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PG&E Corp - Quarter Report: 2015 June (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 June 30, 2015

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, California 94177

______________________________________

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 July 20,2015:

 

PG&E Corporation:

482,010,056

Pacific Gas and Electric Company:

264,374,809



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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2015

 

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

RATEMAKING PROCEEDINGS

LEGISLATIVE AND REGULATORY INITIATIVES

Proposal for Electric Vehicle (EV) Infrastructure Development

ENVIRONMENTAL MATTERS

CONTRACTUAL COMMITMENTS

RISK MANAGEMENT ACTIVITIES

CRITICAL ACCOUNTING POLICIES

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

CAUTIONARY LANGUAGE REGARDING 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.

 

2014 Form 10-K

PG&E Corporation's and Pacific Gas and Electric Company's combined Annual Report on Form 10-K for the year ended December 31, 2014

AFUDC

allowance for funds used during construction

ASU

Accounting Standards Update issued by the FASB (see below)

CPUC

California Public Utilities Commission

CRRs

congestion revenue rights

DTSC

California Department of Toxic Substances Control

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

GRC

general rate case

GT&S

gas transmission and storage

IRS

Internal Revenue Service

NRC

Nuclear Regulatory Commission

NTSB

National Transportation Safety Board

PSEP

pipeline safety enhancement plan

Regional Board

California Regional Water Control Board, Lahontan Region

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

 

Six Months Ended

 

June 30,

 

June 30,

(in millions, except per share amounts)

2015

 

2014

 

2015

 

2014

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

Electric

$

3,463 

 

$

3,233 

 

$

6,476 

 

$

6,234 

Natural gas

 

754 

 

 

719 

 

 

1,640 

 

 

1,609 

Total operating revenues

 

4,217 

 

 

3,952 

 

 

8,116 

 

 

7,843 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

Cost of electricity

 

1,277 

 

 

1,349 

 

 

2,277 

 

 

2,559 

Cost of natural gas

 

118 

 

 

200 

 

 

392 

 

 

560 

Operating and maintenance

 

1,484 

 

 

1,328 

 

 

3,407 

 

 

2,627 

Depreciation, amortization, and decommissioning

 

651 

 

 

557 

 

 

1,282 

 

 

1,095 

Total operating expenses

 

3,530 

 

 

3,434 

 

 

7,358 

 

 

6,841 

Operating Income

 

687 

 

 

518 

 

 

758 

 

 

1,002 

Interest income

 

3 

 

 

2 

 

 

4 

 

 

5 

Interest expense

 

(192)

 

 

(188)

 

 

(381)

 

 

(373)

Other income, net

 

18 

 

 

43 

 

 

76 

 

 

62 

Income Before Income Taxes

 

516 

 

 

375 

 

 

457 

 

 

696 

Income tax provision

 

110 

 

 

104 

 

 

17 

 

 

195 

Net Income

 

406 

 

 

271 

 

 

440 

 

 

501 

Preferred stock dividend requirement of subsidiary

 

4 

 

 

4 

 

 

7 

 

 

7 

Income Available for Common Shareholders

$

402 

 

$

267 

 

$

433 

 

$

494 

Weighted Average Common Shares Outstanding, Basic

 

480 

 

 

467 

 

 

479 

 

 

463 

Weighted Average Common Shares Outstanding, Diluted

 

483 

 

 

469 

 

 

483 

 

 

465 

Net Earnings Per Common Share, Basic

$

0.84 

 

$

0.57 

 

$

0.90 

 

$

1.07 

Net Earnings Per Common Share, Diluted

$

0.83 

 

$

0.57 

 

$

0.90 

 

$

1.06 

Dividends Declared Per Common Share

$

0.46 

 

$

0.46 

 

$

0.91 

 

$

0.91 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

(Unaudited)

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Net Income

$

406 

 

$

271 

 

$

440 

 

$

501 

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, $7, $12 and $3, at respective dates)

 

- 

 

 

(11)

 

 

(17)

 

 

(6)

Total other comprehensive income (loss)

 

- 

 

 

(11)

 

 

(17)

 

 

(6)

Comprehensive Income

 

406 

 

 

260 

 

 

423 

 

 

495 

Preferred stock dividend requirement of subsidiary

 

4 

 

 

4 

 

 

7 

 

 

7 

Comprehensive Income Attributable to

 

 

 

 

 

 

 

 

 

 

 

Common Shareholders

$

402 

 

$

256 

 

$

416 

 

$

488 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

June 30,

 

December 31,

(in millions)

2015

 

2014

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

$

249 

 

$

151 

Restricted cash

 

287 

 

 

298 

Accounts receivable:

 

 

 

 

 

Customers (net of allowance for doubtful accounts of $56 and $66

 

 

 

 

 

   at respective dates)

 

1,049 

 

 

960 

Accrued unbilled revenue

 

936 

 

 

776 

Regulatory balancing accounts

 

2,204 

 

 

2,266 

Other

 

352 

 

 

377 

Regulatory assets

 

441 

 

 

444 

Inventories:

 

 

 

 

 

Gas stored underground and fuel oil

 

141 

 

 

172 

Materials and supplies

 

315 

 

 

304 

Income taxes receivable

 

192 

 

 

198 

Other

 

280 

 

 

443 

Total current assets

 

6,446 

 

 

6,389 

Property, Plant, and Equipment

 

 

 

 

 

Electric

 

46,687 

 

 

45,162 

Gas

 

16,208 

 

 

15,678 

Construction work in progress

 

2,075 

 

 

2,220 

Other

 

2 

 

 

2 

Total property, plant, and equipment

 

64,972 

 

 

63,062 

Accumulated depreciation

 

(19,962)

 

 

(19,121)

Net property, plant, and equipment

 

45,010 

 

 

43,941 

Other Noncurrent Assets

 

 

 

 

 

Regulatory assets

 

6,476 

 

 

6,322 

Nuclear decommissioning trusts

 

2,504 

 

 

2,421 

Income taxes receivable

 

94 

 

 

91 

Other

 

1,101 

 

 

963 

Total other noncurrent assets

 

10,175 

 

 

9,797 

TOTAL ASSETS

$

61,631 

 

$

60,127 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

June 30,

 

December 31,

(in millions, except share amounts)

2015

 

2014

LIABILITIES AND EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Short-term borrowings

$

1,016 

 

$

633 

Accounts payable:

 

 

 

 

 

Trade creditors

 

1,178 

 

 

1,244 

Regulatory balancing accounts

 

876 

 

 

1,090 

Other

 

458 

 

 

476 

Disputed claims and customer refunds

 

448 

 

 

434 

Interest payable

 

203 

 

 

197 

Other

 

2,123 

 

 

1,846 

Total current liabilities

 

6,302 

 

 

5,920 

Noncurrent Liabilities

 

 

 

 

 

Long-term debt

 

15,544 

 

 

15,050 

Regulatory liabilities

 

6,330 

 

 

6,290 

Pension and other postretirement benefits

 

2,536 

 

 

2,561 

Asset retirement obligations

 

3,609 

 

 

3,575 

Deferred income taxes

 

8,732 

 

 

8,513 

Other

 

2,307 

 

 

2,218 

Total noncurrent liabilities

 

39,058 

 

 

38,207 

Commitments and Contingencies (Note 9)

 

 

 

 

 

Equity

 

 

 

 

 

Shareholders' Equity

 

 

 

 

 

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

 

 

 

 

 

481,575,453 and 475,913,404 shares outstanding at respective dates

 

10,717 

 

 

10,421 

Reinvested earnings

 

5,308 

 

 

5,316 

Accumulated other comprehensive income (loss)

 

(6)

 

 

11 

Total shareholders' equity

 

16,019 

 

 

15,748 

Noncontrolling Interest - Preferred Stock of Subsidiary

 

252 

 

 

252 

Total equity

 

16,271 

 

 

16,000 

TOTAL LIABILITIES AND EQUITY

$

61,631 

 

$

60,127 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Unaudited)

 

Six Months Ended June 30,

(in millions)

2015

 

2014

Cash Flows from Operating Activities

 

 

 

 

 

Net income

$

440 

 

$

501 

Adjustments to reconcile net income to net cash provided by

 

 

 

 

 

operating activities:

 

 

 

 

 

Depreciation, amortization, and decommissioning

 

1,282 

 

 

1,095 

Allowance for equity funds used during construction

 

(53)

 

 

(46)

Deferred income taxes and tax credits, net

 

219 

 

 

51 

Disallowed capital expenditures

 

128 

 

 

- 

Other

 

149 

 

 

139 

Effect of changes in operating assets and liabilities:

 

 

 

 

 

     Accounts receivable

 

(241)

 

 

(30)

     Inventories

 

20 

 

 

(7)

     Accounts payable

 

78 

 

 

(101)

     Income taxes receivable/payable

 

6 

 

 

(39)

     Other current assets and liabilities

 

77 

 

 

94 

     Regulatory assets, liabilities, and balancing accounts, net

 

(62)

 

 

(311)

     Other noncurrent assets and liabilities

 

(184)

 

 

(66)

Net cash provided by operating activities

 

1,859 

 

 

1,280 

Cash Flows from Investing Activities

 

 

 

 

 

Capital expenditures

 

(2,410)

 

 

(2,320)

Decrease in restricted cash

 

11 

 

 

2 

Proceeds from sales and maturities of nuclear decommissioning

 

 

 

 

 

     trust investments

 

779 

 

 

877 

Purchases of nuclear decommissioning trust investments

 

(879)

 

 

(873)

Other

 

13 

 

 

21 

Net cash used in investing activities

 

(2,486)

 

 

(2,293)

Cash Flows from Financing Activities

 

 

 

 

 

Repayments under revolving credit facilities

 

- 

 

 

(260)

Net issuances of commercial paper, net of discount of $2

 

 

 

 

 

     and $1 at respective dates

 

681 

 

 

237 

Proceeds from issuance of short-term debt, net of issuance costs

 

- 

 

 

300 

Short-term debt matured

 

(300)

 

 

- 

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

 

 

 

 

 

    and issuance costs of $14 at respective dates

 

486 

 

 

1,236 

Repayments of long-term debt

 

- 

 

 

(889)

Common stock issued

 

252 

 

 

589 

Common stock dividends paid

 

(424)

 

 

(408)

Other

 

30 

 

 

44 

Net cash provided by financing activities

 

725 

 

 

849 

Net change in cash and cash equivalents

 

98 

 

 

(164)

Cash and cash equivalents at January 1

 

151 

 

 

296 

Cash and cash equivalents at June 30

$

249 

 

$

132 

 



 

Supplemental disclosures of cash flow information

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

$

(334)

 

$

(318)

Income taxes, net

 

- 

 

 

(1)

Supplemental disclosures of noncash investing and financing activities

 

 

 

 

 

Common stock dividends declared but not yet paid

$

219 

 

$

215 

Capital expenditures financed through accounts payable

 

177 

 

 

224 

Noncash common stock issuances

 

10 

 

 

10 

Terminated capital leases

 

- 

 

 

68 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

 

 

(Unaudited)

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Operating Revenues

 

 

 

 

 

 

 

 

 

 

 

Electric

$

3,462 

 

$

3,232 

 

$

6,476 

 

$

6,232 

Natural gas

 

754 

 

 

719 

 

 

1,640 

 

 

1,609 

Total operating revenues

 

4,216 

 

 

3,951 

 

 

8,116 

 

 

7,841 

Operating Expenses

 

 

 

 

 

 

 

 

 

 

 

Cost of electricity

 

1,277 

 

 

1,349 

 

 

2,277 

 

 

2,559 

Cost of natural gas

 

118 

 

 

200 

 

 

392 

 

 

560 

Operating and maintenance

 

1,483 

 

 

1,321 

 

 

3,406 

 

 

2,618 

Depreciation, amortization, and decommissioning

 

651 

 

 

556 

 

 

1,282 

 

 

1,094 

Total operating expenses

 

3,529 

 

 

3,426 

 

 

7,357 

 

 

6,831 

Operating Income

 

687 

 

 

525 

 

 

759 

 

 

1,010 

Interest income

 

3 

 

 

3 

 

 

4 

 

 

5 

Interest expense

 

(189)

 

 

(185)

 

 

(376)

 

 

(364)

Other income, net

 

20 

 

 

17 

 

 

46 

 

 

37 

Income Before Income Taxes

 

521 

 

 

360 

 

 

433 

 

 

688 

Income tax provision

 

115 

 

 

110 

 

 

23 

 

 

210 

Net Income

 

406 

 

 

250 

 

 

410 

 

 

478 

Preferred stock dividend requirement

 

4 

 

 

4 

 

 

7 

 

 

7 

Income Available for Common Stock

$

402 

 

$

246 

 

$

403 

 

$

471 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

 

(Unaudited)

 

Three Months Ended

 

 

Six Months Ended

 

June 30,

 

 

June 30,

(in millions)

2015

 

2014

 

 

2015

 

2014

Net Income

$

406 

 

$

250 

 

$

410 

 

$

478 

Other Comprehensive Income

 

 

 

 

 

 

 

 

 

 

 

Pension and other postretirement benefit plans obligations

 

 

 

 

 

 

 

 

 

 

 

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

 

- 

 

 

- 

 

 

- 

 

 

- 

Total other comprehensive income (loss)

 

- 

 

 

- 

 

 

- 

 

 

- 

Comprehensive Income

$

406 

 

$

250 

 

$

410 

 

$

478 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying Notes to the Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

June 30,

 

December 31,

(in millions)

2015

 

2014

ASSETS

 

 

 

 

 

Current Assets

 

 

 

 

 

Cash and cash equivalents

$

148 

 

$

55 

Restricted cash

 

287 

 

 

298 

Accounts receivable:

 

 

 

 

 

Customers (net of allowance for doubtful accounts of $56 and $66

 

 

 

 

 

  at respective dates)

 

1,049 

 

 

960 

Accrued unbilled revenue

 

936 

 

 

776 

Regulatory balancing accounts

 

2,204 

 

 

2,266 

Other

 

351 

 

 

375 

Regulatory assets

 

441 

 

 

444 

Inventories:

 

 

 

 

 

Gas stored underground and fuel oil

 

141 

 

 

172 

Materials and supplies

 

315 

 

 

304 

Income taxes receivable

 

160 

 

 

168 

Other

 

280 

 

 

409 

Total current assets

 

6,312 

 

 

6,227 

Property, Plant, and Equipment

 

 

 

 

 

Electric

 

46,687 

 

 

45,162 

Gas

 

16,208 

 

 

15,678 

Construction work in progress

 

2,075 

 

 

2,220 

Total property, plant, and equipment

 

64,970 

 

 

63,060 

Accumulated depreciation

 

(19,961)

 

 

(19,120)

Net property, plant, and equipment

 

45,009 

 

 

43,940 

Other Noncurrent Assets

 

 

 

 

 

Regulatory assets

 

6,476 

 

 

6,322 

Nuclear decommissioning trusts

 

2,504 

 

 

2,421 

Income taxes receivable

 

94 

 

 

91 

Other

 

998 

 

 

864 

Total other noncurrent assets

 

10,072 

 

 

9,698 

TOTAL ASSETS

$

61,393 

 

$

59,865 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

 

 

(Unaudited)

 

Balance At

 

June 30,

 

December 31,

(in millions, except share amounts)

2015

 

2014

LIABILITIES AND SHAREHOLDERS' EQUITY

 

 

 

 

 

Current Liabilities

 

 

 

 

 

Short-term borrowings

$

1,011 

 

$

633 

Accounts payable:

 

 

 

 

 

Trade creditors

 

1,177 

 

 

1,243 

Regulatory balancing accounts

 

876 

 

 

1,090 

Other

 

482 

 

 

444 

Disputed claims and customer refunds

 

448 

 

 

434 

Interest payable

 

200 

 

 

195 

Other

 

1,899 

 

 

1,604 

Total current liabilities

 

6,093 

 

 

5,643 

Noncurrent Liabilities

 

 

 

 

 

Long-term debt

 

15,194 

 

 

14,700 

Regulatory liabilities

 

6,330 

 

 

6,290 

Pension and other postretirement benefits

 

2,449 

 

 

2,477 

Asset retirement obligations

 

3,609 

 

 

3,575 

Deferred income taxes

 

8,992 

 

 

8,773 

Other

 

2,263 

 

 

2,178 

Total noncurrent liabilities

 

38,837 

 

 

37,993 

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

 

6,703 

 

 

6,514 

Reinvested earnings

 

8,175 

 

 

8,130 

Accumulated other comprehensive income

 

5 

 

 

5 

Total shareholders' equity

 

16,463 

 

 

16,229 

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY

$

61,393 

 

$

59,865 

 

 

 

 

 

 

See accompanying Notes to the Condensed Consolidated Financial Statements.



PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

(Unaudited)

 

Six Months Ended June 30,

(in millions)

2015

 

2014

Cash Flows from Operating Activities

 

 

 

 

 

Net income

$

410 

 

$

478 

Adjustments to reconcile net income to net cash provided by

 

 

 

 

 

operating activities:

 

 

 

 

 

Depreciation, amortization, and decommissioning

 

1,282 

 

 

1,094 

Allowance for equity funds used during construction

 

(53)

 

 

(46)

Deferred income taxes and tax credits, net

 

219 

 

 

18 

    Disallowed capital expenditures

 

128 

 

 

- 

    Other

 

119 

 

 

108 

Effect of changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(242)

 

 

(31)

Inventories

 

20 

 

 

(7)

Accounts payable

 

134 

 

 

(72)

Income taxes receivable/payable

 

8 

 

 

(35)

Other current assets and liabilities

 

67 

 

 

141 

Regulatory assets, liabilities, and balancing accounts, net

 

(62)

 

 

(311)

        Other noncurrent assets and liabilities

 

(170)

 

 

(76)

Net cash provided by operating activities

 

1,860 

 

 

1,261 

Cash Flows from Investing Activities

 

 

 

 

 

Capital expenditures

 

(2,410)

 

 

(2,320)

Decrease in restricted cash

 

11 

 

 

2 

Proceeds from sales and maturities of nuclear decommissioning

 

 

 

 

 

trust investments

 

779 

 

 

877 

Purchases of nuclear decommissioning trust investments

 

(879)

 

 

(873)

Other

 

13 

 

 

17 

Net cash used in investing activities

 

(2,486)

 

 

(2,297)

Cash Flows from Financing Activities

 

 

 

 

 

Net issuances of commercial paper, net of discount of $2 and $1

 

 

 

 

 

   at respective dates

 

676 

 

 

125 

Proceeds from issuance of short-term debt, net of issuance costs

 

- 

 

 

300 

Short-term debt matured

 

(300)

 

 

- 

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

 

 

 

 

 

and issuance costs of $14 and $11 at respective dates

 

486 

 

 

889 

Repayments of long-term debt

 

- 

 

 

(539)

Preferred stock dividends paid

 

(7)

 

 

(7)

Common stock dividends paid

 

(358)

 

 

(358)

Equity contribution from PG&E Corporation

 

185 

 

 

580 

Other

 

37 

 

 

51 

Net cash provided by financing activities

 

719 

 

 

1,041 

Net change in cash and cash equivalents

 

93 

 

 

5 

Cash and cash equivalents at January 1

 

55 

 

 

65 

Cash and cash equivalents at June 30

$

148 

 

$

70 

 



 

Supplemental disclosures of cash flow information

 

 

 

 

 

Cash paid for:

 

 

 

 

 

Interest, net of amounts capitalized

$

(330)

 

$

(307)

Income taxes, net

 

- 

 

 

(1)

Supplemental disclosures of noncash investing and financing activities

 

 

 

 

 

Capital expenditures financed through accounts payable

$

177 

 

$

224 

Terminated capital leases

 

- 

 

 

68 

 

 

 

 

 

 

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 operating in 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. 

 

On April 9, 2015, the CPUC approved  final decisions in the three investigations pending against the Utility relating to (1) the Utility’s safety recordkeeping for its natural gas transmission system, (2) the Utility’s operation of its natural gas transmission pipeline system in or near locations of higher population density, and (3) the Utility’s pipeline installation, integrity management, recordkeeping and other operational practices, and other events or courses of conduct, that could have led to or contributed to the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  A decision was issued in each investigative proceeding to determine the violations that the Utility committed.  The CPUC also approved a fourth decision (the “Penalty Decision”) which imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million. The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base.  The remainder will be allocated to safety-related expenses.  (See Note 9.)

 

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.

 

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, 2014 in the Condensed Consolidated Balance Sheets included in this quarterly report was derived from the audited Consolidated Balance Sheets in the 2014 Form 10-K.  This quarterly report should be read in conjunction with the 2014 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.  Actual results could differ materially from those estimates.

 

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 2014 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 was the primary beneficiary of any of these VIEs at June 30, 2015, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at June 30, 2015, it did not consolidate any of them.

 

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 six months ended June 30, 2015 and 2014 were as follows:

 

 

Pension Benefits

 

Other Benefits

 

Three Months Ended June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Service cost for benefits earned

$

118 

 

$ 

96 

 

$ 

14 

 

$ 

11 

Interest cost

 

169 

 

 

173 

 

 

18 

 

 

19 

Expected return on plan assets

 

(218)

 

 

(201)

 

 

(28)

 

 

(26)

Amortization of prior service cost

 

3 

 

 

5 

 

 

5 

 

 

5 

Amortization of net actuarial loss

 

3 

 

 

1 

 

 

1 

 

 

1 

Net periodic benefit cost

 

75 

 

 

74 

 

 

10 

 

 

10 

Regulatory account transfer (1)

 

9 

 

 

9 

 

 

- 

 

 

- 

Total

$ 

84 

 

$ 

83 

 

$ 

10 

 

$ 

10 

 

 

 

 

 

 

 

 

 

 

 

 

(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

 

Six Months Ended June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Service cost for benefits earned

$

237 

 

$ 

195 

 

$ 

27 

 

$ 

22 

Interest cost

 

337 

 

 

346 

 

 

36 

 

 

38 

Expected return on plan assets

 

(436)

 

 

(403)

 

 

(56)

 

 

(52)

Amortization of prior service cost

 

7 

 

 

10 

 

 

10 

 

 

11 

Amortization of net actuarial loss

 

6 

 

 

1 

 

 

2 

 

 

1 

Net periodic benefit cost

 

151 

 

 

149 

 

 

19 

 

 

20 

Regulatory account transfer (1)

 

18 

 

 

19 

 

 

- 

 

 

- 

Total

$ 

169 

 

$ 

168 

 

$ 

19 

 

$ 

20 

 

 

 

 

 

 

 

 

 

 

 

 

(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

 

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 June 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)

 

2 

 

 

3 

 

 

5 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

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

 

1 

 

 

1 

 

 

2 

Regulatory account transfer

 

 

 

 

 

 

 

 

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

 

(3)

 

 

(4)

 

 

(7)

Net current period other comprehensive 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

 

Other

 

 

 

 

Benefits

 

Benefits

 

Investments

 

Total

(in millions, net of income tax)

Three Months Ended June 30, 2014

Beginning balance

$

(7)

 

$

15 

 

$

47 

 

$

55 

Other comprehensive income before reclassifications:

 

 

 

 

 

 

 

 

 

 

 

Change in investments

 

 

 

 

 

 

 

 

 

 

 

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

 

- 

 

 

- 

 

 

5 

 

 

5 

Amounts reclassified from other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior service cost

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $2, $2, and $0, respectively) (1)

 

3 

 

 

3 

 

 

- 

 

 

6 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

 

 

 

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

 

1 

 

 

1 

 

 

- 

 

 

2 

Regulatory account transfer

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $2, $2, and $0, respectively) (1)

 

(4)

 

 

(4)

 

 

- 

 

 

(8)

Change in investments

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, and $10, respectively)

 

- 

 

 

- 

 

 

(16)

 

 

(16)

Net current period other comprehensive loss

 

- 

 

 

- 

 

 

(11)

 

 

(11)

Ending balance

$

(7)

 

$ 

15 

 

$ 

36 

 

$ 

44 

 

 

 

 

 

 

 

 

 

 

 

 

(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)

Six Months Ended June 30, 2015

Beginning balance

$

(21)

 

$ 

15 

 

$

17 

 

$

11 

Amounts reclassified from other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

Amortization of prior service cost

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $3, $4, and $0, respectively) (1)

 

4 

 

 

6 

 

 

- 

 

 

10 

Amortization of net actuarial loss

 

 

 

 

 

 

 

 

 

 

 

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

 

3 

 

 

1 

 

 

- 

 

 

4 

Regulatory account transfer

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $6, $5, and $0, respectively) (1)

 

(7)

 

 

(7)

 

 

- 

 

 

(14)

Change in investments

 

 

 

 

 

 

 

 

 

 

 

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

 

- 

 

 

- 

 

 

(17)

 

 

(17)

Net current period other comprehensive 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.)

 

 

Pension

 

Other

 

Other

 

 

 

 

Benefits

 

Benefits

 

Investments

 

Total

(in millions, net of income tax)

Six Months Ended June 30, 2014

Beginning balance

$

(7)

 

$

15 

 

$

42 

 

$

50 

Other comprehensive income before reclassifications:

 

 

 

 

 

 

 

 

 

 

 

Change in investments

 

 

 

 

 

 

 

 

 

 

 

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

 

- 

 

 

- 

 

 

10 

 

 

10 

Amounts reclassified from other comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

      Amortization of prior service cost

 

 

 

 

 

 

 

 

 

 

 

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

 

6 

 

 

7 

 

 

- 

 

 

13 

      Amortization of net actuarial loss

 

 

 

 

 

 

 

 

 

 

 

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

 

1 

 

 

1 

 

 

- 

 

 

2 

     Regulatory account transfer

 

 

 

 

 

 

 

 

 

 

 

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

 

(7)

 

 

(8)

 

 

- 

 

 

(15)

Change in investments

 

 

 

 

 

 

 

 

 

 

 

(net of taxes of $0, $0, and $10, respectively)

 

- 

 

 

- 

 

 

(16)

 

 

(16)

Net current period other comprehensive loss

 

- 

 

 

- 

 

 

(6)

 

 

(6)

Ending balance

$

(7)

 

$

15 

 

$

36 

 

$

44 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

 


Accounting Standards Issued But Not Yet Adopted

 

Fair Value Measurement

 

In May 2015, the FASB issued ASU No. 2015-07, 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. The accounting standards update will be effective for fiscal years beginning after December 15, 2015. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their disclosures and will adopt this standard starting in the first quarter of 2016.

 

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.  The accounting standards update will be effective on January 1, 2016.  PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their consolidated financial statements and related disclosures and will adopt this standard starting in the first quarter of 2016.

 

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 existing presentation of debt issuance costs.  PG&E Corporation and the Utility currently disclose debt issuance costs in current assets – other and noncurrent assets – other.  The amendments in this Accounting Standard Update, effective on January 1, 2016, 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 do not expect this reclassification to have a material impact on their consolidated financial statements.  PG&E Corporation and the Utility will adopt this standard starting in the first quarter of 2016.

 

Revenue Recognition Standard

 

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. In July 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. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their 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

 

June 30,

 

December 31,

(in millions)

2015

 

2014

Pension benefits

$

2,316 

 

$

2,347 

Deferred income taxes

 

2,649 

 

 

2,390 

Environmental compliance costs

 

686 

 

 

717 

Utility retained generation

 

434 

 

 

456 

Price risk management

 

142 

 

 

127 

Unamortized loss, net of gain, on reacquired debt

 

103 

 

 

113 

Electromechanical meters

 

36 

 

 

70 

Other

 

110 

 

 

102 

Total long-term regulatory assets

$

6,476 

 

$

6,322 

 


Regulatory Liabilities

 

Long-term regulatory liabilities are composed of the following:

 

 

Balance at

 

June 30,

 

December 31,

(in millions)

2015

 

2014

Cost of removal obligations

$

4,414 

 

$

4,211 

Recoveries in excess of asset retirement obligations

 

719 

 

 

754 

Public purpose programs

 

708 

 

 

701 

Other

 

489 

 

 

624 

Total long-term regulatory liabilities

$

6,330 

 

$

6,290 

 

Regulatory Balancing Accounts

 

The Utility’s recovery of revenue requirements and costs is generally decoupled from the volume of sales.  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.  Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected. 

 

Current regulatory balancing accounts receivable and payable are composed of the following:

 

 

Receivable

 

Balance at

 

June 30,

 

December 31,

(in millions)

2015

 

2014

Electric distribution

$

672 

 

$

344 

Utility generation

 

392 

 

 

261 

Gas distribution

 

504 

 

 

566 

Energy procurement

 

308 

 

 

608 

Public purpose programs

 

82 

 

 

109 

Other

 

246 

 

 

378 

Total regulatory balancing accounts receivable

$

2,204 

 

$

2,266 

 

 

Payable

 

Balance at

 

June 30,

 

December 31,

(in millions)

2015

 

2014

Energy procurement

$

173 

 

$

188 

Public purpose programs

 

177 

 

 

154 

Other (1)

 

526 

 

 

748 

Total regulatory balancing accounts payable

$

876 

 

$

1,090 

 

 

 

 

 

 

(1) At June 30, 2015 and December 31, 2014, Other regulatory balancing accounts payable mostly included energy supplier settlements related to the Utility’s outstanding bankruptcy claims.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 below).

 

 


NOTE 4: DEBT

 

Short-term Borrowings

 

Revolving Credit Facilities and Commercial Paper Program

 

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013.  The amendments and restatements extended the termination dates of the credit facilities from April 1, 2019 to April 27, 2020, reduced the amount of lender commitments to the letter of credit sublimits from $100 million to $50 million for PG&E Corporation’s credit facility and from $1.0 billion to $500 million for the Utility’s credit facility, and reduced the swingline commitment on the Utility’s credit facility from $300 million to $75 million. 

 

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at June 30, 2015:

 

 

 

 

 

 

Letters of

 

 

 

 

 

Termination

 

Facility

 

Credit

 

Commercial

 

Facility

(in millions)

Date

 

Limit

 

Outstanding

 

Paper

 

Availability

PG&E Corporation

April 2020

 

$

300 

(1)

$

- 

 

$

5 

 

$

295 

Utility

April 2020

 

 

3,000 

(2)

 

33 

 

 

1,011 

 

 

1,956 

Total revolving

 

 

 

 

 

 

 

 

 

 

 

 

 

credit facilities

 

 

$

3,300 

 

$

33 

 

$

1,016 

 

$

2,251 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)Includes a $50 million sublimit for letters of credit 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 sublimit for letters of credit and a $75 million commitment for swingline loans.

 

In July 2015, the Utility increased the commercial paper program limit from $1.75 billion to $2.5 billion.  PG&E Corporation and the Utility can issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively.  PG&E Corporation and the Utility treat the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.

 

Long-term Debt

 

Issuances and Maturities

 

In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045.  The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper.  In addition, $300 million principal amount of the Utility’s Floating Rate Senior Notes matured in May 2015.

 

Variable Rate Interest

 

At June 30, 2015, 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 0.01% to 0.03%.  At June 30, 2015, the interest rates on the $309 million principal amount of pollution control bonds Series 2009 A-D and the related loan agreements ranged from 0.02% to 0.03%.

 



NOTE 5: EQUITY

 

PG&E Corporation’s and the Utility’s changes in equity for the six months ended June 30, 2015 were as follows:

 

 

PG&E Corporation

 

Utility

 

Total

 

Total

(in millions)

Equity

 

Shareholders' Equity

Balance at December 31, 2014

$

16,000 

 

$

16,229 

Comprehensive income

 

423 

 

 

410 

Equity contributions

 

- 

 

 

185 

Common stock issued

 

262 

 

 

- 

Share-based compensation

 

34 

 

 

4 

Common stock dividends declared

 

(441)

 

 

(358)

Preferred stock dividend requirement

 

- 

 

 

(7)

Preferred stock dividend requirement of subsidiary

 

(7)

 

 

- 

Balance at June 30, 2015

$

16,271 

 

$

16,463 

 

In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  In the first quarter of 2015, PG&E Corporation sold 1.4 million shares under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million. No shares were sold during the three months ended June 30, 2015.

 

PG&E Corporation 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 six months ended June 30, 2015, 4.3 million shares were issued for cash proceeds of $178 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

 

Six Months Ended

 

June 30,

 

June 30,

(in millions, except per share amounts)

2015

 

2014

 

2015

 

2014

Income available for common shareholders

$

402 

 

$

267 

 

$

433 

 

$

494 

Weighted average common shares outstanding, basic

 

480 

 

 

467 

 

 

479 

 

 

463 

Add incremental shares from assumed conversions:

 

 

 

 

 

 

 

 

 

 

 

Employee share-based compensation

 

3 

 

 

2 

 

 

4 

 

 

2 

Weighted average common share outstanding, diluted

 

483 

 

 

469 

 

 

483 

 

 

465 

Total earnings per common share, diluted

$

0.83 

 

$

0.57 

 

$

0.90 

 

$

1.06 

 

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

 

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 forward contracts, swaps, futures, options, and CRRs.

 


Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets on a net basis in accordance with master netting arrangements for each counterparty.  The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.  

 

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets.  These instruments are not held for speculative purposes and are subject to certain regulatory requirements.  The Utility expects to fully recover in rates all costs related to derivatives 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

 

 

 

 

June 30,

 

December 31,

Underlying Product

 

Instruments

 

2015

 

2014

Natural Gas (1) (MMBtus (2))

 

Forwards and Swaps

 

267,835,872

 

308,130,101

 

 

Options

 

125,392,380

 

164,418,002

Electricity (Megawatt-hours)

 

Forwards and Swaps

 

4,904,985

 

5,346,787

 

 

Congestion Revenue Rights (3)

 

197,344,663

 

224,124,341

 

 

 

 

 

 

 

(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 June 30, 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

$

70 

 

$

(4)

 

$

15 

 

$

81 

Other noncurrent assets – other

 

156 

 

 

(5)

 

 

- 

 

 

151 

Current liabilities – other

 

(70)

 

 

4 

 

 

23 

 

 

(43)

Noncurrent liabilities – other

 

(147)

 

 

5 

 

 

19 

 

 

(123)

Net commodity risk

$

9 

 

$

- 

 

$

57 

 

$

66 

 


At December 31, 2014, 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

$

73 

 

$

(4)

 

$

19 

 

$

88 

Other noncurrent assets – other

 

178 

 

 

(13)

 

 

- 

 

 

165 

Current liabilities – other

 

(78)

 

 

4 

 

 

26 

 

 

(48)

Noncurrent liabilities – other

 

(140)

 

 

13 

 

 

9 

 

 

(118)

Net commodity risk

$

33 

 

$

- 

 

$

54 

 

$

87 

 

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

 

 

Commodity Risk

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

(in millions)

2015

 

2014

 

2015

 

2014

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

$

28 

 

$ 

27 

 

$

(24)

 

$

85 

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

 

10 

 

 

(8)

 

 

3 

 

 

(26)

Realized loss - cost of natural gas (2)

 

(4)

 

 

(3)

 

 

(5)

 

 

(3)

Net commodity risk

$

34 

 

$ 

16 

 

$

(26)

 

$

56 

 

 

 

 

 

 

 

 

 

 

 

 

(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 June 30, 2015, 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

 

June 30,

 

December 31,

(in millions)

2015

 

2014

Derivatives in a liability position with credit risk-related

 

 

 

 

 

contingencies that are not fully collateralized

$

(2)

 

$

(47)

Collateral posting in the normal course of business related to

 

 

 

 

 

these derivatives

 

- 

 

 

44 

Net position of derivative contracts/additional collateral

 

 

 

 

 

posting requirements (1)

$

(2)

 

$

(3)

 

 

 

 

 

 

(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 and other investments are held by PG&E Corporation and not the Utility):

 

 

Fair Value Measurements

 

At June 30, 2015

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market investments

$

109 

 

$

- 

 

$

- 

 

$

- 

 

$

109 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

 

32 

 

 

- 

 

 

- 

 

 

- 

 

 

32 

  Global equity securities

 

1,587 

 

 

13 

 

 

- 

 

 

- 

 

 

1,600 

  Fixed-income securities

 

681 

 

 

541 

 

 

- 

 

 

- 

 

 

1,222 

Total nuclear decommissioning trusts (2)

 

2,300 

 

 

554 

 

 

- 

 

 

- 

 

 

2,854 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Electricity

 

1 

 

 

8 

 

 

212 

 

 

6 

 

 

227 

  Gas

 

1 

 

 

4 

 

 

- 

 

 

- 

 

 

5 

Total price risk management instruments

 

2 

 

 

12 

 

 

212 

 

 

6 

 

 

232 

Rabbi trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Fixed-income securities

 

- 

 

 

42 

 

 

- 

 

 

- 

 

 

42 

  Life insurance contracts

 

- 

 

 

72 

 

 

- 

 

 

- 

 

 

72 

Total rabbi trusts

 

- 

 

 

114 

 

 

- 

 

 

- 

 

 

114 

Long-term disability trust

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

 

4 

 

 

- 

 

 

- 

 

 

- 

 

 

4 

  Global equity securities

 

- 

 

 

22 

 

 

- 

 

 

- 

 

 

22 

  Fixed-income securities

 

- 

 

 

117 

 

 

- 

 

 

- 

 

 

117 

Total long-term disability trust

 

4 

 

 

139 

 

 

- 

 

 

- 

 

 

143 

Total assets

$

2,415 

 

$

819 

 

$

212 

 

$

6 

 

$

3,452 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 7)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Electricity

$

47 

 

$

4 

 

$

164 

 

$

(51)

 

$

164 

  Gas

 

- 

 

 

2 

 

 

- 

 

 

- 

 

 

2 

Total liabilities

$

47 

 

$

6 

 

$

164 

 

$

(51)

 

$

166 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

(2) Represents amount before deducting $350 million, primarily related to deferred taxes on appreciation of investment value.

 


 

Fair Value Measurements

 

At December 31, 2014

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Money market investments

$

94 

 

$

- 

 

$

- 

 

$

- 

 

$

94 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

 

17 

 

 

- 

 

 

- 

 

 

- 

 

 

17 

  Global equity securities

 

1,585 

 

 

13 

 

 

- 

 

 

- 

 

 

1,598 

  Fixed-income securities

 

741 

 

 

389 

 

 

- 

 

 

- 

 

 

1,130 

Total nuclear decommissioning trusts (2)

 

2,343 

 

 

402 

 

 

- 

 

 

- 

 

 

2,745 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 9 in the 2014 Form 10-K)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Electricity

 

- 

 

 

17 

 

 

232 

 

 

2 

 

 

251 

  Gas

 

1 

 

 

1 

 

 

- 

 

 

- 

 

 

2 

Total price risk management instruments

 

1 

 

 

18 

 

 

232 

 

 

2 

 

 

253 

Rabbi trusts

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Fixed-income securities

 

- 

 

 

42 

 

 

- 

 

 

- 

 

 

42 

  Life insurance contracts

 

- 

 

 

72 

 

 

- 

 

 

- 

 

 

72 

Total rabbi trusts

 

- 

 

 

114 

 

 

- 

 

 

- 

 

 

114 

Long-term disability trust

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

 

7 

 

 

- 

 

 

- 

 

 

- 

 

 

7 

  Global equity securities

 

- 

 

 

25 

 

 

- 

 

 

- 

 

 

25 

  Fixed-income securities

 

- 

 

 

128 

 

 

- 

 

 

- 

 

 

128 

Total long-term disability trust

 

7 

 

 

153 

 

 

- 

 

 

- 

 

 

160 

Other investments

 

33 

 

 

- 

 

 

- 

 

 

- 

 

 

33 

Total assets

$

2,478 

 

$

687 

 

$

232 

 

$

2 

 

$

3,399 

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Price risk management instruments

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Note 9 in the 2014 Form 10-K)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Electricity

$

47 

 

$

5 

 

$

163 

 

$

(52)

 

$

163 

  Gas

 

- 

 

 

3 

 

 

- 

 

 

- 

 

 

3 

Total liabilities

$

47 

 

$

8 

 

$

163 

 

$

(52)

 

$

166 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

(2) Represents amount before deducting $324 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.  Investments, primarily consisting of equity securities, that are valued using a net asset value per share can be redeemed quarterly with notice not to exceed 90 days.  Equity investments valued at net asset value per share utilize investment strategies aimed at matching the performance of indexed funds.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the six months ended June 30, 2015 and 2014.

 


Trust Assets

 

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity securities, debt securities, and life insurance policies.  In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

 

Equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.  Equity securities also include commingled funds that are composed of equity securities traded publicly on exchanges across multiple industry sectors in the U.S. and other regions of the world.  Investments in these funds are classified as Level 2 because price quotes are readily observable and available.

 

Debt 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.

 

Price Risk Management Instruments

 

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, swaps, options, and CRRs that are traded either on an exchange or over-the-counter. 

 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded forwards and swaps that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded forwards and swaps, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2. 

 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

 

The Utility holds CRRs to hedge the financial risk of California Independent System Operator-imposed congestion charges in the day-ahead market.  CRRs are classified as Level 3 and are valued based on CRR auction prices, including historical prices.  Limited market data is available in the California Independent System Operator auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions. 

 

Level 3 Measurements and Sensitivity Analysis

 

The Utility’s market and credit risk management function, which reports to the Chief Risk 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 June 30, 2015

 

Valuation

 

Unobservable

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Technique

 

Input

 

Range (1)

Congestion revenue rights

 

$

212 

 

$ 

62 

 

Market approach

 

CRR auction prices

 

$

(47.09) - 8.17

Power purchase agreements

 

$

- 

 

$ 

102 

 

Discounted cash flow

 

Forward prices

 

$

22.04 - 57.00 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Represents price per megawatt-hour

 

 

 

Fair Value at

 

 

 

 

 

 

 

(in millions)

 

At December 31, 2014

 

Valuation

 

Unobservable

 

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

Technique

 

Input

 

Range (1)

Congestion revenue rights

 

$

232 

 

$

63 

 

Market approach

 

CRR auction prices

 

$

(15.97) - 8.17

Power purchase agreements

 

$

- 

 

$

100 

 

Discounted cash flow

 

Forward prices

 

$

16.04 - 56.21 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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 six months ended June 30, 2015 and 2014:

 

 

Price Risk Management Instruments

(in millions)

2015

 

2014

Asset (liability) balance as of April 1

$

42 

 

$

(22)

Net realized and unrealized gains:

 

 

 

 

 

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

 

6 

 

 

11 

Asset (liability) balance as of June 30

$

48 

 

$

(11)

 

 

 

 

 

 

(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

 

 

Price Risk Management Instruments

(in millions)

2015

 

2014

Asset (liability) balance as of January 1

$

69 

 

$

(30)

Net realized and unrealized gains:

 

 

 

 

 

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

 

(21)

 

 

19 

Asset (liability) balance as of June 30

$

48 

 

$

(11)

 

 

 

 

 

 

(1) The costs related to price risk management activities are recoverable through customer rates, therefore, balancing account revenue is recorded for amounts settled and purchased and there is no impact to net income. Unrealized gains and losses are deferred in regulatory liabilities and assets.

 

Financial Instruments

 

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments:

 

  • The fair values of cash, restricted cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, floating rate senior notes, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at June 30, 2015 and December 31, 2014, 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 June 30, 2015 and December 31, 2014

 


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 June 30, 2015

 

At December 31, 2014

(in millions)

Carrying Amount

 

Level 2 Fair Value

 

Carrying Amount

 

Level 2 Fair Value

PG&E Corporation

$

350 

 

$

351 

 

$

350 

 

$

352 

Utility

 

14,272 

 

 

15,715 

 

 

13,778 

 

 

15,851 

 

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 June 30, 2015

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

$

32 

 

$

- 

 

$

- 

 

$

32 

  Global Equity securities

 

516 

 

 

1,091 

 

 

(7)

 

 

1,600 

  Fixed Income securities

 

1,169 

 

 

60 

 

 

(7)

 

 

1,222 

Total (1)

$

1,717 

 

$

1,151 

 

$

(14)

 

$

2,854 

As of December 31, 2014

 

 

 

 

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

 

 

  Money market investments

$

17 

 

$

- 

 

$

- 

 

$

17 

  Global Equity securities

 

520 

 

 

1,087 

 

 

(9)

 

 

1,598 

  Fixed-income securities

 

1,059 

 

 

75 

 

 

(4)

 

 

1,130 

Total nuclear decommissioning trusts (1)

 

1,596 

 

 

1,162 

 

 

(13)

 

 

2,745 

Other investments

 

5 

 

 

28 

 

 

- 

 

 

33 

Total

$

1,601 

 

$

1,190 

 

$

(13)

 

$

2,778 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Represents amounts before deducting $350 million and $324 million at June 30, 2015 and December 31, 2014, respectively, primarily related to deferred taxes on appreciation of investment value.

 

The fair value of debt securities by contractual maturity is as follows:

 

 

As of

(in millions)

June 30, 2015

Less than 1 year

$

19 

1–5 years

 

458 

5–10 years

 

277 

More than 10 years

 

468 

Total maturities of debt securities

$

1,222 

 


The following table provides a summary of activity for the debt and equity securities:

 

 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

2015

 

2014

 

 

2015

 

2014

(in millions)

 

 

 

 

 

 

 

 

 

 

 

Proceeds from sales and maturities of nuclear decommissioning 

 

 

 

 

 

 

 

 

 

 

 

trust investments

$

362 

 

$

347 

 

$

779 

 

$

877 

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

 

12 

 

 

28 

 

 

47 

 

 

84 

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

 

(10)

 

 

(2)

 

 

(13)

 

 

(3)

 

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.  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 also may be affected by the outcome of the following matters.

 

Enforcement and Litigation Matters

 

Improper CPUC Communications 

 

In the Penalty Decision (further described below), the CPUC stated that it will begin a new investigation to examine allegations by the City of San Bruno that communications between the Utility’s employees and CPUC personnel violated the CPUC’s rules relating to ex parte communications.  Ex parte communications include any communication between a decision maker and an interested person concerning substantive issues in certain identified categories of formal proceedings before the CPUC.  The Utility believes that the communications cited by San Bruno are not prohibited ex parte communications.  If the CPUC determines that the communications constitute ex parte violations, it is reasonably possible that the CPUC will impose penalties or other remedies, but the Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.

 

In September 2014, the Utility notified the CPUC of ex parte communications between the Utility and the CPUC regarding the 2015 GT&S rate case.  In November 2014, the CPUC imposed a fine of $1.05 million on the Utility for these communications.  In addition, the CPUC disallowed the Utility from recovering  up to the entire amount of the revenue increase that may be authorized in the pending GT&S rate case and that otherwise would have been collected from ratepayers over a five-month period.  The CPUC will determine the amount of this disallowance when it issues its decision to authorize the Utility’s GT&S revenue requirements.

 

In October and December 2014, the Utility also notified the CPUC of additional email communications between the Utility and the CPUC regarding various matters (not limited to the GT&S rate case) that the Utility believes may constitute or describe ex parte communications.  For these additional communications, the Utility believes it is probable that CPUC enforcement action will be taken.  The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining the final penalties.

 

On May 21, 2015, the Utility filed various documents (including copies of internal email correspondence) with the CPUC to complete its response to orders issued by CPUC administrative law judges regarding potential ex parte communications between the Utility and CPUC personnel. The Utility also notified the CPUC of an additional potential ex parte communication made in the 2011 General Rate Case to supplement a notification that the Utility voluntarily provided on October 6, 2014. It is uncertain what action the CPUC or other parties will take in response to these additional reported communications. It is possible that additional orders will be issued to which the Utility will be required to respond. The CPUC could impose fines and penalties on the Utility relating to communications reported to the CPUC or with respect to additional communications that the Utility may identify and report in response to new orders that may be issued or in connection with new or ongoing investigations or legal proceedings.

 

The U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have also begun investigations in connection with the ex parte communications.  The Utility is cooperating with the federal and state investigators.  It is uncertain whether any charges will be brought against the Utility.  


Other CPUC Matters

 

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 for its natural gas distribution service and facilities.  The order also requires 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 cites 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 April 10, 2015, the assigned Commissioner issued a scoping memo and ruling stating that the scope of the proceeding is whether or not the Utility violated any applicable laws, rules, or regulations “by its record-keeping policies and practices with respect to maintaining safe operation of its gas distribution system.”  The scope of the proceeding also may include matters resulting from the SED’s ongoing reviews of the Utility’s record-keeping practices relating to mapping, pre-excavation location and marking, and pressure validation for distribution facilities, among other issues.

 

The procedural schedule requires the SED’s and intervenors’ testimony to be submitted starting in September 2015 with the Utility’s response due in November 2015, followed by rebuttal testimony in December 2015.  Hearings are scheduled for January 2016.

 

PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose penalties on the Utility or require the Utility to implement operational remedies. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties and given the fact that the extent of any alleged violations is currently unknown. In addition, the Utility could incur material costs to implement operational remedies, which may not be recoverable.

 

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 has been completed and that remediation work, including removal of the encroachments, is 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 or take other enforcement action 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.  In addition, the California utilities are required to inform the SED of self-identified or self-corrected violations.  The SED has authority to issue citations and impose fines for violations identified through audits, investigations, or self-reports.  The SED can consider various factors in determining whether to impose fines and the amount of fines, including the severity of the safety risk associated with each violation, the number and duration of the violations, whether the violation was self-reported, and whether corrective actions were taken.

 

The SED has imposed fines on the Utility ranging from $50,000 to $16.8 million for violations of 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 natural gas 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.

 


Federal Matters

 

Federal Criminal Indictment

 

On July 29, 2014, a federal grand jury for the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court that succeeded the original indictment that was returned on April 1, 2014.  The superseding indictment charges 27 felony counts alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to recordkeeping, pipeline integrity management, and identification of pipeline threats.  The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident.  The maximum statutory fine for each felony count is $500,000, for total fines of $14 million.  The superseding indictment also seeks an alternative fine under the Alternative Fines Act which 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.”  Based on the superseding indictment’s allegations that the Utility derived gross gains of approximately $281 million and that the victims suffered losses of approximately $565 million, the maximum alternative fine would be approximately $1.13 billion. 

 

The Utility entered a plea of not guilty.  The Utility believes that criminal charges and the alternative fine allegations are not merited and that it did not knowingly and willfully violate minimum safety standards under the Natural Gas Pipeline Safety Act or obstruct the NTSB’s investigation, as alleged in the superseding indictment.  PG&E Corporation and the Utility have not accrued any charges for criminal fines in their Condensed Consolidated Financial Statements as such amounts are not considered to be probable.  The trial is set to begin March 8, 2016.

 

Other Federal Matters

 

The Utility was informed that the U.S. Attorney’s Office was investigating a natural gas explosion that occurred in Carmel, California on March 3, 2014.  (For more information refer to Note 14 of the Notes to the Consolidated Financial Statements appearing under Item 8 in the 2014 Form 10-K).  It is uncertain whether any charges will be brought against the Utility. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case.

 

Capital Expenditures relating to Pipeline Safety Enhancement Plan

 

At June 30, 2015, approximately $645 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Condensed Consolidated Balance Sheets.  The Utility would be required to record charges to the statement of income in future periods to the extent PSEP-related capital costs are higher than currently expected.

 

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

 

The Penalty Decision (see Note 1 above) imposes penalties on the Utility totaling $1.6 billion comprised of: (1) a $300 million fine to be paid to the State General Fund, (2) a one-time $400 million bill credit to the Utility’s natural gas customers, (3) $850 million to fund future pipeline safety projects and programs, and (4) remedial measures that the CPUC estimates will cost the Utility at least $50 million.

 

For the three months and six months ended June 30, 2015, the Utility recorded additional charges of $75 million and $628 million, respectively, as a result of the Penalty Decision. The cumulative charges at June 30, 2015, and the anticipated future financial impact are shown in the following table:

 


 

 

 

 

 

 

 

Anticipated

 

 

 

 

Six Months

 

Cumulative

 

Future

 

 

 

Ended

 

Charges

 

Financial

 

Total

(in millions)

June 30, 2015

 

June 30, 2015

 

Impact

 

Amount

Fine payable to the state (1)

$

100

 

$

300

 

$

- 

 

$

300

Customer bill credit

 

400

 

 

400

 

 

- 

 

 

400

Charge for disallowed capital (2)

 

128

 

 

128

 

 

561

 

 

689

Disallowed revenue for pipeline safety

 

 

 

 

 

 

 

 

 

 

 

  expenses (3)

 

- 

 

 

- 

 

 

161

 

 

161

CPUC estimated cost of other remedies (4)

 

- 

 

 

20

 

 

30

 

 

50

Total Penalty Decision fines and remedies

 

 

 

 

 

 

 

 

 

 

 

  recorded

$

628

 

$

848

 

$

752

 

$

1,600

 

 

 

 

 

 

 

 

 

 

 

 

(1)In March 2015, the Utility increased its accrual from $200 million at December 31, 2014 to $300 million.

(2)The Penalty Decision prohibits the Utility from recovering certain expenses and capital spending associated with pipeline safety-related projects and programs that the CPUC will identify in the final decision to be issued in the Utility’s 2015 GT&S rate case. The Utility estimates that approximately $75 million and $128 million of capital spending (which include less than $1 million for remedy related capital costs)in the three months and six months ended June 30, 2015, respectively, are probable of disallowance, subject to adjustment based on the final 2015 GT&S rate case decision.

(3)These costs are being expensed as incurred. Future GT&S revenues will be reduced for these unrecovered expenses.

(4)In the Penalty Decision, the CPUC estimates that the Utility would incur $50 million to comply with the other remedies in the Penalty Decision, including $30 million to reimburse the CPUC for the costs of future audits.  Remedial costs are expensed as incurred.  Other than the refund of CPUC audit costs, the majority of the remedies have been completed or are underway and the associated costs have already been incurred.

 

At June 30, 2015, the Condensed Consolidated Balance Sheets include $300 million in other current liabilities for the fines payable, and $400 million in current regulatory liabilities for the one-time bill credit due to the Utility’s natural gas customers.  The charges recorded are reflected in operating and maintenance expenses in the June 30, 2015, Condensed Consolidated Statements of Income. 

 

The Penalty Decision requires that at least $688.5 million of the $850 million be allocated to capital expenditures and that the Utility be precluded from including these capital costs in rate base.  The remainder will be allocated to safety-related expenses.  The CPUC will determine which safety projects and programs will be funded by shareholders in the Utility’s pending 2015 GT&S rate case.  If the $850 million is not exhausted by designated safety-related projects and programs in the GT&S proceeding, the CPUC will identify additional projects in future proceedings to ensure that the full $850 million is spent. It is uncertain what costs the CPUC will ultimately count towards the $850 million shareholder-funded obligation.  To the extent the Utility’s actual costs exceed qualified amounts and are not authorized for recovery, the Utility may be required to record additional charges in future periods. The CPUC is expected to issue a final decision in the Utility’s 2015 GT&S rate case in 2016 to identify the safety-related project and programs that will be subject to the disallowance.

 

Other Legal and Regulatory Contingencies

 

Accruals for other legal and regulatory contingencies (excluding amounts related to the enforcement and litigation matters described above) totaled $43 million at June 30, 2015, and $55 million at December 31, 2014.  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. 

 


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

(in millions)

June 30, 2015

 

December 31, 2014

Topock natural gas compressor station (1)

$

297 

 

$ 

291 

Hinkley natural gas compressor station (1)

 

149 

 

 

158 

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

 

263 

 

 

257 

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

  other facilities, and third-party disposal sites

 

153 

 

 

150 

Fossil fuel-fired generation facilities and sites

 

96 

 

 

98 

Total environmental remediation liability

$

958 

 

$ 

954 

 

 

 

 

 

 

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

 

At June 30, 2015, the Utility expected to recover $676 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC.  The Utility will also incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.

 

Natural Gas Compressor Station Sites

 

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations.  One of these stations is located near 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 is also 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 overseen by the Regional Board.  In January 2015, the Regional Board issued an updated draft clean-up and abatement order that proposes the Utility continues and improves its remedial treatment methods and contains a proposed monitoring and reporting program.  The Regional Board is expected to issue a revised draft clean-up and abatement order in August 2015.  After a public comment period, the Regional Board is expected to consider adoption of a final clean-up and abatement order (which may include deadlines to meet specified interim clean up targets) at its November 2015 meeting.

 

The Utility’s environmental remediation liability at June 30, 2015 reflects the Utility’s best estimate of probable future costs associated with its final remediation plan and interim remediation measures.  Future costs will depend on many factors, including the levels of hexavalent chromium the Utility is required to use as the standard for remediation, the required time period by which those standards must be met, and the nature and extent of the chromium contamination.  Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition, results of operations, and cash flows. 

 

Topock Site

 

The Utility's remediation and abatement efforts at the Topock site are overseen by the DTSC and the U.S. Department of the Interior.  While the Utility has been working with these agencies to develop a final remediation plan, the Utility has been employing various interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of the chromium plume toward the Colorado River.  In September 2014, the Utility submitted its near-final remediation plan to the agencies for approval.  The Utility’s plan 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 plan, and the Utility anticipates that the DTSC’s draft environmental impact report will be issued for public comment in July 2016.  After the DTSC considers public comments that may be made, the DTSC is expected to issue a final environmental impact report in December 2016.  After the Utility modifies its plan in response to the final report, the Utility plans to seek approval to begin construction of the new in-situ treatment system in early 2017.

 


The Utility's environmental remediation liability at June 30, 2015 reflects its best estimate of probable future costs associated with its final remediation plan.  Future costs will depend on many factors, including the scope and timing of required remediation work.  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.

 

Reasonably Possible Environmental Contingencies

 

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, the Utility’s undiscounted future costs could increase to as much as $1.8 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 during the period in which they are recorded.

 

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. 

 

At December 31, 2014, the Consolidated Balance Sheets reflected $434 million in net claims, within Disputed claims and customer refunds, and $291 million of cash in escrow for payment of the remaining net disputed claims, within Restricted cash.  There were no significant changes to these balances during the six months ended June 30, 2015.

 

Tax Matters

 

The IRS is currently reviewing several matters in the 2011, 2012, and 2013 tax returns.  The most significant relates to a 2011 accounting method change to adopt guidance issued by the IRS in determining which repair costs are deductible for the electric transmission and distribution businesses.  PG&E Corporation and the Utility expect that the IRS will complete its review of the deductible repair costs for the electric transmission and distribution businesses in 2015.  The IRS is also expected to issue guidance during 2015 that determines which repair costs are deductible for the natural gas transmission and distribution businesses.  PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months depending on the IRS guidance that is issued and the resolution of the audits related to the 2011, 2012, and 2013 tax returns.  As of June 30, 2015, it is reasonably possible that unrecognized tax benefits will decrease by approximately $370 million within the next 12 months, and most of this decrease would not impact net income.

 

There were no other significant developments to tax matters during the six months ended June 30, 2015.  (Refer to Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.) 

 

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, 2014 the Utility had undiscounted future expected obligations of approximately $53.3 billion.  (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)  During the six months ended June 30, 2015, the Utility entered into several renewable energy and other power purchase agreements that were approved by the CPUC and completed major milestones with respect to construction, resulting in additional commitments of approximately $465 million over the next 25 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 operating in 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 and 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 also is subject 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 2014 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.  PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short- and long-term operating plans, and employee incentive compensation. PG&E Corporation believes that earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance.  Earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.

 


 

Three Months Ended

 

Six Months Ended

 

June 30,

 

June 30,

 

 

 

 

EPS

 

 

 

 

EPS

(in millions, except per share amounts)

Earnings

 

(Diluted)

 

Earnings

 

(Diluted)

Income Available for Common Shareholders - 2014

$

267 

 

$

0.57 

 

$

494 

 

$

1.06 

Natural gas matters (1)

 

57 

 

 

0.12 

 

 

81 

 

 

0.18 

Earnings from Operations - 2014 (2)

$

324 

 

$

0.69 

 

$

575 

 

$

1.24 

2014 GRC cost recovery (3)

 

99 

 

 

0.21 

 

 

198 

 

 

0.41 

Growth in rate base earnings

 

26 

 

 

0.05 

 

 

52 

 

 

0.11 

Nuclear refueling outage

 

- 

 

 

- 

 

 

26 

 

 

0.05 

Timing of taxes (4)

 

18 

 

 

0.04 

 

 

38 

 

 

0.08 

Gain on disposition of SolarCity stock (5)

 

(14)

 

 

(0.03)

 

 

- 

 

 

- 

Timing of 2015 GT&S cost recovery (6)

 

(44)

 

 

(0.09)

 

 

(80)

 

 

(0.17)

Increase in shares outstanding

 

- 

 

 

(0.02)

 

 

- 

 

 

(0.05)

Other

 

33 

 

 

0.06 

 

 

51 

 

 

0.11 

Earnings from Operations - 2015 (2)

$

442 

 

$

0.91 

 

$

860 

 

$

1.78 

Pipeline-related expenses (7)

 

(9)

 

 

(0.02)

 

 

(19)

 

 

(0.04)

Legal and regulatory related expenses (7)

 

(10)

 

 

(0.02)

 

 

(18)

 

 

(0.04)

Fines and penalties (8)

 

(44)

 

 

(0.09)

 

 

(413)

 

 

(0.85)

Insurance recoveries (9)

 

23 

 

 

0.05 

 

 

23 

 

 

0.05 

Income Available for Common Shareholders - 2015

$

402 

 

$

0.83 

 

$

433 

 

$

0.90 

 

 

 

 

 

 

 

 

 

 

 

 

(1) In 2014, natural gas matters included pipeline-related costs to perform work under the PSEP and other activities associated with safety improvements to the Utility's natural gas system, as well as legal

    and other costs related to natural gas matters.  Natural gas matters also included charges recorded related to fines, third party liability claims, and insurance recoveries in 2014.


(2) "Earnings from operations" is not calculated in accordance with GAAP and excludes the items impacting comparability shown in Note (1) above and Notes (6), (7), and (8) below.

(3) Represents the increase in base revenues authorized by the CPUC in the 2014 GRC decision for the three and six months ended June 30, 2015, including the impact of flow-through ratemaking treatment for federal tax deductions for repairs.  In 2014, the Utility was incurring approximately $200 million of expense and $1 billion of capital costs above authorized levels until the 2014 GRC decision authorized revenues that supported this higher level of spending.  The increase in revenue related to 2014 was not recognized until the quarter ended September 30, 2014, when the 2014 GRC decision was issued.

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

(5) Represents the comparative negative impact of a gain recognized during the three months ended June 30, 2014 as compared to the three months ended June 30, 2015 during which no comparable gain was recognized.  For the six months ended June 30, 2015, this comparative negative impact was offset by a gain recognized during the three months ended March 31, 2015.

(6) Represents expenses reflected in Earnings from Operations during the three and six months ended June 30, 2015 as compared to the same periods in 2014, with no corresponding increase in revenue.  The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case.  Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.

(7) In 2015, pipeline-related expenses includes costs incurred to identify and remove encroachments from transmission pipeline rights of way and to perform remaining work under the Utility's PSEP.  Legal and regulatory related expenses includes various enforcement, regulatory, and litigation activities regarding natural gas matters and regulatory communications.

(8) Represents the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements for before-tax amounts).

(9) Insurance recoveries related to third-party claims and associated legal costs recognized in the three and six months ended June 30, 2015 (See "Results of Operations" below).

 


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: 

 

Penalties, Fines and Remedial Costs. Future financial results will be impacted by the timing and amount of disallowed costs the Utility incurs for designated pipeline safety-related projects and programs and to implement remedial measures, as required by the Penalty Decision.  The Utility also could be required to pay fines associated with pending federal criminal charges alleging that the Utility knowingly and willfully violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation into the cause of the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010.  Based on the superseding indictment’s allegations, the maximum statutory fine would be $14 million and the maximum alternative fine would be approximately $1.13 billion.  Federal and state authorities also are conducting investigations in connection with certain communications between the Utility and CPUC personnel.  The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case.  Fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to these and other enforcement matters, including new CPUC investigations.  (See “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements.)

 

 

The Timing and Outcome of Ratemaking Proceedings.  In the GT&S rate case, the Utility has requested that the CPUC authorize revenue requirements for the Utility’s gas transmission and storage operations from 2015 through 2017.  The Utility has requested an increase in its 2015 revenue requirements of $555 million over the comparable authorized revenues, as well as increases for 2016 and 2017.  Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC is expected to issue a two-part decision, the first decision to authorize GT&S revenue requirements (which would reflect a potential disallowance to be imposed as a penalty for the Utility’s violation of the CPUC’s ex parte communication rules as well as a reduction in the Utility's request to reflect any costs associated with implementing the remedies ordered by the Penalty Decision), and a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision.  Any revenue requirement increase would be retroactive to January 1, 2015. Based on the procedural schedule it is unlikely that the Utility will be able to recognize any increase in GT&S revenues in 2015. If the Utility does not recognize any increase in 2015, the authorized revenue increase would be recorded in 2016.  (See “Ratemaking Proceedings” below for more information.)  In addition, the Utility intends to file its 2017 GRC application with the CPUC by September 2015, to request that the CPUC authorize revenue requirements for the Utility’s electric generation business and its electric and natural gas distribution business for 2017 and future years.  The outcome of ratemaking 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 Operating Costs and Capital Expenditures.  Whether the Utility is able to earn its authorized rate of return could be materially affected if the Utility’s actual costs differ from the amounts that have been authorized in the final 2014 GRC decision and that may be authorized in the 2015 GT&S rate case and future rate case decisions.  In addition to incurring shareholder-funded costs and costs associated with remedial measures required by the Penalty Decision, the Utility forecasts that in 2015 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.  Actual costs could be higher.  The ultimate amount of unrecovered costs also could be affected by how the CPUC determines which costs are included in determining whether the $850 million shareholder-funded obligation under the Penalty Decision has been met, and the outcome of pending and future investigations and enforcement matters.  (See “Enforcement and Litigation Matters” below.) The Utility’s ability to recover costs in the future also could be affected by decreases in customer demand driven by legislative and regulatory initiatives relating to distributed generation resources, renewable energy requirements, and changes in the electric rate structure.

 

 


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 six months ended June 30, 2015, PG&E Corporation issued $252 million of common stock and made equity contributions to the Utility of $185 million.  PG&E Corporation forecasts that it will continue issuing a material amount of equity to support the Utility’s capital expenditures and to fund unrecovered pipeline-related costs (including costs incurred under the Penalty Decision) and to pay the fine imposed by the Penalty Decision and additional fines and penaltiesthat may be required by the final outcomes of ongoing enforcement matters.  These equity issuances would have a further material dilutive effect on PG&E Corporation’s EPS.  PG&E Corporation’s and the Utility’s ability to access the capital markets and the terms and rates of future financings could be affected by the outcome of the matters discussed in “Enforcement and Litigation Matters” below, 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 2014 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 “Cautionary Language Regarding 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 six months ended June 30, 2015 and 2014:

 

 

Three Months Ended June 30,

 

Six Months Ended June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Consolidated Total

$ 

402 

 

$ 

267 

 

$ 

433 

 

$ 

494 

PG&E Corporation

 

- 

 

 

21 

 

 

30 

 

 

23 

Utility

$ 

402 

 

$ 

246 

 

$ 

403 

 

$ 

471 

 

PG&E Corporation’s net income primarily consists of interest expense on long-term debt, income taxes, and other income from investments.  Results include approximately $30 million and $20 million of realized gains and associated tax benefits related to an investment in SolarCity Corporation recognized in the first quarter of 2015 and second quarter of 2014, respectively.

 

Utility

 

The tables below show certain items from the Utility’s Condensed Consolidated Statements of Income for the three and six months ended June 30, 2015 and 2014.  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 six months ended June 30, 2015 reflect charges associated with the impact of the Penalty Decision.  (See “Utility Revenues and Costs that Impacted Earnings” below.)

 


 

Three Months Ended June 30, 2015

 

Three Months Ended June 30, 2014

 

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

$

1,877 

$

1,585 

$

3,462 

 

$

1,632 

$

1,600 

$

3,232 

Natural gas operating revenues

 

526 

 

228 

 

754 

 

 

454 

 

265 

 

719 

Total operating revenues

 

2,403 

 

1,813 

 

4,216 

 

 

2,086 

 

1,865 

 

3,951 

Cost of electricity

 

- 

 

1,277 

 

1,277 

 

 

- 

 

1,349 

 

1,349 

Cost of natural gas

 

- 

 

118 

 

118 

 

 

- 

 

200 

 

200 

Operating and maintenance

 

1,065 

 

418 

 

1,483 

 

 

1,005 

 

316 

 

1,321 

Depreciation, amortization, and decommissioning

 

651 

 

- 

 

651 

 

 

556 

 

- 

 

556 

Total operating expenses

 

1,716 

 

1,813 

 

3,529 

 

 

1,561 

 

1,865 

 

3,426 

Operating income

 

687 

 

- 

 

687 

 

 

525 

 

- 

 

525 

Interest income (1)

 

 

 

 

 

3 

 

 

 

 

 

 

3 

Interest expense (1)

 

 

 

 

 

(189)

 

 

 

 

 

 

(185)

Other income, net (1)

 

 

 

 

 

20 

 

 

 

 

 

 

17 

Income before income taxes

 

 

 

 

 

521 

 

 

 

 

 

 

360 

Income tax provision (1)

 

 

 

 

 

115 

 

 

 

 

 

 

110 

Net income

 

 

 

 

 

406 

 

 

 

 

 

 

250 

Preferred stock dividend requirement (1)

 

 

 

 

 

4 

 

 

 

 

 

 

4 

Income Available for Common Stock

 

 

 

 

$

402 

 

 

 

 

 

$

246 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) These items impacted earnings for the three months ended June 30, 2015 and 2014.

 

 

Six Months Ended June 30, 2015

 

Six Months Ended June 30, 2014

 

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

$

3,662 

$

2,814 

$

6,476 

 

$

3,217 

$

3,015 

$

6,232 

Natural gas operating revenues

 

1,031 

 

609 

 

1,640 

 

 

925 

 

684 

 

1,609 

Total operating revenues

 

4,693 

 

3,423 

 

8,116 

 

 

4,142 

 

3,699 

 

7,841 

Cost of electricity

 

- 

 

2,277 

 

2,277 

 

 

- 

 

2,559 

 

2,559 

Cost of natural gas

 

- 

 

392 

 

392 

 

 

- 

 

560 

 

560 

Operating and maintenance

 

2,652 

 

754 

 

3,406 

 

 

2,038 

 

580 

 

2,618 

Depreciation, amortization, and decommissioning

 

1,282 

 

- 

 

1,282 

 

 

1,094 

 

- 

 

1,094 

Total operating expenses

 

3,934 

 

3,423 

 

7,357 

 

 

3,132 

 

3,699 

 

6,831 

Operating income

 

759 

 

- 

 

759 

 

 

1,010 

 

- 

 

1,010 

Interest income (1)

 

 

 

 

 

4 

 

 

 

 

 

 

5 

Interest expense (1)

 

 

 

 

 

(376)

 

 

 

 

 

 

(364)

Other income, net (1)

 

 

 

 

 

46 

 

 

 

 

 

 

37 

Income before income taxes

 

 

 

 

 

433 

 

 

 

 

 

 

688 

Income tax (benefit) provision (1)

 

 

 

 

 

23 

 

 

 

 

 

 

210 

Net income

 

 

 

 

 

410 

 

 

 

 

 

 

478 

Preferred stock dividend requirement (1)

 

 

 

 

 

7 

 

 

 

 

 

 

7 

Income Available for Common Stock

 

 

 

 

$

403 

 

 

 

 

 

$

471 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) These items impacted earnings for the six months ended June 30, 2015 and 2014.

 

Utility Revenues and Costs that Impacted Earnings

 

The following discussion presents the Utility’s operating results for the three and six months ended June 30, 2015 and 2014, focusing on revenues and expenses that impacted earnings for these periods.

 


Operating Revenues

 

The Utility’s electric and natural gas operating revenues that impacted earnings increased by $317 million, or 15%, and by $551 million, or 13%, in the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014The increases reflect approximately $320 million and $585 million of higher base revenues in the three and six months ended June 30, 2015, respectively, as authorized by the CPUC in the 2014 GRC decision and for nuclear decommissioning costs and the FERC in the TO rate case. The increases to base revenues include approximately $115 million and $230 million for the three and six months ended June 30, 2015, respectively, related to 2014 increases that were not recognized until the quarter ended September 30, 2014, as a result of the timing of the GRC decision.  The increases in operating revenues were partially offset by the absence of $35 million and $68 million in the three and six months ended June 30, 2015, respectively, of revenues the CPUC authorized the Utility to collect for recovery of certain PSEP-related costs during the same periods in 2014. 

 

Recovery of PSEP-related costs incurred during 2015 will depend upon the timing and outcome of the GT&S rate case.  The Utility has requested the CPUC authorize an increase to its revenue requirements for 2015, 2016, and 2017 in its GT&S rate case.  Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.  (See “Ratemaking Proceedings” below.)

 

Operating and Maintenance

 

The Utility’s operating and maintenance expenses that impacted earnings increased by $60 million, or 6%, and by $614 million, or 30%, in the three and six months ended June 30, 2015 compared to the same periods in 2014.  The increases for both periods are primarily due to $75 million and $628 million in charges associated with the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements).  The increases were partially offset by $39 million in insurance recoveries related to third-party claims and associated legal costs related to natural gas matters recognized in the three and six months ended June 30, 2015 with no similar activity in 2014.  The Utility has recovered a cumulative total of $505 million through insurance of the $558 million of cumulative charges for these claims.

 

The Utility’s future financial statements will continue to be impacted by additional charges associated with the Penalty Decision 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 $95 million, or 17%, and by $188 million, or 17%, respectively, in the three and six months ended June 30, 2015 compared to the same periods in 2014, primarily due to an increase in depreciation rates as authorized by the CPUC in the 2014 GRC decision and an increase in capital additions.

 

Interest Income, Interest Expense, and Other Income, Net

 

There were no material changes to interest income, interest expense, and other income, net for the periods presented.  

 

Income Tax Provision

 

The Utility’s revenue requirements for the 2014 GRC decision period reflects flow-through ratemaking for income tax expense benefits attributable to the accelerated recognition of repair costs and certain other property-related costs for federal tax purposes. The Utility began to recognize the impact of these income tax expense benefits in the third quarter of 2014 when it received a final GRC decision. The Utility’s financial results reflect a reduction in income tax expense associated with these temporary differences, resulting in a lower effective tax rate.  (See Note 8 of the Notes to the Consolidated Financial Statements in Item 8 of the 2014 Form 10-K.)

 

The income tax provision increased by $5 million, or 5%, and decreased by $187 million, or 89%, in the three and six months ended June 30, 2015 as compared to the same periods in 2014The decrease in the income tax provision in the six months ended June 30, 2015 is primarily due to lower pre-tax income resulting from the impact of the Penalty Decision (see Note 9 of the Notes to the Condensed Consolidated Financial Statements).

 


The following describes the change in the Utility’s effective tax rate for the three and six months ended June 30, 2015 as compared to the same periods in 2014:

 

 

The effective tax rates for the three months ended June 30, 2015 and 2014 were 22% and 31%, respectively.  The decrease in the effective tax rate was primarily due to the effect of the flow-through treatment of property-related costs for federal tax purposes that the Utility began to record in the quarter ended September 30, 2014.

 

 

The effective tax rates for the six months ended June 30, 2015 and 2014 were 5% and 31%, respectively.  The decrease in the effective tax rate was primarily due to the effect of the flow-through treatment of property-related costs for federal tax purposes that the Utility began to record in the quarter ended September 30, 2014 and the impact of the Penalty Decision recorded in 2015 with no comparable amount recorded for the same period in 2014.  Under applicable accounting standards, charges resulting from the Penalty Decision are recorded at the statutory rate in the period incurred.

 

In June 2015, State Bill 681 was introduced and proposes that the Utility be denied applicable state tax deductions for charges associated with the Penalty Decision.  The tax treatment of the costs and resulting financial impact will be affected by the final outcome of this legislation (see “Item 1A. Risk Factors” in Part II below).

 

Utility Revenues and Costs that did not Impact Earnings

 

Cost of Electricity

 

The Utility’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 June 30,

 

Six Months Ended June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Cost of purchased power

$

1,207 

 

$

1,287 

 

$

2,129 

 

$

2,399 

Fuel used in own generation facilities

 

70 

 

 

62 

 

 

148 

 

 

160 

Total cost of electricity

$

1,277 

 

$

1,349 

 

$

2,277 

 

$

2,559 

Average cost of purchased power per kWh (1)

$

0.103 

 

$

0.097 

 

$

0.101 

 

$

0.093 

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

 

11,747 

 

 

13,320 

 

 

21,038 

 

 

25,788 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Average cost of purchased power for the three and six months ended June 30, 2015 increased compared to the same periods in 2014 primarily due to a higher volume of renewables.  This increase was partially offset by lower market prices for natural gas. 

(2)The decrease in purchased power resulted from an increase at the Utility’s own generation facilities.  This increased generation reflects increases in gas-fired generation in both the three and six months ended June 30, 2015 and nuclear generation at Diablo Canyon during the six months ended June 30, 2015 as compared to the same periods in 2014.

 

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

 

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 storage and transportation, and changes in customer demand.  The Utility expects the cost of natural gas for 2015 will continue to be lower due to lower market prices.

 


 

Three Months Ended June 30,

 

Six Months Ended June 30,

(in millions)

2015

 

2014

 

2015

 

2014

Cost of natural gas sold

$

83 

 

$

165 

 

$

317 

 

$

489 

Transportation cost of natural gas sold

 

35 

 

 

35 

 

 

75 

 

 

71 

Total cost of natural gas

$

118 

 

$

200 

 

$

392 

 

$

560 

Average cost per Mcf (1) of natural gas sold

$

2.18 

 

$

4.34 

 

$

2.88 

 

$

4.22 

Total natural gas sold (in millions of Mcf)

 

38 

 

 

38 

 

 

110 

 

 

116 

 

 

 

 

 

 

 

 

 

 

 

 

(1) One thousand cubic feet

 

 

 

 

 

 

 

 

 

 

 

 

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 to 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 debt financing costs. 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 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 borrowings and repayments under its revolving credit facility.  PG&E Corporation relies on short-term debt, including commercial paper, to fund temporary financing needs.   

 

PG&E Corporation forecasts that it will issue between $700 million and $800 million in common stock during 2015 primarily to fund equity contributions to the Utility.  The Utility’s equity needs will continue to be affected by unrecovered pipeline-related costs (including costs incurred to comply with the Penalty Decision) and to pay fines imposed by the Penalty Decision and additional fines and penalties 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 made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code.  (See “Resolution of Remaining Chapter 11 Disputed Claims” in Note 9 of the Notes to the Condensed Consolidated Financial Statements).  The Utility is uncertain when and how the remaining disputed claims will be resolved.

 

Financial Resources

 

Debt and Equity Financings

 

In February 2015, PG&E Corporation entered into a new equity distribution agreement providing for the sale of PG&E Corporation common stock having an aggregate gross sales price of up to $500 million.  In the first quarter of 2015, PG&E Corporation sold 1.4 million shares under this agreement for cash proceeds of $74 million, net of commissions paid of $1 million.  No shares were sold during the three months ended June 30, 2015

 

In addition, PG&E Corporation 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 six months ended June 30, 2015, 4.3 million shares were issued for cash proceeds of $178 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 six months ended June 30, 2015, PG&E Corporation made equity contributions to the Utility of $185 million.  Additionally, PG&E Corporation and the Utility expect to continue to issue long-term and short-term debt for general corporate purposes and to maintain the CPUC-authorized capital structure during 2015.

 

In June 2015, the Utility issued $400 million principal amount of 3.50% Senior Notes due June 15, 2025 and $100 million of 4.30% Senior Notes due March 15, 2045.  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

 

On April 27, 2015, PG&E Corporation and the Utility amended and restated their respective $300 million and $3.0 billion revolving credit facilities that were entered into on April 1, 2013.  At June 30, 2015, PG&E Corporation and the Utility had $295 million and $2.0 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 and “Item 5. Other Information”)

 

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.  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, these revolving credit facilities include usual and customary provisions regarding events of default and covenants limiting liens, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes.  At June 30, 2015, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.

 

Dividends

 

In June 2015, the Board of Directors of PG&E Corporation declared quarterly dividends of $0.455 per share, totaling $219 million, of which approximately $214 million was paid on July 15, 2015 to shareholders of record on June 30, 2015.  

 

In June 2015, the Board of Directors of the Utility declared a common stock dividend of $179 million that was paid to PG&E Corporation on June 17, 2015.

 

In June 2015, the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable on August 15, 2015, to shareholders of record on July 31, 2015.

 

Utility Cash Flows

 

The Utility’s cash flows were as follows:

 

 

Six Months Ended June 30,

(in millions)

2015

 

2014

Net cash provided by operating activities

$

1,860 

 

$

1,261 

Net cash used in investing activities

 

(2,486)

 

 

(2,297)

Net cash provided by financing activities

 

719 

 

 

1,041 

Net change in cash and cash equivalents

$

93 

 

$

5 

 

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 six months ended June 30, 2015, net cash provided by operating activities increased by $599 million compared to the same period in 2014.  This increase was primarily due to higher base revenue collections authorized in the 2014 GRC and lower purchased power costs (see “Cost of Electricity” under “Results of Operations – Utility Revenues and Costs that did not Impact Earnings” above).

 


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

 

the shareholder-funded bill credit of $400 million to natural gas customers in 2016, and the payment of a $300 million fine to the State General Fund during 2015, as required by the Penalty Decision (see “Enforcement and Litigation Matters” below);

 

 

the timing and amounts of other fines or penalties that may be imposed in connection with the criminal prosecution of the Utility and the remaining investigations and other enforcement matters (see “Enforcement and Litigation Matters” below);

 

 

the timing and outcome of ratemaking proceedings, including the 2015 GT&S rate case;

 

 

the timing and amount of costs the Utility incurs, but does not recover, associated with its natural gas system (including costs to implement remedial measures and $850 million to pay for designated pipeline safety projects and programs, as required by the Penalty Decision);

 

 

the timing and amount of tax payments, 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 $189 million during the six months ended June 30, 2015 as compared to the same period in 2014.  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 $5.5 billion in capital expenditures in 2015 and between $5.3 billion and $5.8 billion in 2016. 

 

Financing Activities

 

During the six months ended June 30, 2015, net cash provided by financing activities decreased by $322 million compared to the same period in 2014.  Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments.  The Utility generally utilizes long-term debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

 

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 in 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. 

 


Potential CPUC Investigation of the Utility’s Safety Culture

 

In connection with the issuance of the Penalty Decision, the President of the CPUC questioned whether the Utility has developed a safety culture that is effective throughout the organization and whether the CPUC’s theories of deterrence – its system of penalties and remedies – assure an effective safety culture in a utility.  He directed the CPUC to begin a new investigation to examine the Utility’s safety culture and practices, including whether they are effective and comprehensive across the organization, and whether there is sufficient accountability for safety results.  He also questioned whether the Utility “is too big to succeed” from a safety perspective, although he did not order the CPUC to begin a new investigation into this issue.  He stated that he intended to request the CPUC’s Legal Division to analyze and evaluate the CPUC’s policies regarding penalties and remedies, and make recommendations for adoption by the CPUC.

 

The timing, scope, and potential outcome of the new investigation and analysis are uncertain.

 

Other Pending Lawsuits and Claims

 

As previously reported, PG&E Corporation received a letter, dated March 26, 2015, on behalf of a purported shareholder demanding that the PG&E Corporation Board of Directors (1) take all necessary actions to recover from certain officers and directors the amount of damages sustained by PG&E Corporation as a result of their alleged misconduct in connection with the events surrounding the San Bruno accident and other matters, and (2) institute corporate governance changes and improvements.  In May 2015, the Board created an Evaluation Committee to evaluate the matters set forth in the demand letter and to recommend to the Board an appropriate response to these matters.

 

On June 5, 2015, the purported shareholder who submitted the demand letter filed a derivative lawsuit in San Mateo County Superior Court, alleging that his shareholder demand was wrongfully refused.  As of June 30, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. 

 

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

 

RATEMAKING PROCEEDINGS

 

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 2014 Form 10-K was filed with the SEC are discussed below.

 

2015 Gas Transmission and Storage Rate Case

 

In the 2015 GT&S rate case, the Utility requested that the CPUC authorize a 2015 revenue requirement of $1.29 billion to recover anticipated costs of providing natural gas transmission and storage services, an increase of $555 million over currently authorized amounts.  The Utility also requested attrition increases of $61 million in 2016 and $168 million in 2017.  The Utility requested that the CPUC authorize the Utility’s forecast of its 2015 weighted average rate base for its gas transmission and storage business of $3.56 billion, which includes capital spending above authorized levels for the prior rate case period.  

 

The Office of Ratepayer Advocates has recommended a 2015 revenue requirement of $1.044 billion, an increase of $329 million over authorized amounts.  TURN recommended that the Utility not recover costs associated with hydrostatic testing for pipeline segments placed in service between January 1, 1956 and June 30, 1961, as well as certain other work that TURN considers to be remedial.  TURN also recommended the disallowance of about $200 million of capital expenditures incurred over the period 2011 through 2014 and recommended that about $500 million of capital expenditures during this period be subject to a reasonableness review and an independent audit.  TURN states that the Utility’s cost recovery should not begin until the CPUC issues a decision on the independent audit.

 

The Utility also has proposed changes to the revenue sharing mechanism authorized in the last GT&S rate case (covering 2011-2014) that subjected a portion of the Utility’s transportation and storage revenue requirement to market risk.  The Utility proposed full balancing account treatment that allows for recovery of the Utility’s authorized transportation and storage revenue requirements (except for the revenue requirement associated with the Utility’s 25% interest in the Gill Ranch storage field). 

 


Based on the scoping ruling and procedural schedule that was issued on June 11, 2015, the CPUC is expected to issue a two-part decision, the first decision to authorize GT&S revenue requirements (which would include a potential disallowance to be imposed as a penalty for the Utility’s violation of the CPUC’s ex parte communication rules as well as a reduction in the Utility's request to reflect any costs associated with implementing the remedies ordered by the Penalty Decision), and a second decision to reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision.  (See Note 9 in the Condensed Consolidated Financial Statements for more information about the CPUC’s Penalty Decision.)  Under the procedural schedule, the CPUC’s decision to authorize revenue requirements likely will not be issued until 2016 and the CPUC’s decision to determine the revenue requirement reduction will follow.  (The ruling states that, in any event, the case would be completed within 18 months of the date of the ruling, or by December 2016.Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.

 

FERC TO Rate Cases

 

On July 30, 2014, the Utility requested 2015 retail electric transmission revenue requirement of $1.366 billion, a $326 million increase over the currently authorized revenue requirement of $1.040 billion.  The Utility’s proposed rates went into effect on March 1, 2015, subject to refund, and pending a final decision by the FERC.  On July 2, 2015, the Utility and other settling parties (including the CPUC) filed a motion at the FERC requesting that the FERC approve a settlement proposing that the Utility’s 2015 retail electric transmission revenue requirement be set at $1.201 billion, a $161 million increase to the currently authorized revenue requirement of $1.040 billion.  The settlement is subject to the FERC’s approval.  If approved by the FERC, the outcome is not expected to have a material effect.  The FERC is expected to issue a decision in late 2015 or early 2016. 

 

On July 29, 2015, the Utility filed a rate case at FERC that requests a 2016 retail electric transmission revenue requirement of $1.515 billion, a $314 million increase over the settled revenue requirement of $1.201 billion pending FERC approval.  The Utility forecasts that it will make investments of $1.246 billion in 2016 in various capital projects.  The Utility's forecasted rate base for 2016 is $5.85 billion, compared to forecasted rate base of $5.12 billion in 2015.  The Utility has requested that the FERC approve a 10.96% return on equity.  The Utility's rate case is pending acceptance at the FERC.

 

 LEGISLATIVE AND REGULATORY INITIATIVES

 

The California Legislature and the CPUC require the California investor-owned electric utilities to accommodate the growth in distributed electric generation resources (including solar installations), increase the amount of renewable energy delivered to customers, and meet cost-effective energy storage targets.  These mandates, along with other state laws and regulations relating to the reduction of GHG emissions, the establishment of energy efficiency standards for buildings, and the creation of community choice aggregators that provide electric service to their communities, have affected, and are likely to continue to affect, customer demand for the Utility’s electric and natural gas service.  Future changes in state laws to increase the amount of renewable energy targets, to establish higher building energy efficiency standards, or to increase the maximum number of “direct access” customers who can procure electricity from alternate energy providers, could further decrease customer demand.  Customer demand also can be affected as 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 net energy metering rules, and allow customers to have greater control over their energy use.  The Utility’s ability to recover its investments, including investments associated with new requirements and 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 to identify optimal locations on its electric distribution system for deployment of distributed generation resources.  The Utility’s proposal allows 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.  Some of the Utility’s initiatives include smart grid infrastructure modernization and new community solar programs.  The Utility plans to request authorization in its 2017 GRC and future applications, to recover the investment costs that it forecasts it will incur under its proposed electric distribution resources plan.

 


Electric Rate Reform and Net Energy Meeting

 

New state legislation that became effective on January 1, 2014 (AB 327) grants the CPUC authority to approve fixed charges to be collected from retail electric residential customers and to revise residential electric rate designs to more closely reflect the cost of service.  In February 2014, as ordered by the CPUC, the Utility submitted a long-term residential electric rate reform plan that proposes a fixed customer charge, gradual flattening of the tiered rate structure, and an optional time-of-use rate.  On July 3, 2015, the CPUC approved a final decision providing for the gradual flattening of the tiered rate structure from four tiers to two tiers with a 1.25 to 1 rate price ratio by January 1, 2019, to bring residential electric rates closer to the Utility’s cost of service.  The decision creates a Super User Electric Surcharge to apply to extremely high electricity users beginning in 2017.  The Utility is required to file a proposal no later than January 1, 2018, to charge residential customers based on time-of- use rates unless customers elect otherwise.  The Utility also may propose to impose a fixed charge on customers.  Under the CPUC’s decision, time-of-use rates must be implemented before the CPUC will permit the imposition of a fixed charge.  The CPUC also approved increased minimum bill charges for residential customers.

 

AB 327 also requires the CPUC to develop a new tariff or contract for net energy metering by December 31, 2015, that must be implemented no later than July 1, 2017.  California’s net energy metering tariff currently allows customers installing renewable distributed generation to offset their electric consumption and receive bill credits for power delivered to the grid at their full retail rate.  Increasing levels of installed renewable distributed generation by customers, coupled with net energy metering that provides full retail rate credits that do not reflect the Utility’s cost structure, have shifted costs from distributed generation customers to other customers.  AB 327 requires the CPUC to assess opportunities to reduce this cost-shift through residential rate and net energy metering tariff reform.  In July 2014, the CPUC began a new rulemaking proceeding to develop a successor to the existing net energy metering tariff to comply with the requirements of AB 327. The Utility is scheduled to file its successor tariff proposal on August 3, 2015.  The CPUC is expected to issue a decision by December 2015.

 

Proposal for Electric Vehicle (EV) Infrastructure Development

 

On February 9, 2015, the Utility filed an application requesting the CPUC to approve the Utility’s proposal to deploy, own, and maintain EV charging infrastructure in its service territory to accelerate EV infrastructure deployment and customer education programs in support of California’s climate goals.  Future use of this charging infrastructure could aid the integration of increased intermittent renewable energy on the state’s electric power grid.  Under the Utility’s proposal, the Utility would develop more than 25,000 EV charging stations and the associated infrastructure over an estimated five years.  The Utility estimates this would meet approximately 25% of projected EV charging station needs by 2020.  The Utility plans to contract with third party EV service providers to operate and maintain the charging stations.  The Utility estimates that it would incur capital costs of $551 million and operating costs of $103 million over the proposed project timeline.  The Utility has requested that the CPUC authorize the Utility to collect an average annual revenue requirement over the project development years of $81 million to recover these costs.  The Utility has requested that the CPUC issue a decision before the end of 2015. Under the proposal, the Utility would begin implementation in 2016, with first deployments of charging stations in 2017.

 

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 14 in the 2014 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 “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 2014 Form 10-K.

 


Off-Balance Sheet Arrangements

 

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 14 of the Notes to the Consolidated Financial Statements in the 2014 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 energy 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.  These activities arediscussed in detail in the 2014 Form 10-K.  There were no significant developments to the Utility and PG&E Corporation’s risk management activities during the six months ended June 30, 2015.

 

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 2014 Form 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.

 


CAUTIONARY LANGUAGE REGARDING 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:

 

The outcome and timing of the 2015 GT&S rate case, including the amount of revenue disallowance imposed as a penalty for improper ex parte communications and how the authorized revenue requirements are reduced to reflect the disallowance of costs associated with designated safety-related projects and programs as required by the Penalty Decision;

 

 

the outcomes of the federal criminal prosecution of the Utility, the CPUC’s investigation of the Utility’s natural gas distribution operations, the SED’s unresolved enforcement action matters, and the other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, and the amount of fines, penalties, and remedial costs that the Utility may incur in connection with such matters;

 

 

the timing and outcome of the CPUC’s investigation and the pending criminal investigations relating to 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 whether such matters negatively affect the final decisions to be issued in the 2015 GT&S rate case or other ratemaking proceedings;

 

 

whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by the criminal prosecution of the Utility, the state and federal investigations of natural gas incidents, improper communications between  the CPUC and the Utility; and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

 

 

the restrictions on communications between the Utility and the CPUC that have been imposed by the CPUC that, along with continuing public criticism of the Utility and the CPUC, may make it more difficult for the Utility to sustain or repair a constructive working relationship with the CPUC and achieve balanced regulatory outcomes;

 

 

the timing and outcome of ratemaking proceedings (such as the 2015 GT&S rate case, the 2017 GRC and the TO rate cases) and the Utility’s ability to control its costs within the adopted levels of spending;

 

 

the amount and timing of additional common stock and debt issuances by PG&E Corporation, the proceeds of which are contributed as equity to maintain the Utility’s authorized capital structure as the Utility incurs charges and costs that it cannot recover through rates (including shareholder-funded costs to complete designated safety projects and programs as ordered in the Penalty Decision) and fines;

 

 

the outcome of the anticipated CPUC investigation into the Utility’s safety culture, and future legislative or regulatory actions that may be taken to require the Utility to restructure into separate entities, undertake some other corporate restructuring, or implement corporate governance changes;

 

 

the outcomes 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; and whether the current or potentially worsening state regulatory environment increases the likelihood of unfavorable outcomes;

 

 

 



 

the impact of environmental laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; the extent to which the Utility is able to recover environmental costs in rates or from other sources; and the ultimate amount of environmental costs the Utility incurs but does not recover, such as the remediation costs associated with the Utility’s natural gas compressor station site located near Hinkley, California;

 

 

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; and whether the Utility decides to resume its pursuit to renew the two Diablo Canyon operating licenses, and if so, whether the licenses are renewed;

 

 

the impact of droughts or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, or 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; and subject the Utility to third-party liability for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory penalties on the Utility;

 

 

the impact of environmental laws and regulations aimed at the reduction of greenhouse gases, and 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 the cost of renewable energy procurement;

 

 

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’s business strategy to address the impact of growing distributed and renewable generation resources and changing customer demands is successful;

 

 

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;

 

 

whether the Utility’s information technology, operating systems and networks, including the advanced metering system infrastructure, customer billing, financial, and other systems, can continue to function accurately while meeting regulatory requirements; whether the Utility is able to protect its 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; and whether the Utility can continue to rely on third-party vendors and contractors that maintain and support some of the Utility’s operating systems;

 

 

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;

 

 

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;

 

 

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;

 

 

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 criminal prosecution, 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;

 

 

 


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, including whether state law is enacted to prohibit the Utility from claiming tax deductions for costs associated with designated safety-related projects and programs that are disallowed by the Penalty Decision; and

 

 

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 2014 Form 10-K and in Part II, 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 June 30, 2015, 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 June 30, 2015, 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 Statements.

 

CPUC Investigations Related to Natural Gas Transmission

 

For description of this matter, see “Part II, Item 1. Legal Proceedings” in the Form 10-Q for the quarter ended March 31, 2015.  In addition, see discussion entitled “Enforcement and Litigation Matters” in Note 9 of the Notes to the Condensed Consolidated Financial Statements. 

 

Federal Criminal Indictment

 

For description of this matter, see “Part II, Item 1. Legal Proceedings” in the Form 10-Q for the quarter ended March 31, 2015.  In addition, see discussion 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 June 30, 2015, there were six purported derivative lawsuits seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. 

 

PG&E Corporation received a letter, dated March 26, 2015, on behalf of a purported shareholder demanding that the PG&E Corporation Board of Directors (1) take all necessary actions to recover from certain officers and directors the amount of damages sustained by PG&E Corporation as a result of their alleged misconduct in connection with the events surrounding the San Bruno accident and other matters, and (2) institute corporate governance changes and improvements.  In May 2015, the Board created an Evaluation Committee to assess the matters set forth in the demand letter and to recommend to the Board an appropriate response to these matters.

 

On June 5, 2015, the purported shareholder who submitted the demand letter filed a derivative lawsuit in San Mateo County Superior Court, alleging that his shareholder demand was wrongfully refused. 

 

PG&E Corporation and the Utility are uncertain when and how the above lawsuits and the shareholder demand 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 2014 Form 10-K.

 

Other Enforcement Matters

 

In addition, fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to the Utility’s self-reports of noncompliance with natural gas safety regulations, 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 1, 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 2014 Form 10-K.

 

Diablo Canyon Nuclear Power Plant 

 

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board and the Utility, see “Part I, Item 3. Legal Proceedings” in the 2014 Form 10-K.



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 2014 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Cautionary Language Regarding Forward-Looking Statements.”

 

PG&E Corporation’s and the Utility’s future financial results will continue to be materially affected as the Utility complies with the Penalty Decision and also may be materially affected by the outcomes of new CPUC investigative enforcement proceedings that are expected to be brought against the Utility, the ongoing federal criminal prosecution of the Utility, and the other federal, state and regulatory investigations and enforcement matters discussed above. 

 

PG&E Corporation's EPS will be materially affected by dilutive common stock issuances needed to fund equity contributions to the Utility to comply with the terms of the Penalty Decision, as discussed above in Note 9 of the Condensed Consolidated Financial Statements.  The Utility will incur material unrecoverable costs to meet the Penalty Decision's requirement to fund safety-related projects and programs to be identified by the CPUC in the GT&S rate case.  The CPUC is expected to issue an initial decision to authorize GT&S revenue requirements.  (The authorized revenue requirements will be reduced by the amount of costs associated with implementing the remedies ordered by the Penalty Decision.  They may be further reduced by a disallowance to be imposed as a penalty for the Utility's violation of the CPUC's ex parte communication rules.)  The CPUC will issue a second decision to further reduce the authorized revenue requirements by the costs of designated safety-related projects and programs up to the $850 million maximum cost disallowance imposed by the Penalty Decision.  Under the procedural schedule, the CPUC's decision to authorize revenue requirements likely will not be issued until 2016 and the CPUC's decision to determine the revenue requirement reduction will follow.  (The ruling states that, in any event, the case would be completed within 18 months of the date of the ruling, or by December 2016.)  Based on the procedural schedule, it is unlikely that the Utility will be able to recognize any increase in its GT&S revenue in 2015.

 

The ultimate financial impact of the Penalty Decision will be affected by the tax treatment of the costs the Utility incurs to comply with the Penalty Decision.  In statements made at the CPUC meeting at which the Penalty Decision was approved, the participating Commissioners indicated that they would inform state and federal tax authorities that the CPUC intended the shareholder-funded costs to be characterized as penalties and not a “cost of doing business.” Furthermore, State Bill 681 was introduced in June 2015 and proposes that the Utility be denied applicable state tax deductions for charges associated with the Penalty Decision. 

 

On June 8, 2015, the Utility filed its compliance plan describing how it had complied, or would comply, with the remedies ordered by the Penalty Decision.  On June 8, 2015, the SED also filed its audit plan for review of the Utility's gas transmission operations, including review of the Utility's compliance with the remedies ordered by the Penalty Decision.  The Penalty Decision requires the SED to conduct annual audits (for a minimum of ten years) of the Utility's recordkeeping practices.  The Utility could incur material charges, including fines and other penalties, depending on the outcome of these future audits.
 

In addition, the CPUC stated in the Penalty Decision that it would begin an investigation into the City of San Bruno’s allegations that the Utility violated the CPUC’s rules regarding ex parte communications.  As discussed in the 2014 Form 10-K, the CPUC also may bring enforcement action against the Utility relating to other communications between the Utility and the CPUC. PG&E Corporation’s and the Utility’s financial results could be materially affected by fines or penalties that may be imposed by the CPUC. Federal and state law enforcement authorities also have begun investigations in connection with these matters and they could take enforcement action in the future against the Utility

 

In addition, the Utility could incur material charges, including fines and other penalties, in connection with the CPUC’s investigation of the Utility’s compliance with natural gas distribution record-keeping practices, the SED’s review of the Utility’s natural gas distribution practices and procedures, and the self-reports the Utility has submitted to the CPUC in accordance with the SED’s safety citation program.  Further, if the Utility is convicted of federal criminal charges that the Utility knowingly and willfully violated pipeline safety laws and illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident, the Utility could be required to pay a material amount of fines. Based on the superseding indictment’s allegations, the maximum alternative fine would be approximately $1.13 billion. The U.S. Attorney’s Office in San Francisco also continues to investigate matters relating to the indicted case.  The Utility also could incur a material amount of costs to comply with remedial measures that the CPUC or a federal judge may impose on the Utility, such as a requirement that the Utility’s natural gas operations be supervised by a third-party monitor.

 


Further, the CPUC is expected to begin a new investigation to examine the Utility’s safety culture and practices, including whether they are effective and comprehensive across the organization, and whether there is sufficient accountability for safety results.  The President of the CPUC also has questioned whether the Utility “is too big to succeedfrom a safety perspective and has requested the CPUC’s Legal Division to analyze and evaluate the CPUC’s policies regarding penalties and remedies, and make recommendations for adoption by the CPUC.  The scope, timing, and outcome of the new investigation are uncertain.



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

 

During the quarter ended June 30, 2015, PG&E Corporation made equity contributions totaling $85 million to the Utility in order to maintain the 52% common equity component of its CPUC-authorized capital structure.  Neither PG&E Corporation nor the Utility made any sales of unregistered equity securities during the quarter ended June 30, 2015.

 

Issuer Purchases of Equity Securities

 

During the quarter ended June 30, 2015, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the quarter ended June 30, 2015, 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 six months ended June 30, 2015 was 1.82The Utility’s earnings to combined fixed charges and preferred stock dividends ratio for the six months ended June 30, 2015 was 1.80. 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 six months ended June 30, 2015 was 1.84. 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

Bylaws of Pacific Gas and Electric Company amended as of August 17, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on July 14, 2015 (File No. 1-2348), Exhibit 99.2)

 

 

4

Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on June 12, 2015 (File No. 1-2348), Exhibit 4.1)

 

 

10.1

Amended and restated credit agreement dated April 27, 2015, among (1) PG&E Corporation as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)

 

 

10.2

Amended and restated credit agreement dated April 27, 2015, among (1) Pacific Gas and Electric Company as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A. as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)

 

 

*10.3

Form of Restricted Stock Unit Agreement for 2015 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.4

Letter regarding Compensation Agreement between PG&E Corporation and Julie M. Kane dated March 11, 2015 for employment starting May 18, 2015

 

 

*10.5

Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.6

Non-Annual Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015

 

 

*10.7

Performance Share Agreement subject to financial goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.8

Performance Share Agreement subject to safety and customer affordability goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

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

 



 

 

31.2

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

 

 

**32.1

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

 

 

**32.2

Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

 

 

101.INS

XBRL Instance Document

 

 

101.SCH

XBRL Taxonomy Extension Schema Document

 

 

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

 

 

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

 

 

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

 

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.



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

 

KENT M. HARVEY

Kent M. Harvey
Senior Vice President and Chief Financial Officer
(duly authorized officer and principal financial officer)

 

 

PACIFIC GAS AND ELECTRIC COMPANY

 

DINYAR B. MISTRY

Dinyar B. Mistry

Vice President, Chief Financial Officer and Controller

(duly authorized officer and principal financial officer)

 

 

 

Dated: July 29,2015


EXHIBIT INDEX

 

3

Bylaws of Pacific Gas and Electric Company amended as of August 17, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on July 14, 2015 (File No. 1-2348), Exhibit 99.2)

 

 

4

Twenty-Fifth Supplemental Indenture, dated as of June 12, 2015, relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due June 15, 2025 and $100,000,000 aggregate principal amount of its 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K filed on June 12, 2015 (File No. 1-2348), Exhibit 4.1)

 

 

10.1

Amended and restated credit agreement dated April 27, 2015, among (1) PG&E Corporation as borrower, (2) Bank of America, N.A., as administrative agent and a lender, (3) J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Citibank N.A. and JPMorgan Chase Bank, N.A., as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-12609), Exhibit 10.1)

 

 

10.2

Amended and restated credit agreement dated April 27, 2015, among (1) Pacific Gas and Electric Company as borrower, (2) Citibank N.A., as administrative agent and a lender, (3) Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, and Wells Fargo Securities LLC as joint lead arrangers and joint bookrunners, (4) Bank of America, N.A. and JPMorgan Chase Bank, N.A. as co-syndication agents and lenders, (5) Wells Fargo Bank, National Association as documentation agent and lender, and (6) the following other lenders: Barclays Bank PLC, BNP Paribas, Goldman Sachs Bank USA, Morgan Stanley Bank, N.A., Morgan Stanley Senior Funding, Inc., The Bank of New York Mellon, N.A., Mizuho Corporate Bank, Ltd., Royal Bank of Canada, U.S. Bank National Association, Union Bank, N.A., TD Bank, N.A., Canadian Imperial Bank of Commerce, New York Branch, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2015 (File No. 1-2348), Exhibit 10.2)

 

 

*10.3

Form of Restricted Stock Unit Agreement for 2015 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.4

Letter regarding Compensation Agreement between PG&E Corporation and Julie M. Kane dated March 11, 2015 for employment starting May 18, 2015

 

 

*10.5

Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.6

Non-Annual Restricted Stock Unit Agreement between Julie M. Kane and PG&E Corporation dated May 29, 2015

 

 

*10.7

Performance Share Agreement subject to financial goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

*10.8

Performance Share Agreement subject to safety and customer affordability goals between Julie M. Kane and PG&E Corporation dated May 29, 2015 for 2015 grant under the PG&E Corporation 2014 Long-Term Incentive Plan

 

 

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

 

 

31.2

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

 

 


 

**32.1

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

 

 

**32.2

Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

 

 

101.INS

XBRL Instance Document

 

 

101.SCH

XBRL Taxonomy Extension Schema Document

 

 

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document

 

 

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document

 

 

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document

 

 

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document

 

*Management contract or compensatory agreement.

**Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.