISK FACTORS

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

ITEM 5. OTHER INFORMATION

ITEM 6. EXHIBITS

SIGNATURES


 


GLOSSARY

 

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

 

2015 Form 10-K

PG&E Corporation and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2015

2016 Q1 Form 10-Q

PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended March 31, 2016

2016 Q2 Form 10-Q

PG&E Corporation and Pacific Gas and Electric Company's combined Quarterly Report on Form 10-Q for the quarter ended June 30, 2016

AFUDC

allowance for funds used during construction

ALJ

Administrative Law Judge

ARO(s)

asset retirement obligation(s)

ASU

Accounting Standards Update issued by the FASB (see below)

Cal Fire

California Department of Forestry and Fire Protection

CAISO

California Independent System Operator Corporation

Central Coast Water Board

Central Coast Regional Water Quality Control Board

CPUC

California Public Utilities Commission

CRRs

congestion revenue rights

DER

distributed energy resources

Diablo Canyon

Diablo Canyon nuclear power plant

DOI

U.S. Department of the Interior

DTSC

California Department of Toxic Substances Control

EMANI

European Mutual Association for Nuclear Insurance

Energy Division

CPUC’s Energy Division

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

GWH

gigawatt-hours

IOU(s)

investor-owned utility(ies)

MOD POD

modified presiding officer's decision

NAV

net asset value

NDCTP

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

POD

presiding officer's decision

PSEP

pipeline safety enhancement plan

PV

photovoltaic

Regional Board

California Regional Water Control Board, Lahontan Region

RPS

Renewable Portfolio Standards

SEC

U.S. Securities and Exchange Commission

SED

Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD

TO

transmission owner

 


TURN

The Utility Reform Network

Utility

Pacific Gas and Electric Company

VIE(s)

variable interest entity(ies)


 


PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

(Unaudited)

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(in millions, except per share amounts)

2016

 

2015

 

2016

 

2015

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

Electric

$

3,994 

 

$

3,868 

 

$

10,590 

 

$

10,344 

Natural gas

 

816 

 

 

682 

 

 

2,363 

 

 

2,322 

Total operating revenues

 

4,810 

 

 

4,550 

 

 

12,953 

 

 

12,666 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

Cost of electricity

 

1,613 

 

 

1,681 

 

 

3,719 

 

 

3,958 

Cost of natural gas

 

80 

 

 

50 

 

 

377 

 

 

442 

Operating and maintenance

 

1,783 

 

 

1,621 

 

 

5,631 

 

 

5,028 

Depreciation, amortization, and decommissioning

 

694 

 

 

653 

 

 

2,090 

 

 

1,935 

Total operating expenses

 

4,170 

 

 

4,005 

 

 

11,817 

 

 

11,363 

Operating Income

 

640 

 

 

545 

 

 

1,136 

 

 

1,303 

Interest income

 

8 

 

 

2 

 

 

17 

 

 

6 

Interest expense

 

(211)

 

 

(194)

 

 

(621)

 

 

(575)

Other income, net

 

24 

 

 

24 

 

 

74 

 

 

100 

Income Before Income Taxes

 

461 

 

 

377 

 

 

606 

 

 

834 

Income tax provision (benefit)

 

70 

 

 

67 

 

 

(105)

 

 

84 

Net Income

 

391 

 

 

310 

 

 

711 

 

 

750 

Preferred stock dividend requirement of subsidiary

 

3 

 

 

3 

 

 

10 

 

 

10 

Income Available for Common Shareholders

$

388 

 

$

307 

 

$

701 

 

$

740 

Weighted Average Common Shares Outstanding, Basic

 

501 

 

 

486 

 

 

497 

 

 

481 

Weighted Average Common Shares Outstanding, Diluted

 

503 

 

 

489 

 

 

500 

 

 

484 

Net Earnings Per Common Share, Basic

$

0.77 

 

$

0.63 

 

$

1.41 

 

$

1.54 

Net Earnings Per Common Share, Diluted

$

0.77 

 

$

0.63 

 

$

1.40 

 

$

1.53 

Dividends Declared Per Common Share

$

0.49 

 

$

0.46 

 

$

1.44 

 

$

1.37 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


 

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

(Unaudited)

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Net Income

$

391 

 

$

310 

 

$

711 

 

$

750 

Other Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

Pension and other postretirement benefit plans obligations

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, $0 and $0, at respective dates)

 

- 

 

 

- 

 

 

- 

 

 

- 

Net change in investments

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, $0 and $12, at respective dates)

 

- 

 

 

- 

 

 

- 

 

 

(17)

Total other comprehensive income (loss)

 

- 

 

 

- 

 

 

- 

 

 

(17)

Comprehensive Income

 

391 

 

 

310 

 

 

711 

 

 

733 

Preferred stock dividend requirement of subsidiary

 

3 

 

 

3 

 

 

10 

 

 

10 

Comprehensive Income Attributable to

 

 

 

 

 

 

 

 

 

 

 

Common Shareholders

$

388 

 

$

307 

 

$

701 

 

$

723 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

September 30,

 

December 31,

(in millions)

2016

 

2015

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

$

71 

 

$

123 

Restricted cash

 

168 

 

 

234 

Accounts receivable:

 

 

 

 

 

Customers (net of allowance for doubtful accounts of $53 and $54

 

 

 

 

 

   at respective dates)

 

1,233 

 

 

1,106 

Accrued unbilled revenue

 

956 

 

 

855 

Regulatory balancing accounts

 

1,475 

 

 

1,760 

Other

 

475 

 

 

286 

Regulatory assets

 

370 

 

 

517 

Inventories:

 

 

 

 

 

Gas stored underground and fuel oil

 

134 

 

 

126 

Materials and supplies

 

343 

 

 

313 

Income taxes receivable

 

218 

 

 

155 

Other

 

306 

 

 

338 

Total current assets

 

5,749 

 

 

5,813 

Property, Plant, and Equipment

 

 

 

 

 

Electric

 

51,532 

 

 

48,532 

Gas

 

17,384 

 

 

16,749 

Construction work in progress

 

2,117 

 

 

2,059 

Other

 

2 

 

 

2 

Total property, plant, and equipment

 

71,035 

 

 

67,342 

Accumulated depreciation

 

(21,605)

 

 

(20,619)

Net property, plant, and equipment

 

49,430 

 

 

46,723 

Other Noncurrent Assets

 

 

 

 

 

Regulatory assets

 

7,534 

 

 

7,029 

Nuclear decommissioning trusts

 

2,597 

 

 

2,470 

Income taxes receivable

 

70 

 

 

135 

Other

 

1,185 

 

 

1,064 

Total other noncurrent assets

 

11,386 

 

 

10,698 

TOTAL ASSETS

$

66,565 

 

$

63,234 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

September 30,

 

December 31,

(in millions, except share amounts)

2016

 

2015

LIABILITIES AND EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Short-term borrowings

$

1,145 

 

$

1,019 

Long-term debt, classified as current

 

160 

 

 

160 

Accounts payable:

 

 

 

 

 

Trade creditors

 

1,370 

 

 

1,414 

Regulatory balancing accounts

 

764 

 

 

715 

Other

 

496 

 

 

398 

Disputed claims and customer refunds

 

233 

 

 

454 

Interest payable

 

144 

 

 

206 

Other

 

1,958 

 

 

1,997 

Total current liabilities

 

6,270 

 

 

6,363 

Noncurrent Liabilities

 

 

 

 

 

Long-term debt

 

16,528 

 

 

15,925 

Regulatory liabilities

 

6,613 

 

 

6,321 

Pension and other postretirement benefits

 

2,632 

 

 

2,622 

Asset retirement obligations

 

4,672 

 

 

3,643 

Deferred income taxes

 

9,850 

 

 

9,206 

Other

 

2,394 

 

 

2,326 

Total noncurrent liabilities

 

42,689 

 

 

40,043 

Commitments and Contingencies (Note 9)

 

 

 

 

 

Equity

 

 

 

 

 

Shareholders' Equity

 

 

 

 

 

Common stock, no par value, authorized 800,000,000 shares;

 

 

 

 

 

505,183,752 and 492,025,443 shares outstanding at respective dates

 

12,083 

 

 

11,282 

Reinvested earnings

 

5,278 

 

 

5,301 

Accumulated other comprehensive loss

 

(7)

 

 

(7)

Total shareholders' equity

 

17,354 

 

 

16,576 

Noncontrolling Interest - Preferred Stock of Subsidiary

 

252 

 

 

252 

Total equity

 

17,606 

 

 

16,828 

TOTAL LIABILITIES AND EQUITY

$

66,565 

 

$

63,234 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Unaudited)

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

Cash Flows from Operating Activities

 

 

 

 

 

Net income

$

711 

 

$

750 

Adjustments to reconcile net income to net cash provided by

 

 

 

 

 

operating activities:

 

 

 

 

 

Depreciation, amortization, and decommissioning

 

2,090 

 

 

1,935 

Allowance for equity funds used during construction

 

(84)

 

 

(80)

Deferred income taxes and tax credits, net

 

644 

 

 

260 

Disallowed capital expenditures

 

517 

 

 

270 

Other

 

293 

 

 

247 

Effect of changes in operating assets and liabilities:

 

 

 

 

 

     Accounts receivable

 

(546)

 

 

(322)

     Inventories

 

(38)

 

 

5 

     Accounts payable

 

189 

 

 

95 

     Income taxes receivable/payable

 

(63)

 

 

42 

     Other current assets and liabilities

 

254 

 

 

(87)

     Regulatory assets, liabilities, and balancing accounts, net

 

(634)

 

 

78 

Other noncurrent assets and liabilities

 

(85)

 

 

(251)

Net cash provided by operating activities

 

3,248 

 

 

2,942 

Cash Flows from Investing Activities

 

 

 

 

 

Capital expenditures

 

(4,128)

 

 

(3,662)

Decrease in restricted cash

 

66 

 

 

11 

Proceeds from sales and maturities of nuclear decommissioning

 

 

 

 

 

trust investments

 

1,019 

 

 

1,023 

Purchases of nuclear decommissioning trust investments

 

(1,050)

 

 

(1,124)

Other

 

10 

 

 

18 

Net cash used in investing activities

 

(4,083)

 

 

(3,734)

Cash Flows from Financing Activities

 

 

 

 

 

Net issuances (repayments) of commercial paper, net of discount of $5

 

 

 

 

 

     and $2 at respective dates

 

(128)

 

 

545 

Short-term debt financing

 

250 

 

 

- 

Short-term debt matured

 

- 

 

 

(300)

Proceeds from issuance of long-term debt, net of discount and

 

 

 

 

 

     issuance costs of $6 and $14 at respective dates

 

594 

 

 

486 

Common stock issued

 

727 

 

 

689 

Common stock dividends paid

 

(678)

 

 

(638)

Other

 

18 

 

 

13 

Net cash provided by financing activities

 

783 

 

 

795 

Net change in cash and cash equivalents

 

(52)

 

 

3 

Cash and cash equivalents at January 1

 

123 

 

 

151 

Cash and cash equivalents at September 30

$

71 

 

$

154 

 

 


Supplemental disclosures of cash flow information

 

 

 

 

 

Cash received (paid) for:

 

 

 

 

 

Interest, net of amounts capitalized

$

(611)

 

$

(569)

Income taxes, net

 

154 

 

 

- 

Supplemental disclosures of noncash investing and financing activities

 

 

 

 

 

Common stock dividends declared but not yet paid

$

248 

 

$

223 

Capital expenditures financed through accounts payable

 

325 

 

 

245 

Noncash common stock issuances

 

15 

 

 

15 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

(Unaudited)

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

Electric

$

3,993 

 

$

3,868 

 

$

10,590 

 

$

10,344 

Natural gas

 

816 

 

 

682 

 

 

2,363 

 

 

2,322 

Total operating revenues

 

4,809 

 

 

4,550 

 

 

12,953 

 

 

12,666 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

Cost of electricity

 

1,613 

 

 

1,681 

 

 

3,719 

 

 

3,958 

Cost of natural gas

 

80 

 

 

50 

 

 

377 

 

 

442 

Operating and maintenance

 

1,782 

 

 

1,622 

 

 

5,630 

 

 

5,028 

Depreciation, amortization, and decommissioning

 

694 

 

 

653 

 

 

2,090 

 

 

1,935 

Total operating expenses

 

4,169 

 

 

4,006 

 

 

11,816 

 

 

11,363 

Operating Income

 

640 

 

 

544 

 

 

1,137 

 

 

1,303 

Interest income

 

8 

 

 

2 

 

 

16 

 

 

6 

Interest expense

 

(209)

 

 

(191)

 

 

(614)

 

 

(567)

Other income, net

 

23 

 

 

22 

 

 

68 

 

 

68 

Income Before Income Taxes

 

462 

 

 

377 

 

 

607 

 

 

810 

Income tax provision (benefit)

 

73 

 

 

72 

 

 

(99)

 

 

95 

Net Income

 

389 

 

 

305 

 

 

706 

 

 

715 

Preferred stock dividend requirement

 

3 

 

 

3 

 

 

10 

 

 

10 

Income Available for Common Stock

$

386 

 

$

302 

 

$

696 

 

$

705 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


 

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

(Unaudited)

 

Three Months Ended

 

 

Nine Months Ended

 

September 30,

 

 

September 30,

(in millions)

2016

 

2015

 

 

2016

 

2015

Net Income

$

389 

 

$

305 

 

$

706 

 

$

715 

Other Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

Pension and other postretirement benefit plans obligations

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, $0 and $0, at respective dates )

 

- 

 

 

- 

 

 

1 

 

 

- 

Total other comprehensive income (loss)

 

- 

 

 

- 

 

 

1 

 

 

- 

Comprehensive Income

$

389 

 

$

305 

 

$

707 

 

$

715 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

September 30,

 

December 31,

(in millions)

2016

 

2015

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

$

68 

 

$

59 

Restricted cash

 

168 

 

 

234 

Accounts receivable:

 

 

 

 

 

Customers (net of allowance for doubtful accounts of $53 and $54

 

 

 

 

 

  at respective dates)

 

1,233 

 

 

1,106 

Accrued unbilled revenue

 

956 

 

 

855 

Regulatory balancing accounts

 

1,475 

 

 

1,760 

Other

 

473 

 

 

284 

Regulatory assets

 

370 

 

 

517 

Inventories:

 

 

 

 

 

Gas stored underground and fuel oil

 

134 

 

 

126 

Materials and supplies

 

343 

 

 

313 

Income taxes receivable

 

194 

 

 

130 

Other

 

306 

 

 

338 

Total current assets

 

5,720 

 

 

5,722 

Property, Plant, and Equipment

 

 

 

 

 

Electric

 

51,532 

 

 

48,532 

Gas

 

17,384 

 

 

16,749 

Construction work in progress

 

2,117 

 

 

2,059 

Total property, plant, and equipment

 

71,033 

 

 

67,340 

Accumulated depreciation

 

(21,603)

 

 

(20,617)

Net property, plant, and equipment

 

49,430 

 

 

46,723 

Other Noncurrent Assets

 

 

 

 

 

Regulatory assets

 

7,534 

 

 

7,029 

Nuclear decommissioning trusts

 

2,597 

 

 

2,470 

Income taxes receivable

 

70 

 

 

135 

Other

 

1,066 

 

 

958 

Total other noncurrent assets

 

11,267 

 

 

10,592 

TOTAL ASSETS

$

66,417 

 

$

63,037 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

September 30,

 

December 31,

(in millions, except share amounts)

2016

 

2015

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Short-term borrowings

$

981 

 

$

1,019 

Long-term debt, classified as current

 

160 

 

 

160 

Accounts payable:

 

 

 

 

 

Trade creditors

 

1,370 

 

 

1,414 

Regulatory balancing accounts

 

764 

 

 

715 

Other

 

765 

 

 

418 

Disputed claims and customer refunds

 

233 

 

 

454 

Interest payable

 

144 

 

 

203 

Other

 

1,681 

 

 

1,750 

Total current liabilities

 

6,098 

 

 

6,133 

Noncurrent Liabilities

 

 

 

 

 

Long-term debt

 

16,179 

 

 

15,577 

Regulatory liabilities

 

6,613 

 

 

6,321 

Pension and other postretirement benefits

 

2,540 

 

 

2,534 

Asset retirement obligations

 

4,672 

 

 

3,643 

Deferred income taxes

 

10,135 

 

 

9,487 

Other

 

2,350 

 

 

2,282 

Total noncurrent liabilities

 

42,489 

 

 

39,844 

Commitments and Contingencies (Note 9)

 

 

 

 

 

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

 

7,955 

 

 

7,215 

Reinvested earnings

 

8,291 

 

 

8,262 

Accumulated other comprehensive income

 

4 

 

 

3 

Total shareholders' equity

 

17,830 

 

 

17,060 

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

$

66,417 

 

$

63,037 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Unaudited)

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

Cash Flows from Operating Activities

 

 

 

 

 

Net income

$

706 

 

$

715 

Adjustments to reconcile net income to net cash provided by

 

 

 

 

 

operating activities:

 

 

 

 

 

Depreciation, amortization, and decommissioning

 

2,090 

 

 

1,935 

Allowance for equity funds used during construction

 

(84)

 

 

(80)

Deferred income taxes and tax credits, net

 

648 

 

 

245 

    Disallowed capital expenditures

 

517 

 

 

270 

    Other

 

234 

 

 

200 

Effect of changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(546)

 

 

(321)

Inventories

 

(38)

 

 

5 

Accounts payable

 

194 

 

 

148 

Income taxes receivable/payable

 

(64)

 

 

14 

Other current assets and liabilities

 

258 

 

 

(45)

Regulatory assets, liabilities, and balancing accounts, net

 

(634)

 

 

78 

    Other noncurrent assets and liabilities

 

(75)

 

 

(232)

Net cash provided by operating activities

 

3,206 

 

 

2,932 

Cash Flows from Investing Activities

 

 

 

 

 

Capital expenditures

 

(4,128)

 

 

(3,662)

Decrease in restricted cash

 

66 

 

 

11 

Proceeds from sales and maturities of nuclear decommissioning

 

 

 

 

 

trust investments

 

1,019 

 

 

1,023 

Purchases of nuclear decommissioning trust investments

 

(1,050)

 

 

(1,124)

Other

 

10 

 

 

18 

Net cash used in investing activities

 

(4,083)

 

 

(3,734)

Cash Flows from Financing Activities

 

 

 

 

 

Net issuances (repayments) of commercial paper, net of discount of $5

 

 

 

 

 

     and $2 at respective dates

 

(293)

 

 

545 

Short-term debt financing

 

250 

 

 

- 

Short-term debt matured

 

- 

 

 

(300)

Proceeds from issuance of long-term debt, net of discount and

 

 

 

 

 

     issuance costs of $6 and $14 at respective dates

 

594 

 

 

486 

Preferred stock dividends paid

 

(10)

 

 

(10)

Common stock dividends paid

 

(423)

 

 

(537)

Equity contribution from PG&E Corporation

 

740 

 

 

605 

Other

 

28 

 

 

20 

Net cash provided by financing activities

 

886 

 

 

809 

Net change in cash and cash equivalents

 

9 

 

 

7 

Cash and cash equivalents at January 1

 

59 

 

 

55 

Cash and cash equivalents at September 30

$

68 

 

$

62 

 

 


Supplemental disclosures of cash flow information

 

 

 

 

 

Cash received (paid) for:

 

 

 

 

 

Interest, net of amounts capitalized

$

(602)

 

$

(561)

Income taxes, net

 

151 

 

 

- 

Supplemental disclosures of noncash investing and financing activities

 

 

 

 

 

Common stock dividends declared but not yet paid

$

244 

 

$

- 

Capital expenditures financed through accounts payable

 

325 

 

 

245 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.


 


NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

 

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 quarterly report on Form 10-Q is a combined report of PG&E Corporation and the Utility.  PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries.  The Utility’s Condensed 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 Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.  PG&E Corporation and the Utility operate in one segment, as the companies assess financial performance and allocate resources on a consolidated basis.

 

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments (consisting only of normal recurring adjustments) that management believes are necessary for the fair presentation of PG&E Corporation and the Utility’s financial condition, results of operations, and cash flows for the periods presented.  The information at December 31, 2015 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2015 Form 10-K.  This quarterly report should be read in conjunction with the 2015 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, asset retirement obligations, and pension and other postretirement benefit plans obligations.  Management believes that its estimates and assumptions reflected in the Condensed 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 during the period in which such change occurred.

 

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

 

The significant accounting policies used by PG&E Corporation and the Utility are discussed in Note 2 of the Notes to the Consolidated Financial Statements in the 2015 Form 10-K.

 

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 has a controlling interest or was the primary beneficiary of any of these VIEs at September 30, 2016, the Utility 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 September 30, 2016, it did not consolidate any of them.

 

 


Asset Retirement Obligations

 

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three yearsin conjunction with the Nuclear Decommissioning Cost Triennial ProceedingsIn the first quarter of 2016, the Utility submitted its updated decommissioning cost estimate with the CPUC, which reflects an increase of approximately $1.4 billion in the estimated undiscounted cost to decommission the Utility’s nuclear power plants.  The change in total estimated cost resulted in an $818 million adjustment to the ARO recognized on the Condensed Consolidated Balance Sheets.  The adjustment relates to spent fuel storage, staffing, and out-of-state waste disposal costs.  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 June 20, 2016, the Utility entered into a joint proposalwith certain parties to retire Diablo Canyon nuclear power plant at the expiration of its current operating licenses in 2024 (Unit 1) and 2025 (Unit 2), subject to certain approvals, resulting in an additional $115 million increase to the ARO recognized on the Condensed Consolidated Balance Sheets in the second quarter of 2016. 

 

The estimated total nuclear decommissioning cost of $4.8 billion is discounted for GAAP purposes and recognized as an ARO on the Condensed Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.5 billion at September 30,2016 and $2.5 billion at December 31, 2015.  Changes in these estimates could materially affect the amount of the recorded ARO for these assets.

 

Pension and Other Postretirement Benefits

 

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.

 

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2016 and 2015 were as follows:

 

 

Pension Benefits

 

Other Benefits

 

Three Months Ended September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Service cost for benefits earned

$

113 

 

$ 

123 

 

$ 

13 

 

$ 

14 

Interest cost

 

179 

 

 

168 

 

 

19 

 

 

18 

Expected return on plan assets

 

(207)

 

 

(219)

 

 

(26)

 

 

(28)

Amortization of prior service cost

 

2 

 

 

4 

 

 

3 

 

 

4 

Amortization of net actuarial loss

 

6 

 

 

1 

 

 

1 

 

 

1 

Net periodic benefit cost

 

93 

 

 

77 

 

 

10 

 

 

9 

Regulatory account transfer (1)

 

(8)

 

 

8 

 

 

- 

 

 

- 

Total

$ 

85 

 

$ 

85 

 

$ 

10 

 

$ 

9 

 

 

 

 

 

 

 

 

 

 

 

 

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

 

 


 

Pension Benefits

 

Other Benefits

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Service cost for benefits earned

$

339 

 

$ 

360 

 

$ 

39 

 

$ 

41 

Interest cost

 

537 

 

 

505 

 

 

57 

 

 

54 

Expected return on plan assets

 

(621)

 

 

(655)

 

 

(80)

 

 

(84)

Amortization of prior service cost

 

6 

 

 

11 

 

 

11 

 

 

14 

Amortization of net actuarial loss

 

18 

 

 

7 

 

 

3 

 

 

3 

Net periodic benefit cost

 

279 

 

 

228 

 

 

30 

 

 

28 

Regulatory account transfer (1)

 

(25)

 

 

26 

 

 

- 

 

 

- 

Total

$ 

254 

 

$ 

254 

 

$ 

30 

 

$ 

28 

 

 

 

 

 

 

 

 

 

 

 

 

(1) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

 

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (Loss)

 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:

 

 

Pension

 

Other

 

 

 

 

Benefits

 

Benefits

 

Total

(in millions, net of income tax)

Three Months Ended September 30, 2016

Beginning balance

$

(23)

 

$

16 

 

$

(7)

Amounts reclassified from other comprehensive income: (1)

 

 

 

 

 

 

 

 

Amortization of prior service cost

 

 

 

 

 

 

 

 

(net of taxes of $0 and $2, respectively)

 

2 

 

 

1 

 

 

3 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

(net of taxes of $3 and $0, respectively)

 

3 

 

 

1 

 

 

4 

Regulatory account transfer

 

 

 

 

 

 

 

 

(net of taxes of $3 and $2, respectively)

 

(5)

 

 

(2)

 

 

(7)

Net current period other comprehensive gain (loss)

 

- 

 

 

- 

 

 

- 

Ending balance

$ 

(23)

 

$ 

16 

 

$ 

(7)

 

 

 

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)

 

 


 

Pension

 

Other

 

 

 

 

Benefits

 

Benefits

 

Total

(in millions, net of income tax)

Three Months Ended September 30, 2015

Beginning balance

$

(21)

 

$

15 

 

$

(6)

Amounts reclassified from other comprehensive income: (1)

 

 

 

 

 

 

 

 

Amortization of prior service cost

 

 

 

 

 

 

 

 

(net of taxes of $1 and $2, respectively)

 

3 

 

 

2 

 

 

5 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

(net of taxes of $0, and $0, respectively)

 

1 

 

 

1 

 

 

2 

Regulatory account transfer

 

 

 

 

 

 

 

 

(net of taxes of $3 and $3, respectively)

 

(4)

 

 

(3)

 

 

(7)

Net current period other comprehensive gain (loss)

 

- 

 

 

- 

 

 

- 

Ending balance

$

(21)

 

$ 

15 

 

$ 

(6)

 

 

 

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)

 

 

Pension

 

Other

 

 

 

 

Benefits

 

Benefits

 

Total

(in millions, net of income tax)

Nine Months Ended September 30, 2016

Beginning balance

$

(23)

 

$ 

16 

 

$

(7)

Amounts reclassified from other comprehensive income: (1)

 

 

 

 

 

 

 

 

Amortization of prior service cost

 

 

 

 

 

 

 

 

(net of taxes of $2 and $5, respectively)

 

4 

 

 

6 

 

 

10 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

(net of taxes of $7 and $1, respectively)

 

11 

 

 

2 

 

 

13 

Regulatory account transfer

 

 

 

 

 

 

 

 

(net of taxes of $9 and $6, respectively)

 

(15)

 

 

(8)

 

 

(23)

Net current period other comprehensive gain (loss)

 

- 

 

 

- 

 

 

- 

Ending balance

$

(23)

 

$

16 

 

$

(7)

 

 

 

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)

 

 


 

Pension

 

Other

 

Other

 

 

 

 

Benefits

 

Benefits

 

Investments

 

Total

(in millions, net of income tax)

Nine Months Ended September 30, 2015

Beginning balance

$

(21)

 

$

15 

 

$

17 

 

$

11 

Amounts reclassified from other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

      Amortization of prior service cost

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $4, $6, and $0, respectively) (1)

 

7 

 

 

8 

 

 

- 

 

 

15 

      Amortization of net actuarial loss

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $3, $1, and $0, respectively) (1)

 

4 

 

 

2 

 

 

- 

 

 

6 

     Regulatory account transfer

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $7, $7, and $0, respectively) (1)

 

(11)

 

 

(10)

 

 

- 

 

 

(21)

Change in investments

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, and $12, respectively)

 

- 

 

 

- 

 

 

(17)

 

 

(17)

Net current period other comprehensive gain (loss)

 

- 

 

 

- 

 

 

(17)

 

 

(17)

Ending balance

$

(21)

 

$ 

15 

 

$ 

- 

 

$ 

(6)

 

 

 

 

 

 

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See the “Pension and Other Postretirement Benefits” table above for additional details.)

 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above, with the exception of other investments which are held by PG&E Corporation.

 

Recently Adopted Accounting Guidance

 

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 the net asset value per share.  PG&E Corporation and the Utility adopted this guidance effectiveJanuary 1, 2016 and applied the requirements retrospectively for all periods presentedThe adoption of this standard did not impact their Condensed Consolidated Financial Statements.  All prior periods presented in these Condensed Consolidated financial statements reflect the retrospective adoption of this guidance. (See Note 8 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 Condensed 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 Condensed Consolidated Financial Statements.  PG&E Corporation and the Utility reclassified $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 Condensed Consolidated Financial Statements reflect the retrospective adoption of this guidance.  

 

 


Accounting Standards Issued But Not Yet Adopted

 

Share-based Payment Accounting

 

In March 2016, the FASB issued ASU No. 2016-09, CompensationStock 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.  The ASU will be effective for PG&E Corporation and the Utility on January 1, 2017.  PG&E Corporation and the Utility will early adopt this guidance in the fourth quarter of 2016 and do not expect this ASU to have a material impact on their Condensed Consolidated Financial Statements and related disclosures.

 

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 disclosing key information about leasing arrangements.  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 Condensed 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 Condensed 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 the existing revenue recognition guidanceIn August 2015, the FASB deferred the effective date of this amendment for public companies by one year to January 1, 2018, with early adoption permitted as of the original effective date of January 1, 2017.  (See ASU No. 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.)  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

 

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

 

Regulatory Assets

 

Long-term regulatory assets are composed of the following:

 

 

Balance at

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Pension benefits

$

2,416 

 

$

2,414 

Deferred income taxes 

 

3,649 

 

 

3,054 

Utility retained generation

 

376 

 

 

411 

Environmental compliance costs

 

760 

 

 

748 

Price risk management

 

96 

 

 

138 

Unamortized loss, net of gain, on reacquired debt

 

81 

 

 

94 

Other

 

156 

 

 

170 

Total long-term regulatory assets

$

7,534 

 

$ 

7,029 

 

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.

 

 


Regulatory Liabilities

 

Long-term regulatory liabilities are composed of the following:

 

 

Balance at

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Cost of removal obligations

$

4,939 

 

$

4,605 

Recoveries in excess of asset retirement obligations

 

656 

 

 

631 

Public purpose programs 

 

539 

 

 

600 

Other

 

479 

 

 

485 

Total long-term regulatory liabilities

$

6,613 

 

$

6,321 

 

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.

 

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 Condensed Consolidated Balance Sheets.  These differences do not have an impact on net incomeBalancing 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

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Electric distribution

$

43 

 

$

380 

Utility generation

 

- 

 

 

122 

Gas distribution

 

583 

 

 

493 

Energy procurement

 

174 

 

 

262 

Public purpose programs

 

122 

 

 

155 

Other

 

553 

 

 

348 

Total regulatory balancing accounts receivable

$

1,475 

 

$

1,760 

 

 

Payable

 

Balance at

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Utility generation

$

47 

 

$

- 

Energy procurement

 

109 

 

 

112 

Public purpose programs

 

289 

 

 

244 

Other

 

319 

 

 

359 

Total regulatory balancing accounts payable

$

764 

 

$

715 

 

 

 

 

 

 

 

 


The electric distribution, utility generation, and gas distribution balancing accounts track the collection of revenue requirements approved in the GRC.  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 and low income energy efficiency.

 

NOTE 4: DEBT

 

Revolving Credit Facilities and Commercial Paper Program

 

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at September 30, 2016:

 

 

 

 

 

 

Letters of

 

 

 

 

 

Termination

 

Facility

 

Credit

 

Commercial

 

Facility

(in millions)

Date

 

Limit

 

Outstanding

 

Paper

 

Availability

PG&E Corporation

April 2021

 

$

300 

(1)

$

- 

 

$

165 

 

$

135 

Utility

April 2021

 

 

3,000 

(2)

 

31 

 

 

731 

 

 

2,238 

Total revolving credit facilities

 

 

$

3,300 

 

$

31 

 

$

896 

 

$

2,373 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 

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.

 

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.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

 

Senior Notes Issuances

 

In March 2016, the Utility issued $600 million principal amount of 2.95% Senior Notes due March 1, 2026. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

 

Variable Rate Interest

 

AtSeptember 30, 2016, the interest rates on the $614 million principal amount of pollution control bonds Series 1996 C, E, F, and 1997 B and the related loan agreements ranged from 0.89% to 0.92%.  At September 30, 2016, the interest rates on the $309  million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.77% to 0.85%.  Pollution control bonds Series 2009 C and D will mature on December 1, 2016.

 

 


NOTE 5: EQUITY

 

PG&E Corporation’s and the Utility’s changes in equity for the nine months ended September 30, 2016were as follows:

 

 

PG&E Corporation

 

Utility

 

Total

 

Total

(in millions)

Equity

 

Shareholders' Equity

Balance at December 31, 2015

$

16,828 

 

$

17,060 

Comprehensive income

 

711 

 

 

707 

Equity contributions

 

- 

 

 

740 

Common stock issued

 

742 

 

 

- 

Share-based compensation

 

59 

 

 

- 

Common stock dividends declared

 

(724)

 

 

(667)

Preferred stock dividend requirement

 

- 

 

 

(10)

Preferred stock dividend requirement of subsidiary

 

(10)

 

 

- 

Balance at September 30, 2016

$

17,606 

 

$

17,830 

 

During the three and nine months ended September 30, 2016, PG&E Corporation sold 0.4 million and 2.6 million shares of its common stock under the February 2015 equity distribution agreement for cash proceeds of $26 million and $149 million, respectively, net of commissions paid of $0.2 million and $1.3 million, respectively. As of September 30, 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.

 

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 the nine months ended September 30, 2016, 5.7 million shares were issued for cash proceeds of $269 million under these plans.

 

NOTE 6: 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:

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(in millions, except per share amounts)

2016

 

2015

 

2016

 

2015

Income available for common shareholders

$

388 

 

$

307 

 

$

701 

 

$

740 

Weighted average common shares outstanding, basic

 

501 

 

 

486 

 

 

497 

 

 

481 

Add incremental shares from assumed conversions:

 

 

 

 

 

 

 

 

 

 

 

Employee share-based compensation

 

2 

 

 

3 

 

 

3 

 

 

3 

Weighted average common shares outstanding, diluted

 

503 

 

 

489 

 

 

500 

 

 

484 

Total earnings per common share, diluted

$

0.77 

 

$

0.63 

 

$

1.40 

 

$

1.53 

 

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 7: 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 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. 

 


 

Derivatives are recorded at fair value and are presented in the Utility’sCondensed 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.  

 

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 as long as the current ratemaking mechanism remains in place and 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 Condensed 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 Condensed Consolidated Balance Sheets at fair value.  Eligible derivatives are accounted for under the accrual method of accounting.

 

Volume of Derivative Activity

 

The volumes of the Utility’s outstanding derivatives were as follows:

 

 

 

 

Contract Volume at

 

 

 

 

September 30,

 

December 31,

Underlying Product

 

Instruments

 

2016

 

2015

Natural Gas (1) (MMBtus (2))

 

Forwards, Futures and Swaps

 

376,296,893

 

333,091,813

 

 

Options

 

118,017,176

 

111,550,004

Electricity (Megawatt-hours)

 

Forwards, Futures and Swaps

 

3,128,038

 

3,663,512

 

 

Congestion Revenue Rights (3)

 

172,756,395

 

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 September 30, 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

$

100 

 

$

(8)

 

$

14 

 

$

106 

Other noncurrent assets – other

 

128 

 

 

(8)

 

 

- 

 

 

120 

Current liabilities – other

 

(67)

 

 

8 

 

 

10 

 

 

(49)

Noncurrent liabilities – other

 

(104)

 

 

8 

 

 

7 

 

 

(89)

Net commodity risk

$

57 

 

$

- 

 

$

31 

 

$

88 

 

At December 31, 2015, 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

$

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)

Net commodity risk

$

27 

 

$

- 

 

$

90 

 

$

117 

 

 


Gains and losses associated with price risk management activities were recorded as follows:

 

 

Commodity Risk

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Unrealized gain (loss) - regulatory assets and liabilities (1)

$

(29)

 

$ 

(45)

 

$

30 

 

$

(69)

Realized gain (loss) - cost of electricity (2)

 

(7)

 

 

1 

 

 

(48)

 

 

4 

Realized loss - cost of natural gas (2)

 

(9)

 

 

(3)

 

 

(15)

 

 

(8)

Net commodity risk

$

(45)

 

$ 

(47)

 

$

(33)

 

$

(73)

 

 

 

 

 

 

 

 

 

 

 

 

(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 Condensed 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 Condensed 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 September 30, 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

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Derivatives in a liability position with credit risk-related

 

 

 

 

 

contingencies that are not fully collateralized

$

(8)

 

$

(2)

Related derivatives in an asset position

 

4 

 

 

- 

Collateral posting in the normal course of business related to

 

 

 

 

 

these derivatives

 

2 

 

 

- 

Net position of derivative contracts/additional collateral

 

 

 

 

 

posting requirements (1)

$

(2)

 

$

(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 8: FAIR VALUE MEASUREMENTS

 

PG&E Corporation and the Utility measure their cash equivalents, trust assets, price risk management instruments, and other investments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

 

  • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

 

  • Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

 

  • 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.


 


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 September 30, 2016

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

$

- 

 

$

- 

 

$

- 

 

$

- 

 

$

- 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

 

1 

 

 

- 

 

 

- 

 

 

- 

 

 

1 

Global equity securities

 

1,678 

 

 

- 

 

 

- 

 

 

- 

 

 

1,678 

Fixed-income securities

 

720 

 

 

530 

 

 

- 

 

 

- 

 

 

1,250 

Assets measured at NAV

 

- 

 

 

- 

 

 

- 

 

 

- 

 

 

14 

Total nuclear decommissioning trusts (2)

 

2,399 

 

 

530 

 

 

- 

 

 

- 

 

 

2,943 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electricity

 

10 

 

 

16 

 

 

192 

 

 

(2)

 

 

216 

Gas

 

- 

 

 

10 

 

 

- 

 

 

- 

 

 

10 

Total price risk management instruments

 

10 

 

 

26 

 

 

192 

 

 

(2)

 

 

226 

Rabbi trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed-income securities

 

- 

 

 

59 

 

 

- 

 

 

- 

 

 

59 

Life insurance contracts

 

- 

 

 

77 

 

 

- 

 

 

- 

 

 

77 

Total rabbi trusts

 

- 

 

 

136 

 

 

- 

 

 

- 

 

 

136 

Long-term disability trust

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

 

4 

 

 

- 

 

 

- 

 

 

- 

 

 

4 

Assets measured at NAV

 

- 

 

 

- 

 

 

- 

 

 

- 

 

 

138 

Total long-term disability trust

 

4 

 

 

- 

 

 

- 

 

 

- 

 

 

142 

Total assets

$

2,413 

 

$

692 

 

$

192 

 

$

(2)

 

$

3,447 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Electricity

$

25 

 

$

8 

 

$

136 

 

$

(33)

 

$

136 

Gas

 

- 

 

 

2 

 

 

- 

 

 

- 

 

 

2 

Total liabilities

$

25 

 

$

10 

 

$

136 

 

$

(33)

 

$

138 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

 (2) Represents amount before deducting $346 million, primarily related to deferred taxes on appreciation of investment value.

 

 


 

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 in the 2015 Form 10-K)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 in the 2015 Form 10-K)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.  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 nine months ended September 30, 2016 and 2015.

 

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 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.

 

Assets Measured at NAV Using Practical Expedient

 

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 Condensed 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 Condensed 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 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 Risk and Audit Officer of the Utility, 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 7 above.)

 


 

 

 

Fair Value at

 

 

 

 

 

 

 

(in millions)

 

At September 30, 2016

 

Valuation

 

Unobservable

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Technique

 

Input

 

Range (1)

Congestion revenue rights

 

$

192 

 

$ 

43 

 

Market approach

 

CRR auction prices

 

$

(23.81) - 8.76

Power purchase agreements

 

$

- 

 

$ 

93 

 

Discounted cash flow

 

Forward prices

 

$

18.07 - 38.80 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 (1) Represents price per megawatt-hour

 

 

 

Fair Value at

 

 

 

 

 

 

 

(in millions)

 

At December 31, 2015

 

Valuation

 

Unobservable

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Technique

 

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

 

Level 3 Reconciliation

 

The following tables present the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2016 and 2015:

 

 

Price Risk Management Instruments

(in millions)

2016

 

2015

Asset (liability) balance as of July 1

$

66 

 

$

48 

Net realized and unrealized gains:

 

 

 

 

 

Included in regulatory assets and liabilities or balancing accounts (1)

 

(10)

 

 

(27)

Asset (liability) balance as of September 30

$

56 

 

$

21 

 

 

 

 

 

 

(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.

 

 

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)

 

(33)

 

 

(48)

Asset (liability) balance as of September 30

$

56 

 

$

21 

 

 

 

 

 

 

(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:

 

  • The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at September 30, 2016 and December 31, 2015, as they are short-term in nature or have interest rates that reset daily. 

 

  • 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 September 30, 2016 and December 31, 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 September 30, 2016

 

At December 31, 2015

(in millions)

Carrying Amount

 

Level 2 Fair Value

 

Carrying Amount

 

Level 2 Fair Value

PG&E Corporation

$

350 

 

$

356 

 

$

350 

 

$

354 

Utility

 

15,417 

 

 

18,440 

 

 

14,918 

 

 

16,422 

 

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 September 30, 2016

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

$

1 

 

$

- 

 

$

- 

 

$

1 

Global equity securities

 

579 

 

 

1,116 

 

 

(3)

 

 

1,692 

Fixed-income securities

 

1,164 

 

 

89 

 

 

(3)

 

 

1,250 

Total (1)

$

1,744 

 

$

1,205 

 

$

(6)

 

$

2,943 

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 $346 million and $314 million at September 30, 2016 and December 31, 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:

 

 

As of

(in millions)

September 30, 2016

Less than 1 year

$

33 

1–5 years

 

443 

5–10 years

 

271 

More than 10 years

 

503 

Total maturities of fixed-income securities

$

1,250 

 

The following table provides a summary of activity for the investments:

 

 

Three Months Ended

 

Nine Months Ended

 

September 30,

 

September 30,

 

2016

 

2015

 

 

2016

 

2015

(in millions)

 

 

 

 

 

 

 

 

 

 

 

Proceeds from sales and maturities of nuclear decommissioning 

 

 

 

 

 

 

 

 

 

 

 

trust investments

$

257 

 

$

244 

 

$

1,019 

 

$

1,023 

Gross realized gains on securities held as available-for-sale

 

6 

 

 

3 

 

 

15 

 

 

50 

Gross realized losses on securities held as available-for-sale

 

(14)

 

 

(12)

 

 

(17)

 

 

(25)

 


NOTE 9: 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.  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 July 12, 2016, the assigned commissioner and ALJ issued a ruling that adopted recommendations included in a process report jointly submitted by the Cities of San Bruno and San Carlos, ORA, the SED, TURN (together, the “other parties”), and the Utility in April 2016.  The approved framework for resolving the proceeding included a total of 159 communications (the 46 communications already included in the OII and 113 additional communications) in the scope of the proceeding, a procedure for moving undisputed facts into the evidentiary record and a diligence process for providing additional factual information.  The Utility and the other parties disagreed on the inclusion of an additional 21 communications in the scope and filed briefs on the issue.  The ruling confirmed that these additional 21 communications were not included within the scope of the OII and do not, in themselves, appear to be ex parte violations, but granted the other parties’ request to seek additional information regarding these communications. 

 

In a status report jointly submitted to the CPUC on October 14, 2016, the parties proposed an update to the framework for resolving the proceeding.  The revised framework includes a total of 165 communications (159 communications previously included in the proceeding, reduced by two communications the other parties agreed not to pursue, plus 8 additional communications out of 21 communications previously in disagreement).  The parties also proposed to begin settlement discussions on November 30, 2016, followed by a joint status report proposed for January 13, 2017.  In the event a settlement cannot be reached, the parties proposed to submit their opening briefs on January 27, 2017, and reply briefs on February 17, 2017.  On October 31, 2016, the CPUC issued a proposed decision adopting the schedule proposed by the parties in the October 14, 2016 status report.  The proposed decision extends the statutory deadline for this proceeding to May 17, 2017 in order to allow the parties to complete settlement discussions or file briefs, and for the ALJ to prepare and file a proposed decision. 

 

 


The Utility expects that the other parties may argue that the number of violations exceeds the 165 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 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 but are unable to 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, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also have been investigating matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility is cooperating with these 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 unanimously approved a modified presiding officer’s decision (the “MOD POD”) issued on August 17, 2016 in this investigation.  In accordance with the MOD POD, the amount of the fine increased from $24.3 million to $25.6 million, to include a $50,000 fine omitted from the June 1, 2016 presiding officer’s decision (the “POD”) and $1.3 million resulting from the per-day fine increase for the missing leak repair records for the De Anza division. 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.

 

In accordance with the MOD POD, the decision denies the appeals previously filed by the SED and Carmel from the POD, and closes this proceeding but allows 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 thoserelated to the missing DeAnza 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, the Utility held a meet and confer with parties to develop remedial measures necessary to address the issues identified in the CPUC decision with the objective of establishing a compliance plan that includes all feasible and cost-effective measures necessary to improve the Utility’s natural gas distribution system record-keeping.  Under the current schedule, the parties are expected to submit a compliance plan to the CPUC on or before December 16, 2016.

 

 


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 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 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.

 

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 fines for violations identified through audits, investigations, or self-reports.  The SED can impose fines up to $50,000 for each violation, per day, and 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.  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.  The decision closes the proceeding.

 

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 fines or take other enforcement action based on some of the Utility’s self-reported non-compliance with laws and regulations or based on allegations of non-compliance with such laws and regulations that are contained in some of the SED’s audits.  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 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.  The SED is investigating the Utility’s self-report.

 

The SED could impose fines on the Utility of up to $50,000 per inspection, and also for failure to timely file a self-report in connection with such inspectionsThe SED has the authority to issue more than one citation for a series of related incidents, 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 as a result of the SED’s investigation. 

 

 


Federal Matters

 

Federal Criminal Trial

 

On June 14, 2016, a federal criminal trial against the Utilitybegan 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 illegally 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 Count 13 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 2, 2016, the remaining Alternative Fines Act sentencing allegations in the case were dismissed.  The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”  (The remaining allegations related to $281 million of gross gains that the government alleged the Utility derived.  As previously disclosed, in December 2015, the court dismissed the government’s allegations regarding the amount of losses.)

 

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 August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict.  The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument. The Utility is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017.

 

The maximum statutory fine for each felony count is $500,000, for total potential maximum statutory fines of $3 million. At September 30, 2016, the Utility’s Condensed Consolidated Balance Sheets include a $3 million accrual in connection with the jury verdict.  The Utility also could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed, such as a requirement that the Utility’s natural gas operations and/or compliance and ethics programs be supervised by an independent third-party monitor. If appointed, the Utility expects a monitor would serve for a period of time and report periodically to the court or a department or agency of the government. 

 

Other Federal Matters

 

In July 2014, the Utility was informed that the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the criminal trial discussed above.  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 Litigation 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, and destroyed 549 homes, 368 outbuildings and four commercial properties.  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 its vegetation management contractors 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 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 September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 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 preference cases (presented by individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling).  The Utility also has begun scheduling mediation of other cases.  Case management conferences were held on July 14, 2016 and September 1, 2016.  The next case management conference is scheduled for December 1, 2016. 

 

 


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.

 

Based on the evidence described in the Cal Fire report that the Gray Pine tree contacted an electric line of the Utility, the Utility believes that it is probable that it will incur a loss of $350 million for property damages (including estimated damages to structures and their contents, and to trees) in connection with this matter, which corresponds to the lower end of the range of its reasonably estimable losses.  This amount is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the extent of damage to such structures and contents, and other property damage. The estimate does not include fire suppression costs, personal injury damages and other damages that the Utility could be liable for if it were found to have been negligent

 

The Utility believes that it is reasonably possible that it will incur losses related to Butte fire claims in excess of the $350 million accrued through September 30, 2016The Utility believes that $90 million is a reasonable estimate of fire suppression costs (this amount is not included in the $350 million accrued through September 30, 2016).  The Utility currently is unable to reasonably estimate the upper end of the range because it is still at 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, including for estimated property damages, requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including 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, including management’s ability to reasonably estimate a range of loss.

 

The Utility has liability insurance from various insurers, which provides coverage for third-party liability attributable to the Butte fire.  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.  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, included in Other accounts receivable in the Condensed Consolidated Balance Sheets.  The Utility plans to seek recovery of all insured losses, and while the Utility believes that a significant portion of costs incurred for third-party claims (and associated legal expenses) relating to Butte fire will ultimately be recovered through its insurance, it is unable to predict the amount and timing of such insurance recoveries. 

 

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 during such reporting periods.

 

 


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 $84 million at September 30, 2016 and $63 million at December 31, 2015.  These amounts are included in Other current liabilities in the Condensed 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 Condensed Consolidated Statements of Income.  Disallowances as a result of the CPUC’s June 23, 2016 final phase one 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.

 

2015 GT&S Rate Case Disallowance of Capital Expenditures

 

On June 23, 2016, the CPUC approved a final decision in phase one of 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 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 included $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.  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 third party 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 pending 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 November 1, 2016, the assigned ALJ issued a phase two proposed 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.  The Utility expects a final CPUC decision to be voted in December 2016.

 

 


For the three and nine months ended September 30, 2016, the Utility recorded charges for disallowed capital spending of $51 million and $286 million, respectively, as a result of the Penalty Decision.  The cumulative charges at September 30, 2016, and the additional future charges to reach the $1.6 billion total are shown in the following table:

 

 

 

 

 

 

 

 

 

 

 

 

Nine Months

 

Cumulative

 

Future

 

 

 

Ended

 

Charges

 

Charges

 

 

 

 

September 30,

 

 

September 30,

 

and

 

Total

(in millions)

2016

 

2016

 

Costs

 

Amount

Fine paid to the state

$

- 

 

$ 

300 

 

$ 

- 

 

$ 

300 

Customer bill credit paid

 

- 

 

 

400 

 

 

- 

 

 

400 

Charge for disallowed capital (1)

 

286 

 

 

692 

 

 

- 

 

 

692 

Disallowed revenue for pipeline safety

 

 

 

 

 

 

 

 

 

 

 

  expenses (2)

 

8 

 

 

8 

 

 

150 

 

 

158 

CPUC estimated cost of other remedies (3)

 

- 

 

 

- 

 

 

- 

 

 

50 

Total Penalty Decision fines and remedies

$

294 

 

$ 

1,400 

 

$ 

150 

 

$ 

1,600 

 

 

 

 

 

 

 

 

 

 

 

 

(1)The Penalty Decision disallows the Utility from recovering $850 million in costs associated with pipeline safety-related projects and programs that the CPUC will finalize in a final phase two decision to be issued in the Utility’s 2015 GT&S rate case.  The CPUC recommended in its May 5, 2016 phase one proposed decision in the Utility’s 2015 GT&S rate case that at least $692 million of the $850 million cost disallowance be allocated to capital expenditures.  On November 1, 2016, the CPUC issued a phase two proposed decision in the 2015 GT&S rate case which allocates $689 million to capital expenditures.

(2) Future GT&S revenues will be reduced for these unrecovered expenses. 

(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 nor the Utility’s estimated future remedy-related costs.  These costs would be expensed as incurred.

 

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 September 30, 2016, the Utility has spent $1.3 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 2016.  The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected.

 

Environmental Remediation Contingencies

 

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is composed of the following:

 

 

Balance at

 

September 30,

 

December 31,

(in millions)

2016

 

2015

Topock natural gas compressor station (1)

$

300 

 

$ 

300 

Hinkley natural gas compressor station (1)

 

140 

 

 

140 

Former manufactured gas plant sites owned by the Utility or third parties

 

305 

 

 

271 

Utility-owned generation facilities (other than fossil fuel-fired),

  other facilities, and third-party disposal sites

 

143 

 

 

164 

Fossil fuel-fired generation facilities and sites

 

104 

 

 

94 

Total environmental remediation liability

$

992 

 

$ 

969 

 

 

 

 

 

 

(1) See “Natural Gas Compressor Station Sites” below.

 

The Utility’s environmental remediation liability at September 30, 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 September 30, 2016, the Utility expected to recover $704 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  Some of the Utility’s environmental remediation liability, such as the environmental remediation costs associated with the Hinkley site discussed below, will not be recovered in rates.

 

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 Hinkley, California and is referred to below as the “Hinkley site.”  Another station is located near Needles, California and is referred to below as the “Topock site.”  The Utility also is required to take measures to abate the effects of the contamination on the environment.

 

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. On November 4, 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. 

 

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 is conducting an additional environmental review of the proposed design, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in early 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.

 

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 $2.0 billion (including amounts related to the Hinkley and Topock 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

 

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, the current maximum aggregate annual retrospective premium obligation for the Utility is 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 $2.1 million.  For more information about the Utility’s NEIL coverage, see Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K. 

 

 


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.  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. 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 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 onthe Condensed Consolidated Balance Sheets.  The settlement agreement did not result in a refund to customers or an impact to net income.    

 

At September 30, 2016 and December 31, 2015, respectively, the Consolidated Balance Sheets reflected $233 million and $454 million in net claims within Disputed claims and customer refunds as well as $161 million and $228 million of cash in escrow within Restricted cash.  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.

 

Tax Matters

 

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 September 30, 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.

 

Purchase Commitments

 

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments.  At December 31, 2015, the Utility hadundiscounted future expected obligations of approximately $50 billion.  (See Note 13 of the Notes to the Consolidated Financial Statements in Item 8 of the 2015 Form 10-K.)  During the nine months ended September 30, 2016, the Utility entered into several renewable energy power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $406 million over the next 20 years.


 


ITEM 2. 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 is regulated primarily by the CPUC and the FERC.  The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage.  The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts.  The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.  The Utility is alsosubject to the jurisdiction of other federal, state, and local governmental agencies.

 

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report.  It should also be read in conjunction with the 2015 Form 10-K.


 


 

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 on an earnings from operations basis) compared to the same period in the prior year (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, including certain pipeline related expenses, certain legal and regulatory related expenses, fines and penalties, Butte fire related costs, and impacts of the 2015 GT&S rate case.  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 planning, 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

 

Nine Months Ended

 

September 30,

 

September 30,

 

 

 

 

EPS

 

 

 

 

EPS

(in millions, except per share amounts)

Earnings (1)

 

(Diluted)

 

Earnings (1)

 

(Diluted)

Income Available for Common Shareholders - September 30, 2015

$

307 

 

$

0.63 

 

$

740 

 

$

1.53 

Fines and penalties

 

84 

 

 

0.16 

 

 

497 

 

 

1.03 

Pipeline-related expenses

 

19 

 

 

0.04 

 

 

38 

 

 

0.08 

Legal and regulatory related expenses

 

8 

 

 

0.02 

 

 

26 

 

 

0.05 

Natural gas matters insurance recoveries

 

(6)

 

 

(0.01)

 

 

(29)

 

 

(0.06)

Earnings from Operations - September 30, 2015 (2)

$

412 

 

$

0.84 

 

$

1,272 

 

$

2.63 

Timing of 2015 GT&S revenue collection (3)

 

58 

 

 

0.11 

 

 

58 

 

 

0.11 

Growth in rate base earnings

 

25 

 

 

0.05 

 

 

76 

 

 

0.15 

Timing of taxes (4)

 

(22)

 

 

(0.04)

 

 

(103)

 

 

(0.20)

Nuclear refueling outage

 

- 

 

 

- 

 

 

(30)

 

 

(0.06)

Regulatory and legal matters

 

23 

 

 

0.05 

 

 

- 

 

 

- 

Gain on disposition of SolarCity stock (5)

 

- 

 

 

- 

 

 

(14)

 

 

(0.03)

Increase in shares outstanding

 

- 

 

 

(0.03)

 

 

- 

 

 

(0.08)

Miscellaneous

 

(25)

 

 

(0.04)

 

 

(50)

 

 

(0.10)

Earnings from Operations - September 30, 2016 (2)

$

471 

 

$

0.94 

 

$

1,209 

 

$

2.42 

Butte fire related costs (net of insurance) (6)

 

(9)

 

 

(0.02)

 

 

(110)

 

 

(0.22)

Fines and penalties (7)

 

(42)

 

 

(0.08)

 

 

(206)

 

 

(0.41)

Pipeline-related expenses (8)

 

(18)

 

 

(0.04)

 

 

(47)

 

 

(0.10)

Legal and regulatory related expenses (9)

 

(14)

 

 

(0.03)

 

 

(32)

 

 

(0.06)

GT&S capital disallowance (10)

 

- 

 

 

- 

 

 

(113)

 

 

(0.23)

Income Available for Common Shareholders - September 30, 2016

$

388 

 

$

0.77 

 

$

701 

 

$

1.40 

 

 

 

 

 

 

 

 

 

 

 

 

(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 (7) below.

 

(2“Earnings from operations” is not calculated in accordance with GAAP and excludes the items impacting comparability shown in footnotes (6) through (10).

 

(3)  Represents the incremental authorized revenue collected through rates beginning August 1, 2016 in accordance with the final phase one decision in the Utility’s 2015 GT&S rate case during the three and nine months ended September 30, 2016. 

 

(4)  Represents the timing of taxes reportable in quarterly financial statements.

 

(5)  Represents the gain recognized during the nine months ended September 30, 2015. No comparable gain was recognized in 2016.

 

 


(6)The Utility accrued charges of $350 million (before the tax impact of $143 million) for the nine months ended September 30, 2016, related to estimated property damages in connection with the Butte fire, partially offset by $260 million (before the tax impact of $106 million) recorded as probable insurance recoveries recognized during the nine months ended September 30, 2016.  No additional charges or recoveries were recognized in the three months ended September 30, 2016 related to third-party claims.  The Utility also incurred charges of $16 million (before the tax impact of $7 million) and $96 million (before the tax impact of $39 million) for the three and nine months ended September 30, 2016, respectively, for Utility clean-up, repair, and legal costs associated with the Butte fire. 

 

(7) Represents the impact of the Penalty Decision and other enforcement and litigation matters (see Note 9 of the Notes to the Condensed Consolidated Financial Statements).  For the three and nine months ended September 30, 2016, the Utility incurred costs of $59 million (before the tax impact of $23 million) and $294 million (before the tax impact of $119 million), respectively, associated with estimated safety-related cost disallowances imposed by the CPUC in its April 9, 2015 decision in the gas transmission pipeline investigations.  Specific projects to be disallowed will be determined in the phase two decision of the 2015 GT&S rate case.  In addition, for the three and nine months ended September 30, 2016, the Utility accrued fines, which are not deductible for tax purposes, of $1 million and $26 million, respectively, in connection with the MOD POD in the CPUC’s investigation regarding natural gas distribution facilities record-keeping practices and of $3 million for the three and nine months ended September 30, 2016 as a result of the federal criminal trial.  In the three and nine months ended September 30, 2016, the Utility also recorded $4 million (before the tax impact of $2 million), for probable disallowance that will be imposed for prohibited ex parte communications. 

 

(8)The Utility incurred costs of $31 million (before the tax impact of $13 million) and $80 million (before the tax impact of $33 million) during the three and nine months ended September 30, 2016, respectively, for pipeline related expenses incurred in connection with the multi-year effort to identify and remove encroachments from transmission pipeline rights of way. 

 

(9) The Utility incurred costs of $23 million (before the tax impact of $9 million) and $54 million (before the tax impact of $22 million) during the three and nine months ended September 30, 2016, respectively, for legal and regulatory related expenses incurred in connection with various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

 

(10)Represents charges of $190 million (before the tax impact of $77 million) of probablecapitaldisallowancesas a result of the finalphase one 2015 GT&S rate case decision that the Utility incurred in the nine months ended September 30, 2016, including $134 million (before the tax impact of $54 million) for 2011 through 2014 capital expenditures in excess of adopted amounts and $56 million (before the tax impact of $23 million) for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts.  No additional charges or recoveries were recognized in the three months ended September 30, 2016. (See “Regulatory Matters below for more information.)

 

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:

 

  • The Outcome of Enforcement, Litigation, and Regulatory MattersThe Utility’s future financial results may continue to be impacted by current and future enforcement, litigation and regulatory matters and their outcome, including potential remedial and other measures or designation of one or more independent third-party monitor(s)as a result of the federal criminal trial and debarment proceeding, potential fines associated with the alleged violations of the CPUC’s ex parte communication rules, litigation claims related to the Butte fire, and a number of investigations and/or requests for information by government agencies, including in connection with the Utility’s self-report related to its atmospheric corrosion inspections.  (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

 

  • The Timing and Outcome of Ratemaking Proceedings.  There are several rate cases that are currently pending at the CPUC and the FERC.The CPUC approved 2015 GT&S “interim” revenue requirements in its final phase one decision dated June 23, 2016.  The authorized revenue requirements are effective retroactive to January 1, 2015.  However, the Utility will not be able to record the full revenue requirement increase since January 1, 2015 until after the final phase two decision is issued.  On November 1, 2016, the assigned ALJ issued a phase two proposed decision in the 2015 GT&S rate case that applies $689 million of the $850 million San Bruno Penalty disallowance to capital expenditures(See “Regulatory Matters – 2015 Gas Transmission and Storage Rate Case” below for more information.)  Additionally, on August 3, 2016, the Utility and other intervening parties filed a motion with the CPUC seeking approval of a settlement agreement in the Utility’s 2017 GRC. The settlement agreement proposes a revenue requirement increase of $88 million for 2017.  Under the current schedule, a final CPUC decision is expected in February 2017. (See “Regulatory Matters − 2017 General Rate Case” below for more information.)  In addition, on July 29, 2016, the Utility filed a rate case at the FERC requesting a 2017 retail electric transmission revenue requirementThe FERC accepted the Utility’s filing on September 30, 2016 and set the proceeding for settlement negotiations.  (See “Regulatory MattersFERC Transmission Owner Rate Cases” below for more information.)  The outcome of regulatory proceedings can be affected by many factors, including the level of opposition by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors.

 

  • 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 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 2016 it will incur unrecovered pipeline-related expenses ranging from $100 million to $150 million which primarily relate to costs to identify and remove encroachments from transmission pipeline rights-of-way.  Also, the June 23, 2016 final phase one 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. The ultimate amount of unrecovered costs also could be affected by how the CPUC determines in its final phase two decision of the 2015 GT&S rate case which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met. (See Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

 

  • 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.  For the nine months ended September 30, 2016, PG&E Corporation issued $742 million of common stock and used $740 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 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 would 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 Note 9 of the Notes to the Condensed Consolidated Financial Statements in Item 1, Financial Statements and Supplementary Data, 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 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 the 2015 Form 10-K and in Part II below under “Item 1A. Risk Factors. In addition, this quarterly 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.  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

 

PG&E Corporation

 

The consolidated results of operations consist primarily of balances related to the Utility, which are discussed below.  The following table provides a summary of net income available for common shareholders for the three and nine months ended September 30, 2016 and 2015:

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Consolidated Total

$ 

388 

 

$ 

307 

 

$ 

701 

 

$ 

740 

PG&E Corporation

 

2 

 

 

5 

 

 

5 

 

 

35 

Utility

$ 

386 

 

$ 

302 

 

$ 

696 

 

$ 

705 

 

PG&E Corporation’s net income primarily consists of interest expense on long-term debt, income taxes, and other income from investments.  Results for the nine months ended September 30, 2015 include approximately $30 million of realized gains and associated tax benefits related to an investment in SolarCity Corporation with no corresponding gains for the same period in 2016.

 

 


Utility

 

The tables below shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2016 and 2015.  The tables separately identify 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.

 

The Utility’s operating results for the three and nine months ended September 30, 2016 and 2015 reflect charges associated with the impact of the Penalty Decision.  (See “Utility Revenues and Costs that Impacted Earnings” below.)

 

 

Three Months Ended September 30, 2016

 

Three Months Ended September 30, 2015

 

Revenues/Costs:

 

 

 

 

Revenues/Costs:

 

 

 

(in millions)

That Impacted Earnings

That Did Not Impact Earnings

Total Utility

 

That Impacted Earnings

That Did Not Impact Earnings

Total Utility

Electric operating revenues

$

2,086 

$

1,907 

$

3,993 

 

$

1,907 

$

1,961 

$

3,868 

Natural gas operating revenues

 

621 

 

195 

 

816 

 

 

516 

 

166 

 

682 

Total operating revenues

 

2,707 

 

2,102 

 

4,809 

 

 

2,423 

 

2,127 

 

4,550 

Cost of electricity

 

- 

 

1,613 

 

1,613 

 

 

- 

 

1,681 

 

1,681 

Cost of natural gas

 

- 

 

80 

 

80 

 

 

- 

 

50 

 

50 

Operating and maintenance

 

1,373 

 

409 

 

1,782 

 

 

1,226 

 

396 

 

1,622 

Depreciation, amortization, and decommissioning

 

694 

 

- 

 

694 

 

 

653 

 

- 

 

653 

Total operating expenses

 

2,067 

 

2,102 

 

4,169 

 

 

1,879 

 

2,127 

 

4,006 

Operating income

 

640 

 

- 

 

640 

 

 

544 

 

- 

 

544 

Interest income (1)

 

 

 

 

 

8 

 

 

 

 

 

 

2 

Interest expense (1)

 

 

 

 

 

(209)

 

 

 

 

 

 

(191)

Other income, net (1)

 

 

 

 

 

23 

 

 

 

 

 

 

22 

Income before income taxes

 

 

 

 

 

462 

 

 

 

 

 

 

377 

Income tax provision (1)

 

 

 

 

 

73 

 

 

 

 

 

 

72 

Net income

 

 

 

 

 

389 

 

 

 

 

 

 

305 

Preferred stock dividend requirement (1)

 

 

 

 

 

3 

 

 

 

 

 

 

3 

Income Available for Common Stock

 

 

 

 

$

386 

 

 

 

 

 

$

302 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) These items impacted earnings for the three months ended September 30, 2016 and 2015.

 

 


 

Nine Months Ended September 30, 2016

 

Nine Months Ended September 30, 2015

 

Revenues/Costs:

 

 

 

 

Revenues/Costs:

 

 

 

(in millions)

That Impacted Earnings

That Did Not Impact Earnings

Total Utility

 

That Impacted Earnings

That Did Not Impact Earnings

Total Utility

Electric operating revenues

$

5,996 

$

4,594 

$

10,590 

 

$

5,569 

$

4,775 

$

10,344 

Natural gas operating revenues

 

1,670 

 

693 

 

2,363 

 

 

1,547 

 

775 

 

2,322 

Total operating revenues

 

7,666 

 

5,287 

 

12,953 

 

 

7,116 

 

5,550 

 

12,666 

Cost of electricity

 

- 

 

3,719 

 

3,719 

 

 

- 

 

3,958 

 

3,958 

Cost of natural gas

 

- 

 

377 

 

377 

 

 

- 

 

442 

 

442 

Operating and maintenance

 

4,439 

 

1,191 

 

5,630 

 

 

3,878 

 

1,150 

 

5,028 

Depreciation, amortization, and decommissioning

 

2,090 

 

- 

 

2,090 

 

 

1,935 

 

- 

 

1,935 

Total operating expenses

 

6,529 

 

5,287 

 

11,816 

 

 

5,813 

 

5,550 

 

11,363 

Operating income

 

1,137 

 

- 

 

1,137 

 

 

1,303 

 

- 

 

1,303 

Interest income (1)

 

 

 

 

 

16 

 

 

 

 

 

 

6 

Interest expense (1)

 

 

 

 

 

(614)

 

 

 

 

 

 

(567)

Other income, net (1)

 

 

 

 

 

68 

 

 

 

 

 

 

68 

Income before income taxes

 

 

 

 

 

607 

 

 

 

 

 

 

810 

Income tax (benefit) provision (1)

 

 

 

 

 

(99)

 

 

 

 

 

 

95 

Net income

 

 

 

 

 

706 

 

 

 

 

 

 

715 

Preferred stock dividend requirement (1)

 

 

 

 

 

10 

 

 

 

 

 

 

10 

Income Available for Common Stock

 

 

 

 

$

696 

 

 

 

 

 

$

705 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) These items impacted earnings for the nine months ended September 30, 2016 and 2015.

 

Utility Revenues and Costs that Impacted Earnings

 

The following discussion presents the Utility’s operating results for the three and nine months ended September 30, 2016 and 2015, focusing on revenues and expenses that impacted earnings for these periods. 

 

The Utility has received a final phase one decision in its 2015 GT&S rate case.  This decision authorized the revenue requirements that the Utility began to collect through rates beginning August 1, 2016 for the 2015 GT&S rate case periodThe 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.  However, the Utility will not be able to recognize the full impact of revenues retroactive to January 1, 2015 until the CPUC issues a final phase two decision in this rate case.  In addition, accounting rules preclude the Utility from recording the full amount of the revenue requirement increase until 2017. (See “Regulatory Matters” below.) 

 

Operating Revenues

 

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $284 million, or 12%, and by $550 million, or 8%, in the three and nine months ended September 30, 2016, compared to the same periods in 2015 primarily due to additional base revenues authorized by the CPUC in the 2014 GRC decision and in the 2015 GT&S rate case as discussed above, and by the FERC in the TO rate case. (See “Regulatory Matters” below.)

 

Operating and Maintenance

 

The Utility’s operating and maintenance expenses that impacted earnings increased by $147 million, or 12%, in the three months ended September 30, 2016 compared to the same period in 2015 primarily due to escalation related to labor, benefits, and service contracts, and accelerated transmission and distribution project work.  In addition, the Utility incurred $16 million in charges related to the Butte fire and $4 million in charges recorded in connection with the MOD POD related to the natural gas distribution facilities record-keeping investigation and the federal criminal trial during the three months ended September 30, 2016.  These increases were partially offset by approximately $90 million of lower disallowed capital charges related to the Penalty Decision compared to the same period in 2015.  (See Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

 

 


The Utility’s operating and maintenance expenses that impacted earnings increased by $561 million, or 14%, in the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to escalation related to labor, benefits, and service contracts, and accelerated transmission and distribution project work.  In addition, the Utility incurred $446 million in charges related to the Butte fire, $190 million in permanently disallowed capital spending (see “Regulatory Matters” below), $50 million in costs related to a scheduled nuclear refueling outage at Diablo Canyon, and $29 million in charges recorded in connection with the MOD POD related to the natural gas distribution facilities record-keeping investigation and the federal criminal trial during the nine months ended September 30, 2016.  These increases were partially offset by $500 million in charges associated with the Penalty Decision for fines and customer refunds incurred in the first nine months of 2015 with no corresponding charges in 2016.  Additionally, the Utility recorded approximately $260 million in probable insurance recoveries related to the Butte fire in the nine months ended September 30, 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 9 of the Notes to the Condensed Consolidated Financial Statements.)

 

The Utility’s future financial statements will continue to be impacted by additional charges associated with the Penalty Decision, costs related to the Butte fire, and unrecoverable pipeline-related expenses.  (See “Key Factors Affecting Financial Results” above and Note 9 of the Notes to the Condensed Consolidated Financial Statements.)  

 

Depreciation, Amortization, and Decommissioning

 

The Utility’s depreciation, amortization, and decommissioning expenses increased by $41 million, or 6%, and by $155 million, or 8%, in the three and nine months ended September 30, 2016 compared to the same periods in 2015.  These increases were primarily due to the impact of capital additions as authorized by the CPUC in the 2014 GRC decision.

 

Interest Expense

 

The Utility’s interest expenseincreased by $18 million, or 9%, and by $47 million, or 8%, in the three and nine months ended September 30, 2016 compared to the same periods in 2015.  These increases were primarily driven by higher levels of long term debt and short term borrowings in 2016 compared to the same periods in 2015.

 

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 income tax provision increased by $1 millionin the three months ended September 30, 2016 and decreased by $194 million in the nine months ended September 30, 2016 as compared to the same periods in 2015.  The following describes the changes in the Utility’s effective tax rate for the three and nine months ended September 30, 2016 as compared to the same periods in 2015:

 

The effective tax rates for the three months ended September 30, 2016 and 2015 were 16% and 19%, respectively. The decrease in the effective tax rate was primarily due to higherbenefits resulting from various property-related tax deductions recorded during the three months ended September 30, 2016 with lower comparable amounts in the three month period ending September 30, 2015. 

 

The effective tax rates for the nine months ended September 30, 2016 and 2015 were (16)% and 12%, respectively.  The decrease in the effective tax rate was primarily due to higherbenefits resulting from various property-related tax deductions recorded during the nine months ended September 30, 2016 with lower comparable amounts in the nine month period ending September 30, 2015, as well asbenefits resulting from various tax audit results recorded during the nine months ended September 30, 2016 with no comparable amounts in the nine month period ending September 30, 2015.

 

 


Utility Revenues and Costs that did not Impact Earnings

 

Fluctuations in revenues that did not impact earnings are primarily driven by electricity and natural gas procurement costs.  See below for more information.

 

Cost of Electricity

 

TheUtility’s cost of electricity includes the costs 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 7 of the Notes to the Condensed Consolidated Financial Statements.) 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Cost of purchased power

$

1,541 

 

$

1,605 

 

$

3,540 

 

$

3,734 

Fuel used in own generation facilities

 

72 

 

 

76 

 

 

179 

 

 

224 

Total cost of electricity

$

1,613 

 

$

1,681 

 

$

3,719 

 

$

3,958 

Average cost of purchased power per kWh (1)

$

0.123 

 

$

0.111 

 

$

0.110 

 

$

0.105 

Total purchased power (in millions of kWh) (2)

 

12,560 

 

 

14,424 

 

 

32,327 

 

 

35,462 

 

 

 

 

 

 

 

 

 

 

 

 

(1)Average cost of purchased power for the three and nine months ended September 30, 2016 increased compared to the same periods in 2015 primarily due to a higher percentage of renewable energy resources.  

(2) The decrease in purchased power for the three and nine months ended September 30, 2016 resulted from an increase year-to-date in generation from the Utility’s own generation facilities and lower electric customer demand.  Hydroelectric generation increased during the three and nine months ended September 30, 2016 as compared to the same periods in 2015.

 

The Utility’s total purchased power is driven by customer demand, the availability of the Utility’s own generation facilities (including the Diablo Canyon nuclear generation power plant and hydroelectric plants), and the cost-effectiveness of each source of electricity.

 

Cost of Natural Gas

 

The Utility’s cost of natural gas includes the costs of procurement, storage, 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 7 of the Notes to the Condensed Consolidated Financial Statements.)  The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of transportation and storage, and changes in customer demand. 

 

 

Three Months Ended September 30,

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

 

2016

 

2015

Cost of natural gas sold

$

50 

 

$

18 

 

$

275 

 

$

335 

Transportation cost of natural gas sold

 

30 

 

 

32 

 

 

102 

 

 

107 

Total cost of natural gas

$

80 

 

$

50 

 

$

377 

 

$

442 

Average cost per Mcf (1) of natural gas sold (2)

$

1.79 

 

$

0.69 

 

$

1.88 

 

$

2.46 

Total natural gas sold (in millions of Mcf) (1)

 

28 

 

 

26 

 

 

146 

 

 

136 

 

 

 

 

 

 

 

 

 

 

 

 

(1) One thousand cubic feet

 

 

 

 

 

 

 

 

 

 

 

(2) Average cost of natural gas sold was primarily impacted by fluctuations in the market price of natural gas in the three and nine months ended September 30, 2016 compared to the same periods in 2015.

 

Operating and Maintenance Expenses

 

The Utility’s operating expenses also include certain recoverable costs that the Utility incurs as part of its operations such as pension contributions and public purpose programs costs.  If the Utility were to spend over authorized amounts, these expenses could have an impact on earnings. 


 


 

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 long-term senior unsecured debt issuances to maintain its CPUC-authorized capital structure consisting of 52% equity and 48% debt and preferred stock.  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’s 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 equity contributions to the Utility are funded primarily through common stock issuances. PG&E Corporation forecasts that it will issue approximately $800 million in common stock during 2016 and between $400 million and $600 million 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 the final phase two decision in the 2015 GT&S rate case, by 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” below.  Common stock issuances by PG&E Corporation to fund these needs would have a material dilutive impact on PG&E Corporation’s EPS.

 

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 primarily consists of cash held in escrow pending the resolution of the remaining disputed claims that were filed in the Utility’s reorganization proceedings under Chapter 11 of the U.S. Bankruptcy Code.  As part of the settlement approved in the third quarter of 2016, the Utility agreed to release $66 million of cash from escrow to the California Power Exchange.  Additionally, on October 13, 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 9 of the Notes to the Condensed Consolidated Financial Statements.)

 

Financial Resources

 

Debt and Equity Financings

 

During the three and nine months ended September 30, 2016, PG&E Corporation sold 0.4 million and 2.6 million shares of its common stock under the February 2015 equity distribution agreement for cash proceeds of $26 million and $149 million, respectively, net of commissions paid of $0.2 million and $1.3 million, respectively. As of September 30, 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.

 

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 the nine months ended September 30, 2016, 5.7million shares were issued for cash proceeds of $269 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 nine months ended September 30, 2016, PG&E Corporation made equity contributions to the Utility of $740 million.

 

 


In March 2016, the Utility issued $600 million principal amount of 2.95% Senior Notes due March 1, 2026. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. In addition, in March 2016, the Utility entered into a $250 million floating rate unsecured term loan that matures on February 2, 2017.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.

 

Revolving Credit Facilities and Commercial Paper Program

 

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 September 30, 2016, PG&E Corporation and the Utility had $135 million and $2.2 billion available under their respective $300 million and $3.0 billion revolving credit facilities.  (See Note 4 of the Notes to the Condensed Consolidated Financial Statements.)

 

PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $1.75 billion, respectively.  For the nine months ended September 30, 2016, PG&E Corporation and the Utility had an average outstanding commercial paper balance of $76 million and $869 million, and a maximum outstanding balance of $176 million and $1.4 billion, respectively.  At September 30, 2016, PG&E Corporation and the Utility had an outstanding commercial paper balance of $165 million and $731 million, respectively.

 

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 September 30, 2016, PG&E Corporation’s and the Utility’s total consolidated debt to total consolidated capitalization was 51% and 49%, 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 September 30, 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.

 

In September 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 October 15, 2016, to shareholders of record on September 30, 2016. 

 

In September 2016, the Board of Directors of the Utility declared a common stock dividend of $244 million that was paid to PG&E Corporation on October 3, 2016.

 

In September 2016, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on November 15, 2016, to shareholders of record on October 31, 2016.

 

Utility Cash Flows

 

The Utility’s cash flows were as follows:

 

 

Nine Months Ended September 30,

(in millions)

2016

 

2015

Net cash provided by operating activities

$

3,206 

 

$

2,932 

Net cash used in investing activities

 

(4,083)

 

 

(3,734)

Net cash provided by financing activities

 

886 

 

 

809 

Net change in cash and cash equivalents

$

9 

 

$

7 

 

 


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 the nine months ended September 30, 2016, net cash provided by operating activities increased by $274 million compared to the same period in 2015.  This increase was primarily due to tax refunds of $151 million received during 2016 compared to no tax refunds received or tax payments made during 2015.  The remaining increase was primarily due to fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections and vendor billings and payments.

 

Future cash flow from operating activities will be affected by various factors, including:

 

the timing and amounts of costs that may be incurred in connection with potential remedial and other measures that may be imposed on the Utility as a result of the jury’s verdict in the federal criminal trial and in connection with the DOI debarment proceeding, and fines or penalties that may be imposed in connection with the remaining investigations and other enforcement and litigation matters and the timing and amount of related insurance recoveries (see Note 9 of the Notes to the Condensed Consolidated Financial Statements);

 

 

the timing and outcome of ratemaking proceedings, including of a final phase two decision in the 2015 GT&S rate case, the 2017 GRC, and the TO rate cases;

 

 

the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system;

 

 

the timing and amount of tax payments (including the bonus depreciation), tax refunds, net collateral payments, and interest payments; and

 

 

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 $349 million during the nine months ended September 30, 2016 as compared to the same period in 2015.  The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers.  Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments.  The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

 

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$5.7 billion in capital expenditures in 2016 and approximately $6.0 billion in each of the years 2017, 2018 and 2019. 

 

Financing Activities

 

During the nine months ended September 30, 2016, net cash provided by financing activities increased by $77 million compared to the same period in 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.

 

 


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 9 of the Notes to the Condensed Consolidated Financial Statements.  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.  In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the 2015 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.  Significant regulatory developments that have occurred since the 2015 Form 10-K was filed with the SEC are discussed below.

 

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.  The Utility continues to fully cooperate with the DOI and is addressing its questions. 

 

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.  (The federal criminal trial is discussed in Note 9 of the Notes to the Condensed Consolidated Financial Statements and in Item 1 Legal Proceedings.)  The Utility does not believe that the updated registration will affect its existing contracts with the federal government, but it does affect execution of new contracts with the federal government.  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. 

 

Following the update of the SAM, the Utility and the DOI have been in discussions regarding such a determination and a possible interim administrative agreement that would allow the federal government agencies to contract with the Utility while the DOI is completing its debarment inquiry. It is uncertain when and if the Utility and the DOI will enter into an interim administrative agreement. It is also uncertain when or if further action will be taken by the DOI.  The DOI debarment inquiry could result in the Utility’s suspension or debarment from future federal government contracts for a fixed, specified time period or entering into an administrative agreement with the DOI to resolve debarment matters.

 

As a result of the DOI inquiry and/or of the August 9, 2016 jury’s guilty verdict on six felony counts in the federal criminal trial, the Utility may be required to 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).  If appointed, the Utility expects a monitor or monitors would serve for a period of time and report periodically to the court or a department or agency of the government.  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 September 30, 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. PG&E Corp. 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 September 16, 2016, the San Mateo Superior Court requested that all counsel appear for a status conference in the consolidated matter.  The date of the conference has been set for November 16, 2016.

 

 


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.

 

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 criminal proceedings against the Utility and ordered the parties to submit a joint status report on or before March 15, 2017.

 

A case management conference in the action entitled Tellardin v. PG&E Corp. et al., also pending in the Superior Court of California, San Mateo County, had been scheduled for August 9, 2016.  On July 19, 2016, plaintiff requested that the court vacate the August 9, 2016 conference because, pursuant to the parties’ agreement, defendants are not required to respond to the complaint in this action until 30 days after an order lifting the stay in the San Bruno Fire Derivative Cases.  On August 2, 2016, the court vacated the August 9, 2016 conference. 

 

The federal criminal proceeding is still pending.  For more information about the federal criminal proceeding, see Note 9 of the Notes to the Condensed Consolidated Financial Statements and Item 1 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.  Significant regulatory developments that have occurred since the 2015 Form 10-K was filed with the SECare discussed below.

 

2017 General Rate Case

 

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 one-day 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 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.)  In its GRC application, the Utility requested an overall increase in electric distribution, natural gas distribution, and utility-owned electric generation revenue requirements of $319 million over currently authorized amounts (as updated through the Utility’s May 27, 2016 rebuttal testimony), effective January 1, 2017.

 

 


Revenue Requirements and Attrition Year Revenues

 

The settlement agreement proposes 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 provides for 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 identifies 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 post-test year for this cycle that would provide for an additional increase of $361 million.  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 the one-day workshop.

 

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:

 Year

 

Increase Requested in GRC Application

(in millions)

 

 

Increase Proposed in Settlement Agreement

(in millions)

 

 

Difference(1)

(Decrease from GRC Application)

(in millions)

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:

 

 

 

 

 

 

 

 

Increase/(Decrease) Proposed in Settlement Agreement

 

 

Difference(1) (Decrease from GRC Application)

(in millions)

 

Increase Requested in 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.

 

 


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:

 

 

 

 

 

 

 

 

 

 

Increase/

 

Increase/

 

Amounts

 

Amounts

 

 

 

 

(Decrease)

 

(Decrease)

 

Requested in

 

Proposed in

 

 

 

2016 Amounts

 

2016 Amounts

(in millions) (1)

2017 GRC

 

Settlement

 

Difference

 

vs. 2017 GRC

 

vs. Settlement

Line of Business:

Application

 

Agreement

 

(Decrease)

 

Application

 

Agreement

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 proposes 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 proposes 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 company-wide reductions, including reductions to the Short-Term 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.

 

 


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.

 

On August 30, 2016, the CPUC held a workshop to allow the assigned CPUC commissioner, the assigned ALJ, and other interested parties to pose questions to the Utility and other settling parties regarding the settlement agreement.  The Utility and the parties also discussed post-test years 2018 and 2019, including imputed capital additions and rate base amounts, and the two contested issues: a third post-test year or “attrition” year for this GRC cycle (i.e. for 2020) and 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 estimated authorized capital expenditures of $3.6 billion 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 Utility also estimateda 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.  Under the current schedule, a proposed decision is expected to be released in January 2017, and a final CPUC decision is expected to be issued in February 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.

 

For more information, see Item 4 of the 2015 Form 10-K and Item 2 of the 2016 Q1 Form 10-Q and the 2016 Q2 Form 10-Q.

 

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 “interim” 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.  The Utility will not be able to record the full revenue requirement increase since January 1, 2015 until after the final phase two decision is issued.  In addition, 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 not be able to complete recording the full retroactive revenue requirement increase in 2016.

 

The phase one decision adopts capital expenditures of roughly $700 million to $800 million per year through 2018 and authorizes weighted average rate base of $2.9 billion in 2015, $3.3 billion in 2016, $3.6 billion in 2017, and $4.2 billion in 2018, before the application of the shareholder-funded safety work disallowance associated with the Penalty Decision.  The authorized weighted average rate base excludes $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.  As a result, 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.  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 third party 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, 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, subject to refund upon a reasonableness review in the Utility’s next GT&S rate case.  The decision authorizes the Utility to track costs exceeding $157 million and seek recovery in the next GT&S rate case, subject to a reasonableness review.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

 

 


On November 1, 2016, the assigned ALJ issued a phase two proposed decision (“phase two PD”) regarding the $850 million penalty assessed in the Penalty Decision.  In accordance with the phase one decision, the phase two PD would first reduce the recommended revenue requirement by the $850 million San Bruno penalty to determine the revenue requirement to be collected from customers, and then apply the ex parte disallowance.  The phase two PD would apply $689 million of the $850 million penalty (81 percent) to capital expenditures and the remaining $161 million (19 percent) to expenses, and then reduce the 2015 revenue requirement by $72 million for the 5-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this proceeding.

 

Accordingly, the phase two PD would adopt a 2015 revenue requirement of $815 million, a 2016 revenue requirement of $1.061 billion, a 2017 revenue requirement of $1.125 billion, and a 2018 revenue requirement of $1.230 billion.  These amounts reflect attrition increases of $246 million in 2016, $64 million in 2017, and $105 million in 2018.  Excluding the $161 million for the expense portion of the Penalty Decision disallowance and the $72 million ex parte disallowance, the attrition increase would be $13 million in 2016. 

 

The following table shows the revenue requirement amounts requested by the Utility in the 2015 GT&S rate case, the “interim” revenue requirement amounts adopted in the phase one decision, and the revenue requirement amounts recommended in the phase two PD, including adjustments for the $850 million Penalty Decision disallowance and the ex parte disallowance:

 

(in millions)

2015

 

2016

 

2017

 

2018

Utility Requested Revenue Requirement

$

1,263 

 

$ 

1,346 

 

$ 

1,488 

 

$ 

N/A 

 

 

 

 

 

 

 

 

 

 

 

 

Phase One Decision "Interim" Revenue Requirement

 

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)

 

 

 

 

 

 

 

 

 

Phase Two PD Revenue Requirement

$ 

815 

 

$ 

1,061 

 

$ 

1,125 

 

$ 

1,230 

 

 

 

 

 

 

 

 

 

 

 

 

 

The phase two PD also recommends weighted average rate base reductions of $99 million in 2015, $453 million in 2016, $670 million in 2017, and $658 million in 2018, resulting in 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 proposed decision would reduce rate base by the full amount of the disallowed capital expenditures but would not remove the associated deferred taxes, resulting in a larger rate base reduction.  It is unclear whether this treatment would apply beyond this rate case period.

 

In addition, the phase two PD would approve 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.

 

Opening briefs on the phase two PD are due on November 21, 2016 and reply briefs are due on November 28, 2016.  The final phase two decision is expected to be issued within 30 days of the reply briefs.  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.

 

For more information, see Item 4 of the 2015 Form 10-K and Item 2 of the 2016 Q1 Form 10-Q and the 2016 Q2 Form 10-Q.

 

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 currently 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 currently authorized revenue requirement.  The settlement is subject to the FERC’s approval.  The Utility also filed a motion on September 1, 2016, requesting the implementation of interim rates that, as of result of the settlement, became effective for wholesale customers on September 1, 2016 and for retail customers on October 1, 2016, subject to refund and pending a final decision by the FERC.  The FERC is expected to issue a decision in late 2016 or early 2017.   

 

 


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 $203 million increase over the 2016 requested revenue requirement of $1.515 billion (and a $387 million increase over the pending settlement revenue requirement of $1.331 billion).  The forecasted network transmission rate base for 2017 is $6.7 billion, compared to a forecasted rate base of $5.85 billion in 2016.  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 first settlement conference took place on October 19, 2016.  The next settlement conference is scheduled for February 7 and February 8, 2017.

 

CPUC Cost of Capital Decision

 

On February 25, 2016, the CPUC issued a decision granting a petition for modification filed by the Utility and the other two California investor-owned electric utilities to clarify that the CPUC’s previously adopted cost of capital adjustment mechanism would not be triggered before their 2018 cost of capital applications are due on April 20, 2017.  As a result, the Utility’s currently authorized return on equity of 10.40% and capital structure, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock, will remain the same for 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, 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 non-bypassable 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 non-bypassable 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 $350 million; and a community mitigation program to compensate San Luis Obispo County for the decline in local economic stimulus provided by Diablo Canyon through a transition period ending in 2025, estimated at approximately $50 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 applicationA prehearing conference on the application was held on October 6, 2016. The ALJ heard arguments on the scope of issues to be addressed in the proceeding and stated he would issue a scoping order after the public participation hearings that were held in San Luis Obispo on October 20, 2016.  On October 27, 2016, the ALJ issued a ruling requiring the Utility to submit supplemental testimony related to Diablo Canyon land ownership no later than November 18, 2016.  The Utility expects that a final decision will be issued by the end of 2017.  Upon CPUC approval of the application, the Utility will withdraw its license renewal application currently pending before the NRC when such approval has become final and non-appealable.  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. No schedule has been set for consideration of the writ at this time but the Utility expects a ruling in the first half of 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 non-bypassable 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.  Additionally, as a result of the joint proposal discussed above, an increase of $115 million to the ARO was recognized on the Utility’s Condensed Consolidated Balance Sheetsin the second quarter of 2016.

 

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 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 Condensed Consolidated Balance Sheets.  The total nuclear decommissioning obligation accrued in accordance with GAAP was $3.5 billion at September 30, 2016, which includes an $818 million adjustment to reflect the increased cost estimates and the $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 September 30, 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. 

 

For additional information, see the 2015 Form 10-K, the 2016 Q1 Form 10-Q, and the 2016 Q2 Form 10-Q.

 

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 consultants 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 and next actions in the proceeding. The timing, scope and potential outcome of the investigation are uncertain.

 

Rehearing of CPUC Decisions Approving 2006 – 2008 Energy Efficiency Incentive Awards

 

On September 17, 2015, the CPUC granted TURN’s and ORA’s long-standing applications for rehearing of the CPUC decisions that awarded energy efficiency incentive payments to the California IOUs for the 2006-2008 energy efficiency program cycle.  Under the incentive ratemaking mechanism applicable to the 2006-2008 program cycle, the Utility could have earned incentive revenues up to a maximum of $180 million, depending on the extent to which the Utility achieved the energy savings targets.  Conversely, to the extent the Utility failed to achieve the targets, the Utility could have been required to offset future incentive earnings claims by amounts previously awarded, and, in addition, could have incurred penalties of up to $180 million.  The Utility was awarded a total of $104 million for the 2006-2008 program cycle.

 

 


On September 15, 2016, the CPUC approved a settlement agreement filed by the Utility, ORA, and TURN to resolve all issues related to the 2006-2008 customer energy efficiency shareholder incentives. The final decision requires the Utility to reduce future energy efficiency shareholder incentives by $29.1 million.  The reduction of the shareholder incentive award 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.  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 $29.1 million 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. The first offset was requested by the Utility in the September 1, 2016 shareholder incentive advice letter related to the 2014-2015 Energy Efficiency Incentive Awards (see below).

 

20142015 Energy Efficiency Incentive Awards

 

On September 1, 2016, the Utility filed an advice letter with the CPUC requesting a shareholder incentive award for a portion of the energy savings it achieved through its energy efficiency programs in the 2014 and 2015 program years.  The Utility requested $24.9 million, and further requested that this amount be reduced by $5.8 million as a result of the settlement agreement related to the 2006-2008 energy efficiency awards, for a total award of $19.1 million.  As indicated above, on September 15, 2016, the CPUC approved the settlement agreement.  On October 7, 2016, the Utility submitted a supplemental shareholder incentive advice letter reflecting the approval by the CPUC of the settlement agreement and other minor modifications to its September 1, 2016 incentive award requestThe advice letter requires CPUC approval in a resolution, which the Utility anticipates receiving during the fourth quarter of 2016.

 

Utility-Owned PV Generation Cost Savings Incentive Award

 

In April 2010, the CPUC authorized the Utility to develop, own, and operate PV facilities and established a cost savings incentive mechanism which states that shareholders are eligible to retain ten percent of the difference between the actual average cost per unit and the threshold set by the CPUC.  From 2011 – 2013, the Utility constructed nine PV projects with a total capacity of 150 MW and the weighted average unit capital cost came in below the CPUC specified threshold.  In July 2016, the CPUC approved the recovery of $16 million in shareholder incentives related to these projects under the PV capital cost savings incentive mechanism.

 

 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, accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, foster the development of a state-wide electric vehicle charging infrastructure to encourage the use of electric vehicles, promote customer energy efficiency and demand response programs, and implement new state law requirements applicable to natural gas storage facilities.  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 and rates for net energy metering (which currently allow certain self-generating customers to receive bill credits for surplus power at the full retail rate), and allow customers to have greater control over their energy use. Significant developments that have occurred since the 2015 Form 10-K was filed with the SEC 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.  

 

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, titled the Grid of Things™, that would allow customers to choose new advanced energy supply technologies and services to meet their needs consistent with safe, reliable and affordable electric service. 

 

 


In August 2016, as part of the CPUC’s consideration of the Utility’s electric distribution resources plan, hearings were held on field demonstration projects proposed by the Utility to test various distribution-related services that DERs might provide to the Utility.  A CPUC decision is expected later this year on the field demonstration projects. 

 

Additionally, on August 22, 2016, the Utility filed comments generally supporting a CPUC ruling proposing a revised scope and schedule for the proceeding.  At this time, it is uncertain 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 assumes 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 exact figure would be determined later if the proposal or a similar alternative is adopted by the CPUC.  The ruling also states that it does not intend for this phase to adopt a new regulatory framework or business model for the California electric utilities.

 

On May 9 and May 23, 2016, the Utility, two other California utilities (the “Joint Utilities”) and other parties filed their comments.  The Joint Utilities indicate that providing a regulatory incentive to utilities to deploy DERs in place of distribution investment is premature until the operating and performance characteristics of DERs are better understood and evaluated as part of pilot projects.  The Joint Utilities instead propose initiating DER pilots that would advance understanding of distribution deferral and DER procurement processes.

 

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 rate-setting, consolidated remaining issues into one phase, and proposed a revised regulatory incentive pilot to test how an earnings opportunity affects DER sourcing.  On September 15 and September 22, 2016, the Joint Utilities and other parties filed comments on the revised regulatory incentive pilot.  The Joint Utilities support piloting different earnings mechanisms to better compare advantages and disadvantages of different alternatives and repeated their recommendation that the CPUC enable a broader dialogue on utility compensation mechanisms, rather than narrowly focusing on regulatory incentives for DER deployment.  A proposed CPUC decision is expected later this year.

 

Electric Rate Reform and Net Energy Metering

 

On July 3, 2015, the CPUC approved a final decision to authorize the California IOUs to gradually flatten their tiered residential electric rate structures from four tiers to two tiers by January 1, 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 and rates.  The new rules and rates are expected to become effective for new NEM customers later in 2016, when the Utility is expected to reach its current NEM cap.  The CPUC indicated that it may revisit the NEM successor tariff in 2019.  After the current NEM cap is reached, 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 non-bypassable 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. 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. 

 

 


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 more than 25,000 EV charging stations and the associated infrastructure.  The Utility proposed to engage with third-party EV service providers to operate and maintain the charging stations.  The Utility requested that the CPUC approve forecasted capital expenditures of $551 million over the five-year deployment period.

 

On September 4, 2015, the assigned CPUC commissioner and the ALJ issued a scoping memo and procedural schedule that required the Utility to supplement its application by submitting a more phased deployment approach that will be considered in a first phase of the proceeding.  On October 12, 2015, the Utility submitted supplemental testimony presenting two separate proposals, with the first proposal including capital expenditures of $70 million for approximately 2,500 charging stations and the second proposal comprising $187 million for approximately 7,500 charging stations.

 

After discussions with a number of parties about the two proposals, the Utility filed with the CPUC a settlement agreement on March 21, 2016 that it entered into with environmental advocates, automakers, electric vehicle drivers, labor, and environmental justice advocates, to deploy about 7,500 charging stations over three years with forecasted capital expenditures of $132 million.  (TURN, ORA, and certain equipment suppliers are not parties to the settlement agreementand filed responses on April 12, 2016, generally opposing the settlement agreement.)  The settlement agreement is subject to approval by the CPUC. Hearings were held in April 2016 and a proposed decision for the first phase of the proceeding is expected to be issued in the fourth quarter of 2016. Further deployment of EV charging stations would be considered in a second phase of the proceeding depending on the outcome of the first phase. 

 

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, such as groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations; the reporting and reduction of carbon dioxide and other greenhouse gas emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel.  (See Note 9 of the Notes to the Condensed Consolidated Financial Statements, as well as “Item 1A. Risk Factors” and Note 13 of the Notes to the Consolidated Financial Statements in the 2015 Form 10-K.)

 

CONTRACTUAL COMMITMENTS

 

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities.  (See “Purchase Commitments” in Note 9 of the Notes to the Condensed Consolidated Financial Statements).  Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing.  For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Commitments in the 2015 Form 10-K.

 

Off-Balance Sheet Arrangements

 

PG&E Corporation and the Utility do not have anyoff-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 in the 2015 Form 10-K (the Utility’s commodity purchase agreements).

 

 


RISK MANAGEMENT ACTIVITIES

 

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows.  PG&E Corporation and the Utility face market risk associated with their operations; their financing arrangements; the marketplace for electricity, natural gas, electric transmission, natural gas transportation, and storage; emissions allowances and offset credits, other goods and services; and other aspects of their businesses.  PG&E Corporation and the Utility categorize market risks as “price risk” and “interest rate risk.”  The Utility is also exposed to “credit risk,” the risk that counterparties fail to perform their contractual obligations. 

 

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.  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.  These activities arediscussed in detail in the 2015 Form 10-K.  There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the nine months ended September 30, 2016.

 

CRITICAL ACCOUNTING POLICIES

 

The preparation of the Condensed 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 Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period.  PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, asset retirement obligations, and pension and other postretirement benefits plans to be critical accounting policies. These policies are considered 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. These accounting policies and their key characteristics are discussed in detail in the 2015Form 10-K.

 

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

 

See the discussion above in Note 2 of the Notes to the Condensed 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 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:

 

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the timing and outcomes of the final phase two CPUC decision in the 2015 GT&S rate case, the 2017 GRC, the TO rate cases, and other ratemaking and regulatory proceedings;

 

 

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the timing and outcomes of the debarment proceeding and potential remedial and other measures that may be imposed on the Utility as a result of the debarment proceeding and the jury’s verdict in the federal criminal trial of the Utility (including a potential appointment of one or more independent third-party monitor(s)), the Utility’s motion for judgment of acquittal, 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-related laws and regulations, including the U.S. Attorney’s Office investigation in connection with the natural gas explosion that occurred in Carmel, California on March 3, 2014 and the U.S. Attorney’s Office in San Francisco investigation in connection with matters relating to the federal criminal trial discussed above, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

 

 

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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 parte communications or are otherwise alleged to be improper, 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;

 

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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;

 

 

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whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the jury’s verdict in the federal criminal trial and a possible conviction of the Utility, 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;

 

 

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whether the Utility can control its costs within the authorized levels of spending, 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;

 

 

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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;

 

 

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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;

 

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the outcomes of the SED’s investigations of potential violations identified though audits, investigations, or self-reports, including in connection with the Utility’s September 2016 self-report related to atmospheric corrosion inspections;

 

 


 
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 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;

 

 

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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;

 

 

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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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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;

 

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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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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;

 

 

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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;

 

 

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whether the Utility’s climate change adaptation strategies are successful;

 

 

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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 and changing customer demand for natural gas and electric services;

 

 

 



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;

 

 

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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;

 

 

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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;

 

 

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changes in credit ratings which could result in increased borrowing costs especially if PG&E Corporation or the Utility were to lose its investment grade credit ratings;

 

 

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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;

 

 

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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; and

 

 

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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 these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see “Risk Factors” in the 2015 Form 10-K and in “ Item. 1A. Risk Factors” below.  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 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices.  PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only.  Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates.  (See the section above entitled “Risk Management Activities” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.)

 

ITEM 4. CONTROLS AND PROCEDURES

 

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of September 30, 2016, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were 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 Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms.  In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the Securities Exchange Act of 1934 is 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.

 

There were no changes in internal control over financial reporting that occurred during the quarter ended September 30, 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.


 


PART II. OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.  For more information regarding PG&E Corporation’s and the Utility’s contingencies, see Note 9 of the Notes to the Condensed Consolidated Financial Statement and Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Enforcement and Litigation Matters.”

 

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

 

For a description of this matter, see “Part I, Item 3. Legal Proceedingsin the 2015 Form 10-K, the discussion of the Penalty Decision in Note 13 of the Notes to the Consolidated Financial Statements inthe 2015 Form 10-K, and the discussion included in Note 9 of the Notes to the Condensed Consolidated Financial Statements.

 

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 illegally 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 Count 13 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 2, 2016, the remaining Alternative Fines Act sentencing allegations in the case were dismissed.  The Alternative Fines Act states, in part: “If any person derives pecuniary gain from the offense, or if the offense results in pecuniary loss to a person other than the defendant, the defendant may be fined not more than the greater of twice the gross gain or twice the gross loss.”  (The remaining allegations related to $281 million of gross gains that the government alleged the Utility derived.  As previously disclosed, in December 2015, the court dismissed the government’s allegations regarding the amount of losses.)

 

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 August 16, 2016, the Utility filed a motion under Federal Rule of Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict.  The court indicated that it will decide on this motion based on briefs filed by the parties, without oral argument. The Utility is not able to predict when the court will decide on the motion. A sentencing hearing is currently scheduled for January 23, 2017.

 

For description of this matter, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K, the section entitled “Enforcement and Litigation Matters” in Note 13 of the Notes to the Consolidated Financial Statements in Item 8 in the 2015 Form 10-K, and  the section  entitled “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements. 

 

Litigation Related to the San Bruno Accident and Natural Gas Spending

 

As of September 30, 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. PG&E Corp. 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 September 16, 2016, the San Mateo Superior Court requested that all counsel appear for a status conference in the consolidated matter.  The date of the conference has been set for November 16, 2016.

 

 


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.

 

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 criminal proceedings against the Utility and ordered the parties to submit a joint status report on or before March 15, 2017.

 

A case management conference in the action entitled Tellardin v. PG&E Corp. et al., also pending in the Superior Court of California, San Mateo County, had been scheduled for August 9, 2016.  On July 19, 2016, plaintiff requested that the court vacate the August 9, 2016 conference because, pursuant to the parties’ agreement, defendants are not required to respond to the complaint in this action until 30 days after an order lifting the stay in the San Bruno Fire Derivative Cases.  On August 2, 2016, the court vacated the August 9, 2016 conference. 

 

PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.

 

For additional information regarding these matters, see the discussion entitled “Enforcement and Litigation Matters” above in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.  In addition, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

 

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, and destroyed 549 homes, 368 outbuildings and four commercial properties.  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 its vegetation management contractors 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 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 September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 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 preference cases (presented by individuals who due to their age and/or physical condition are not likely to meaningfully participate in a trial under normal scheduling).  The Utility also has begun scheduling mediation of other cases.  Case management conferences were held on July 14, 2016 and September 1, 2016.  The next case management conference is scheduled for December 1, 2016. 

 

 


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 negligentThe Utility believes it was not negligent; however, there can be no assurance that a court or a jury would agree with the Utility.

 

For more information regarding the Butte fire, see Note 9 “Contingencies and Commitments” of the Notes to the Condensed Consolidated Financial Statements. 

 

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 natural gas safety regulations, prohibited ex parte communications between the Utility and CPUC personnel, investigations that were commenced after a pipeline explosion in Carmel, California on March 3, 2014, and other enforcement matters.  See the discussion entitled “Enforcement and Litigation Matters” above in Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and in Note 9 of the Notes to the Condensed Consolidated Financial Statements.  In addition, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

 

Diablo Canyon Nuclear Power Plant

 

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 its decision to retire Diablo Canyon will affect the terms of the final settlement agreementbetween the Utility, the Central Coast Water Board and the California Attorney General’s Office.  Also, as required under the California State Water Resources Control Board’s Once-Through Cooling Water Policy, beginning in 2016, 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.

 

For more information regarding the 2003 settlement agreement between the Central Coast Water Board, the Utility, and the California Attorney General’s Office, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

 

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 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.  On October 28, 2015, the district attorney informed the Utility that it would seek civil penalties in excess of $100,000 but is willing to continue to explore settlement options with the Utility.  The Utility remains in settlement discussions with the district attorney’s office.

 

For more information, see “Part I, Item 3. Legal Proceedings” in the 2015 Form 10-K.

 

 


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.  The Utility is in the process of settlement negotiations with the Sonoma County District Attorney’s Office

 

ITEM 1A. RISK FACTORS

 

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s future financial condition, results of operations, and cash flows, see the section of the 2015 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Forward-Looking Statements.”

 

PG&E Corporation and the Utility may incur material liability 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 the Cal Fire’s report, the fire burned 70,868 acres, resulted in two fatalities, and destroyed 549 homes, 368 outbuildings and four commercial properties.  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 its vegetation management contractors 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 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 September 30, 2016, approximately 50 complaints have been filed against the Utility and its vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador involving approximately 1,850 individual plaintiffs representing approximately 800 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 process for estimating costs associated with claims relating to the Butte fire, including for estimated property damages, requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, including discoveries 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 during such reporting periods.

 

 


PG&E Corporation’s and the Utility’s future financial results could be materially affected by the jury’s verdict in the federal criminal trial and possible judgment of conviction of the Utility, the debarment proceeding and an increased number of government investigations and requests for information.

 

As previously disclosed, on August 9, 2016, the jury returned its verdict in the federal criminal trial against the Utility on 11 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 illegally obstructed the NTSB investigation into the cause of the San Bruno accident.  The jury acquitted the Utility on all six of the record-keeping allegations but found the Utility guilty on six felony counts that include obstructing a federal agency proceeding and violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act.  On August 16, 2016, the Utility filed a motion under Federal Criminal Procedure 29 for a judgment of acquittal, arguing that the evidence was insufficient to sustain a conviction for the six counts on which the jury returned a guilty verdict.

 

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 SanBruno 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.

 

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.  Following the update of the SAM, the Utility and the DOI have been in discussions regarding such a determination and regarding a possible interim administrative agreement that would allow the federal government agencies to contract with the Utility while the DOI is completing its debarment inquiry. It is uncertain when and if the Utility and the DOI will enter into an interim administrative agreement. It is also uncertain when or if further action will be taken by the DOI.  The DOI debarment inquiry could result in the Utility’s suspension or debarment from future federal government contracts for a fixed, specified time period or entering into an administrative agreement with the DOI to resolve debarment matters.

 

As a result of the DOI inquiry and/or of the August 9, 2016 jury’s guilty verdict on six felony counts in the federal criminal trial, the Utility may be required to 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).  If appointed, the Utility expects a monitor or monitors would serve for a period of time and report periodically to the court or a department or agency of the government.

 

The jury’s verdict, a possible judgment of conviction of the Utility 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 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, 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.  The Utility also could incur material costs, not recoverable through rates, to implement remedial and other measures that could be imposed.

 

The Utility is also a target of an increased number of investigations and government requests for information.  As previously disclosed, the U.S. Attorney’s Office is investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014.  The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the criminal trial discussed above.  The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office also are investigating 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 recently contacted by certain other federal agencies with requests for information.  While the Utility believes that these requests for information are routine, theiroutcome is uncertain.  The Utility also is unable to predict the outcome of pending investigations, including whether any charges will be brought against the Utility.  Any charges that could be brought against the Utility or proceedings that could result from the current and future government investigations and requests for information could result in material costs to PG&E Corporation and the Utility.

 


 

The Utility’s conviction, the outcome of the debarment proceeding and any proceedings that could result from the current and future government investigations and requests for information could harm its 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 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, the SED continues evaluating PG&E Corporation’s and the Utility’s organizational structure in the CPUC’s pending investigation to examine the Utility’s safety culture.

 

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’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.  (See “Risks Related to Operations and Information Technology” in Item 1A Risk Factors of the 2015 Form 10-K.)   Current 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.   (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 the Butte fire” above.)

 

In addition, 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 cyberand physical attacks) 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.

 

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 and physical attacksCyberattacks 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 third-party 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 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 the 2015 Form 10-K.) 

 

On June 20, 2016, the Utility entered into a proposal to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025, subject to certain regulatory approvals.  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.

 

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 in the 2015 Form 10-K.)  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 September 30, 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 risk of regulatory uncertainty regarding the measures that could have been imposed on the Utility or 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 of the Notes to Condensed Consolidated Financial Statements in Item 1 herein and Note 2 of the Notes to the Consolidated Financial Statement in Item 8 of the 2015 Form 10-K.)  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.


 


 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

During the quarter ended September 30, 2016, PG&E Corporation made equity contributions totaling $460 million to the Utility in order to maintain the 52% common equity component of the Utility’s CPUC-authorized capital structure.  Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended September 30, 2016.

 

Issuer Purchases of Equity Securities

 

During the quarter endedSeptember 30, 2016, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended September 30, 2016, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

 

ITEM 5. OTHER INFORMATION

 

Ratio of Earnings to Fixed Charges and Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends

 

The Utility’s earnings to fixed charges ratio for the nine months ended September 30, 2016 was 1.57. The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the nine months ended September 30, 2016 was1.55. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and Exhibits into the Utility’s Registration Statement No. 333-193879.

 

PG&E Corporation’s earnings to fixed charges ratio for the nine months ended September 30, 2016 was 1.55. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12.3 hereto, is included herein for the purpose of incorporating such information and Exhibit into PG&E Corporation’s Registration Statement No. 333-193880.


 


ITEM 6. EXHIBITS

 

3.1

Bylaws of PG&E Corporation amended as of September 20, 2016

 

 

3.2

Bylaws of Pacific Gas and Electric Company amended as of September 20, 2016

 

 

*10.1

Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason dated August 8, 2016

 

 

*10.2

Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E Corporation dated August 8, 2016 

 

 

*10.3

Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016

 

 

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

 

 

31.1

Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

 

 

31.2

Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

 

 

**32.1

Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

 

 

**32.2

Certifications of the Principal Executive Officers and the Principal 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.


 


SIGNATURES

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this Quarterly Report on Form 10-Q to be signed on their behalf by the undersigned thereunto duly authorized.

 

 

PG&E CORPORATION

 

/s/ JASON P. WELLS

Jason P. Wells
Senior Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)

 

 

PACIFIC GAS AND ELECTRIC COMPANY

 

/s/ DAVID S. THOMASON

David S. Thomason

Vice President, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

 

 

 

Dated: November 4, 2016

 


EXHIBIT INDEX

 

3.1

Bylaws of PG&E Corporation amended as of September 20, 2016

 

 

3.2

Bylaws of Pacific Gas and Electric Company amended as of September 20, 2016

 

 

*10.1

Non-Annual Restricted Stock Unit Award Agreement between PG&E Corporation and David S. Thomason dated August 8, 2016

 

 

*10.2

Performance Share Award Agreement subject to financial goals between David S. Thomason and PG&E Corporation dated August 8, 2016 

 

 

*10.3

Performance Share Award Agreement subject to safety and customer affordability goals between David S. Thomason and PG&E Corporation dated August 8, 2016

 

 

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

 

 

31.1

Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002

 

 

31.2

Certifications of the Principal Executive Officers and the Principal Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002

 

 

**32.1

Certifications of the Principal Executive Officer and the Principal Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002

 

 

**32.2

Certifications of the Principal Executive Officers and the Principal 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.