SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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(Mark One)
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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the Fiscal Year Ended December 31, 2014
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Or
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o
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _________ to ___________
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Commission
File Number
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Exact Name of Registrant
as Specified In Its Charter
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State or Other Jurisdiction of
Incorporation or Organization
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IRS Employer
Identification Number
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1-12609
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PG&E CORPORATION
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California
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94-3234914
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1-2348
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PACIFIC GAS AND ELECTRIC COMPANY
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California
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94-0742640
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 77 Beale Street, P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
(415) 973-1000
(Registrant's telephone number, including area code)
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 77 Beale Street, P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip Code)
(415) 973-7000
(Registrant's telephone number, including area code)
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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PG&E Corporation: Common Stock, no par value
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New York Stock Exchange
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Pacific Gas and Electric Company: First Preferred Stock,
cumulative, par value $25 per share:
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NYSE Amex Equities
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Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%
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Nonredeemable: 6%, 5.50%, 5%
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:
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PG&E Corporation
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Yes þ No o
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Pacific Gas and Electric Company
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Yes þ No o
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Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:
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PG&E Corporation
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Yes o No þ
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Pacific Gas and Electric Company
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Yes o No þ
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Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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PG&E Corporation
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Yes þ No o
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Pacific Gas and Electric Company
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Yes þ No o
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Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
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PG&E Corporation
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Yes þ No o
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Pacific Gas and Electric Company
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Yes þ No o
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K:
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PG&E Corporation
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þ
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Pacific Gas and Electric Company
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þ
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):
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PG&E Corporation
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Pacific Gas and Electric Company
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Large accelerated filer þ
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Large accelerated filer o
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Accelerated filer o
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Accelerated filer o
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Non-accelerated filer o
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Non-accelerated filer þ
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Smaller reporting company o
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Smaller reporting company o
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
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PG&E Corporation
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Yes o No þ
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Pacific Gas and Electric Company
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Yes o No þ
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Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2014, the last business day of the most recently completed second fiscal quarter:
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PG&E Corporation common stock
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$22,602 million
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Pacific Gas and Electric Company common stock
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Wholly owned by PG&E Corporation
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Common Stock outstanding as of January 27, 2015:
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PG&E Corporation:
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476,399,910
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Pacific Gas and Electric Company:
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264,374,809 shares (wholly owned by PG&E Corporation)
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DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved:
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Designated portions of the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders
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Part III (Items 10, 11, 12, 13 and 14)
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Contents
i
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 63 | ||
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PG&E Corporation
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63
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64
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65
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| Consolidated Statements of Cash Flows | 67 | |||
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68
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Pacific Gas and Electric Company
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69
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70
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71
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| Consolidated Statements of Cash Flows | 73 | |||
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74
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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75
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75
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81
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84
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87
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NOTE 6: | Preferred Stock | 90 | |
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90
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| NOTE 8: | Income Taxes | 91 | ||
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94
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97
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| NOTE 11: | Employee Benefit Plans | 104 | ||
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114
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| NOTE 13: | Related Party Agreements and Transactions | 115 | ||
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115
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| 125 | ||||
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126
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127
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| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 129 | ||
| ITEM 9A. |
129
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| ITEM 9B. |
129
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| PART III |
130
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| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
130
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| ITEM 11. |
130
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| ITEM 12. |
131
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| ITEM 13. |
131
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| ITEM 14. |
131
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| PART IV | 132 | |||
| ITEM 15. | Exhibits and Financial Statement Schedules | 132 | ||
| SIGNATURES |
142
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| REPORT OF INDEPENDENT REGISTERD PUBLIC ACCOUNTING FIRM | 144 | |||
| FINANCIAL STATEMENT SCHEUDLES | 145 | |||
ii
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1 Kilowatt (kW)
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=
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One thousand watts
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1 Kilowatt-Hour (kWh)
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=
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One kilowatt continuously for one hour
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1 Megawatt (MW)
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=
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One thousand kilowatts
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1 Megawatt-Hour (MWh)
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=
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One megawatt continuously for one hour
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1 Gigawatt (GW)
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=
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One million kilowatts
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1 Gigawatt-Hour (GWh)
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=
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One gigawatt continuously for one hour
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1 Kilovolt (kV)
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=
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One thousand volts
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1 MVA
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=
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One megavolt ampere
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1 Mcf
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=
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One thousand cubic feet
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1 MMcf
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=
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One million cubic feet
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1 Bcf
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=
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One billion cubic feet
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1 MDth
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=
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One thousand decatherms
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iii
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
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2014 Annual Report
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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, including the information incorporated by reference into the report
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AB
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Assembly Bill
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AFUDC
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allowance for funds used during construction
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ALJ
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administrative law judge
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ARO
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asset retirement obligation
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CAISO
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California Independent System Operator
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CARB
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California Air Resources Board
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CCA
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Community Choice Aggregator
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| Central Coast Board | Central Coast Regional Water Quality Control Board |
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CPUC
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California Public Utilities Commission
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CRRs
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congestion revenue rights
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DOE
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Department of Energy
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EPA
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Environmental Protection Agency
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EPS
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earnings per common share
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EV
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electric vehicle
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FERC
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Federal Energy Regulatory Commission
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GAAP
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U.S. Generally Accepted Accounting Principles
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GHG
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greenhouse gas
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GRC
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general rate case
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GT&S
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gas transmission and storage
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IRS
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Internal Revenue Service
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LTIP
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long term incentive plan
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MD&A
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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NEIL
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Nuclear Electric Insurance Limited
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NRC
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Nuclear Regulatory Commission
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NTSB
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National Transportation Safety Board
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ORA
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Office of Ratepayer Advocates
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PSEP
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pipeline safety enhancement plan
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QF
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Qualifying facility
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Regional Board
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California Regional Water Quality Control Board, Lahontan Region
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REITS
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Global real estate investment trust
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ROE
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return on equity
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RPS
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renewable portfolio standard
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SEC
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U.S. Securities and Exchange Commission
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SED
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Safety and Enforcement Division of the CPUC, formerly known as the Consumer Protection and Safety Division or the CPSD
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TO
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transmission owner
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TURN
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The Utility Reform Network
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Utility
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Pacific Gas and Electric Company
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VIE(s)
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variable interest entity(ies)
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Water Board
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California State Water Resources Control Board
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iv
PG&E Corporation, incorporated in California in 1995, is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility operating in northern and central California. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries in 1997. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. At the state level, the Utility is regulated primarily by the CPUC. At the federal level, the Utility is subject to the jurisdiction of the FERC and the NRC. PG&E Corporation’s and the Utility’s operating revenues, income, and total assets can be found in Item 6. Selected Financial Data.
The principal executive offices of PG&E Corporation and the Utility are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177. PG&E Corporation’s telephone number is (415) 973-1000 and the Utility’s telephone number is (415) 973-7000.
At December 31, 2014, PG&E Corporation and its subsidiaries had 22,581 employees, including 22,569 employees of the Utility. Of the Utility’s regular employees, 13,649 are covered by collective bargaining agreements with the local chapters of three labor unions: the International Brotherhood of Electrical Workers (“IBEW”); the Engineers and Scientists of California (“ESC”); and the Service Employees International Union (“SEIU”). The two agreements with IBEW, and the single agreement with ESC, will expire on December 31, 2015. The SEIU collective bargaining agreement will expire on July 31, 2015.
This is a combined Annual Report on Form 10-K for PG&E Corporation and the Utility. PG&E Corporation’s and the Utility’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and proxy statements, are available free of charge on both PG&E Corporation's website, www.pgecorp.com, and the Utility's website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC. The information contained on these websites is not part of this or any other report that PG&E Corporation and the Utility files with, or furnishes to, the SEC.
This Annual Report on Form 10-K contains forward-looking statements that are necessarily subject to various risks and uncertainties. For a discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see “Item 1A. Risk Factors” and the section entitled “Cautionary Language Regarding Forward-Looking Statements” in Item 7. MD&A. In particular, PG&E Corporation’s and the Utility’s financial results are expected to be materially affected by the final outcome of the CPUC’s pending investigative enforcement proceedings against the Utility. These investigations relate 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 pipeline accident that occurred in San Bruno, California on September 9, 2010. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have been materially affected by the costs the Utility has incurred related to shareholder funded safety work, the ongoing regulatory investigations, and civil lawsuits that commenced following the San Bruno accident. In addition, PG&E Corporation’s and the Utility’s financial results could be materially affected by the outcome of the federal criminal prosecution of the Utility and the other enforcement matters discussed in “Enforcement and Litigation Matters” in Item 7. MD&A.
1
The Utility's business is subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory proceedings affecting the Utility. See “Enforcement and Litigation Matters” and “Ratemaking and Other Regulatory Proceedings” in Item 7. MD&A for discussion of specific pending regulatory matters that are expected to materially affect PG&E Corporation and the Utility.
PG&E Corporation is a “public utility holding company” as defined under the Public Utility Holding Company Act of 2005 and is subject to regulatory oversight by the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the Public Utility Holding Company Act of 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
The California Public Utilities Commission
The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction over the rates and terms and conditions of service for the Utility's electricity and natural gas distribution operations, electricity generation, and natural gas transmission and storage services. The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.
The California Legislature also directs the CPUC to implement state laws and policies, such as the laws relating to increasing renewable energy resources, the development and widespread deployment of distributed generation and self-generation resources, the reduction of GHG emissions, and the development of energy storage technologies and facilities. In addition, the CPUC is responsible for approving funding and administration of state-mandated public purpose programs such as energy efficiency and other customer programs.
The CPUC enforces state laws that set forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility electric and gas facilities. The CPUC also has authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities. The CPUC has adopted a gas safety enforcement program and authorized the SED to issue citations and impose fines for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. (See “Enforcement and Litigation Matters” in Item 7. MD&A for information about the presiding officer decisions issued in the three CPUC investigative enforcement proceedings pending against the Utility and SED’s enforcement actions taken against the Utility.) In December 2014, the CPUC also adopted an interim electric safety enforcement program that became effective January 1, 2015. (On January 7, 2015, the Utility requested that the CPUC reconsider this decision.) Under both the gas and electric programs, the SED can impose fines up to $50,000 per violation, per day. The CPUC is expected to review both safety programs during 2015 to determine whether any further changes are needed.
In addition, the CPUC conducts audits and reviews of the Utility’s accounting, performance and compliance with regulatory guidelines, as well as investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC has imposed various conditions that govern the relationship between the Utility and PG&E Corporation and other affiliates, including financial conditions that require PG&E Corporation’s Board of Directors to give first priority to the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner. (For more information, see “Liquidity and Financial Resources” in Item 7. MD&A and Item 1A. Risk Factors.)
2
The Federal Energy Regulatory Commission and the California Independent System Operator
The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas. The FERC regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations and the terms and rates of wholesale electricity sales. The FERC also is charged with adopting and enforcing mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches. The FERC has authority to impose fines of up to $1 million per day for violation of certain federal statutes and regulations.
The CAISO is the FERC-approved regional transmission organization for the Utility’s service territory. The CAISO controls the operation of the transmission system in California and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for planning transmission system additions, ensuring the maintenance of adequate reserves of generation capacity, and ensuring that the reliability of the transmission system is maintained.
The Nuclear Regulatory Commission
The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility’s two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay. (See “Electric Generation Resources” below.) NRC regulations require extensive monitoring and review of the safety, radiological, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and substantial capital expenditures could be required in the future.
Other Regulation
The California Energy Resources Conservation and Development Commission, commonly called the CEC, is the state's primary energy policy and planning agency. The CEC is responsible for licensing all thermal power plants over 50 MW within California. The CEC also is responsible for forecasts of future energy needs used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.
The CARB is the state agency charged with setting and monitoring GHG and other emission limits. The CARB also is responsible for adopting and enforcing regulations to implement state law requirements to gradually reduce GHG emissions in California to 1990 levels by 2020. (See “Environmental Regulation — Air Quality and Climate Change” below.)
In addition, the Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas that grant the Utility rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations. The Utility has franchise agreements with approximately 300 cities and counties that permit the Utility to install, operate, and maintain the Utility's electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date.
3
The Utility’s rates for electricity and natural gas utility services are set at levels that are intended to allow the Utility to recover its costs of providing service including a return on invested capital (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC conduct various proceedings to determine the annual amount that the Utility will be authorized to collect from its customers (“revenue requirements”). The Utility’s revenue requirements consist primarily of a base amount set to enable the Utility to recover its reasonable operating expenses (maintenance, administration and general expenses) and capital costs (depreciation, tax, and financing expenses). In addition, the CPUC authorizes the Utility to collect revenues to recover costs that it is allowed to “pass-through” to customers, including its costs to procure electricity, natural gas and nuclear fuel, to administer public purpose and customer programs, and to decommission its nuclear facilities.
The Utility’s rate of return on electric transmission assets is determined in the FERC TO proceedings. The authorized rate of return on all other assets is set in the CPUC’s cost of capital proceeding. Other than its electric transmission and certain gas transmission and storage revenues, the Utility’s base revenues are “decoupled” from its sales volume. Regulatory balancing accounts, or revenue adjustment mechanisms, ensure that the Utility will fully collect its authorized base revenue requirements. The Utility’s earnings primarily depend on its ability to manage its base operating and capital costs (referred to as “Utility Revenues and Costs that Impact Earnings” in Item 7. MD&A) within its authorized base revenue requirements.
To develop retail rates, authorized revenue requirements are allocated among customer classes which are mainly residential, commercial, industrial, and agricultural. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions.
California AB 327, which became effective on January 1, 2014, repealed prior law that restricted the CPUC’s ability to change residential electric rates and to reduce the level of rate assistance for certain low-income customers. AB 327 also authorized the CPUC to approve fixed charges to be collected from residential customers. In 2012, the CPUC opened a rulemaking proceeding to examine residential rate design in California that, consistent with AB 327, allows the CPUC to simplify the rate structure to bring marginal rates closer to reflecting the Utility’s actual costs. In February 2014, as ordered by the CPUC, the Utility submitted a long-term residential rate reform plan that proposes a fixed customer charge, gradual flattening of the tiered rate structure, and an optional time-of-use rate. The CPUC is expected to issue a final decision by the summer of 2015.
AB 327 also requires the CPUC to develop a new structure for net energy metering by December 31, 2015, that must be implemented no later than July 1, 2017. California’s net energy metering program currently allows customers installing renewable distributed generation to receive bill credits for power delivered to the grid at their full retail rate. Increasing levels of self-generation of electricity by customers, coupled with net metering and retail rates that do not reflect the Utility’s cost structure, has shifted costs to the remaining customers. AB 327 gives the CPUC new authority to reduce the cost shift associated with renewable distributed generation through residential rate and net energy metering reform. In July 2014, the CPUC began a rulemaking proceeding to develop a successor to the existing net energy metering program to comply with the requirements of AB 327. The CPUC is expected to issue a proposed decision in the fall of 2015.
From time to time, the CPUC may use incentive ratemaking mechanisms that provide the Utility an opportunity to earn additional revenues. For example, the Utility has earned incentives for the successful implementation of energy efficiency programs. (See “Results of Operations” in Item 7. MD&A.)
4
Base Revenues
General Rate Cases
The GRC is the primary proceeding in which the CPUC determines the amount of base revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s anticipated costs, including return on rate base, related to its electricity and natural gas distribution and Utility owned electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC approves the annual revenue requirements for the first year (or “test year”) of the GRC period and typically authorizes the Utility to receive annual increases (known as “attrition adjustments”) in revenue requirements for the subsequent years of the GRC period. Attrition rate adjustments are generally provided for cost increases related to inflation and increases in invested capital. Parties in the Utility's GRC include the ORA and TURN, who generally represent the overall interests of residential customers, as well as a myriad of other intervenors who represent residential and other customer interests.
On August 14, 2014, the CPUC issued a decision in the Utility’s 2014 GRC, authorizing the Utility to collect a total 2014 revenue requirement of approximately $7.1 billion to recover anticipated costs associated with electric generation, as well as electric and natural gas distribution (See “Results of Operations” in Item 7. MD&A.) The CPUC also authorized attrition increases of $324 million for 2015 and $371 million for 2016.
On December 9, 2014, the CPUC issued a decision adopting a risk-based decision-making framework for the CPUC to use in evaluating future major rate cases. The CPUC ordered the utilities to file an application on May 1, 2015, to initiate a new proceeding called the Safety Model Assessment Proceeding in which the CPUC will review the models the utilities use to assess and prioritize risks. After this proceeding concludes, each utility would file an application to initiate the first phase of their next GRC. In this phase, known as the Risk Assessment Mitigation Phase, the CPUC will examine the utility’s assessment of its key risks and its proposed programs for mitigating those risks.
Natural Gas Transmission and Storage Rate Cases
The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage services in the GT&S rate case. In December 2013, the Utility filed its 2015 GT&S rate case application (covering 2015 through 2017) requesting the CPUC approve a total annual revenue requirement of $1.29 billion for anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2015. See “Ratemaking and Other Regulatory Proceedings – 2015 GT&S Rate Case” in Item 7. MD&A for additional information.
Cost of Capital Proceedings
The CPUC periodically conducts a cost of capital proceeding to authorize the Utility's capital structure and rates of return for its electric generation, electric and natural gas distribution, and natural gas transmission and storage rate base. The CPUC has authorized the Utility’s capital structure through 2016, consisting of 52% common equity, 47% long-term debt, and 1% preferred stock. The CPUC also authorized the Utility to earn a 10.40% ROE effective January 1, 2013, compared to the 11.35% previously authorized. The Utility’s ROE can be automatically adjusted if the utility bond index changes by certain thresholds on an annual basis. The index changes to date have not exceeded the threshold so the 2015 ROE has remained at 10.40%. The Utility’s next cost of capital application is due in April 2016.
Electricity Transmission Owner Rate Cases
The FERC determines the amount of authorized revenue requirement, including rate of return on electric transmission assets, that the Utility may collect in rates in the TO tariff rate case. The Utility generally files a TO tariff rate case every year. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. These FERC-approved rates are included by the CPUC in the Utility's retail electric rates and are collected from retail electric customers. (See “Ratemaking and Other Regulatory Proceedings – FERC Transmission Owner Rate Cases” in Item 7. MD&A.) The Utility also recovers revenue requirements for its wholesale electric transmission costs through charges collected under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in 1998. These wholesale customers are charged individualized rates based on the terms of their contracts.
5
Revenues to Recover Energy Procurement and Other Pass-Through Costs
Electricity Procurement Costs
California investor-owned electric utilities are responsible for procuring electricity required to meet customer demand, plus applicable reserve margins, that are not satisfied from their own generation facilities and existing electricity contracts. The utilities are responsible for scheduling and bidding electric generation resources, including electricity procured from third parties or the wholesale market, to meet customer demand according to which resources are the least expensive (i.e., using the principles of “least-cost dispatch”). In addition, the utilities are required to obtain CPUC approval of their procurement plans based on long-term demand forecasts. In January 2012, the CPUC approved the Utility’s procurement plan (covering 2012 through 2020).
California law allows electric utilities to recover the costs incurred in compliance with their CPUC-approved electricity procurement plans without further after-the-fact reasonableness review. Costs associated with electricity purchases may be disallowed if they are not in compliance with the CPUC-approved plan or if the utility failed to follow the principles of least-cost dispatch. The Utility recovers its electricity procurement costs annually through the energy resource recovery account (“ERRA”). (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.) Each year, the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements, derivative instruments, GHG costs, and generation fuel expense and approves a forecasted revenue requirement. The CPUC may adjust a utility’s retail electricity rates more frequently if the forecasted aggregate over-collections or under-collections in the ERRA exceed five percent of its prior year electricity procurement revenues. The CPUC performs an annual compliance review of the transactions recorded in the ERRA.
The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved procurement plan, the renewable energy mandate, and resource adequacy requirements. See “Electric Utility Operations – Electricity Resources” below as well as Note 14 of the Notes to the Consolidated Financial Statements in Item 8 for additional information.
Natural Gas Procurement and Transportation Costs
The Utility sets the natural gas procurement rate for small commercial and residential customers (referred to as “core” customers) monthly, based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility recovers the cost of gas purchased on behalf of core customers as well as the cost of derivative instruments through its retail gas rates subject to limits as set forth in its Core Procurement Incentive Mechanism (“CPIM”). The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates. This is accomplished through monthly advice letters that are effective upon filing. The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered annually through retail electricity rates.
The CPIM protects the Utility against after-the-fact reasonableness reviews of these gas procurement costs. Under the CPIM, the Utility’s natural gas purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility's customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The Utility retains the remaining amount of savings as incentive revenues, subject to a cap equal to 1.5% of total natural gas commodity costs. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.
6
The Utility incurs transportation costs under various agreements with interstate and Canadian third-party transportation service providers. These providers transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada, the U.S. Rocky Mountains, and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. These agreements are governed by FERC-approved tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The transportation costs the Utility incurs under these agreements are recovered through CPUC-approved rates as core natural gas procurement costs or as a cost of electricity.
Costs Associated with Public Purpose and Customer Programs
The CPUC authorizes the Utility to recover the costs of various public purpose and other customer programs through the collection of rates from most Utility customers. These programs relate to energy efficiency, demand response, distributed generation, energy research and development, and other matters. Additionally, the CPUC has authorized the Utility to provide a discount rate for low-income customers, known as California Alternate Rates for Energy (“CARE”), which is subsidized by the Utility’s other customers.
Nuclear Decommissioning Costs
The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility files an application with the CPUC every three years requesting approval of the Utility’s estimated decommissioning costs and authorization to recover the estimated costs through rates. Nuclear decommissioning charges collected through rates are held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit.
The Utility generates electricity and provides electricity transmission and distribution services throughout its service territory in northern and central California to residential, commercial, industrial, and agricultural customers. The Utility provides “bundled” services (i.e., electricity, transmission and distribution services) to most customers in its service territory. Customers also can obtain electricity from alternative providers such as municipalities or CCAs, as well as from self-generation resources, such as rooftop solar installations.
During 2014, the Utility continued to make improvements to its electric transmission and distribution systems to accommodate the integration of new renewable energy resources, distributed generation resources, and energy storage facilities, and to help create a platform for the development of new Smart Grid technologies. The Utility plans to continue making similar improvements in 2015. In December 2014, the CPUC issued a decision that permits the California investor-owned electric utilities to own EV retail charging equipment in their respective service territories to help meet the state’s goal of reducing GHG emissions by promoting cleaner transportation. On February 9, 2015, the Utility filed an application to request that the CPUC approve the Utility’s proposal to develop, maintain, and operate an EV-charging infrastructure in its service territory. (For more information about the Utility’s application, see “Ratemaking And Other Regulatory Proceedings” in Item 7. MD&A.)
7
Electricity Resources
The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is required to dispatch, or schedule all of the electricity resources within its portfolio in the most cost-effective way.
The following table shows the percentage of the Utility’s total deliveries of electricity to customers in 2014 represented by each major electricity resource, and further discussed below.
Total 2014 Actual Electricity Generated and Procured – 74,547 GWh (1):
|
Percent of Bundled Retail Sales
|
||||||
|
Owned Generation Facilities
|
||||||
|
Nuclear
|
20.6
|
%
|
||||
|
Small Hydroelectric
|
0.8
|
%
|
||||
|
Large Hydroelectric
|
6.6
|
%
|
||||
|
Fossil fuel-fired
|
7.4
|
%
|
||||
|
Solar
|
0.4
|
%
|
||||
|
Total
|
35.8
|
%
|
||||
|
Qualifying Facilities
|
||||||
|
Renewable
|
3.7
|
%
|
||||
|
Non-Renewable
|
8.5
|
%
|
||||
|
Total
|
12.2
|
%
|
||||
|
Irrigation Districts and Water Agencies
|
||||||
|
Small Hydroelectric
|
0.1
|
%
|
||||
|
Large Hydroelectric
|
0.8
|
%
|
||||
|
Total
|
0.9
|
%
|
||||
|
Other Third-Party Purchase Agreements
|
||||||
|
Renewable
|
22.0
|
%
|
||||
|
Large Hydroelectric
|
0.9
|
%
|
||||
|
Non-Renewable
|
6.6
|
%
|
||||
|
Total
|
29.5
|
%
|
||||
|
Others, Net (2)
|
21.6
|
%
|
||||
|
Total (3)
|
100.0
|
%
|
||||
(2) Mainly comprised of net CAISO open market purchases.
(3) Non-renewable sources, including nuclear, large hydroelectric, and fossil fuel-fired are offset by transmission and distribution related system losses.
Renewable Energy Resources. California law requires load-serving entities, such as the Utility, to gradually increase the amount of renewable energy they deliver to their customers to at least 33% of their total annual retail sales. This program, known as the RPS program, became effective in December 2011, established three multi-year compliance periods that have gradually increasing RPS targets: 2011 through 2013, 2014 through 2016, and 2017 through 2020. After 2020, the RPS compliance periods will be annual.
Renewable generation resources, for purposes of the RPS program, include bioenergy such as biogas and biomass, certain hydroelectric facilities (30 MW or less), wind, solar, and geothermal energy. During 2014, 27% of the Utility’s energy deliveries were from renewable energy sources, exceeding the annual RPS target of 23.3%. Approximately 22% of the renewable energy delivered to the Utility’s customers was purchased from non-QF third parties. Additional renewable resources were provided by QFs (3.8%), the Utility’s small hydroelectric facilities (0.8%), and the Utility’s solar facilities (0.5%).
The total 2014 renewable deliveries shown above were comprised of the following:
|
GWh
|
Percent of Bundled Retail Sales
|
|||||||
|
Biopower
|
3,458 | 4.6 | % | |||||
|
Geothermal
|
3,867 | 5.2 | % | |||||
|
Wind
|
5,399 | 7.2 | % | |||||
|
RPS-Eligible Hydroelectric
|
981 | 1.3 | % | |||||
|
Solar
|
6,478 | 8.7 | % | |||||
|
Total
|
20,183 | 27.0 | % | |||||
8
Energy Storage. As required by California law, the CPUC has established initial energy storage procurement targets to be achieved by each load-serving entity, such as the Utility. The Utility has an 80.5 MW of energy storage target to meet its 2014 energy storage plan. In December 2014, the Utility held its first competitive request for two types of proposals: (1) an energy storage agreement with the owner of an energy storage facility that would enable the Utility to offer stored energy into the CAISO market and (2) a purchase and sale agreement under which the counterparty would build a storage facility and transfer the facility to the Utility provided the facility meets certain operational conditions. Offers are due by February 17, 2015. The Utility intends to complete negotiations and execute contracts by October 1, 2015 and to submit the executed contracts for CPUC approval by December 1, 2015.
Owned Generation Facilities. At December 31, 2014, the Utility owned the following generation facilities, all located in California, listed by energy source and further described below:
|
Generation Type
|
County Location
|
Number of Units
|
Net Operating Capacity (MW)
|
||||||
|
Nuclear (1):
|
|||||||||
|
Diablo Canyon
|
San Luis Obispo
|
2 | 2,240 | ||||||
|
Hydroelectric (2):
|
|||||||||
|
Conventional
|
16 counties in northern and central California
|
104 | 2,677 | ||||||
|
Helms pumped storage
|
Fresno
|
3 | 1,212 | ||||||
|
Fossil fuel-fired:
|
|||||||||
|
Colusa Generating Station
|
Colusa
|
1 | 657 | ||||||
|
Gateway Generating Station
|
Contra Costa
|
1 | 580 | ||||||
|
Humboldt Bay Generating Station
|
Humboldt
|
10 | 163 | ||||||
|
Fuel Cell:
|
|||||||||
|
CSU East Bay Fuel Cell
|
Alameda
|
1 | 1 | ||||||
|
SF State Fuel Cell
|
San Francisco
|
2 | 2 | ||||||
|
Photovoltaic (3):
|
Various
|
13 | 152 | ||||||
|
Total
|
137 | 7,684 | |||||||
(1) The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2. For the year ended December 31, 2014, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 87%. The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. (See Note 14 to the Consolidated Financial Statements in Item 8.) The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 49.5 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors. The NRC operating licenses for the two operating units at Diablo Canyon include various license conditions related to seismic design and safety. The current licenses expire in 2024 and 2025. In November 2009, the Utility filed an application with the NRC to seek the renewal of the licenses, a process which can take several years. After the March 2011 earthquake in Japan that damaged nuclear facilities, the NRC granted the Utility’s request to delay processing its renewal application until certain advanced seismic studies of the fault zones in the region surrounding Diablo Canyon were completed. The seismic studies have been completed and in September 2014, the Utility submitted a report to the NRC and the CPUC’s Independent Peer Review Panel that confirmed the seismic safety of the plant. The Independent Review Panel is providing comments on the report and the Utility expects its review to be completed within the next six to eight months. (See also “Environmental Matters” and Item 1A. Risk Factors.)
(2) The Utility’s hydroelectric system consists of 107 generating units at 67 powerhouses. All of the Utility’s powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years.
(3) The Utility’s larger operational photovoltaic facilities include the Five Points solar station (15 MW), the Westside solar station (15 MW), the Stroud solar station (20 MW), the Huron solar station (20 MW), the Cantua solar station (20 MW), the Giffen solar station (10 MW), the Gates solar station (20 MW), the West Gates solar station (10 MW) and the Guernsey solar station (20 MW). All of these facilities are located in Fresno County, except for the Guernsey solar station, which is located in Kings County.
Generation Resources from Third Parties. The Utility has entered into various agreements to purchase power and electric capacity, including agreements for renewable energy resources, in accordance with its CPUC-approved procurement plan. (See “Ratemaking Mechanisms” above.) For more information regarding the Utility’s power purchase agreements, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
9
Electricity Transmission
At December 31, 2014, the Utility owned approximately 18,100 circuit miles of interconnected transmission lines operating at voltages ranging from 60 kV to 500 kV. The Utility also operated 91 electric transmission substations with a capacity of approximately 63,400 MVA. The Utility’s electric transmission system is interconnected with electric power systems in the Western Electricity Coordinating Council, which includes many western states, Alberta and British Columbia, and parts of Mexico.
In November 2013, the Utility, MidAmerican Transmission, LLC, and Citizens Energy Corporation were selected by the CAISO to jointly develop a new 230-kV transmission line to address the growing power demand in Fresno, Madera and Kings counties area. The 70-mile line will connect the Utility-owned and -operated Gates and Gregg substations. The new line will help reduce the number and duration of power outages, improve voltage in the area, support economic development, and bolster efforts to integrate clean, renewable energy onto the grid. The transmission line is expected to commence operations by 2022, and could come online earlier.
Throughout 2014, the Utility upgraded several critical substations and re-conductored a number of transmission lines to improve maintenance and system flexibility, reliability and safety. The Utility expects to undertake various additional transmission projects over the next several years to upgrade and expand the capacity of its transmission system to accommodate system load growth, secure access to renewable generation resources, replace aging or obsolete equipment and improve system reliability. The Utility also has taken steps to improve the physical security of its transmission substations and equipment.
Electricity Distribution
The Utility's electricity distribution network consists of approximately 141,700 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead), 55 transmission switching substations, and 603 distribution substations, with a capacity of approximately 30,200 MVA. The Utility’s distribution network interconnects with its transmission system, primarily at switching and distribution substations, where equipment reduces the high-voltage transmission voltages to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers.
These distribution substations serve as the central hubs for the Utility’s electric distribution network. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution facilities to entities, such as municipal and other utilities, that resell the electricity. In October 2014, the Utility commenced operations at the first of three new electric distribution control centers. This 24,000-square foot, state-of-the-art facility, located in Fresno, California, will enhance electric reliability and resiliency for the Utility’s customers throughout the Central Valley and will utilize current and future Smart Grid technologies. Additional facilities in Rocklin and Concord, California, are expected to be completed in 2015 and 2016, respectively. These control centers form a key part of the Utility’s efforts to create a smarter, more resilient grid.
In 2014, the Utility replaced approximately 295,000 feet of underground cable, replaced approximately 975,000 feet of overhead wire, and installed or replaced 20 distribution substation transformer banks to improve reliability and provide capacity to accommodate growing demand. The Utility plans to continue performing work to improve the reliability and safety of its electricity distribution operations in 2015.
10
Electricity Operating Statistics
The following table shows certain of the Utility’s operating statistics from 2012 to 2014 for electricity sold or delivered, including the classification of revenues by type of service.
|
2014
|
2013
|
2012
|
||||||||||
|
Customers (average for the year)
|
5,276,025 | 5,243,216 | 5,214,170 | |||||||||
|
Deliveries (in GWh) (1)
|
86,303 | 86,513 | 86,113 | |||||||||
|
Revenues (in millions):
|
||||||||||||
|
Residential
|
$ | 4,784 | $ | 5,091 | $ | 4,953 | ||||||
|
Commercial
|
5,141 | 4,905 | 4,735 | |||||||||
|
Industrial
|
1,543 | 1,388 | 1,408 | |||||||||
|
Agricultural
|
1,172 | 1,021 | 901 | |||||||||
|
Public street and highway lighting
|
79 | 75 | 79 | |||||||||
|
Other (2)
|
(172 | ) | (128 | ) | (11 | ) | ||||||
|
Subtotal
|
12,547 | 12,352 | 12,065 | |||||||||
|
Regulatory balancing accounts (3)
|
1,109 | 137 | (51 | ) | ||||||||
|
Total operating revenues
|
$ | 13,656 | $ | 12,489 | $ | 12,014 | ||||||
|
Selected Statistics:
|
||||||||||||
|
Average annual residential usage (kWh)
|
6,458 | 6,752 | 5,961 | |||||||||
|
Average billed revenues per kWh:
|
||||||||||||
|
Residential
|
$ | 0.1603 | $ | 0.1643 | $ | 0.1594 | ||||||
|
Commercial
|
0.1585 | 0.1499 | 0.1449 | |||||||||
|
Industrial
|
0.0998 | 0.0928 | 0.917 | |||||||||
|
Agricultural
|
0.1516 | 0.1454 | 0.1458 | |||||||||
|
Net plant investment per customer
|
$ | 6,339 | $ | 6,002 | $ | 4,919 | ||||||
|
(1) These amounts include electricity provided to direct access customers and CCAs who procure their own supplies of electricity.
|
(2) This activity is primarily related to a remittance of revenue to the Department of Water Resources (“DWR”) (the Utility acts as a billing and collection agent on behalf of the DWR), partially offset by other miscellaneous revenue items.
(3) These amounts represent revenues authorized to be billed. The 2014 activity represents an increase to balancing account receivable primarily related to the adoption of the 2014 GRC.
11
The Utility provides natural gas transportation services to “core” customers (i.e., small commercial and residential customers) and to “non-core” customers (i.e., industrial, large commercial, and natural gas-fired electric generation facilities) that are connected to the Utility’s gas system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or non-utility third-party gas procurement service providers (referred to as core transport agents). When core customers purchase gas supply from a core transport agent, the Utility continues to provide gas delivery, metering and billing services to customers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, more than 91% of core customers, representing nearly 80% of the annual core market demand, receive bundled natural gas service from the Utility.
The Utility does not provide procurement service to non-core customers, who must purchase their gas supplies from third-party suppliers. The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility's backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers. The Utility also delivers gas to off-system customers (i.e., outside of the Utility’s service territory) and to third-party natural gas storage customers.
Natural Gas Supplies
The Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California. The Utility purchases natural gas to serve its core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2014, the Utility purchased approximately 269,590 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 17% of the total natural gas volume the Utility purchased during 2014.
Natural Gas System Assets
The Utility owns and operates an integrated natural gas transmission, storage, and distribution system that includes most of northern and central California. At December 31, 2014, the Utility’s natural gas system consisted of approximately 42,700 miles of distribution pipelines, over 6,400 miles of backbone and local transmission pipelines, and various storage facilities. The Utility owns and operates eight natural gas compressor stations on its backbone transmission system and one small station on its local transmission system that are used to move gas through the Utility’s pipelines. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems.
The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest, LLC, which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility also has firm transportation agreements with Ruby Pipeline, LLC to transport this gas from the U.S Rocky Mountains to the interconnection point with the Utility’s natural gas transportation system in the area of Malin, Oregon, at the California border, and firm transportation agreements with Transwestern Pipeline Company, LLC and El Paso Natural Gas Company to transport this natural gas from supply points in the U.S. Southwest to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona. The Utility also has a transportation agreement with Kern River Gas Transmission Company to transport gas from the U.S. Rocky Mountains to the interconnection point with the Utility’s natural gas system in the area of Daggett, California. For more information regarding the Utility’s natural gas transportation agreements, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
12
The Utility owns and operates three underground natural gas storage fields and has a 25% interest in a fourth storage field, all of which are connected to the Utility’s transmission system. The Utility owns and operates compressors and other facilities at these storage fields that are used to inject gas into the fields for storage and later withdrawal. In addition, four independent storage operators are interconnected to the Utility's northern California transmission system.
The Utility also owns and operates a 42,000-square-foot control center in San Ramon, California to monitor and control all aspects of its natural gas system across its service area.
During 2014, the Utility completed its system-wide replacement of 847 miles of cast iron natural gas distribution pipeline with plastic pipe. Additionally, the Utility conducted an annual system-wide review of its transmission pipeline class location designations. As part of its distribution integrity management program, during 2014 the Utility completed inspections of approximately 35,000 sewer laterals.
Since work began on the PSEP and other gas transmission work in 2011, the Utility has validated the maximum allowable operating pressure for all of its transmission pipelines through records verification; accomplished four-year goal of strength testing or records validation of 783 miles of transmission pipeline; replaced 127 miles of transmission pipeline; automated 208 valves; and collected and digitized more than 3.8 million pipeline records.
Natural Gas Operating Statistics
The following table shows the Utility's operating statistics from 2012 through 2014 (excluding subsidiaries) for natural gas, including the classification of revenues by type of service.
|
2014
|
2013
|
2012
|
||||||||||
|
Customers (average for the year)
|
4,394,283 | 4,378,797 | 4,353,278 | |||||||||
|
Gas purchased (MMcf)
|
202,215 | 240,414 | 247,792 | |||||||||
|
Average price of natural gas purchased
|
$ | 4.09 | $ | 3.29 | $ | 2.45 | ||||||
|
Bundled gas sales (MMcf):
|
||||||||||||
|
Residential
|
143,514 | 181,775 | 185,376 | |||||||||
|
Commercial
|
42,080 | 46,668 | 47,341 | |||||||||
|
Total Bundled Gas Sales
|
185,594 | 228,443 | 232,717 | |||||||||
|
Revenues (in millions):
|
||||||||||||
|
Bundled gas sales:
|
||||||||||||
|
Residential
|
$ | 1,683 | $ | 1,870 | $ | 1,852 | ||||||
|
Commercial
|
419 | 395 | 383 | |||||||||
|
Other
|
51 | 44 | 66 | |||||||||
|
Bundled gas revenues
|
2,153 | 2,309 | 2,301 | |||||||||
|
Transportation service only revenue
|
662 | 555 | 499 | |||||||||
|
Subtotal
|
2,815 | 2,864 | 2,800 | |||||||||
|
Regulatory balancing accounts
|
617 | 240 | 221 | |||||||||
|
Total operating revenues
|
$ | 3,432 | $ | 3,104 | $ | 3,021 | ||||||
|
Selected Statistics:
|
||||||||||||
|
Average annual residential usage (Mcf)
|
34 | 44 | 45 | |||||||||
|
Average billed bundled gas sales revenues per Mcf:
|
||||||||||||
|
Residential
|
$ | 11.72 | $ | 10.29 | $ | 9.99 | ||||||
|
Commercial
|
9.96 | 8.47 | 8.09 | |||||||||
|
Net plant investment per customer
|
$ | 2,468 | $ | 2,234 | $ | 1,696 | ||||||
13
Competition in the Electricity Industry
California law allows qualifying non-residential customers of investor-owned electric utilities to purchase electricity from energy service providers other than the regulated utilities, (referred to as “direct access”) up to certain annual and overall GWh limits that have been specified for each utility.
The Utility’s customers may, under certain circumstances, obtain power from a CCA instead of from the Utility. California law permits cities and counties and certain other public agencies to generate and/or purchase electricity for their local residents and businesses after they have registered as CCAs and submitted an Implementation Plan to the CPUC. Under these arrangements, the Utility continues to provide transmission, distribution, metering, and billing services to the customers of the CCAs and remains the electricity provider of last resort for those customers. The law provides that a CCA can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The Utility is able to recover from each CCA any costs of implementing the program that are reasonably attributable to the CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a CCA.
In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.
The Utility is also subject to increased competition due to the increasing viability of distributed generation and energy storage. The levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits at the full retail rate, are increasing.
Competition in the Natural Gas Industry
The Utility primarily competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.
The Utility’s operations are subject to extensive federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including the remediation of hazardous and radioactive substances; the discharge of pollutants into the air, water, and soil; the reporting and reduction of carbon monoxide (CO2 ) and other GHG emissions; the transportation, handling, storage and disposal of spent nuclear fuel; and the environmental impacts of land use, including endangered species and habitat protection. The penalties for violation of these laws and requirements can be severe and may include significant fines, damages, and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. (See Item 1A. Risk Factors.) Generally, the Utility has recovered most of the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean-up of most sites that contain hazardous substances are subject to a special ratemaking mechanism described in Note 14: Contingencies—Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in Item 8.
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Hazardous Waste Compliance and Remediation
The Utility's facilities are subject to the requirements of the federal Resource Conservation and Recovery Act and the Comprehensive Environmental Response, Compensation and Liability Act of 1980 as amended (CERCLA). The Utility is also subject to the regulations adopted by the EPA, the federal agency responsible for implementing the federal environmental laws. The Utility also must comply with environmental laws and regulations adopted by the State of California and various state and local agencies. These federal and state laws impose strict liability for the release of a hazardous substance on the (1) owner or operator of the site where the release occurred, (2) on companies that disposed of, or arranged for the disposal of, the hazardous substances, and (3) in some cases, their corporate successors. Under CERCLA these persons (known as “potentially responsible parties”) may be jointly and severally liable for the costs of cleaning up the hazardous substances, paying for the harm caused to natural resources, and paying for the costs of required health studies.
The Utility has a comprehensive program in place to comply with these federal, state, and local laws and regulations. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site. The Utility’s remediation activities are overseen by the California Department of Toxic Substances Control, several California regional water quality control boards, and various other federal, state, and local agencies. The Utility has incurred significant environmental remediation liabilities associated with former manufactured gas plant sites, power plant sites, gas gathering sites, sites where natural gas compressor stations are located, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous substances. Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility is responsible for remediating this groundwater contamination and for abating the effects of the contamination on the environment.
For more information about environmental remediation liabilities, see Note 14: Commitments and Contingencies−Environmental Remediation Contingencies, of the Notes to the Consolidated Financial Statements in Item 8.
Air Quality and Climate Change
The Utility's electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, CO2, sulfur dioxide (SO2), mono-nitrogen oxide (NOx), particulate matter, and other GHG emissions.
In December 2009, the EPA concluded that GHG emissions contribute to climate change and issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare. In May 2014, the United States released its third National Climate Assessment, which stated that the global climate is changing and that impacts related to climate change are already evident in many sectors and are expected to become increasingly disruptive across the nation throughout this century and beyond.
Federal Regulation. At the federal level, the EPA is charged with implementation and enforcement of the Clean Air Act. Although there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions, comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions.
In January 2014, the EPA published draft regulations under section 111(b) of the Clean Air Act to control CO2, the most common GHG, from new fossil fuel-fired power plants. While these draft regulations as presently written do not apply to the Utility’s power plants, it is possible that the final regulations may affect the design, construction, operation and cost of future fossil fuel-fired power plants. The EPA is expected to issue final regulations in 2015.
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In June 2014, the EPA published draft federal regulations under section 111(d) of the Clean Air Act that are designed to reduce CO2 emissions from existing fossil fuel-fired power plants on a national basis by as much as 30% by 2030, compared with 2005 levels. The EPA is expected to issue final regulations in 2015. As proposed, once the EPA has finalized regulations, states have up to two or three years to submit final plans depending on whether they work alone or in partnership with other states, and up to 15 years for full implementation of all emission reduction measures. It is uncertain whether and how these federal regulations will ultimately impact California, since existing state regulation currently requires, among other things, the gradual reduction of state-wide GHG emissions to 1990 levels by 2020. As described below, the Utility expects all costs and revenues associated with the state-wide, comprehensive cap-and-trade program to be passed through to customers.
State Regulation. California law requires the gradual reduction of state-wide GHG emissions to 1990 levels by 2020. The CARB has approved various regulations to implement AB 32, including GHG emissions reporting and a state-wide, comprehensive cap-and-trade program that sets gradually declining limits (or “caps”) on the amount of GHGs that may be emitted by major GHG emission sources within different sectors of the economy. The cap–and-trade program’s first compliance period, which began on January 1, 2013, applied to the electricity generation and large industrial sectors. The next compliance period, which began on January 1, 2015, expanded to include the natural gas and transportation sectors, effectively covering all the economy’s major sectors until 2020. The Utility’s compliance obligation as a natural gas supplier applies to the GHG emissions attributable to the combustion of natural gas delivered to the Utility’s customers other than natural gas delivery customers that are separately regulated as covered entities and have their own compliance obligation. During each year of the program, the CARB issues emission allowances (i.e., the rights to emit GHGs) equal to the amount of GHG emissions allowed for that year. Emitters can obtain allowances from the CARB at quarterly auctions or from third parties or exchanges. Emitters may also satisfy a portion of their compliance obligation through the purchase of offset credits; e.g., credits for GHG reductions achieved by third parties (such as landowners, livestock owners, and farmers) that occur outside of the emitters’ facilities through CARB-qualified offset projects such as reforestation or biomass projects. The Utility expects all costs and revenues associated with the GHG cap-and-trade program to be passed through to customers. The California RPS program that requires the utilities to gradually increase the amount of renewable energy delivered to their customers is also expected to help reduce GHG emissions in California.
Climate Change Mitigation and Adaptation Strategies. During 2014, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to plan for the actions that it will need to take to adapt to the likely impacts of climate change on the Utility’s future operations. The Utility regularly reviews the most relevant scientific literature on climate change such as sea level rise, temperature changes, rainfall and runoff patterns, and wildfire risk, to help the Utility identify and evaluate climate change-related risks and develop the necessary adaptation strategies. The Utility also engages with leaders from business, government, academia, and non-profit organizations to share information and plan for the future.
With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme, persistent, and frequent hot weather. The Utility believes its strategies to reduce GHG emissions—through energy efficiency and demand response programs, infrastructure improvements, and the use of renewable energy and energy storage—are effective strategies for adapting to the expected increase in demand for electricity. The Utility’s vegetation management activities also reduce the risk of wildfire impacts on electric and gas facilities. Over the long-term, the Utility also faces the risk of higher flooding potential at coastal and low elevation facilities due to sea level rise.
Climate scientists also predict that climate change will result in significant reductions in snowpack in parts of the Sierra Nevada Mountains. This could, in turn, affect the Utility’s hydroelectric generation. To plan for this potential change, the Utility is engaging with state and local stakeholders and also adopting strategies such as maintaining higher winter carryover reservoir storage levels, reducing discretionary reservoir water releases, and developing new modeling tools for forecasting runoff.
With respect to natural gas operations, both safety-related pipeline strength testing and normal pipeline maintenance and operations release the GHG methane into the atmosphere. The Utility has taken steps to reduce the release of methane by implementing techniques including drafting and cross-compression, which reduce the pressure and volume of natural gas within pipelines prior to venting. In addition, the Utility continues to replace a substantial portion of its older cast iron, steel and plastic distribution pipelines and steel gas transmission mains with new pipe, which reduces leakage.
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Emissions Data
PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility reports its GHG emissions to the CARB and the EPA on a mandatory basis. On a voluntary basis, The Utility reports a more comprehensive emissions inventory to The Climate Registry, a non-profit organization. The Utility’s third-party verified voluntary GHG inventory reported to The Climate Registry for 2013 totaled more than 57 million metric tonnes of CO2-e, two-thirds of which came from natural gas use. The following table shows the 2013 GHG emissions data the Utility reported to the CARB under AB 32. PG&E Corporation and the Utility publish additional GHG emissions data in their annual Corporate Responsibility and Sustainability Report.
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Amount (metric tonnes CO2 – equivalent)
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||||
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Fossil Fuel-Fired Plants (1)
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2,382,463 | |||
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Natural Gas Compressor Stations (2)
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325,701 | |||
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Distribution Fugitive Natural Gas Emissions
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213,858 | |||
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Customer Natural Gas Use (3)
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43,506,493 | |||
(1) Includes nitrous oxide and methane emissions from the Utility’s generating stations.
(2) Includes compressor stations emitting more than 25,000 metric tonnes of CO2-e annually.
(3) Includes emissions from the combustion of natural gas delivered to all entities on the Utility’s distribution system, including entities that have their own compliance obligation under AB 32. The Utility’s compliance obligation under AB 32 (discussed above under “State Regulation”) applies to the combustion of natural gas delivered to customers other than customers that have their own compliance obligation. Excluding the GHG emissions of entities that have their own compliance obligation, the Utility’s GHG emissions for 2013 were approximately 19 million metric tonnes, as calculated by the CARB.
The following table shows the Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2013 as compared to the national and California averages for electric utilities:
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Amount (Pounds of CO2 per MWh)
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||||
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U.S. Average (1)
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1,232 | |||
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California’s Average (1)
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611 | |||
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Pacific Gas and Electric Company (2)
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427 | |||
(1) Source: EPA eGRID.
(2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s emissions rate.
Air Emissions Data for Utility-Owned Generation
In addition to GHG emissions data provided above, the table below sets forth information about the air emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36.4% of the Utility’s delivered electricity in 2013. PG&E Corporation and the Utility also publish air emissions data in their annual Corporate Responsibility and Sustainability Report.
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2013
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2012
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|||||||
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Total NOx Emissions (tons)
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153 | 158 | ||||||
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NOx Emissions Rate (pounds/MWh)
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0.01 | 0.01 | ||||||
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Total SO2 Emissions (tons)
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17 | 15 | ||||||
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SO2 Emissions Rate (pounds/MWh)
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0.0011 | 0.0009 | ||||||
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Water Quality
On May 19, 2014, the EPA issued final regulations to implement the requirements of the federal Clean Water Act that require cooling water intake structures at electric power plants, such as the nuclear generation facilities at Diablo Canyon, to reflect the best technology available to minimize adverse environmental impacts. The federal regulations provide more flexibility in complying with some of the Clean Water Act’s requirements. Various industry and environmental groups have challenged the federal regulations in proceedings pending in the U.S. Court of Appeals for the Fourth Circuit. California’s once-through cooling policy discussed below is considered to be at least as stringent as the new federal regulations. Therefore, California’s implementation process for the state policy will likely continue without any significant change.
At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. The California Water Board has appointed a committee to evaluate the feasibility and cost of using alternative technologies to achieve compliance at Diablo Canyon. The committee’s consultant submitted its final report to the California Water Board in September 2014 and the board is expected to issue a final decision regarding Diablo Canyon’s compliance with the state policy in 2015. If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliances measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the California Water Board’s policy by December 31, 2024.
The final requirements of the federal and state cooling water policies could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. (See “Diablo Canyon Power Plant” in Item 3. Legal Proceedings below.)
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982, the DOE and electric utilities with commercial nuclear power plants were authorized to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste by January 1998, in exchange for fees paid by the utilities’ customers. The DOE has been unable to meet its contractual obligation with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and the retired nuclear facility at Humboldt Bay. As a result, the Utility constructed interim dry cask storage facilities to store its spent fuel onsite at Diablo Canyon and at Humboldt Bay until such time as the DOE fulfills its contractual obligation to take possession of the spent fuel. The Utility and other nuclear power plant owners sued the DOE to recover the costs that they incurred to construct interim storage facilities for spent nuclear fuel.
In September 2012, the U.S. Department of Justice and the Utility executed a settlement agreement that awarded the Utility $266 million for spent fuel storage costs incurred through December 31, 2010. The settlement agreement also provided a claims process by which the Utility submits annual requests for reimbursement of its ongoing spent fuel storage costs. In 2013 and 2014, the Utility was awarded an additional $50 million for costs incurred between 2011 and July 2014. These proceeds are being refunded to customers through rates. The settlement agreement, as amended, does not address costs incurred for spent fuel storage beyond 2016 and such costs could be subject to future litigation. Considerable uncertainty continues to exist regarding when and whether the DOE will meet its contractual obligation to the Utility and other nuclear power plant owners to dispose of spent fuel.
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PG&E Corporation’s and the Utility’s financial results are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. (Also see Cautionary Language Regarding Forward-Looking Statements in Item 7. MD&A.) In addition to other disclosures within this Form 10-K, including MD&A in Item 7 and Note 2: Summary of Significant Accounting Policies in the Notes to the Consolidated Financial Statements in Item 8 and other documents filed with the SEC from time to time, the following key risk factors should be considered in evaluating an investment in PG&E Corporation and the Utility. Such factors could affect actual results of operations and cause results to differ substantially from historical results or from results that are currently sought.
Risks Related to the Outcome of Enforcement Matters, Investigations, and Regulatory Proceedings
PG&E Corporation’s and the Utility’s financial results could be materially affected by the outcomes of the CPUC investigative enforcement proceedings pending against the Utility, the federal criminal prosecution of the Utility, and the investigations and other potential enforcement matters discussed in Item 7. MD&A.
In September 2014, the CPUC ALJs overseeing the three investigative enforcement proceedings against the Utility issued a decision to impose total penalties of $1.4 billion on the Utility based on their findings that the Utility committed approximately 3,700 violations of natural gas regulations. The Utility and other parties have appealed these decisions. (See “Enforcement and Litigation Matters – Pending CPUC Investigations” in Item 7. MD&A.) The CPUC could issue a final decision that imposes a materially higher amount of penalties. The impact on PG&E Corporation’s and the Utility’s consolidated financial statements will vary depending on the forms and amounts of penalties imposed.
Further, if the Utility is convicted of the pending federal criminal charges, 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. (See “Enforcement and Litigation Matters – Federal Criminal Indictment” in Item 7. MD&A.) 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.
The CPUC could impose penalties or take other enforcement action with respect to communications that may have violated the CPUC’s rules regarding ex parte communications (See “Enforcement and Litigation Matters – Improper CPUC Communications” in Item 7. MD&A.) In response to the Utility’s violations of the CPUC’s rules regarding ex parte communications relating to the 2015 GT&S rate case, the CPUC issued a decision to disallow up to the entire amount of incremental revenues that would have been collected from ratepayers over the five-month period between March 2015 and August 2015. The exact amount of the revenue disallowance will be determined in the CPUC’s final decision in the 2015 GT&S rate case. See “Ratemaking and Other Regulatory Proceedings – 2015 Gas Transmission and Storage Rate Case” in Item 7. MD&A. Federal and state law enforcement authorities have begun investigations in connection with these matters and they could take enforcement action in the future. The Utility could be subject to additional penalties or reputational harm if it fails to comply with the restrictions on communications between the Utility and the CPUC imposed by the CPUC in November 2014.
In addition, the Utility could incur material charges, including fines and other penalties, in connection with the new CPUC investigation of the Utility’s compliance with natural gas distribution record-keeping practices, the self-reports the Utility has submitted to the CPUC in accordance with the SED’s gas safety citation program, the SED’s audit findings, the other matters discussed in “Enforcement and Litigation Matters” in Item 7. MD&A, and other self-reports the Utility may file under the gas safety program or under the new electric safety program.
The Utility could be subject to additional regulatory or governmental enforcement action with respect to compliance with federal, state or local laws, regulations or orders that could result in additional fines, penalties or customer refunds, including those regarding renewable energy and resource adequacy requirements; customer billing; customer service; affiliate transactions; vegetation management; design, construction, operating and maintenance practices; safety and inspection practices; and federal electric reliability standards. The amount of such fines, penalties, or customer refunds could have a material effect on PG&E Corporation’s and the Utility’s financial results.
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PG&E Corporation’s and the Utility’s financial results depend upon the amount of revenues the Utility is authorized to collect through rates and the Utility’s ability to manage its operating expenses so that it is able to earn its authorized rate of return in a timely manner.
As a regulated entity, the Utility’s rates are set by the CPUC or the FERC on a prospective basis and are generally designed to allow the Utility to collect sufficient revenues to recover the costs of providing service, including a return on and of its capital investments. PG&E Corporation’s and the Utility’s financial results could be materially affected if the CPUC or the FERC does not authorize sufficient revenues for the Utility to safely and reliably serve its customers and earn its authorized ROE. The outcome of the Utility’s ratemaking proceedings can be affected by many factors, including the level of opposition by intervening parties; general economic conditions and potential rate impacts; increasing levels of regulatory review; changes in the political, regulatory, or legislative environments; and the opinions of the Utility’s regulators, consumer and other stakeholder organizations, and customers, about the Utility’s ability to provide safe, reliable, and affordable electric and gas services. As the Utility’s reputation continues to suffer from the negative media coverage of the ongoing enforcement proceedings, the risk of adverse regulatory outcomes may increase. In addition, the restrictions on communications between the Utility and the CPUC imposed by the CPUC in November 2014 prevent the Utility from fully participating in the regulatory process, which, in turn may affect regulatory outcomes. The Utility’s relationship with the CPUC also may be negatively affected depending on what, if any, future action may be taken, or negative media coverage that may be generated, in response to the release of approximately 65,000 emails between the Utility and the CPUC to the CPUC and the City of San Bruno.
In addition to the amount of authorized revenues, PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility’s actual costs to safely and reliably serve its customers differ from authorized or forecast costs. The Utility may incur additional costs for many reasons including changing market circumstances, unanticipated events (such as storms, accidents, catastrophic or other events affecting the Utility’s operations), or compliance with new state laws or policies. Although the Utility may be allowed to recover some or all of the additional costs, there may be a substantial time lag between when the Utility incurs the costs and when the Utility is authorized to collect revenues to recover such costs. Alternatively, the CPUC or the FERC may disallow costs that they determine were not reasonably or prudently incurred by the Utility.
The Utility’s ability to recover its costs also may be affected by the economy and the economy’s corresponding impact on the Utility’s customers. For example, a sustained downturn or sluggishness in the economy could reduce the Utility’s sales to industrial and commercial customers or the level of uncollectible bills could increase. Although the Utility generally recovers its costs through rates, regardless of sales volume, rate pressures increase when the costs are borne by a smaller sales base.
Changes in commodity prices also may have an adverse effect on the Utility’s ability to timely recover its operating costs and earn its authorized ROE. Although the Utility generally recovers its electricity and natural gas procurement costs from customers as “pass-through” costs, a significant and sustained rise in commodity prices could create overall rate pressures that make it more difficult for the Utility to recover its costs that are not categorized as “pass-through” costs. To relieve some of this upward rate pressure, the CPUC could authorize lower revenues than the Utility requested or disallow full cost recovery. Further, should the deployment of new electricity generation and energy storage technologies spread and become more cost-effective, the Utility’s ability to recover its investments and earn its authorized ROE could be adversely affected unless rates are appropriately adjusted. Also, a confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service, which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments.
PG&E Corporation’s and the Utility’s future financial results could be materially affected by the extent to which its natural gas transmission costs exceed authorized revenues and whether the Utility is able to continue using regulatory accounting for its natural gas transmission business.
The Utility’s ability to recover its natural gas transmission and storage costs in 2015, 2016, and 2017 and earn its authorized ROE will be materially affected by the amount of revenues the CPUC ultimately authorizes the Utility to collect in the 2015 GT&S rate case proceeding. (See “Ratemaking and Other Regulatory Proceedings” in Item 7. MD&A.) In addition, the Utility plans to perform certain work during 2015 through 2017, including work to complete projects under the PSEP and to identify and remove encroachments from gas transmission pipeline rights-of-way. The Utility has not sought to recover the costs it incurs to perform this work. Actual costs to perform this work could materially exceed forecasts and negatively affect PG&E Corporation’s and the Utility’s results of operations. The Utility expects that it will continue to incur costs to respond to public opposition to the Utility’s work to remove trees and other encroachments. The media attention to the Utility’s encroachment work also may negatively affect the Utility’s reputation.
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If rates in the 2015 GT&S rate case and future rate cases are not set at a level that allows the Utility to recover the cost of providing natural gas transmission service and a reasonable return on its investment in future periods, the Utility may be required to discontinue the application of regulatory accounting to its natural gas transmission business. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8 as well as "Critical Accounting Policies" in Item 7. MD&A.) If that occurs, the regulatory assets and liabilities that do not qualify for regulatory accounting treatment would be charged against income in the period in which that determination was made and these charges could have a material impact on PG&E Corporation’s and the Utility’s financial results. In addition, if regulatory accounting did not apply, the Utility’s future financial results could become more volatile as compared to historical financial results due to the differences in the timing of expense or gain recognition.
PG&E Corporation’s and the Utility’s financial results depend upon the Utility’s continuing ability to recover “pass-through” costs, including electricity and natural gas procurement costs, from customers in a timely manner. The CPUC may disallow procurement costs for a variety of reasons. In addition, the Utility’s ability to recover these costs could be affected by the loss of Utility customers and decreased new customer growth, if the CPUC fails to adjust the Utility’s rates to reflect such events.
The Utility meets customer demand for electricity from a variety of sources, including electricity generated from the Utility’s own generation facilities, electricity provided by third parties under power purchase agreements, and purchases on the wholesale electricity market. The Utility must manage these sources using the commercial and CPUC regulatory principles of “least cost dispatch” and prudent administration of power purchase agreements in compliance with its CPUC-approved long-term procurement plan. The CPUC could disallow procurement costs incurred by the Utility if the CPUC determines that the Utility did not comply with these principles or if the Utility did not comply with its procurement plan. Further, the contractual prices for electricity under the Utility’s power purchase agreements could become uneconomic in the future for a variety of reasons, including developments in alternative energy technology, increased self-generation by customers, an increase in distributed generation, and lower customer demand due to adverse economic conditions or the loss of the Utility’s customers to other generation providers. Despite original CPUC approval of the contracts, the CPUC could disallow contract costs if it determines that the costs are unreasonably above market. The Utility also could incur a CPUC disallowance and/or liability to the counterparties under its contracts to procure electricity from conventional and renewable generation resources if such resources are physically curtailed by the CAISO during periods of over-generation when generation resources scheduled with the CAISO exceed customer load.
The Utility’s ability to recover the costs it incurs in the wholesale electricity market may be affected by the whether the wholesale electricity market in California continues to function effectively. Although market mechanisms are designed to limit excessive prices, these market mechanisms could fail, or the related systems and software on which the market mechanisms rely may not perform as intended which could result in excessive market prices. The CPUC could prohibit the Utility from passing through the higher costs of electricity to customers. For example, during the 2000 and 2001 energy crisis, the market mechanism flaws in California’s then-newly established wholesale electricity market led to dramatically high market prices for electricity that the Utility was unable to recover through customer rates, ultimately causing the Utility to file a petition for reorganization under Chapter 11 of the U.S. Bankruptcy Code.
Further, PG&E Corporation’s and the Utility’s financial results could be affected by the loss of Utility customers and decreased new customer growth that occurs through municipalization of the Utility’s facilities, an increase in the number of CCAs who provide electricity to their residents, and an increase in the number of consumers who become direct access customers of alternative generation providers. (See “Competition in the Electric Industry” in Item 1.) As the number of bundled customers (i.e., those primarily residential customers who receive electricity and distribution service from the Utility) declines, the rates for remaining customers could increase as the Utility would have a smaller customer base from which to recover its procurement costs. Although the Utility is permitted to collect non-bypassable charges for generation-related costs incurred on behalf of former customers, as well as charges for distribution, metering, or other services the Utility continues to provide to such customers, the charges may not be sufficient for the Utility to fully recover the costs to provide these services. In addition, the Utility’s ability to collect non-bypassable charges has been, and may continue to be, challenged by certain customer groups. Furthermore, if the former customers return to receiving electricity supply from the Utility, the Utility could incur costs to meet their electricity needs that it may not be able to timely recover through rates or that it may not be able to recover at all.
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In addition, increasing levels of self-generation of electricity by customers (primarily solar installations) and the use of customer net energy metering, which allows self-generating customers to receive bill credits for surplus power at the full retail rate, could put upward rate pressure on remaining customers. Also, a confluence of technology-related cost declines and sustained federal or state subsidies could make a combination of distributed generation and energy storage a viable, cost-effective alternative to the Utility’s bundled electric service which could further threaten the Utility’s ability to recover its generation, transmission, and distribution investments. If the number of the Utility’s customers decreases or grows at a slower rate than anticipated, the Utility’s level of capital investment would likely decline as well, in turn leading to a slower growth in rate base and earnings. Reduced energy demand or significantly slowed growth in demand due to customer migration to other energy providers, adoption of energy efficient technology, conservation, increasing levels of distributed generation and self-generation, unless substantially offset through regulatory cost allocations, could adversely impact PG&E Corporation’s and the Utility’s financial results.
PG&E Corporation’s and the Utility’s financial results could be materially affected if the Utility is unable to recover a material portion of its procurement costs and/or if the CPUC fails to adjust the Utility’s rates to reflect the impact of changing loads, the wide deployment of distributed generation, and the development of new electricity generation and energy storage technologies.
Risks Related to Liquidity and Capital Requirements
PG&E Corporation’s and the Utility’s financial results will be affected by their ability to continue accessing the capital markets and by the terms of debt and equity financings.
PG&E Corporation’s and the Utility’s ability to access the capital and credit markets and the costs and terms of available financing depend on many factors, including the ultimate outcome of the matters discussed under “Enforcement and Litigation Matters” in Item 7. MD&A., the ultimate amount of costs the Utility incurs but does not recover through rates, and the outcome of pending and future ratemaking proceedings. These outcomes in turn can affect PG&E Corporation’s and the Utility’s credit ratings and outlook. If PG&E Corporation’s or the Utility’s credit ratings were downgraded to below investment grade, their ability to access the capital and credit markets would be negatively affected and could result in higher borrowing costs, fewer financing options, including reduced access to the commercial paper market, additional collateral posting requirements, which in turn could affect liquidity and lead to an increased financing need. Other factors can affect the availability and terms of debt and equity financing, including changes in the federal or state regulatory environment affecting energy companies generally or PG&E Corporation and the Utility in particular, the overall health of the energy industry, volatility in electricity or natural gas prices, and general economic and financial market conditions.
The reputations of PG&E Corporation and the Utility continue to suffer from the negative publicity about the CPUC investigations, the criminal investigations, the criminal prosecution, and the other pending enforcement matters. Their negative reputations and continuing uncertainty surrounding the outcomes of these matters may undermine investors’ confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment. As a result, investors may be less willing to buy shares of PG&E Corporation common stock resulting in a lower stock price. Further, the market price of PG&E Corporation common stock could decline materially after the outcomes are determined. The amount and timing of future share issuances also could affect the stock price. Declines in the stock price would increase the dilutive effect of future stock issuances and make it more difficult or expensive for PG&E Corporation to complete future equity offerings.
If the Utility were unable to access the capital markets, it could be required to decrease or suspend dividends to PG&E Corporation and PG&E Corporation could be required to contribute capital to the Utility to enable the Utility to fulfill its obligation to serve. To maintain PG&E Corporation’s dividend level in these circumstances, PG&E Corporation would be further required to access the capital or credit markets. PG&E Corporation may need to decrease or discontinue its common stock dividend if it is unable to access the capital or credit markets on reasonable terms.
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PG&E Corporation’s ability to meet its debt service and other financial obligations and to pay dividends on its common stock depends on the Utility’s earnings and cash flows.
PG&E Corporation is a holding company with no revenue generating operations of its own. The Utility must use its resources to satisfy its own obligations, including its obligation to serve customers, to pay principal and interest on outstanding debt, to pay preferred stock dividends, and meet its obligations to employees and creditors, before it can distribute cash to PG&E Corporation. Under the CPUC’s rules applicable to utility holding companies, the Utility’s dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company and PG&E Corporation’s Board of Directors give “first priority” to the Utility’s capital requirements, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. The CPUC has interpreted this “first priority” obligation to include the requirement that PG&E Corporation “infuse the Utility with all types of capital necessary for the Utility to fulfill its obligation to serve.” In addition, before the Utility can pay common stock dividends to PG&E Corporation, the Utility must maintain its authorized capital structure with an average 52% equity component.
Depending on the outcome of the CPUC investigations, criminal prosecution, and other enforcement matters pending against the Utility, future issuances of PG&E Corporation common stock may materially dilute EPS. (See “Liquidity and Financial Resources” in Item 7. MD&A.) Further, if PG&E Corporation were required to infuse the Utility with significant capital or if the Utility was unable to distribute cash to PG&E Corporation, or both, PG&E Corporation may be unable to pay principal and interest on its outstanding debt, pay its common stock dividend or meet other obligations.
PG&E Corporation’s and the Utility’s ability to pay dividends also could be affected by financial covenants contained in their respective credit agreements that require each company to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.
Risks Related to Operations and Information Technology
The operations of the Utility’s electricity and natural gas generation, transmission, and distribution facilities is inherently dangerous and involves significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s financial results, and the Utility’s insurance may not be sufficient to cover losses caused by an operating failure or catastrophic event.
The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive hydroelectric generating system. (See “Utility Operations” in Item 1. Business.) The Utility’s ability to earn its authorized ROE depends on its ability to efficiently maintain, operate, and protect its facilities, and provide electricity and natural gas services safely and reliably. The Utility undertakes substantial capital investment projects to construct, replace, and improve its electricity and natural gas facilities. In addition, the Utility is obligated to decommission its electricity generation facilities at the end of their useful operating lives. The Utility’s ability to safely and reliably operate, maintain, construct and decommission its facilities is subject to numerous risks, many of which are beyond the Utility’s control, including those that arise from:
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the breakdown or failure of equipment, electric transmission or distribution lines, or natural gas transmission and distribution pipelines, that can cause explosions, fires, or other catastrophic events (such as the San Bruno accident discussed in Item 7. MD&A.);
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the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;
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the failure of a large dam or other major hydroelectric facility, or the failure of one or more levees that protect land on which the Utility’s assets are built;
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the failure to take expeditious or sufficient action to mitigate operating conditions, facilities, or equipment, that the Utility has identified, or reasonably should have identified, as unsafe, which failure then leads to a catastrophic event (such as a wild land fire or natural gas explosion), and the failure to respond effectively to a catastrophic event;
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severe weather events such as storms, tornadoes, floods, drought, earthquakes, tsunamis, wild land and other fires, pandemics, solar events, electromagnetic events, or other natural disasters;
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operator or other human error;
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construction performed by third parties, such as ground excavation or “dig-ins” that damage the Utility’s underground facilities;
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the release of hazardous or toxic substances into the air, water, or soil; and
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attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.
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The occurrence of any of these events could interrupt fuel supplies; affect demand for electricity or natural gas; cause unplanned outages or reduce generating output; damage the Utility’s assets or operations; damage the assets or operations of third parties on which the Utility relies; damage property owned by customers or others; and cause personal injury or death. As a result, the Utility could incur costs to purchase replacement power, to repair assets and restore service, to compensate third parties, or to pay penalties or implement remedial measures. These costs may not be recoverable through rates or insurance and could have a material impact of PG&E Corporation’s financial results and reputation. As an example, see the discussion in Item 7. MD&A. of the Utility’s unrecovered pipeline-related costs incurred since the San Bruno accident.
Further, although the Utility often enters into agreements for third-party contractors to perform work, such as patrolling and inspection of facilities or the construction or demolition or facilities, the Utility may retain liability for the quality and completion of the contractor’s work and can be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. Insurance, equipment warranties, or other contractual indemnification requirements may not be sufficient or effective to provide full or even partial recovery under all circumstances or against all hazards or liabilities to which the Utility may become subject. An uninsured loss could have a material effect on PG&E Corporation’s and the Utility’s financial results. Future insurance coverage may not be available at rates and on terms as favorable as the Utility’s current insurance coverage or may not be available at all.
The Utility’s operational and information technology systems could fail to function properly or be damaged by third parties (including cyber-attacks and acts of terrorism), severe weather, natural disasters, or other events. Any of these events could disrupt the Utility’s operations and cause the Utility to incur unanticipated losses and expense or liability to third parties.
The operation of the Utility’s extensive electricity and natural gas systems rely on evolving information and operational technology systems and network infrastructures that are becoming more complex as new technologies and systems are implemented to modernize capabilities to safely and reliably deliver gas and electric services. The Utility’s ability to serve its customers requires the continued operation of complex information technology systems and network infrastructure that are interconnected with the systems and infrastructure owned by third parties. The Utility’s business is highly dependent on its ability to process and monitor, on a daily basis, a very large number of tasks and transactions, many of which are highly complex. Despite implementation of security measures, all of the Utility’s technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. The failure of the Utility’s information and operational systems and networks due to a physical attack, cyber-attack or other cause could significantly disrupt operations; cause harm to the public or employees; result in outages or reduced generating output; damage the Utility’s assets or operations or those of third parties; and subject the Utility to claims by customers or third parties, any of which could have a material effect on PG&E Corporation’s and the Utility’s financial results.
The Utility’s systems, including its financial information, operational systems, advanced metering, and billing systems, require ongoing maintenance, modification, and updating, which can be costly and increase the risk of errors and malfunction. The Utility often relies on third-party vendors to maintain, modify, and update its systems and these third-party vendors could cease to exist. Any disruptions or deficiencies in existing systems, or disruptions, delays or deficiencies in the modification or implementation of new systems, could result in increased costs, the inability to track or collect revenues, the diversion of management’s and employees’ attention and resources, and could negatively affect the effectiveness of the Utility’s control environment, and/or the Utility’s ability to timely file required regulatory reports.
In addition, the Utility’s information systems contain confidential information, including information about customers and employees. The theft, damage, or improper disclosure of confidential information can subject the Utility to penalties for violation of applicable privacy laws, subject the Utility to claims from third parties, reduce the value of proprietary information, and harm the Utility’s reputation.
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The operation and decommissioning of the Utility’s nuclear power plants expose it to potentially significant liabilities and the Utility may not be able to fully recover its costs if regulatory requirements change or the plant ceases operations before the licenses expire.
The operation of the Utility’s nuclear generation facilities exposes it to potentially significant liabilities from environmental, health and financial risks, such as risks relating to the storage, handling and disposal of spent nuclear fuel, the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act. The operation of the nuclear facilities also depends on the availability of adequate fuel supplies. If the Utility incurs losses that are either not covered by insurance or exceed the amount of insurance available, such losses could have a material effect on PG&E Corporation’s and the Utility’s financial results. In addition, the Utility may be required under federal law to pay up to $255 million of liabilities arising out of each nuclear incident occurring not only at the Utility’s Diablo Canyon facility but at any other nuclear power plant in the United States. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
In addition, the Utility continues to face public concern about the safety of nuclear generation and nuclear fuel. Some of these nuclear opposition groups regularly file petitions at the NRC and in other forums challenging the actions of the NRC and urging governmental entities to adopt laws or policies in opposition to nuclear power. Although an action in opposition may ultimately fail, regulatory proceedings may take longer to conclude and be more costly to complete. It is also possible that public pressure could grow and that future changes in legislation, regulations, orders, or their interpretation, could result in the Utility ceasing operations at Diablo Canyon before the licenses expire. In such an instance, the Utility could be required to record a charge for the remaining amount of its unrecovered investment and such charge could have a material effect on PG&E Corporation and the Utility’s financial results.
The Utility has incurred, and may continue to incur, substantial costs to comply with NRC regulations and orders. (See “Regulatory Environment” in Item 1. Business.) If the Utility were unable to recover these costs, PG&E Corporation’s and the Utility’s financial results could be materially affected. The Utility may determine that it cannot comply with the new regulations or orders in a feasible and economic manner and voluntarily cease operations; alternatively, the NRC may order the Utility to cease operations until it can comply with new regulations, orders, or decisions. The Utility may incur a material charge if it ceases operations at Diablo Canyon before the licenses expire.
At the state level, the California Water Board has adopted a policy on once-through cooling that generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities in California by at least 85%. If the California Water Board requires the installation of cooling towers that the Utility believes are not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Even if the Utility is not required to install cooling towers, it could incur significant costs to comply with alternative compliances measures or to make payments to support various environmental mitigation projects.
The Utility also has an obligation to decommission its electricity generation facilities, including its nuclear facilities, as well as gas transmission system assets, at the end of their useful lives. (See Note 2: Summary of Significant Accounting Policies – Asset Retirement Obligations of the Notes to the Consolidated Financial Statement in Item 8.) The CPUC authorizes the Utility to recover its estimated costs to decommission its nuclear facilities through nuclear decommissioning charges that are collected from customers and held in nuclear decommissioning trusts to be used for the eventual decommissioning of each nuclear unit. If the Utility’s actual decommissioning costs, including the amounts held in the nuclear decommissioning trusts, exceed estimated costs, PG&E Corporation’s and the Utility’s financial results could be materially affected.
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Risks Related to Environmental Factors
The Utility’s operations are subject to extensive environmental laws and changes in or liabilities under these laws could adversely affect PG&E Corporation’s and the Utility’s financial results.
The Utility’s operations are subject to extensive federal, state, and local environmental laws, regulations, orders, relating to air quality, water quality and usage, remediation of hazardous wastes, and the protection and conservation of natural resources and wildlife. The Utility incurs significant capital, operating, and other costs associated with compliance with these environmental statutes, rules, and regulations. The Utility has been, and may be, required to pay for environmental remediation costs at sites where it is identified as a potentially responsible party under federal and state environmental laws. Although the Utility has recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the applicable remediation levels, and the financial ability of other potentially responsible parties. (See Note 14 to the Notes to the Consolidated Financial Statements in Item 8 for more information.)
Environmental remediation costs could increase in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application of existing environmental regulations. Failure to comply with these laws and regulations, or failure to comply with the terms of licenses or permits issued by environmental or regulatory agencies, could expose the Utility to claims by third parties or the imposition of civil or criminal fines or other sanctions.
The CPUC has authorized the Utility to recover its environmental remediation costs for certain sites through various ratemaking mechanisms. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites without a reasonableness review. The CPUC may discontinue or change these ratemaking mechanisms in the future or the Utility may incur environmental costs that exceed amounts the CPUC has authorized the Utility to recover in rates.
Some of the Utility’s environmental costs, such as the remediation costs associated with the Hinkley natural gas compressor site, are not recoverable through rates or insurance. (See “Environmental Regulation” in Item 1.) The Utility’s costs to remediate groundwater contamination near the Hinkley natural gas compressor site and to abate the effects of the contamination have had, and may continue to have, a material effect on PG&E Corporation’s and the Utility’s financial results. Their financial results also can be materially affected by changes in estimated costs and by the extent to which actual remediation costs differ from recorded liabilities.
The Utility’s future operations may be affected by climate change that may have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.
The Utility has been studying the potential effects of climate change (increased temperatures, reduced precipitation, rising sea levels) on the Utility’s operations and is developing contingency plans to adapt to those events and conditions that the Utility believes are most significant. Scientists project that climate change will increase electricity demand due to more extreme, persistent and hot weather. Increasing temperatures and lower levels of precipitation in the Utility’s service territory would reduce snowpack in the Sierra Mountains. If the levels of snowpack were reduced, the Utility’s hydroelectric generation would decrease and the Utility would need to acquire additional generation from other sources at a greater cost. Should the Utility increase reliance on conventional generation resources to replace hydroelectric generation and to meet increased customer demand, it may become more costly for the Utility to comply with GHG emissions limits. In addition, increasing temperatures and lower levels of precipitation could increase the occurrence of wildfires in the Utility’s service territory causing damage to the Utility’s facilities or the facilities of third parties on which the Utility relies to provide service. In addition, flooding caused by rising sea levels could damage the Utility’s facilities, including hydroelectric assets such as dams and canals, and the electric transmission assets that are located on levees throughout the Utility’s service territory. The Utility could incur substantial costs to repair or replace facilities, restore service, compensate customers and other third parties for damages or injuries. The Utility anticipates that the increased costs would be recovered through rates, but as rate pressures increase, the likelihood of disallowance or non-recovery may increase.
Events or conditions caused by climate change could have a greater impact on the Utility’s operations than the Utility’s studies suggest and could result in lower revenues or increased expenses, or both. If the CPUC fails to adjust the Utility’s rates to reflect the impact of events or conditions caused by climate change, PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows could be materially affected.
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Other Risk Factors
The Utility may be required to incur substantial costs in order to obtain or renew licenses and permits needed to operate the Utility’s business and the Utility may be subject to fines and penalties for failure to comply or obtain license renewal.
The Utility must comply with the terms of various governmental permits, authorizations, and licenses, including those issued by the FERC for the continued operation of the Utility’s hydroelectric generation facilities, and those issued by environmental and other federal, state and local governmental agencies. Many of the Utility’s capital investment projects, and some maintenance activities, often require the Utility to obtain land use, construction, environmental, or other governmental permits. These permits, authorizations, and licenses may be difficult to obtain on a timely basis, causing work delays. Further, existing permits and licenses could be revoked or modified by the agencies that granted them if facts develop that differ significantly from the facts assumed when they were issued. In addition, the Utility often seeks periodic renewal of a license or permit, such as a waste discharge permit or a FERC operating license for a hydroelectric generation facility. If a license or permit is not renewed for a particular facility and the Utility is required to cease operations at that facility, the Utility could incur an impairment charge or other costs. Before renewing a permit or license, the issuing agency may impose additional requirements that may increase the Utility’s compliance costs. In particular, in connection with a license renewal for one or more of the Utility’s hydroelectric generation facilities or assets, the FERC may impose new license conditions that could, among other things, require increased expenditures or result in reduced electricity output and/or capacity at the facility. In addition, local governments may attempt to assert jurisdiction over various utility operations by requiring permits or other approvals that the Utility has not been previously required to obtain.
The Utility may incur penalties and sanctions for failure to comply with the terms and conditions of licenses and permits which could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. If the Utility cannot obtain, renew, or comply with necessary governmental permits, authorizations, licenses, ordinances, or other requirements, or if the Utility cannot recover the increase in associated compliance and other costs in a timely manner, PG&E Corporation’s and the Utility’s financial results could be materially affected.
Poor investment performance or other factors could require PG&E Corporation and the Utility to make significant unplanned contributions to its pension plan, other postretirement benefits plans, and nuclear decommissioning trusts.
PG&E Corporation and the Utility provide defined benefit pension plans and other postretirement benefits for eligible employees and retirees. The Utility also maintains three trusts for the purposes of providing funds to decommission its nuclear facilities. The performance of the debt and equity markets affects the value of plan assets and trust assets. A decline in the market value may increase the funding requirements for these plans and trusts. The cost of providing pension and other postretirement benefits is also affected by other factors, including interest rates used to measure the required minimum funding levels, the rate of return on plan assets, employee demographics, discount rates used in determining future benefit obligations, rates of increase in health care costs, future government regulation, and prior contributions to the plans. Similarly, funding requirements for the nuclear decommissioning trusts are affected by the rates of return on trust assets, changes in the laws or regulations regarding nuclear decommissioning or decommissioning funding requirements as well as changes in assumptions or forecasts related to decommissioning dates, technology and the cost of labor, materials and equipment. (See Note 2: Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements in Item 8.) If the Utility is required to make significant unplanned contributions to fund the pension and postretirement plans or if actual nuclear decommissioning costs exceed the amount of nuclear decommissioning trust funds and the Utility is unable to recover the contributions or additional costs in rates, PG&E Corporation’s and the Utility’s financial results could be materially affected.
The Utility’s success depends on the availability of the services of a qualified workforce and its ability to maintain satisfactory collective bargaining agreements which cover a substantial number of employees. PG&E Corporation’s and the Utility’s results may suffer if the Utility is unable to attract and retain qualified personnel and senior management talent, or if prolonged labor disruptions occur.
The Utility’s workforce is aging and many employees are or will become eligible to retire within the next few years. Although the Utility has undertaken efforts to recruit and train new field service personnel, the Utility may be faced with a shortage of experienced and qualified personnel. The majority of the Utility’s employees are covered by collective bargaining agreements with three unions. Labor disruptions could occur depending on the outcome of negotiations to renew the terms of these agreements. In addition, some of the remaining non-represented Utility employees could join one of these unions in the future.
PG&E Corporation and the Utility also may face challenges in attracting and retaining senior management talent especially if they are unable to restore the reputational harm generated by the negative publicity stemming from the ongoing enforcement proceedings. Any such occurrences could negatively impact PG&E Corporation’s and the Utility’s financial condition and results of operations.
None.
The Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, which are described in Item 1. Business, under “Electric Utility Operations” and “Natural Gas Utility Operations.” The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits, or licenses from private landowners or governmental authorities. In total, the Utility occupies 11.2 million square feet of real property, including 8.8 million square feet owned by the Utility. The Utility's corporate headquarters comprises approximately 1.7 million square feet located in several Utility-owned buildings in San Francisco, California.
PG&E Corporation also leases approximately 42,000 square feet of office space from a third party in San Francisco, California. This lease will expire in 2022.
The Utility currently owns approximately 167,000 acres of land, including approximately 140,000 acres of watershed lands. In 2002 the Utility agreed to permanently preserve six “beneficial public values” on all its watershed lands through conservation easements or equivalent protections, and to make up to 44,000 acres of its watershed lands available for donation to public entities or qualified non-profit conservation organizations. The six “beneficial public values” being preserved through these conservation easements include: natural habitat of fish, wildlife, and plants; open space; outdoor recreation by the general public; sustainable forestry; agricultural uses; and historic values. The Pacific Forest Watershed Lands Stewardship Council oversees the implementation of a land conservation plan that articulates the long-term management objectives for these watershed lands. The Utility’s goal is to implement all the transactions needed to implement the land conservation plan by the end of 2017, subject to securing all required regulatory approvals.
ITEM 3. LEGAL PROCEEDINGS
In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, see “Enforcement and Litigation Matters” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8 and in Item 7. MD&A.
Diablo Canyon Power Plant
The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.
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In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the settlement agreement. On June 17, 2003, the settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's permit.
At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.
The final requirements of the federal and state cooling water policies (discussed above in Item 1. Business under “Environmental Regulation – Water Quality”) could affect future negotiations between the Central Coast Board and the Utility regarding the status of the 2003 settlement agreement. PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material impact on the Utility’s financial condition or results of operations.
CPUC Investigations Regarding the Utility’s Gas Transmission System and the San Bruno Accident
There are three CPUC investigative enforcement proceedings pending against the Utility. These investigations relate 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 San Bruno accident.
On September 2, 2014, the assigned CPUC ALJs issued their presiding officer decisions in these investigations in which they determined that the Utility committed approximately 3,700 violations of law, rules and regulations. The ALJs jointly issued a decision calling for total penalties of $1.4 billion on the Utility to address all violations, allocated as follows: (1) $950 million fine to be paid to the State General Fund, (2) $400 million refund to ratepayers of previously authorized revenues, and (3) remedial measures that the ALJs estimate will cost the Utility at least $50 million. The presiding officer decisions are not the final decisions of the CPUC. Three of the five CPUC Commissioners have requested that the CPUC review the decisions. It is possible that one or more Commissioners will issue an alternate penalty decision for consideration by the CPUC. In addition, in October 2014, the Utility and other parties, including the SED, TURN, the ORA, the City and County of San Francisco, and the City of San Bruno appealed the presiding officer decisions.
In its appeals, the Utility argued that the penalties imposed and the findings and conclusions on which they are based do not meet applicable legal standards, are based on the misapplication of California law and regulations, and are unconstitutional. The Utility has asked the CPUC to order the Utility to pay a significantly reduced penalty that is reasonable and proportionate in light of the nature of the violations and that takes into account the substantial unrecovered amounts the Utility has already spent and forecasts that it will spend on gas system safety. The Utility requested that it be allowed 180 days to raise the funds it may be ordered to pay to the State General Fund rather than the 40 days specified in the decision. The Utility also argued that the entire penalty should go toward funding investments in the Utility’s gas transmission system. TURN, the ORA, and the City and County of San Francisco jointly filed an appeal urging the CPUC to disallow the Utility’s recovery of remaining PSEP costs of $877 million and to require the Utility to pay $473 million to the State General Fund. These parties also argue that the record in the investigative proceedings would support an even larger penalty than stated in the decision. The City of San Bruno appealed the rejection of its proposals for the appointment of an independent monitor to oversee the Utility’s natural gas operations and for the establishment of a pipeline safety trust. It is uncertain when the final outcome of the investigations will be determined.
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While the various appeals and requests for review of the presiding officer decisions are unresolved there continues to be significant uncertainty about the ultimate forms and amounts of penalties (including fines) that will be imposed on the Utility. The impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements will depend on the amounts and forms of penalties that are ultimately adopted by the CPUC. For more information, see discussions “Enforcement and Litigation Matters” in Item 7. MD&A and Note 14: Commitments and Contingencies of the Notes to the Consolidated Financial Statements in Item 8.
Federal Criminal Indictment
On July 29, 2014, a federal grand jury in the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court replacing the indictment that had been returned on April 1, 2014. The superseding indictment charges 27 felony counts (increased from 12 counts charged in the original indictment) alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also alleges 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 alternate fine would be approximately $1.13 billion.
The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternate 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. A status conference is scheduled to be held in court on March 9, 2015. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their consolidated financial statements as such amounts are not considered to be probable.
Litigation Related to the San Bruno Accident and Natural Gas Spending
At December 31, 2014, there were also five purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The plaintiffs for three of these lawsuits filed a consolidated complaint with the San Mateo County Superior Court in November 2013, which has been amended to add a fourth shareholder plaintiff and to discuss recent events, including the federal criminal indictment discussed above. In August 2014, the judge lifted the stay on the consolidated complaint for the limited purpose of allowing briefing and hearing on demurrers (state court motions to dismiss). On September 15, 2014, PG&E Corporation, the Utility and the individual defendants asked the court to dismiss the consolidated complaint because the plaintiffs (1) failed to demand that the Boards of Directors pursue claims against the defendant directors and officers and (2) have not adequately pled why such demand should be excused. The court has since clarified that the appropriate board on whom the plaintiffs should have demanded with respect to the claims in the operative complaint is the 2013 PG&E Corporation Board of Directors (and the 2014 Board regarding the allegations first raised in plaintiffs’ 2014 amended consolidated complaint). The Court has invited plaintiffs to amend their complaint to accommodate this clarification, and defendants to refile a demurrer on this amended complaint if they so choose. Accordingly, briefing and litigation on this motion is expected to continue through the first quarter of 2015. On September 22, 2014, PG&E Corporation, the Utility, and the individual defendants filed a petition with the California Court of Appeal requesting a new order continuing the stay until resolution of the federal criminal indictment discussed above. A fifth purported shareholder derivative lawsuit that was filed in the U.S. District Court for the Northern District of California remains stayed.
Not applicable.
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The following individuals serve as executive officers (1) of PG&E Corporation and/or the Utility, as of February 10, 2015. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
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Age
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Positions Held Over Last Five Years
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Time in Position
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Anthony F. Earley, Jr.
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65
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Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
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September 13, 2011 to present
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Executive Chairman of the Board, DTE Energy Company
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October 1, 2010 to September 12, 2011
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Chairman of the Board and Chief Executive Officer, DTE Energy Company
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August 1998 to September 30, 2010
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Christopher P. Johns
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54
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President
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August 1, 2009 to present
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Senior Vice President, Financial Services
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May 1, 2009 to July 31, 2009
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Senior Vice President and Chief Financial Officer, PG&E Corporation
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May 1, 2009 to July 31, 2009
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Nickolas Stavropoulos
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56
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Executive Vice President, Gas Operations
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June 13, 2011 to present
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Executive Vice President and Chief Operating Officer, U.S. Gas Distribution, National Grid
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August 2007 to March 31, 2011
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Geisha J. Williams
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53
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Executive Vice President, Electric Operations
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June 1, 2011 to present
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Senior Vice President, Energy Delivery
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December 1, 2007 to May 31, 2011
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Karen A. Austin
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53
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Senior Vice President and Chief Information Officer
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June 1, 2011 to present
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President, Consumer Electronics, Sears Holdings
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February 2009 to May 2011
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Desmond A. Bell
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52
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Senior Vice President, Safety and Shared Services
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January 1, 2012 to present
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|||
|
Senior Vice President, Shared Services and Chief Procurement Officer
|
October 1, 2008 to December 31, 2011
|
|||||
|
Helen A. Burt
|
58
|
Senior Vice President, Corporate Affairs
|
September 18, 2014 to present
|
|||
|
Senior Vice President, Corporate Affairs, PG&E Corporation
|
September 18, 2014 to present
|
|||||
|
Senior Vice President and Chief Customer Officer
|
February 27, 2006 to September 17, 2014
|
|||||
|
Loraine M. Giammona
|
47
|
Senior Vice President and Chief Customer Officer
|
September 18, 2014 to present
|
|||
|
Vice President, Customer Service
|
January 23, 2012 to September 17, 2014
|
|||||
|
Regional Vice President, Customer Care, Comcast Cable
|
November 2002 to January 2012
|
|||||
|
Edward D. Halpin
|
53
|
Senior Vice President and Chief Nuclear Officer
|
April 2, 2012 to present
|
|||
|
President, Chief Executive Officer and Chief Nuclear Officer, South Texas Project Nuclear Operating Company
|
December 2009 to March 2012
|
|||||
|
Kent M. Harvey
|
56
|
Senior Vice President and Chief Financial Officer, PG&E Corporation
|
August 1, 2009 to present
|
|||
|
Senior Vice President, Financial Services
|
August 1, 2009 to present
|
31
|
Gregory K. Kiraly
|
50
|
Senior Vice President, Electric Distribution Operations
|
September 18, 2012 to present
|
|||
|
Vice President, Electric Distribution Operations
|
October 1, 2011 to September 17, 2012
|
|||||
|
Vice President, SmartMeter Operations
|
August 23, 2010 to September 30, 2011
|
|||||
|
Vice President, Electric Maintenance and Construction
|
January 1, 2010 to August 22, 2010
|
|||||
|
Steven E. Malnight
|
42
|
Senior Vice President, Regulatory Affairs
|
September 18, 2014 to present
|
|||
|
Vice President, Customer Energy Solutions
|
May 15, 2011 to September 17, 2014
|
|||||
|
Vice President, Integrated Demand Side Management
|
July 1, 2010 to May 14, 2011
|
|||||
|
Vice President, Renewable Energy
|
May 1, 2009 to June 30, 2010
|
|||||
|
Hyun Park
|
53
|
Senior Vice President and General Counsel, PG&E Corporation
|
November 13, 2006 to present
|
|||
|
John R. Simon
|
50
|
Senior Vice President, Human Resources
|
April 16, 2007 to present
|
|||
|
Senior Vice President, Human Resources, PG&E Corporation
|
April 16, 2007 to present
|
|||||
|
Jesus Soto, Jr.
|
47
|
Senior Vice President, Engineering, Construction and Operations
|
September 16, 2013 to present
|
|||
|
Senior Vice President, Gas Transmission Operations
|
May 29, 2012 to September 15, 2013
|
|||||
|
Vice President, Operations Services, El Paso Pipeline Group
|
May 2007 to May 2012
|
|||||
|
Fong Wan
|
53
|
Senior Vice President, Energy Procurement
|
October 1, 2008 to present
|
|||
|
Dinyar B. Mistry
|
53
|
Vice President, Chief Financial Officer, and Controller
|
October 1, 2011 to present
|
|||
|
Vice President and Controller, PG&E Corporation
|
March 8, 2010 to present
|
|||||
|
Vice President and Controller
|
March 8, 2010 to September 30, 2011
|
|||||
|
Vice President and Chief Risk and Audit Officer
|
September 16, 2009 to March 7, 2010
|
|||||
|
Vice President and Chief Risk and Audit Officer, PG&E Corporation
|
August 1, 2009 to March 7, 2010
|
|||||
(1) Mr. Earley, Mr. Johns, Ms. Burt, Mr. Harvey, Mr. Park, and Mr. Simon are executive officers of both PG&E Corporation and the Utility. All other listed officers are executive officers of the Utility only.
32
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of January 27, 2015, there were 61,989 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth on page 125 of this report within “Quarterly Consolidated Financial Data (Unaudited)”in Item 8. Shares of common stock of the Utility are wholly owned by PG&E Corporation. Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility for the two most recent fiscal years and information about the restrictions upon the payment of dividends on their common stock Utility appears in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5: Common Stock and Share-Based Compensation−Dividends in Item 8 and in “Liquidity and Financial Resources – Dividends” in Item 7. MD&A.
Sales of Unregistered Equity Securities
PG&E Corporation did not make any equity contributions to the Utility during the quarter ended December 31, 2014. The Utility was in compliance with the 52% common equity component of its capital structure authorized by the CPUC and had adequate capital to fund its capital expenditures. PG&E Corporation did not make any sales of unregistered equity securities during 2014.
Issuer Purchases of Equity Securities
During the quarter ended December 31, 2014, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. Also, during the quarter ended December 31, 2014, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.
33
ITEM 6. SELECTED FINANCIAL DATA
|
(in millions, except per share amounts)
|
2014
|
2013
|
2012
|
2011
|
2010
|
|||||||||||||||
|
PG&E Corporation
|
||||||||||||||||||||
|
For the Year
|
||||||||||||||||||||
|
Operating revenues
|
$ | 17,090 | $ | 15,598 | $ | 15,040 | $ | 14,956 | $ | 13,841 | ||||||||||
|
Operating income
|
2,450 | 1,762 | 1,693 | 1,942 | 2,308 | |||||||||||||||
|
Income from continuing operations
|
1,450 | 828 | 830 | 858 | 1,113 | |||||||||||||||
|
Earnings per common share from continuing
|
||||||||||||||||||||
|
operations, basic (1)
|
3.07 | 1.83 | 1.92 | 2.10 | 2.86 | |||||||||||||||
|
Earnings per common share from continuing
|
||||||||||||||||||||
|
operations, diluted
|
3.06 | 1.83 | 1.92 | 2.10 | 2.82 | |||||||||||||||
|
Dividends declared per common share (2)
|
1.82 | 1.82 | 1.82 | 1.82 | 1.82 | |||||||||||||||
|
At Year-End
|
||||||||||||||||||||
|
Common stock price per share
|
$ | 53.24 | $ | 40.28 | $ | 40.18 | $ | 41.22 | $ | 47.84 | ||||||||||
|
Total assets
|
60,127 | 55,605 | 52,449 | 49,750 | 46,025 | |||||||||||||||
|
Long-term debt (excluding current portion)
|
15,050 | 12,717 | 12,517 | 11,766 | 10,906 | |||||||||||||||
|
Capital lease obligations (excluding current
|
||||||||||||||||||||
|
portion) (3)
|
69 | 90 | 113 | 212 | 248 | |||||||||||||||
|
Energy recovery bonds (excluding current
|
||||||||||||||||||||
|
portion) (4)
|
- | - | - | - | 423 | |||||||||||||||
|
Pacific Gas and Electric Company
|
||||||||||||||||||||
|
For the Year
|
||||||||||||||||||||
|
Operating revenues
|
$ | 17,088 | $ | 15,593 | $ | 15,035 | $ | 14,951 | $ | 13,840 | ||||||||||
|
Operating income
|
2,452 | 1,790 | 1,695 | 1,944 | 2,314 | |||||||||||||||
|
Income available for common stock
|
1,419 | 852 | 797 | 831 | 1,107 | |||||||||||||||
|
At Year-End
|
||||||||||||||||||||
|
Total assets
|
59,865 | 55,049 | 51,923 | 49,242 | 45,679 | |||||||||||||||
|
Long-term debt (excluding current portion)
|
14,700 | 12,717 | 12,167 | 11,417 | 10,557 | |||||||||||||||
|
Capital lease obligations (excluding current
|
||||||||||||||||||||
|
portion) (3)
|
69 | 90 | 113 | 212 | 248 | |||||||||||||||
|
Energy recovery bonds (excluding current
|
||||||||||||||||||||
|
portion) (4)
|
- | - | - | - | 423 | |||||||||||||||
|
(1) See “Summary of Changes in Net Income and Earnings per Share” in Item 7. MD&A.
|
(2) Information about the frequency and amount of dividends and restrictions on the payment of dividends is set forth in “Liquidity and Financial Resources – Dividends” in MD&A in Item 7 and in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and Note 5 in Item 8.
(3) The capital lease obligations amounts are included in noncurrent liabilities – other in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets.
(4) The energy recovery bonds matured in December 2012.
34
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pacific Gas and Electric Company generates revenues mainly through the sale and delivery of electricity and natural gas to customers. PG&E Corporation is the parent holding company of the Utility. The authorized revenue requirements set by the CPUC in the GRC and GT&S rate cases and by the FERC in TO rate cases provide the Utility an opportunity to earn its authorized rates of return on its “rate base” – the Utility’s net investment in facilities, equipment, and other property used or useful in providing utility service to its customers. Other than its electric transmission and certain GT&S revenues, the Utility’s decoupling of base revenues and sales volume eliminates volatility in the revenues earned by the Utility due to fluctuations in customer demand.
The Utility’s revenue requirements are set based on forecast costs. Differences between forecast costs and actual costs can occur for numerous reasons, including the volume of new customer connections, the detection and mitigation of emerging safety threats, and the impact of market forces on the cost of labor and materials. Differences in costs can also arise from changes in laws and regulations at both the state and federal level. Generally, differences between actual costs and forecast costs could affect the Utility’s ability to earn its authorized return (referred to as “Utility Revenues and Costs that Impacted Earnings” in Results of Operations below). However, for certain operating costs, such as costs associated with pension and other employee benefits, the Utility is authorized to track the difference between actual amounts and forecast amounts and recover or refund the difference through rates (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below). The Utility also collects additional revenue requirements to recover certain costs that the CPUC has authorized the Utility to pass on to customers. Therefore, although these costs can fluctuate, they generally do not impact net income (referred to as “Utility Revenues and Costs that did not Impact Earnings” in Results of Operations below). See “Ratemaking Mechanisms” in Item 1 for further discussion.
There may be some types of costs that the CPUC has determined will not be recoverable through rates or for which the Utility does not seek recovery, such as certain pipeline-related costs and fines associated with the Utility’s natural gas transmission system. The CPUC could also disallow recovery of costs that it finds were not prudently or reasonably incurred. The timing and amount of the unrecoverable or disallowed costs can materially impact the Utility’s net income, as described more fully below.
This is a combined report of PG&E Corporation and the Utility, and includes separate Consolidated Financial Statements for each of these two entities. This combined MD&A should be read in conjunction with the Consolidated Financial Statements and the Notes to the Consolidated Financial Statements included in Item 8.
35
Summary of Changes in Net Income and Earnings per Share
PG&E Corporation’s financial results for 2014 reflect an increase in the Utility’s revenues as authorized in the CPUC’s final decision issued in the Utility’s 2014 GRC on August 14, 2014. (See “Results of Operations” below.)
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 for the year ended December 31, 2014 compared to the prior year (see “Results of Operations” below for additional information):
|
EPS
|
||||||||
|
(in millions, except per share amounts)
|
Earnings
|
(diluted)
|
||||||
|
Income Available for Common Shareholders - 2013
|
$ | 814 | $ | 1.83 | ||||
|
Natural gas matters (1)
|
176 | 0.43 | ||||||
|
2014 GRC expense recovery(2)
|
134 | 0.29 | ||||||
|
Tax benefit - repairs method and forecast change (3)
|
115 | 0.24 | ||||||
|
Growth in rate base earnings (4)
|
101 | 0.21 | ||||||
|
Gain on disposition of SolarCity stock
|
27 | 0.06 | ||||||
|
Regulatory matters (5)
|
20 | 0.04 | ||||||
|
Gas transmission revenues
|
8 | 0.02 | ||||||
|
Uneconomic project and lease termination
|
8 | 0.02 | ||||||
|
Increase in shares outstanding (6)
|
- | (0.15 | ) | |||||
|
Other
|
33 | 0.07 | ||||||
|
Income Available for Common Shareholders - 2014
|
$ | 1,436 | $ | 3.06 | ||||
(1) Represents the decrease in net costs related to natural gas matters during 2014 as compared to 2013. These amounts are not recoverable through rates. See “Results of Operations - Operating and Maintenance” below.
(2) In 2013, the Utility incurred approximately $200 million of expense and $1 billion of capital costs above authorized levels. The 2014 GRC decision authorized revenues that support this higher level of spending in 2014 and throughout the GRC period. The amounts in the table represent the after-tax higher authorized revenue recognized during 2014, for the recovery of these expenses and costs.
(3) Represents the favorable impact of recent IRS guidance and forecast changes based on flow-through ratemaking treatment for federal tax deductions resulting from temporary differences attributable to the accelerated recognition of repairs and certain other property-related costs, as reflected in the revenue requirements authorized in the 2014 GRC decision. See “Income Tax Provision” below.
(4) Represents the impact of the increase in rate base as authorized in various rate cases, including the 2014 GRC, during 2014 as compared to 2013.
(5) Includes customer energy efficiency incentive awards.
(6) Represents the impact of a higher number of weighted average shares of common stock outstanding during 2014 as compared to 2013. PG&E Corporation issues shares to fund its equity contributions to the Utility to maintain the Utility’s capital structure and fund operations, including unrecovered expenses.
36
Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows
PG&E Corporation and the Utility believe that their future results of operations, financial condition, and cash flows will be materially affected by the following factors:
|
·
|
The Outcome of Pending Investigations and Enforcement Matters. The assigned CPUC ALJs overseeing the three pending investigations regarding the Utility’s gas transmission system and the San Bruno accident have issued decisions to impose total fines and disallowances of $1.4 billion on the Utility. The Utility and other parties have appealed the decisions and several Commissioners have requested reviews of the decisions. It is uncertain when the final outcome of these investigations will be determined. At December 31, 2014, the Consolidated Balance Sheets included an accrual of $200 million for the minimum amount of fines deemed probable. There is also a pending federal criminal indictment against the Utility alleging that the Utility knowingly and willfully violated the Pipeline Safety Act and illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. 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. Fines may be imposed, or other regulatory or governmental enforcement action could be taken, with respect to these and other enforcement matters. (See “Enforcement and Litigation Matters" below.)
|
|
·
|
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. In response to Utility’s violations of the CPUC’s rules regarding ex parte communications relating to the 2015 GT&S rate case, the CPUC issued a decision to disallow some GT&S incremental revenues that may otherwise be authorized in the final decision which is scheduled to be issued in August 2015. The Utility and other parties have filed applications requesting the CPUC to reconsider this decision. It is uncertain whether this decision will be upheld and what amount of revenue requirements will ultimately be authorized in the final GT&S rate case decision. It is also uncertain whether the final outcome of the pending CPUC investigations will affect the outcome of the 2015 GT&S rate case. In addition, the Utility has a TO rate case pending at the FERC. (See “Ratemaking and Other Regulatory Proceedings” below.) The outcome of regulatory proceedings can be affected by many factors, including the level of opposition by intervening parties, potential rate impacts, the Utility’s reputation, the regulatory and political environments, and other factors discussed in Item 1A. Risk Factors.
|
|
·
|
The Ability of the Utility to Control Operating Costs and Capital Expenditures. PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows could be materially affected if the Utility’s actual costs differ from the amounts authorized in the final 2014 GRC decision and future rate case decisions. During the quarter ended December 31, 2014, the Utility recorded a charge of $116 million for the increase in the Utility’s forecast of PSEP capital expenditures that are expected to exceed authorized amounts. The Utility could incur additional charges in the future if the forecast of PSEP-related capital expenditures increases. The Utility also forecasts that in 2015 it will incur unrecovered pipeline-related expenses ranging from $100 million to $150 million, including costs to perform continuing work under the Utility’s PSEP and other gas transmission safety work, as well as legal and other expenses. Actual costs could be higher. The final outcome of the pending CPUC investigations and the CPUC enforcement actions with respect to the Utility’s violations of the ex parte communication rules also could affect the ultimate amount of unrecovered costs.
|
|
·
|
The Amount and Timing of the Utility’s Financing Needs. PG&E Corporation contributes equity to the Utility as needed to maintain the Utility’s CPUC-authorized capital structure. In 2014, PG&E Corporation issued $802 million of common stock and made equity contributions to the Utility of $705 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. PG&E Corporation expects that it will issue additional common stock to fund its equity contributions to enable the Utility to pay fines and compliance costs as may be required by the final outcomes of the CPUC investigations, the criminal proceeding, and the other enforcements matters. These additional issuances could have a 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 PG&E Corporation’s and the Utility’s future results of operations, financial condition, and cash flows, or that could cause future results to differ from historical results, see Item 1A. Risk Factors. In addition, this 2014 Annual Report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management's knowledge of facts as of the date of this 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. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.
37
The following discussion presents PG&E Corporation’s and the Utility’s operating results for 2014, 2013, and 2012. See “Key Factors Affecting Results of Operations, Financial Condition, and Cash Flows” above for further discussion about factors that could affect future results of operations.
PG&E Corporation
The consolidated results of operations consist primarily of results related to the Utility, which are discussed in the “Utility” section below. The following table provides a summary of net income (loss) available for common shareholders:
|
2014
|
2013
|
2012
|
||||||||||
|
Consolidated Total
|
$ | 1,436 | $ | 814 | $ | 816 | ||||||
|
PG&E Corporation
|
17 | (38 | ) | 19 | ||||||||
|
Utility
|
$ | 1,419 | $ | 852 | $ | 797 | ||||||
PG&E Corporation’s net income or loss consists primarily of interest expense on long-term debt, other income or loss from investments, and income taxes. In 2014, PG&E Corporation’s operating results increased reflecting $45 million of realized gains and associated tax benefits recognized in connection with an equity investment in SolarCity. PG&E Corporation’s operating results in 2013 reflected an impairment loss of $28 million on its tax equity fund investments and higher charitable contributions as compared to 2012.
Utility
The table below shows certain items from the Utility’s Consolidated Statements of Income for 2014, 2013 and 2012. The table separately identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs) and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs, do not impact earnings.
Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return onrate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.
38
The Utility’s operating results for 2014 reflect the increase in authorized revenues effective January 1, 2014 that was approved by the CPUC in the 2014 GRC decision issued on August 14, 2014. (See “Utility Revenues and Costs that Impacted Earnings” below.)
|
2014
|
2013
|
2012
|
||||||||||||||||||||||||||||||||||
|
Revenues and Costs:
|
Revenues and Costs:
|
Revenues and Costs:
|
||||||||||||||||||||||||||||||||||
|
(in millions)
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
That Impacted Earnings
|
That Did Not Impact Earnings
|
Total Utility
|
|||||||||||||||||||||||||||
|
Electric operating revenues
|
$ | 7,059 | $ | 6,597 | $ | 13,656 | $ | 6,465 | $ | 6,024 | $ | 12,489 | $ | 6,414 | $ | 5,600 | $ | 12,014 | ||||||||||||||||||
|
Natural gas operating revenues
|
2,072 | 1,360 | 3,432 | 1,776 | 1,328 | 3,104 | 1,772 | 1,249 | 3,021 | |||||||||||||||||||||||||||
|
Total operating revenues
|
9,131 | 7,957 | 17,088 | 8,241 | 7,352 | 15,593 | 8,186 | 6,849 | 15,035 | |||||||||||||||||||||||||||
|
Cost of electricity
|
- | 5,615 | 5,615 | - | 5,016 | 5,016 | - | 4,162 | 4,162 | |||||||||||||||||||||||||||
|
Cost of natural gas
|
- | 954 | 954 | - | 968 | 968 | - | 861 | 861 | |||||||||||||||||||||||||||
|
Operating and maintenance
|
4,247 | 1,388 | 5,635 | 4,374 | 1,368 | 5,742 | 4,563 | 1,482 | 6,045 | |||||||||||||||||||||||||||
|
Depreciation, amortization, and decommissioning
|
2,432 | - | 2,432 | 2,077 | - | 2,077 | 1,928 | 344 | 2,272 | |||||||||||||||||||||||||||
|
Total operating expenses
|
6,679 | 7,957 | 14,636 | 6,451 | 7,352 | 13,803 | 6,491 | 6,849 | 13,340 | |||||||||||||||||||||||||||
|
Operating income
|
2,452 | - | 2,452 | 1,790 | - | 1,790 | 1,695 | - | 1,695 | |||||||||||||||||||||||||||
|
Interest income (1)
|
8 | 8 | 6 | |||||||||||||||||||||||||||||||||
|
Interest expense (1)
|
(720 | ) | (690 | ) | (680 | ) | ||||||||||||||||||||||||||||||
|
Other income, net (1)
|
77 | 84 | 88 | |||||||||||||||||||||||||||||||||
|
Income before income taxes
|
1,817 | 1,192 | 1,109 | |||||||||||||||||||||||||||||||||
|
Income tax provision (1)
|
384 | 326 | 298 | |||||||||||||||||||||||||||||||||
|
Net income
|
1,433 | 866 | 811 | |||||||||||||||||||||||||||||||||
|
Preferred stock dividend requirement (1)
|
14 | 14 | 14 | |||||||||||||||||||||||||||||||||
|
Income Available for Common Stock
|
$ | 1,419 | $ | 852 | $ | 797 | ||||||||||||||||||||||||||||||
(1) These items impacted earnings.
39
Utility Revenues and Costs that Impacted Earnings
The following discussion presents the Utility’s operating results for 2014, 2013 and 2012, 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 $890 million or 11% in 2014 compared to 2013. This amount includes an increase to base revenues of $460 million as authorized by the CPUC in the 2014 GRC decision. The GRC decision also resulted in higher base revenues of $150 million in 2014 related primarily to the DOE settlement in 2012 for spent nuclear fuel storage costs. (See “Ratemaking and Other Regulatory Proceedings” below.) The total increase in operating revenues also includes approximately $150 million, consisting of revenues authorized by the CPUC for recovery of nuclear decommissioning costs and certain PSEP-related costs and revenues authorized by the FERC in the TO rate case. The Utility also collected higher gas transmission revenues driven by increased demand for gas-fired generation.
The Utility’s electric and natural gas operating revenues increased $55 million or 1% in 2013 compared to 2012, primarily due to an increase of $294 million as authorized in various rate cases, partially offset by a decrease in revenues of $196 million as a result of the lower ROE authorized by the CPUC in the 2013 Cost of Capital proceeding.
Operating and Maintenance
The Utility’s operating and maintenance expenses that impacted earnings decreased $127 million or 3% in 2014 compared to 2013 and $189 million or 4% in 2013 compared to 2012, primarily due to lower net costs incurred in connection with natural gas matters shown in the table below. These decreases were offset by higher benefit-related expenses and other operating expenses of $120 million in 2014 as compared to 2013 and $53 million in 2013 as compared to 2012. Additionally, the Utility incurred an $88 million charge in 2012 for an increase in estimated environmental remediation costs associated with the Hinkley natural gas compressor station site, with no comparable charge taken in 2013.
The following table provides a summary of the Utility’s costs associated with natural gas matters that are not recoverable through rates:
|
2014
|
2013
|
2012
|
Cumulative December 31, 2014
|
|||||||||||||
|
Pipeline-related expenses (1)
|
$ | 347 | $ | 387 | $ | 477 | $ | 1,757 | ||||||||
|
Disallowed capital expenditures (2)
|
116 | 196 | 353 | 665 | ||||||||||||
|
Accrued fines (3)
|
12 | 22 | 17 | 251 | ||||||||||||
|
Third-party liability claims (4)
|
(7 | ) | 110 | 80 | 558 | |||||||||||
|
Insurance recoveries (5)
|
(112 | ) | (70 | ) | (185 | ) | (466 | ) | ||||||||
|
Contribution to City of San Bruno
|
- | - | 70 | 70 | ||||||||||||
|
Total natural gas matters
|
$ | 356 | $ | 645 | $ | 812 | $ | 2,835 | ||||||||
(1) In 2014, the Utility incurred $149 million of PSEP-related expenses, $155 million of other gas safety-related work, and $43 million of legal and other expenses. From December 31, 2010 through December 31, 2014, the Utility incurred respective expenses of $885 million, $502 million, and $370 million. See “Enforcement and Litigation Matters” below.
(2) Amounts represent charges for PSEP capital costs expected to exceed the authorized amount. See “Pipeline Safety Enhancement Plan” in Note 14 of the Consolidated Financial Statements in Item 8.
(3) Includes fines related to ex parte communications, the Carmel incident, and other fines. See “Pending CPUC Investigations” below. The Utility has paid $40 million of fines through December 31, 2014.
(4) Amounts represent third-party liability claims and associated legal costs. The Utility’s liability for third-party claims related to the San Bruno accident was reduced in 2014 to reflect the settlement of all outstanding third-party claims. Since the San Bruno accident, the Utility has made cumulative settlement payments of $532 million through December 31, 2014.
(5) The Utility has recognized insurance recoveries for third-party claims and associated legal costs. The Utility has been engaged in settlement negotiations with its insurers regarding recovery of its remaining claims and costs.
40
Depreciation, Amortization, and Decommissioning
The Utility’s depreciation, amortization, and decommissioning expenses increased $355 million or 17% in 2014 compared to 2013 and $149 million or 8% in 2013 compared to 2012. In 2014, the increase was primarily due to higher depreciation rates as authorized by the CPUC in the 2014 GRC decision and higher nuclear decommissioning expense reflecting the year-to-date increase as authorized by the CPUC in the nuclear decommissioning triennial proceeding. Additionally, depreciation, amortization, and decommissioning expenses were impacted by an increase in capital additions during 2014 as compared to 2013, and during 2013 as compared to 2012.
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 2014 through 2016, as authorized in the 2014 GRC decision, reflect 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. PG&E Corporation and the Utility’s effective tax rates for 2014 are lower as compared to 2013, and are expected to remain lower in 2015 and 2016 due to these temporary differences that are now being flowed through. PG&E Corporation and the Utility’s 2014 financial results reflect a reduction in income tax expense associated with these temporary differences. (See Note 8 of the Notes to the Consolidated Financial Statements in Item 8.)
The Tax Increase Prevention Act, signed into law on December 19, 2014, extended 50% bonus federal tax depreciation on qualified property placed into service in 2014. The Utility’s earnings were not impacted by the incremental tax depreciation as the flow-through ratemaking discussed above does not apply and the 2014 GRC decision requires the Utility to refund to customers the estimated cost of service benefits associated with this tax law change.
The Utility’s income tax provision increased $58 million or 18% in 2014 as compared to 2013 and $28 million or 9% in 2013 as compared to 2012. The increase in the tax provision was primarily due to higher pre-tax income, partially offset by certain reductions in tax expense for flow-through treatment as discussed above.
The following table reconciles the income tax expense at the federal statutory rate to the income tax provision:
|
2014
|
2013
|
2012
|
||||||||||
|
Federal statutory income tax rate
|
35.0 | % | 35.0 | % | 35.0 | % | ||||||
|
Increase (decrease) in income tax rate resulting from:
|
||||||||||||
|
State income tax (net of federal benefit) (1)
|
1.6 | (2.2 | ) | (3.0 | ) | |||||||
|
Effect of regulatory treatment of fixed asset differences (2)
|
(14.7 | ) | (3.8 | ) | (3.9 | ) | ||||||
|
Tax credits
|
(0.7 | ) | (0.4 | ) | (0.6 | ) | ||||||
|
Benefit of loss carryback
|
(0.8 | ) | (1.0 | ) | (0.4 | ) | ||||||
|
Non deductible penalties
|
0.3 | 0.7 | 0.5 | |||||||||
|
Other, net
|
0.4 | (0.9 | ) | (0.8 | ) | |||||||
|
Effective tax rate
|
21.1 | % | 27.4 | % | 26.8 | % | ||||||
|
(1) Includes the effect of state flow-through ratemaking treatment.
|
|
(2) Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed above.
|
41
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, transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, and realized gains and losses on price risk management activities. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.) The volume of power purchased by the Utility is driven by customer demand, the availability of the Utility’s own generation facilities (including hydroelectric generations), and the cost effectiveness of each source of electricity. Additionally, the cost of electricity is impacted by the higher cost of procuring renewable energy as the Utility increases the amount of its renewable energy deliveries to comply with California law.
|
2014
|
2013
|
2012
|
||||||||||
|
Cost of purchased power
|
$ | 5,266 | $ | 4,696 | $ | 3,873 | ||||||
|
Fuel used in own generation facilities
|
349 | 320 | 289 | |||||||||
|
Total cost of electricity
|
$ | 5,615 | $ | 5,016 | $ | 4,162 | ||||||
|
Average cost of purchased power per kWh
|
$ | 0.101 | $ | 0.094 | $ | 0.079 | ||||||
|
Total purchased power (in millions of kWh)
|
52,008 | 49,941 | 48,933 | |||||||||
Cost of Gas
The Utility’s cost of natural gas includes the costs of procurement, storage, transportation of natural gas, and realized gains and losses on price risk management activities. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, changes in customer demand, and by costs associated with complying with California’s GHG laws.
|
2014
|
2013
|
2012
|
||||||||||
|
Cost of natural gas sold
|
$ | 813 | $ | 807 | $ | 676 | ||||||
|
Transportation cost of natural gas sold
|
141 | 161 | 185 | |||||||||
|
Total cost of natural gas
|
$ | 954 | $ | 968 | $ | 861 | ||||||
|
Average cost per Mcf of natural gas sold
|
$ | 4.37 | $ | 3.54 | $ | 2.91 | ||||||
|
Total natural gas sold (in millions of Mcf) (1)
|
186 | 228 | 232 | |||||||||
|
(1) One thousand cubic feet
|
||||||||||||
Operating and Maintenance Expenses
The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs. If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings. For 2014, 2013 and 2012, no material amounts were incurred above authorized amounts.
42
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 debt and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect related to 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 long-term capital structure consisting of 52% equity and 48% debt and preferred stock (see “Ratemaking Mechanisms” in Item 1). The Utility’s future equity needs will continue to be affected by costs that are not recoverable through rates, including costs related to natural gas matters, fines imposed in connection with the pending CPUC investigations and other matters described in “Enforcement and Litigation Matters” below, and certain environmental remediation costs. 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’s and the Utility’s credit ratings may be affected by the ultimate outcome of the pending enforcement and litigation matters. Credit rating downgrades may increase the cost and availability of short-term borrowing, including commercial paper, the costs associated with credit facilities, and long-term debt costs. In addition, 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. 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. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8.)
PG&E Corporation’s equity contributions to the Utility are funded primarily through common stock issuances. During 2014, PG&E Corporation sold 11 million shares of common stock for cash proceeds of $496 million, net of commissions of $4 million, under an equity distribution agreement. There were no sales during the fourth quarter of 2014. In addition, during 2014, PG&E Corporation sold 8 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $306 million.
The proceeds from these equity issuances were used for general corporate purposes, including the contribution of equity into the Utility. For the year ended December 31, 2014, PG&E Corporation made equity contributions to the Utility of $705 million to ensure that the Utility had adequate capital to maintain the 52% common equity ratio authorized by the CPUC. These equity issuances have been dilutive to PG&E Corporation’s EPS to the extent that the proceeds were used by the Utility to restore equity that has been reduced by unrecoverable costs and charges.
PG&E Corporation forecasts that it will issue additional common stock to fund the Utility’s equity needs. PG&E Corporation forecasts that it will issue between $400 million and $600 million in common stock during 2015, excluding amounts attributable to fines the Utility may be required to pay in connection with final outcomes of the CPUC investigations, the criminal proceeding, and other enforcements matters. Future issuances of common stock by PG&E Corporation to fund equity contributions could continue to have a material dilutive effect on EPS depending upon the ultimate outcomes of the matters described in “Enforcement and Litigation Matters” below and the outcome of the GT&S rate case as described in “Ratemaking and Other Regulatory Proceedings” below.
43
Cash and Cash Equivalents
PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to cash and cash equivalents, the Utility holds restricted cash that primarily consists of cash held in escrow pending the resolution of the remaining disputed claims that were filed in the Utility’s reorganization proceeding under Chapter 11 of the U.S. Bankruptcy Code. (See Note 12 of the Notes to the Consolidated Financial Statements in Item 8.)
Revolving Credit Facilities and Commercial Paper Programs
At December 31, 2014, PG&E Corporation and the Utility had $300 million and $2.6 billion available under their respective $300 million and $3.0 billion revolving credit facilities. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)
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 to those permitted under PG&E Corporation’s and the Utility’s senior note indentures, mergers, sales of all or substantially all of PG&E Corporation’s and the Utility’s assets, and other fundamental changes. At December 31, 2014, PG&E Corporation and the Utility were in compliance with all covenants under their respective revolving credit facilities.
2014 Debt Financings
PG&E Corporation and the Utility issued $2.3 billion in long-term debt and $300 million in short-term debt during the year ended December 31, 2014. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)
Dividends
The Board of Directors of PG&E Corporation and the Utility have authority to declare dividends on their respective common stock. Dividends are not payable unless and until declared by the applicable Board of Directors. The CPUC requires that the Utility maintain, on average, its authorized capital structure including a 52% equity component and that the PG&E Corporation Board of Directors give first priority to the Utility’s capital requirements, as determined to be necessary and prudent to meet the Utility’s obligation to serve or to operate the Utility in a prudent and efficient manner. Each Board of Directors retains authority to change the common stock dividend rate at any time, especially if unexpected events occur that would change their view as to the prudent level of cash conservation.
The Board of Directors of PG&E Corporation declared and paid common stock dividends of $0.455 per share for each of the quarters in 2014, 2013, and 2012, for annual dividends of $1.82 per share. The Utility’s Board of Directors declared and paid common stock dividends in the aggregate amount of $179 million to PG&E Corporation for each of the quarters in 2014, 2013, and 2012. The Utility’s preferred stock is cumulative and any dividends in arrears must be paid before the Utility may pay any common stock dividends.
The following table summarizes PG&E Corporation’s and the Utility’s dividends paid:
|
2014
|
2013
|
2012
|
||||||||||
|
PG&E Corporation:
|
||||||||||||
|
Common stock dividends paid
|
$ | 802 | $ | 782 | $ | 746 | ||||||
|
Common stock dividends reinvested in Dividend Reinvestment
|
||||||||||||
|
and Stock Purchase Plan
|
21 | 22 | 22 | |||||||||
|
Utility:
|
||||||||||||
|
Common stock dividends paid
|
$ | 716 | $ | 716 | $ | 716 | ||||||
|
Preferred stock dividends paid
|
14 | 14 | 14 | |||||||||
Additionally, in December 2014, the following dividends were declared:
|
· the Board of Directors of PG&E Corporation declared quarterly common stock dividends of $0.455 per share, totaling $217 million, of which approximately $211 million was paid in January 2015 to shareholders of record on December 31, 2014;
|
|
· the Board of Directors of the Utility declared dividends on its outstanding series of preferred stock, payable in February 2015, to shareholders of record on January 30, 2015.
|
Subject to the outcome of the matters described in “Enforcement and Litigation Matters” below, PG&E Corporation expects that its Board will continue to maintain the current quarterly common stock dividend. (See Item 1A. Risk Factors.)
44
PG&E Corporation
PG&E Corporation affiliates previously entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that were considered VIEs. On July 2, 2014, PG&E Corporation disposed of its interest in the tax equity agreements for $87 million and has no remaining commitment to fund these agreements. Sales proceeds, lease payments, investment contributions, benefits, and customer payments received were included in cash flows from operating and investing activities within the Consolidated Statements of Cash Flows to coincide with the applicable lease structure.
Utility
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.
The Utility’s cash flows from operating activities for 2014, 2013, and 2012 were as follows:
|
2014
|
2013
|
2012
|
||||||||||
|
Net income
|
$ | 1,433 | $ | 866 | $ | 811 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating
|
||||||||||||
|
activities:
|
||||||||||||
|
Depreciation, amortization, and decommissioning
|
2,432 | 2,077 | 2,272 | |||||||||
|
Allowance for equity funds used during construction
|
(100 | ) | (101 | ) | (107 | ) | ||||||
|
Deferred income taxes and tax credits, net
|
731 | 1,103 | 684 | |||||||||
|
PSEP disallowed capital expenditures
|
116 | 196 | 353 | |||||||||
|
Other
|
226 | 299 | 236 | |||||||||
|
Effect of changes in operating assets and liabilities:
|
(1,219 | ) | (1,024 | ) | 679 | |||||||
|
Net cash provided by operating activities
|
$ | 3,619 | $ | 3,416 | $ | 4,928 | ||||||
During 2014, net cash provided by operating activities increased by $203 million as compared to 2013. This increase was primarily due to $500 million in net tax refunds received during 2014 as compared to $62 million in net tax payments made during 2013, $160 million in additional GHG auction proceeds during 2014 as compared to 2013, and $137 million in additional collateral returned to the Utility in 2014 as compared to 2013. The increase was offset by higher purchased power costs of $599 million (see “Cost of Electricity” within “Results of Operations – Utility Revenues and Costs that did not Impact Earnings” above) and various fluctuations in other cash flows.
45
During 2013, net cash provided by operating activities decreased by $1.5 billion as compared to 2012 when the Utility collected $460 million from customers related to the energy recovery bonds which matured at the end of 2012. In addition, in 2013, the amount of cash collateral returned to the Utility by third parties was $243 million lower than in 2012, the payments the Utility received under the DOE settlement for reimbursement of the Utility’s spent nuclear fuel disposal costs was $221 million lower, net of legal fees, than the Utility received in 2012, and the Utility’s tax payments were $236 million higher than in 2012. The remaining changes in cash flows from operating activities consisted of fluctuations in activities within the normal course of business such as the timing and amount of customer billings and collections.
Future cash flow from operating activities will be affected by various factors, including:
|
·
|
the timing and outcome of ratemaking proceedings, including the 2015 GT&S rate case;
|
|
·
|
the timing and amount of fines or penalties that will be imposed in connection with the pending investigations and other enforcement matters, as well as any costs associated with remedial actions the Utility may be required to implement (see “Enforcement and Litigation Matters” below);
|
|
·
|
the timing and amount of pipeline-related costs the Utility incurs, but does not recover, associated with its natural gas system (see “Operating and Maintenance” within “Results of Operations – Utility Revenues and Costs that Impacted Earnings” above);
|
|
·
|
the volatility in energy commodity costs and seasonal load;
|
|
·
|
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 related refunds passed through to customers (see Note 12 of the Notes to the Consolidated Financial Statements in Item 8).
|
Investing Activities
The Utility’s investing activities primarily consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. The amount and timing of the Utility’s capital expenditures is affected by many factors such as the approvals of the CPUC, FERC, and other regulatory agencies, the volume of new customer connections, and the occurrence of storms that cause outages or damages to the Utility’s infrastructure. The funds in the nuclear decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.
The Utility’s cash flows from investing activities for 2014, 2013, and 2012 were as follows:
|
2014
|
2013
|
2012
|
||||||||||
|
Capital expenditures
|
$ | (4,833 | ) | $ | (5,207 | ) | $ | (4,624 | ) | |||
|
Decrease in restricted cash
|
3 | 29 | 50 | |||||||||
|
Proceeds from sales and maturities of nuclear decommissioning trust investments
|
1,336 | 1,619 | 1,133 | |||||||||
|
Purchases of nuclear decommissioning trust investments
|
(1,334 | ) | (1,604 | ) | (1,189 | ) | ||||||
|
Other
|
29 | 21 | 16 | |||||||||
|
Net cash used in investing activities
|
$ | (4,799 | ) | $ | (5,142 | ) | $ | (4,614 | ) | |||
46
Net cash used in investing activities decreased by $343 million in 2014 compared to 2013 due to a decrease of $374 million in capital expenditures. This decrease was primarily due to lower PSEP-related capital expenditures and the absence of additional investment in the Utility’s photovoltaic program.
Net cash used in investing activities increased by $528 million in 2013 compared to 2012 due to an increase of $583 million in capital expenditures, partially offset by net proceeds associated with sales of nuclear decommissioning trust investments in 2013 as compared to net purchases of nuclear decommissioning trust investments in 2012.
Future cash flows used in investing activities primarily depend on the timing and amount of capital expenditures. The Utility forecasts that it will incur $5.5 billion in capital expenditures in 2015 and between $5.3 billion and $5.8 billion in 2016. Most of the Utility’s revenue requirements to recover forecasted capital expenditures are authorized in the GRC, TO, and GT&S rate cases.
Financing Activities
The Utility’s financing activities are impacted by the conditions in the capital markets and the maturity date of existing debt instruments. The Utility forecasts that its financing needs will increase as it incurs non-recoverable pipeline-related costs and fines associated with the pending investigations and other enforcement matters.
The Utility’s cash flows from financing activities for 2014, 2013, and 2012 were as follows:
|
2014
|
2013
|
2012
|
||||||||||
|
Net issuances (repayments) of commercial paper, net of discount
|
$ | (583 | ) | $ | 542 | $ | (1,021 | ) | ||||
|
Proceeds from issuance of short-term debt, net of issuance costs
|
300 | - | - | |||||||||
|
Proceeds from issuance of long-term debt, net of premium, discount, and
|
||||||||||||
|
issuance costs
|
1,961 | 1,532 | 1,137 | |||||||||
|
Short-term debt matured
|
- | - | (250 | ) | ||||||||
|
Repayments of long-term debt
|
(539 | ) | (861 | ) | (50 | ) | ||||||
|
Energy recovery bonds matured
|
- | - | (423 | ) | ||||||||
|
Preferred stock dividends paid
|
(14 | ) | (14 | ) | (14 | ) | ||||||
|
Common stock dividends paid
|
(716 | ) | (716 | ) | (716 | ) | ||||||
|
Equity contribution from PG&E Corporation
|
705 | 1,140 | 885 | |||||||||
|
Other
|
56 | (26 | ) | 28 | ||||||||
|
Net cash provided by (used in) financing activities
|
$ | 1,170 | $ | 1,597 | $ | (424 | ) | |||||
In 2014, net cash provided by financing activities decreased by $427 million compared to the same period in 2013. In 2013, net cash provided by financing activities increased by $2.0 billion compared to 2012. Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depends on the level of cash provided by or used in operating activities and the level of cash provided by or used in investing activities.
47
The following table provides information about PG&E Corporation’s and the Utility’s contractual commitments at December 31, 2014:
|
Payment due by period
|
||||||||||||||||||||
|
Less Than
|
1-3 | 3-5 |
More Than
|
|||||||||||||||||
|
(in millions)
|
1 Year
|
Years
|
Years
|
5 Years
|
Total
|
|||||||||||||||
|
Utility
|
||||||||||||||||||||
|
Long-term debt (1):
|
$ | 714 | $ | 2,304 | $ | 2,870 | $ | 21,779 | $ | 27,667 | ||||||||||
|
Purchase obligations (2):
|
||||||||||||||||||||
|
Power purchase agreements:
|
3,566 | 6,839 | 6,239 | 33,896 | 50,540 | |||||||||||||||
|
Natural gas supply, transportation, and storage
|
544 | 271 | 214 | 648 | 1,677 | |||||||||||||||
|
Nuclear fuel agreements
|
138 | 260 | 224 | 429 | 1,051 | |||||||||||||||
|
Pension and other benefits (3)
|
388 | 776 | 776 | 388 | 2,328 | |||||||||||||||
|
Operating leases (2)
|
44 | 76 | 57 | 183 | 360 | |||||||||||||||
|
Preferred dividends (4)
|
14 | 28 | 28 | - | 70 | |||||||||||||||
|
PG&E Corporation
|
||||||||||||||||||||
|
Long-term debt (1):
|
8 | 16 | 359 | - | 383 | |||||||||||||||
|
Total Contractual Commitments
|
$ | 5,416 | $ | 10,570 | $ | 10,767 | $ | 57,323 | $ | 84,076 | ||||||||||
|
(1) Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at December 31, 2014 and outstanding principal for each instrument with the terms ending at each instrument’s maturity. (See Note 4 of the Notes to the Consolidated Financial Statements in Item 8.)
|
|
(2) See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.
|
|
(3) See Note 11 of the Notes to the Consolidated Financial Statements in Item 8. Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the amount shown in the column entitled “more than 5 years” represents only 1 year of contributions for the Utility’s pension and other benefit plans.
|
|
(4) Based on historical performance, it is assumed for purposes of the table above that dividends are payable within a fixed period of five years.
|
The contractual commitments table above excludes potential payments associated with unrecognized tax positions. Due to the uncertainty surrounding tax audits, PG&E Corporation and the Utility cannot make reliable estimates of the amounts and periods of future payments to major tax jurisdictions related to unrecognized tax benefits. Matters relating to tax years that remain subject to examination are discussed in Note 8 of the Notes to the Consolidated Financial Statements in Item 8.
Off-Balance Sheet Arrangements
PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 14 of the Notes to the Consolidated Financial Statements (the Utility’s commodity purchase agreements) in Item 8.
48
Since the San Bruno accident occurred on September 9, 2010, PG&E Corporation and the Utility have incurred total cumulative charges of approximately $2.8 billion related to natural gas matters that are not recoverable through rates. See “Results of Operations” above.
Pending CPUC Investigations
On September 2, 2014, the assigned CPUC ALJs issued their presiding officer decisions in the three investigative enforcement proceedings pending against the Utility related to the Utility’s natural gas transmission operations and practices and the San Bruno accident. The ALJs determined that the Utility committed approximately 3,700 violations of law, rules and regulations. The ALJs jointly issued a decision calling for total fines and disallowances of $1.4 billion on the Utility to address all violations, allocated as shown in the table below. The ALJs’ decisions are not the final decisions of the CPUC. Three CPUC Commissioners have requested that the CPUC review the decisions. It is possible that one or more Commissioners will issue an alternate penalty decision for consideration by the CPUC. In addition, the Utility and other parties, including the SED, TURN, the ORA, the City and County of San Francisco, and the City of San Bruno have appealed the presiding officer decisions. (For additional information, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8.) It is uncertain when the final outcome of the investigations will be determined.
While the various appeals and requests for review of the presiding officer decisions are unresolved there continues to be significant uncertainty about the ultimate forms and amounts of penalties (including fines) that will be imposed on the Utility. At December 31, 2014, the Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable. The impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements will depend on the amounts and forms of penalties that are ultimately adopted by the CPUC. Fines payable to the State General Fund or refunds of revenues would be charged to net income when it is probable that such fines or refunds will be imposed and the amounts can be reasonably estimated. A disallowance of previously authorized and incurred capital costs would be charged to net income when the disallowance is probable and the amount can be reasonably estimated. Penalties in the form of future disallowed costs would be charged to net income in the period during which the actual costs are incurred. Although PG&E Corporation and the Utility believe it is probable that the CPUC will impose total penalties materially in excess of the $200 million previously accrued, they are unable to make a better estimate due to the variety of potential combinations of amounts and forms of penalties that could ultimately be imposed on the Utility and uncertainty about the timing of recognition. PG&E Corporation and the Utility believe the final outcome of the investigations will have a material impact on their financial condition, results of operations, and cash flows.
If the presiding officer joint decision becomes final, the Utility estimates that its total pre-tax unrecovered costs and fines related to natural gas transmission operations would be about $4.85 billion based on current forecasts, allocated as follows:
|
Amounts (in millions)
|
||||
|
Fine payable to the State General Fund
|
$ | 950 | ||
|
Refund of revenues previously authorized
|
400 | |||
|
Additional estimated unrecoverable costs (1)
|
50 | |||
|
Total penalty
|
1,400 | |||
|
PSEP costs previously disallowed
|
635 | |||
|
Total penalty and PSEP cost disallowance
|
2,035 | |||
|
Gas pipeline safety costs incurred or committed (2)
|
2,800 | |||
|
Less: Credit for PSEP costs previously disallowed
|
(635 | ) | ||
|
Total estimated shareholder impact before non-deductibility of fines
|
4,200 | |||
|
Estimated impact of non-deductibility of fines for tax purposes (3)
|
650 | |||
|
Total estimated shareholder impact (pre-tax)
|
$ | 4,850 | ||
(1) The presiding officer joint decision estimates that the Utility would incur at least $50 million to implement remedial measures. Actual costs could differ materially based on the scope and timing of work. In addition, the decision requires shareholders to reimburse intervenors for legal and litigation expenses.
(2) Actual and forecast costs for gas pipeline safety work in 2010 and beyond that will not be recovered through rates, including previously disallowed PSEP capital and expense. This amount includes charges of $665 million, including an additional charge of $116 million recorded during the three months ended December 31, 2014, for PSEP capital costs that are forecasted to exceed the authorized amounts.
(3) Estimated impact calculated based on the Utility’s statutory tax rate.
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Federal Criminal Indictment
On July 29, 2014, a federal grand jury in the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court replacing the indictment that had been returned on April 1, 2014. The superseding indictment charges 27 felony counts (increased from 12 counts charged in the original indictment) alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also alleges 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 alternate fine would be approximately $1.13 billion.
The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternate 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. A status conference is scheduled to be held in court on March 9, 2015. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their consolidated financial statements as such amounts are not considered to be probable.
Other Enforcement Matters
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.
Improper CPUC Communications
On September 15, 2014, the Utility notified the CPUC and the ALJ overseeing the 2015 GT&S rate case that it believes certain communications between the Utility and CPUC personnel relating to the 2015 GT&S rate case violated the CPUC’s rules regarding 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 discovered the communications as part of an internal review of communications between the Utility and the CPUC undertaken after the City of San Bruno filed a motion at the CPUC in late July 2014 alleging that various email communications between the Utility’s employees and CPUC personnel violated the ex parte communication rules with respect to the pending CPUC investigative enforcement proceedings against the Utility. The Utility believes that the communications cited by San Bruno in its July 2014 motion are not prohibited ex parte communications. The CPUC has not yet addressed San Bruno’s motion and its request that the CPUC penalize the Utility.)
On November 20, 2014, the CPUC issued a decision imposing a fine of $1.05 million on the Utility and disallowing up to the entire amount of the revenue increase that would have been collected from ratepayers over the five-month period between March 2015 and August 2015. The exact amount of the revenue disallowance will be determined in the CPUC’s final decision in the GT&S rate case expected to be issued in August 2015. In addition, the decision prohibits the Utility from engaging in any oral or written ex parte communications, as well as procedural communications, with Commissioners or their advisors in any rate-setting or adjudicatory proceeding and requires the Utility to report communications with senior CPUC staff, in any rate-setting proceeding or adjudicatory proceeding before the CPUC, for one year from the effective date of the decision. With respect to the GT&S rate case, the ban will be in effect until the resolution of the GT&S rate case or one year from the effective date of the decision, whichever is later. The Utility and other parties have requested that the CPUC reconsider its decision. The ORA, TURN, and the City of San Bruno argue that the applicable law supports the imposition of a fine ranging from $2.5 million to $250 million. It is uncertain when the CPUC will address these applications for rehearing. (See “Ratemaking and Other Regulatory Proceedings” below.)
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In October and December 2014, the Utility notified the CPUC of additional email communications between the Utility and CPUC personnel regarding various matters (not limited to the GT&S rate case), that the Utility believes may constitute or describe ex parte communications. As of January 30, 2015, the Utility had provided copies of approximately 65,000 email communications between the CPUC and the Utility to the CPUC and the City of San Bruno. It is uncertain whether any of these email communications will be challenged as prohibited ex parte communications or as improper or illegal.
The Utility believes it is probable that CPUC enforcement actions will be taken in connection with these additional ex parte communications but 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. It is also possible that other parties may request that the CPUC rescind decisions or take other action in open or closed proceedings to address ex parte communications that they may allege occurred regarding substantive issues in those proceedings. For example, TURN and the ORA have filed petitions to request that the CPUC rescind a $29 million shareholder incentive awarded to the Utility in 2010 for the successful implementation of the Utility’s 2006-2008 energy efficiency programs based on their allegation that prohibited ex parte communications tainted the decision. It is uncertain whether the CPUC will grant these petitions or whether parties will request the CPUC to take action in other proceedings. It is also uncertain whether the ex parte communication issues will affect the outcome of other pending legal matters, ratemaking or regulatory proceedings, investigations and enforcement matters.
Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have begun investigations in connection with these communications. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.
Gas Safety Citation Program
The SED, the division of the CPUC primarily responsible for overseeing the safety of electric and natural gas utility operations in California, conducts periodic audits of the Utility’s operating practices and investigates potential violations. In December 2011, the CPUC adopted a gas safety citation program and delegated authority to the SED to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. (As required by state law, a similar program for electric safety became effective on an interim basis on January 1, 2015. For more information, see “Regulatory Environment” in Item 1.) The California gas corporations are required to inform the SED of self-identified or self-corrected violations. 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.
Since the gas safety program became effective, the Utility has filed approximately 84 self-reports and the SED has imposed fines ranging from $50,000 to $16.8 million (including the $10.85 million fine related to an explosion in Carmel, California that is discussed below) for violations identified through self-reports, SED investigations and audits. The SED recently has stated that it will not conduct further investigations into 65 self-reports the Utility had filed through December 31, 2014. The Utility believes it is probable that the SED will impose fines or take other enforcement action with respect to some of the Utility’s remaining self-reports or other self-reports that the Utility has filed since January 1, 2015. The Utility believes it is reasonably possible that the SED will impose fines on the Utility based on allegations of noncompliance 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 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.
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Carmel Incident
On March 3, 2014, a vacant house in Carmel, California was severely damaged due to a natural gas explosion while the Utility’s employees were performing work to upgrade the main natural gas distribution pipeline in the area. There were no injuries or fatalities. The SED conducted an investigation of the incident and alleged that the Utility committed two violations of certain natural gas safety regulations by failing to follow procedures to update records, to provide its welding crew with accurate information, and to take steps to make safe any actual or potential hazard to life or property. On November 20, 2014, the SED issued a citation to the Utility that included a fine of $10.85 million for these alleged violations. The Utility recorded this amount as an expense for 2014. The Utility has appealed the citation to the CPUC. The SED has requested that the CPUC dismiss the Utility’s appeal as untimely. The CPUC has not yet addressed the SED’s request. In addition, the Utility was informed that the U.S. Attorney’s Office was investigating the Carmel incident. It is uncertain whether any charges will be brought against the Utility.
CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping
On November 20, 2014, the CPUC issued an order instituting a new 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. (See “Carmel Incident” above.) On December 22, 2014, as directed by the CPUC, the Utility submitted a report that explained why the Utility believes the SED’s investigative findings do not constitute violations of law and also outlined the various programs, measures and actions the Utility has undertaken to continuously improve its distribution record keeping practices.
PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose fines on the Utility or take other enforcement action in connection with this matter, but are unable to reasonably estimate the amount or range of future loss contingencies.
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 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.
Other Pending Lawsuits and Claims
At December 31, 2014, there were also five purported shareholder derivative lawsuits outstanding against PG&E Corporation and the Utility seeking recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims. The plaintiffs for three of these lawsuits filed a consolidated complaint with the San Mateo County Superior Court in November 2013, which has been amended to add a fourth shareholder plaintiff and to discuss recent events, including the federal criminal indictment discussed above. In August 2014, the judge lifted the stay on the consolidated complaint for the limited purpose of allowing briefing and hearing on demurrers (state court motions to dismiss). On September 15, 2014, PG&E Corporation, the Utility and the individual defendants asked the court to dismiss the consolidated complaint because the plaintiffs (1) failed to demand that the Boards of Directors pursue claims against the defendant directors and officers and (2) have not adequately pled why such demand should be excused. The court has since clarified that the appropriate board on whom the plaintiffs should have demanded with respect to the claims in the operative complaint is the 2013 PG&E Corporation Board of Directors (and the 2014 Board regarding the allegations first raised in plaintiffs’ 2014 amended consolidated complaint). The Court has invited plaintiffs to amend their complaint to accommodate this clarification, and defendants to refile a demurrer on this amended complaint if they so choose. Accordingly, briefing and litigation on this motion is expected to continue through the first quarter of 2015. On September 22, 2014, PG&E Corporation, the Utility, and the individual defendants filed a petition with the California Court of Appeal requesting a new order continuing the stay until resolution of the federal criminal indictment discussed above. A fifth purported shareholder derivative lawsuit that was filed in the U.S. District Court for the Northern District of California remains stayed.
PG&E Corporation and the Utility are uncertain when and how the above lawsuits will be resolved.
52
The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of these and other proceedings may affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows.
2015 Gas Transmission and Storage Rate Case
Utility’s GT&S Request
In its December 2013 GT&S rate case application, 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 based on its forecasted capital expenditures and the associated growth in rate base, as well as increasing costs of labor, materials, and other expenses. 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 the capital spend above authorized levels for the prior rate case period. The Utility has not requested authorization to recover approximately $150 million of costs it forecasts it will incur over the three-year period to pressure test pipelines placed into service after 1961 that lack records and perform remedial work associated with the Utility’s pipeline corrosion control program. The Utility also has not requested authorization to recover costs it forecasts it will incur during 2015 through 2017 to identify and remove encroachments from its gas transmission pipeline rights-of-way.
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.
Intervenors’ Recommendations
The ORA has recommended a 2015 revenue requirement of $1,044 million, an increase of $329 million over authorized amounts, and attrition increases of $39 million for 2016 and $61 million for 2017. The ORA also recommended that the GT&S rate case period be expanded to four years with an attrition increase of $35 million for 2018. The ORA proposed that the CPUC authorize 2015 capital expenditures of $595 million, compared to the Utility’s request of $779 million. TURN has stated that it intends to make its revenue requirement recommendation in its opening brief to be filed after hearings conclude on February 27, 2015. Nevertheless, TURN has submitted testimony recommending 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 these capital expenditures 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.
Procedural Schedule
Hearings began on February 2, 2015 and are scheduled to end on February 27, 2015. The current procedural schedule calls for a final decision to be issued in August 2015. The CPUC has stated that if a final CPUC decision is issued in the three investigative enforcement proceedings pending against the Utility within the schedule of the 2015 GT&S rate case, the schedule and scope of issues to be considered may be further amended to consider the implications of that decision on the Utility’s revenue requirements.
53
Order to Show Cause
On September 15, 2014, the Utility notified the CPUC and the ALJ overseeing the 2015 GT&S rate case that it believes certain communications between the Utility and CPUC personnel relating to the 2015 GT&S rate case violated the CPUC’s rules regarding ex parte communications. The CPUC issued an order to show cause why the Utility should not be penalized. On November 20, 2014, the CPUC issued a decision that prohibits the Utility from recovering up to the entire amount of the revenue increase that would have been collected from ratepayers over the five-month period between March 2015 (the date the final decision was originally scheduled to be issued) and August 2015 (the date called for under the revised procedural schedule issued after the Utility’s notification of ex parte communications). The decision states that the exact amount of this revenue disallowance will be determined in the CPUC’s final decision in the 2015 GT&S rate case. The CPUC also imposed a fine of $1.05 million on the Utility for the violations. (See “Enforcement and Litigation Matters” above regarding additional ex parte communications that were self-reported by the Utility.) The Utility and other parties have filed applications requesting the CPUC to rehear its decision. The ORA, TURN, and the City of San Bruno argue that the applicable law supports the imposition of a fine ranging from $2.5 million to $250 million. It is uncertain when the CPUC will address these applications for rehearing.
Regulatory Accounting
The Utility’s continued use of regulatory accounting under GAAP (which enables it to account for the effects of regulation, including recording regulatory assets and liabilities) for gas transmission and storage service depends on its ability to recover its cost of service. The Utility’s ability to recover its costs of providing gas transmission and storage service will be affected by the outcome of the 2015 GT&S rate case and future GT&S rate cases. If the Utility were unable to continue using regulatory accounting under GAAP, there would be differences in the timing of expense or gain recognition that could materially affect PG&E Corporation’s and the Utility’s future financial results.
Proposal for Electric Vehicle 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, including EV retail charging stations, to promote and facilitate the deployment of EVs. Under the Utility’s proposal, the Utility would develop EV charging infrastructure over an estimated five years to meet approximately 25% of projected EV charging station needs by 2020. The Utility’s EV charging infrastructure is expected to be used in future programs designed to aid the integration of increased intermittent renewable energy on the state’s electric power grid. 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.
FERC Transmission Owner Rate Case
The Utility has one TO rate case pending at the FERC. The Utility has requested a 2015 retail electric transmission revenue requirement of $1,366 million, a $326 million increase to the currently authorized revenue requirement of $1,039.6 million (The FERC approved the current revenue requirement on November 7, 2014). The proposed rates will be effective March 1, 2015, subject to refund, pending a final decision by the FERC. The Utility’s 2015 cost forecasts reflect the continuing need to replace and modernize aging electric transmission infrastructure, to meet the need for increased capacity in the CAISO controlled grid, and to comply with new rules aimed at ensuring the physical and cyber security of the nation’s electric system. The Utility forecasts that it will make investments of $975 million in 2014 and $1,125 million in 2015 in various capital projects. The Utility’s proposed rate base for 2015 is $5.12 billion, compared to $4.57 billion in 2014. The Utility has requested that the FERC approve an 11.26% ROE. The procedural schedule is currently being held in abeyance while settlement discussions are held.
54
The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of CO2 and other GHG emissions; the discharge of pollutants into the air, water, and soil; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Item 1A. Risk Factors and “Environmental Regulation” in Item 1.)
Natural Gas Compressor Station Sites
The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At December 31, 2014, $158 million and $291 million was accrued in the Consolidated Balances Sheets for estimated undiscounted remediation costs associated with the Hinkley site and the Topock site, respectively. Costs associated with the Hinkley site are not recovered through rates. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
The Utility and PG&E Corporation, mainly through its ownership of 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, other goods and services; and other aspects of their businesses. PG&E Corporation and the Utility categorize market risks as “price risk” (see “Ratemaking Mechanisms” in Item 1) 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.
Commodity Price Risk
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities, including the procurement of natural gas and nuclear fuel necessary for electricity generation and natural gas procurement for core customers. As long as the Utility can conclude that it is probable that its reasonably incurred wholesale electricity procurement costs and natural gas costs are recoverable, fluctuations in electricity and natural gas prices will not affect earnings. Such fluctuations, however, may impact cash flows. The Utility’s natural gas transportation and storage costs for core customers are also fully recoverable through a ratemaking mechanism.
The Utility’s authorized revenue requirement for natural gas transportation and storage service to non-core customers is not balancing account protected. The Utility recovers these costs through fixed reservation charges and volumetric charges from long-term contracts, resulting in price and volumetric risk.
The Utility uses value-at-risk to measure its shareholders’ exposure to these risks. The Utility’s value-at-risk was approximately $1 million and $14 million at December 31, 2014 and 2013, respectively. During the 12 months ended December 31, 2014, the Utility’s approximate high, low, and average values-at-risk were $9 million, $1 million and $5 million, respectively. During 2013, the value-at-risk amounts were $14 million, $9 million and $12 million, respectively. (See Note 9 of the Notes to the Consolidated Financial Statements in Item 8 for further discussion of price risk management activities.)
55
Interest Rate Risk
Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2014 and December 31, 2013, if interest rates changed by 1% for all PG&E Corporation and Utility variable rate long-term debt, short-term debt, and cash investments, the impact on net income over the next 12 months would be $9 million and $11 million, respectively, based on net variable rate debt and other interest rate-sensitive instruments outstanding.
Energy Procurement Credit Risk
The Utility conducts business with counterparties mainly in the energy industry, including the CAISO market, other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, electricity generation companies, and oil and natural gas production companies located in the United States and Canada. If a counterparty fails to perform on its contractual obligation to deliver electricity or gas, then the Utility may find it necessary to procure electricity or gas at current market prices, which may be higher than the contract prices.
The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. The Utility ties many energy contracts to master commodity enabling agreements that may require security (referred to as “Credit Collateral” in the table below). Credit collateral may be in the form of cash or letters of credit. The Utility may accept other forms of performance assurance in the form of corporate guarantees of acceptable credit quality or other eligible securities (as deemed appropriate by the Utility). Credit collateral or performance assurance may be required from counterparties when current net receivables and replacement cost exposure exceed contractually specified limits.
The following table summarizes the Utility’s credit risk exposure to its counterparties as of December 31, 2014 and December 31, 2013:
|
Net Credit
|
|||||||||||||||||||||
|
Number of
|
Exposure to
|
||||||||||||||||||||
|
Gross Credit
|
Wholesale
|
Wholesale
|
|||||||||||||||||||
|
Exposure
|
Customers or
|
Customers or
|
|||||||||||||||||||
|
Before Credit
|
Credit
|
Net Credit
|
Counterparties
|
Counterparties
|
|||||||||||||||||
|
(in millions)
|
Collateral (1)
|
Collateral
|
Exposure (2)
|
>10%
|
>10%
|
||||||||||||||||
|
December 31, 2014
|
$ | 88 | $ | (18 | ) | $ | 70 | 3 | 29 | ||||||||||||
|
December 31, 2013
|
87 | $ | (9 | ) | $ | 78 | 2 | 34 | |||||||||||||
(1) Gross credit exposure equals mark-to-market value on physically and financially settled contracts, and net receivables (payables) where netting is contractually allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.
(2) Net credit exposure is the Gross Credit Exposure Before Credit Collateral minus Credit Collateral (cash deposits and letters of credit posted by counterparties and held by the Utility). For purposes of this table, parental guarantees are not included as part of the calculation.
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The preparation of Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.
Regulatory Accounting
The Utility’s rates are primarily set by the CPUC and the FERC and are designed to recover the cost of providing service. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods that the costs are expected to be recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. In addition, the Utility records regulatory liabilities when the CPUC or the FERC requires a refund to be made to customers or has required that a gain or other reduction of net allowable costs be given to customers over future periods. At December 31, 2014, PG&E Corporation and the Utility reported regulatory assets (including current regulatory balancing accounts receivable) of $9.0 billion and regulatory liabilities (including current balancing accounts payable) of $7.6 billion. (See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8.)
Determining probability requires significant judgment by management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders, and the strength or status of applications for rehearing or state court appeals. For some of the Utility’s regulatory assets, including utility retained generation, the Utility has determined that the costs are recoverable based on specific approval from the CPUC. The Utility also records a regulatory asset when a mechanism is in place to recover current expenditures and historical experience indicates that recovery of incurred costs is probable, such as the regulatory assets for pension benefits; deferred income tax; price risk management; and unamortized loss, net of gain, on reacquired debt. The CPUC has not denied the recovery of any material costs previously recognized by the Utility as regulatory assets for the periods 2012 through 2014. If the Utility determined that it is no longer probable that regulatory assets would be recovered or reflected in future rates, or if the Utility ceased to be subject to rate regulation, the regulatory assets would be charged against income in the period in which that determination was made.
In addition, regulatory accounting standards require recognition of a loss if it becomes probable that capital expenditures will be disallowed for ratemaking purposes and if a reasonable estimate of the amount of the disallowance can be made. Such assessments require significant judgment by management regarding probability of recovery, as described above, and the ultimate cost of construction of capital assets. The Utility records a loss to the extent capital costs are expected to exceed the amount to be recovered. The Utility records a provision based on its best estimate; to the extent there is a high degree of uncertainty in the Utility’s forecast, it will record a provision based on the lower end of the range of possible losses. The Utility’s capital forecasts involve a series of complex judgments regarding detailed project plans, estimates included in third-party contracts, historical cost experience for similar projects, permitting requirements, environmental compliance standards, and a variety of other factors. The Utility recorded charges of $116 million, $196 million, and $353 million in 2014, 2013, and 2012, respectively, for PSEP capital costs that are expected to exceed the amount to be recovered. See “Pipeline Safety Enhancement Plan” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8. The additional charge in 2014 primarily reflects costs for Line 109 (that runs through the San Francisco peninsula) mostly related to emergent permitting conditions and requirements, as well as updated estimates for the few remaining PSEP projects. Management will continue to periodically assess its PSEP capital costs and the related CPUC regulatory proceedings, and further charges could be required in future periods.
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Loss Contingencies
Environmental Remediation Liabilities
The Utility is subject to loss contingencies pursuant to federal and California environmental laws and regulations that in the future may require the Utility to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party. Such contingencies may exist for the remediation of hazardous substances at various potential sites, including former manufactured gas plant sites, power plant sites, gas compressor stations, and sites used by the Utility for the storage, recycling, or disposal of potentially hazardous materials, even if the Utility did not deposit those substances on the site.
The Utility generally commences the environmental remediation assessment process upon notification from federal or state agencies, or other parties, of a potential site requiring remedial action. (In some instances, the Utility may initiate action to determine its remediation liability for sites that it no longer owns in cooperation with regulatory agencies. For example, the Utility has begun a program related to certain former manufactured gas plant sites.) Based on such notification, the Utility completes an assessment of the potential site and evaluates whether it is probable that a remediation liability has been incurred. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can reasonably estimate the loss or a range of possible losses. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. Key factors evaluated in developing cost estimates include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties.
When possible, the Utility estimates costs using site-specific information, but also considers historical experience for costs incurred at similar sites depending on the level of information available. Estimated costs are composed of the direct costs of the remediation effort and the costs of compensation for employees who are expected to devote a significant amount of time directly to the remediation effort. These estimated costs include remedial site investigations, remediation actions, operations and maintenance activities, post remediation monitoring, and the costs of technologies that are expected to be approved to remediate the site. Remediation efforts for a particular site generally extend over a period of several years. During this period, the laws governing the remediation process may change, as well as site conditions, thereby possibly affecting the cost of the remediation effort.
At December 31, 2014 and 2013, the Utility’s accruals for undiscounted gross environmental liabilities were $954 million and $900 million, respectively. The Utility’s undiscounted future costs could increase to as much as $1.8 billion if the extent of contamination or necessary remediation is greater than anticipated or if the other potentially responsible parties are not financially able to contribute to these costs, and could increase further if the Utility chooses to remediate beyond regulatory requirements. Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized.
Legal and Regulatory Matters
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, PG&E Corporation and the Utility are subject to claims or named as parties in lawsuits. In addition, the Utility can incur penalties for failure to comply with federal, state, or local laws and regulations. PG&E Corporation and the Utility record a provision for a loss when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. These accruals, and the estimates of any additional reasonably possible losses (or reasonably possible losses in excess of the amounts accrued), are reviewed quarterly and are adjusted to reflect the impacts of negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. In assessing the amount of such losses, PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs. (See “Enforcement and Litigation Matters” and “Legal and Regulatory Contingencies” in Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
58
Asset Retirement Obligations
PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. (See Notes 2 and 3 of the Notes to the Consolidated Financial Statements in Item 8.)
To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, inflation rates, and the estimated date of decommissioning. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation.
At December 31, 2014, the Utility’s recorded ARO for the estimated cost of retiring these long-lived assets was $3.6 billion. Changes in these estimates and assumptions could materially affect the amount of the recorded ARO for these assets. For example, a premature shutdown of the nuclear facilities at Diablo Canyon would increase the likelihood of an earlier start to decommissioning and cause an increase in the ARO. Additionally, if the inflation adjustment increased 25 basis points, the amount of the ARO would increase by approximately 1.70%. Similarly, an increase in the discount rate by 25 basis points would decrease the amount of the ARO by 1.70%.
Pension and Other Postretirement Benefit Plans
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees as well as contributory postretirement health care and medical plans for eligible retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. Pension and other benefit expense is based on the differences between actuarial assumptions and actual plan results and is deferred in accumulated other comprehensive income (loss) and amortized into income on a gradual basis. The differences between pension benefit expense recognized in accordance with GAAP and amounts recognized for ratemaking purposes are recorded as regulatory assets or liabilities as amounts are probable of recovery from customers. To the extent the other benefits are in an overfunded position, the Utility records a regulatory liability for a portion of the credit balance in accumulated other comprehensive income. (See Note 3 of the Notes to the Consolidated Financial Statements in Item 8.)
The pension and other postretirement benefit obligations are calculated using actuarial models as of the December 31 measurement date. The significant actuarial assumptions used in determining pension and other benefit obligations include the discount rate, the average rate of future compensation increases, the health care cost trend rate and the expected return on plan assets. PG&E Corporation and the Utility review these assumptions on an annual basis and adjust them as necessary. While PG&E Corporation and the Utility believe that the assumptions used are appropriate, significant differences in actual experience, plan changes or amendments, or significant changes in assumptions may materially affect the recorded pension and other postretirement benefit obligations and future plan expenses. During 2014, PG&E Corporation and the Utility adopted the Society of Actuaries 2014 Mortality Tables Report (RP-2014) and Mortality Improvement Scale (MP-2014 with modifications), which adjusted the mortality assumptions used for measuring retirement plan obligations. The updated mortality assumptions reflect increasing life expectancies in the United States, resulting in an increase to PG&E Corporation’s and the Utility’s pension and PBOP plans’ projected benefit obligations. Future pension and postretirement expenses are also expected to increase due to the new mortality assumptions.
59
In establishing health care cost assumptions, PG&E Corporation and the Utility consider recent cost trends and projections from industry experts. This evaluation suggests that current rates of inflation are expected to continue in the near term. In recognition of continued high inflation in health care costs and given the design of PG&E Corporation’s plans, the assumed health care cost trend rate for 2014 is 7.5%, gradually decreasing to the ultimate trend rate of 3.5% in 2024 and beyond.
Expected rates of return on plan assets were developed by estimating future stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed-income returns were projected based on real maturity and credit spreads added to a long-term inflation rate. Equity returns were projected based on estimates of dividend yield and real earnings growth added to a long-term rate of inflation. For the Utility’s defined benefit pension plan, the assumed return of 6.2% compares to a ten-year actual return of 9.3%.
The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of approximately 715 Aa-grade non-callable bonds at December 31, 2014. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension and other postretirement benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
The following reflects the sensitivity of pension costs and projected benefit obligation to changes in certain actuarial assumptions:
|
Increase
|
Increase in Projected
|
|||||||||||
|
(Decrease) in
|
Increase in 2014 Pension
|
Benefit Obligation at
|
||||||||||
|
(in millions)
|
Assumption
|
Costs
|
December 31, 2014
|
|||||||||
|
Discount rate
|
(0.50 | ) % | $ | 52 | $ | 1,319 | ||||||
|
Rate of return on plan assets
|
(0.50 | ) % | 62 | - | ||||||||
|
Rate of increase in compensation
|
0.50 | % | 32 | 316 | ||||||||
The following reflects the sensitivity of other postretirement benefit costs and accumulated benefit obligation to changes in certain actuarial assumptions:
|
Increase
|
Increase in 2014
|
Increase in Accumulated
|
||||||||||
|
(Decrease) in
|
Other Postretirement
|
Benefit Obligation at
|
||||||||||
|
(in millions)
|
Assumption
|
Benefit Costs
|
December 31, 2014
|
|||||||||
|
Health care cost trend rate
|
0.50 | % | $ | 4 | $ | 53 | ||||||
|
Discount rate
|
(0.50 | ) % | 3 | 128 | ||||||||
|
Rate of return on plan assets
|
(0.50 | ) % | 9 | - | ||||||||
See Note 2 of the Notes to the Consolidated Financial Statements.
60
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 costs, 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 final outcomes of the pending CPUC investigations and enforcement matters, the federal criminal prosecution of the Utility, and the other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas-related laws and regulations, including the ultimate amount of fines imposed, whether a monitor is appointed to oversee the Utility’s natural gas operations, and the ultimate amount of costs related to the Utility’s natural gas operations that is disallowed or unrecoverable;
|
|
·
|
the timing and outcome of additional regulatory enforcement actions or criminal investigations that may be or have been commenced relating to communications between the Utility and the CPUC that may have violated the CPUC’s rules regarding ex parte communications or are alleged to otherwise be improper, and whether such outcomes or investigations negatively affect the final decisions to be issued in the 2015 GT&S rate case, the pending CPUC investigations, or other ratemaking proceedings;
|
|
·
|
whether PG&E Corporation and the Utility are able to repair the harm to their reputations caused by negative publicity about the San Bruno accident, the criminal prosecution, the citations issued by the SED against the Utility under the CPUC’s gas safety citation program, the state and federal investigations, the CPUC’s restrictions on the Utility’s communications with the CPUC, 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 and the TO rate case) and whether the cost and revenue forecasts assumed in such outcomes prove to be accurate;
|
|
·
|
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 costs and fines associated with natural gas matters and the pending investigations;
|
|
·
|
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;
|
61
|
·
|
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 request that the NRC resume processing the Utility’s renewal application for the two Diablo Canyon operating licenses, and if so, whether the NRC grants the renewal;
|
|
·
|
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 CO2 and GHGs, 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 ROE;
|
|
·
|
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, especially if the integration of renewable generation resources force conventional generation resource providers to curtail production, triggering “take or pay” provisions in the Utility’s power purchase agreements;
|
|
·
|
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; including the timing and amount of insurance recoveries related to third party claims arising from the San Bruno accident;
|
|
·
|
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; 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 Item 1A. Risk Factors above. 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.
62
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information responding to Item 7A is set forth under the heading “Risk Management Activities,” in MD&A in Item 7 and in Note 9: Derivatives and Note 10: Fair Value Measurements of the Notes to the Consolidated Financial Statements in Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PG&E Corporation
(in millions, except per share amounts)
|
Year ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
Operating Revenues
|
||||||||||||
|
Electric
|
$ | 13,658 | $ | 12,494 | $ | 12,019 | ||||||
|
Natural gas
|
3,432 | 3,104 | 3,021 | |||||||||
|
Total operating revenues
|
17,090 | 15,598 | 15,040 | |||||||||
|
Operating Expenses
|
||||||||||||
|
Cost of electricity
|
5,615 | 5,016 | 4,162 | |||||||||
|
Cost of natural gas
|
954 | 968 | 861 | |||||||||
|
Operating and maintenance
|
5,638 | 5,775 | 6,052 | |||||||||
|
Depreciation, amortization, and decommissioning
|
2,433 | 2,077 | 2,272 | |||||||||
|
Total operating expenses
|
14,640 | 13,836 | 13,347 | |||||||||
|
Operating Income
|
2,450 | 1,762 | 1,693 | |||||||||
|
Interest income
|
9 | 9 | 7 | |||||||||
|
Interest expense
|
(734 | ) | (715 | ) | (703 | ) | ||||||
|
Other income, net
|
70 | 40 | 70 | |||||||||
|
Income Before Income Taxes
|
1,795 | 1,096 | 1,067 | |||||||||
|
Income tax provision
|
345 | 268 | 237 | |||||||||
|
Net Income
|
1,450 | 828 | 830 | |||||||||
|
Preferred stock dividend requirement of subsidiary
|
14 | 14 | 14 | |||||||||
|
Income Available for Common Shareholders
|
$ | 1,436 | $ | 814 | $ | 816 | ||||||
|
Weighted Average Common Shares Outstanding, Basic
|
468 | 444 | 424 | |||||||||
|
Weighted Average Common Shares Outstanding, Diluted
|
470 | 445 | 425 | |||||||||
|
Net Earnings Per Common Share, Basic
|
$ | 3.07 | $ | 1.83 | $ | 1.92 | ||||||
|
Net Earnings Per Common Share, Diluted
|
$ | 3.06 | $ | 1.83 | $ | 1.92 | ||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
63
PG&E Corporation
|
Year ended December 31,
|
||||||||||||
|
(in millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Net Income
|
$ | 1,450 | $ | 828 | $ | 830 | ||||||
|
Other Comprehensive Income
|
||||||||||||
|
Pension and other postretirement benefit plans obligations
|
||||||||||||
|
(net of taxes of $10, $80, and $72, at respective dates)
|
(14 | ) | 113 | 108 | ||||||||
|
Net change in investments
|
||||||||||||
|
(net of taxes of $17, $26, and $3 at respective dates)
|
(25 | ) | 38 | 4 | ||||||||
|
Total other comprehensive income (loss)
|
(39 | ) | 151 | 112 | ||||||||
|
Comprehensive Income
|
1,411 | 979 | 942 | |||||||||
|
Preferred stock dividend requirement of subsidiary
|
14 | 14 | 14 | |||||||||
|
Comprehensive Income Attributable to Common Shareholders
|
$ | 1,397 | $ | 965 | $ | 928 | ||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
64
PG&E Corporation
(in millions)
|
Balance at December 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
$ | 151 | $ | 296 | ||||
|
Restricted cash
|
298 | 301 | ||||||
|
Accounts receivable
|
||||||||
|
Customers (net of allowance for doubtful accounts of $66 and $80 at
|
||||||||
|
December 31, 2014 and 2013, respectively)
|
960 | 1,091 | ||||||
|
Accrued unbilled revenue
|
776 | 766 | ||||||
|
Regulatory balancing accounts
|
2,266 | 1,124 | ||||||
|
Other
|
377 | 312 | ||||||
|
Regulatory assets
|
444 | 448 | ||||||
|
Inventories
|
||||||||
|
Gas stored underground and fuel oil
|
172 | 137 | ||||||
|
Materials and supplies
|
304 | 317 | ||||||
|
Income taxes receivable
|
198 | 574 | ||||||
|
Other
|
443 | 611 | ||||||
|
Total current assets
|
6,389 | 5,977 | ||||||
|
Property, Plant, and Equipment
|
||||||||
|
Electric
|
45,162 | 42,881 | ||||||
|
Gas
|
15,678 | 14,379 | ||||||
|
Construction work in progress
|
2,220 | 1,834 | ||||||
|
Other
|
2 | 2 | ||||||
|
Total property, plant, and equipment
|
63,062 | 59,096 | ||||||
|
Accumulated depreciation
|
(19,121 | ) | (17,844 | ) | ||||
|
Net property, plant, and equipment
|
43,941 | 41,252 | ||||||
|
Other Noncurrent Assets
|
||||||||
|
Regulatory assets
|
6,322 | 4,913 | ||||||
|
Nuclear decommissioning trusts
|
2,421 | 2,342 | ||||||
|
Income taxes receivable
|
91 | 85 | ||||||
|
Other
|
963 | 1,036 | ||||||
|
Total other noncurrent assets
|
9,797 | 8,376 | ||||||
|
TOTAL ASSETS
|
$ | 60,127 | $ | 55,605 | ||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||
65
PG&E Corporation
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
|
Balance at December 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
LIABILITIES AND EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Short-term borrowings
|
$ | 633 | $ | 1,174 | ||||
|
Long-term debt, classified as current
|
- | 889 | ||||||
|
Accounts payable
|
||||||||
|
Trade creditors
|
1,244 | 1,293 | ||||||
|
Regulatory balancing accounts
|
1,090 | 1,008 | ||||||
|
Other
|
476 | 471 | ||||||
|
Disputed claims and customer refunds
|
434 | 154 | ||||||
|
Interest payable
|
197 | 892 | ||||||
|
Other
|
1,846 | 1,612 | ||||||
|
Total current liabilities
|
5,920 | 7,493 | ||||||
|
Noncurrent Liabilities
|
||||||||
|
Long-term debt
|
15,050 | 12,717 | ||||||
|
Regulatory liabilities
|
6,290 | 5,660 | ||||||
|
Pension and other postretirement benefits
|
2,561 | 1,601 | ||||||
|
Asset retirement obligations
|
3,575 | 3,539 | ||||||
|
Deferred income taxes
|
8,513 | 7,823 | ||||||
|
Other
|
2,218 | 2,178 | ||||||
|
Total noncurrent liabilities
|
38,207 | 33,518 | ||||||
|
Commitments and Contingencies (Note 14)
|
||||||||
|
Equity
|
||||||||
|
Shareholders' Equity
|
||||||||
|
Common stock, no par value, authorized 800,000,000 shares;
|
||||||||
|
475,913,404 shares outstanding at December 31, 2014 and
|
||||||||
|
456,670,424 shares outstanding at December 31, 2013
|
10,421 | 9,550 | ||||||
|
Reinvested earnings
|
5,316 | 4,742 | ||||||
|
Accumulated other comprehensive income
|
11 | 50 | ||||||
|
Total shareholders' equity
|
15,748 | 14,342 | ||||||
|
Noncontrolling Interest - Preferred Stock of Subsidiary
|
252 | 252 | ||||||
|
Total equity
|
16,000 | 14,594 | ||||||
|
TOTAL LIABILITIES AND EQUITY
|
$ | 60,127 | $ | 55,605 | ||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||
66
PG&E Corporation
(in millions)
|
Year ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
Cash Flows from Operating Activities
|
||||||||||||
|
Net income
|
$ | 1,450 | $ | 828 | $ | 830 | ||||||
|
Adjustments to reconcile net income to net cash provided by
|
||||||||||||
|
operating activities:
|
||||||||||||
|
Depreciation, amortization, and decommissioning
|
2,433 | 2,077 | 2,272 | |||||||||
|
Allowance for equity funds used during construction
|
(100 | ) | (101 | ) | (107 | ) | ||||||
|
Deferred income taxes and tax credits, net
|
690 | 1,075 | 648 | |||||||||
|
PSEP disallowed capital expenditures
|
116 | 196 | 353 | |||||||||
|
Other
|
286 | 355 | 290 | |||||||||
|
Effect of changes in operating assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
13 | (152 | ) | (40 | ) | |||||||
|
Inventories
|
(22 | ) | (10 | ) | (24 | ) | ||||||
|
Accounts payable
|
(61 | ) | 113 | (4 | ) | |||||||
|
Income taxes receivable/payable
|
376 | (363 | ) | (132 | ) | |||||||
|
Other current assets and liabilities
|
205 | (469 | ) | 262 | ||||||||
|
Regulatory assets, liabilities, and balancing accounts, net
|
(1,642 | ) | (202 | ) | 291 | |||||||
|
Other noncurrent assets and liabilities
|
(67 | ) | 80 | 243 | ||||||||
|
Net cash provided by operating activities
|
3,677 | 3,427 | 4,882 | |||||||||
|
Cash Flows from Investing Activities
|
||||||||||||
|
Capital expenditures
|
(4,833 | ) | (5,207 | ) | (4,624 | ) | ||||||
|
Decrease in restricted cash
|
3 | 29 | 50 | |||||||||
|
Proceeds from sales and maturities of nuclear decommissioning
|
||||||||||||
|
trust investments
|
1,336 | 1,619 | 1,133 | |||||||||
|
Purchases of nuclear decommissioning trust investments
|
(1,334 | ) | (1,604 | ) | (1,189 | ) | ||||||
|
Other
|
114 | 56 | 104 | |||||||||
|
Net cash used in investing activities
|
(4,714 | ) | (5,107 | ) | (4,526 | ) | ||||||
|
Cash Flows from Financing Activities
|
||||||||||||
|
Borrowings under revolving credit facilities
|
- | 140 | 120 | |||||||||
|
Repayments under revolving credit facilities
|
(260 | ) | - | - | ||||||||
|
Net issuances (repayments) of commercial paper, net of discount
|
||||||||||||
|
of $2, $2, and $3 at respective dates
|
(583 | ) | 542 | (1,021 | ) | |||||||
|
Proceeds from issuance of short-term debt, net of issuance costs
|
300 | - | - | |||||||||
|
Proceeds from issuance of long-term debt, net of premium, discount,
|
||||||||||||
|
and issuance costs of $17, $18 and $13 at respective dates
|
2,308 | 1,532 | 1,137 | |||||||||
|
Short-term debt matured
|
- | - | (250 | ) | ||||||||
|
Repayments of long-term debt
|
(889 | ) | (861 | ) | (50 | ) | ||||||
|
Energy recovery bonds matured
|
- | - | (423 | ) | ||||||||
|
Common stock issued
|
802 | 1,045 | 751 | |||||||||
|
Common stock dividends paid
|
(828 | ) | (782 | ) | (746 | ) | ||||||
|
Other
|
42 | (41 | ) | 14 | ||||||||
|
Net cash provided by (used in) financing activities
|
892 | 1,575 | (468 | ) | ||||||||
|
Net change in cash and cash equivalents
|
(145 | ) | (105 | ) | (112 | ) | ||||||
|
Cash and cash equivalents at January 1
|
296 | 401 | 513 | |||||||||
|
Cash and cash equivalents at December 31
|
$ | 151 | $ | 296 | $ | 401 | ||||||
|
Supplemental disclosures of cash flow information
|
||||||||||||
|
Cash received (paid) for:
|
||||||||||||
|
Interest, net of amounts capitalized
|
$ | (633 | ) | $ | (623 | ) | $ | (594 | ) | |||
|
Income taxes, net
|
501 | (41 | ) | 114 | ||||||||
|
Supplemental disclosures of noncash investing and financing
|
||||||||||||
|
activities
|
||||||||||||
|
Common stock dividends declared but not yet paid
|
$ | 217 | $ | 208 | $ | 196 | ||||||
|
Capital expenditures financed through accounts payable
|
339 | 322 | 362 | |||||||||
|
Noncash common stock issuances
|
21 | 22 | 22 | |||||||||
|
Terminated capital leases
|
71 | - | 136 | |||||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
67
PG&E Corporation
(in millions, except share amounts)
|
Non
|
||||||||||||||||||||||||||||
|
Accumulated
|
controlling
|
|||||||||||||||||||||||||||
|
Other
|
Interest -
|
|||||||||||||||||||||||||||
|
Common
|
Common
|
Comprehensive
|
Total
|
Preferred
|
||||||||||||||||||||||||
|
Stock
|
Stock
|
Reinvested
|
Income
|
Shareholders'
|
Stock of
|
Total
|
||||||||||||||||||||||
|
Shares
|
Amount
|
Earnings
|
(Loss)
|
Equity
|
Subsidiary
|
Equity
|
||||||||||||||||||||||
|
Balance at December 31, 2011
|
412,257,082 | 7,602 | 4,712 | (213 | ) | 12,101 | 252 | 12,353 | ||||||||||||||||||||
|
Net income
|
- | - | 830 | - | 830 | - | 830 | |||||||||||||||||||||
|
Other comprehensive income
|
- | - | - | 112 | 112 | - | 112 | |||||||||||||||||||||
|
Common stock issued, net
|
18,461,211 | 773 | - | - | 773 | - | 773 | |||||||||||||||||||||
|
Stock-based compensation amortization
|
- | 52 | - | - | 52 | - | 52 | |||||||||||||||||||||
|
Common stock dividends declared
|
- | - | (781 | ) | - | (781 | ) | - | (781 | ) | ||||||||||||||||||
|
Tax benefit from employee stock plans
|
- | 1 | - | - | 1 | - | 1 | |||||||||||||||||||||
|
Preferred stock dividend requirement of
|
||||||||||||||||||||||||||||
|
subsidiary
|
- | - | (14 | ) | - | (14 | ) | - | (14 | ) | ||||||||||||||||||
|
Balance at December 31, 2012
|
430,718,293 | 8,428 | 4,747 | (101 | ) | 13,074 | 252 | 13,326 | ||||||||||||||||||||
|
Net income
|
- | - | 828 | - | 828 | - | 828 | |||||||||||||||||||||
|
Other comprehensive income
|
- | - | - | 151 | 151 | - | 151 | |||||||||||||||||||||
|
Common stock issued, net
|
25,952,131 | 1,067 | - | - | 1,067 | - | 1,067 | |||||||||||||||||||||
|
Stock-based compensation amortization
|
- | 56 | - | - | 56 | - | 56 | |||||||||||||||||||||
|
Common stock dividends declared
|
- | - | (819 | ) | - | (819 | ) | - | (819 | ) | ||||||||||||||||||
|
Tax expense from employee stock plans
|
- | (1 | ) | - | - | (1 | ) | - | (1 | ) | ||||||||||||||||||
|
Preferred stock dividend requirement of
|
||||||||||||||||||||||||||||
|
subsidiary
|
- | - | (14 | ) | - | (14 | ) | - | (14 | ) | ||||||||||||||||||
|
Balance at December 31, 2013
|
456,670,424 | $ | 9,550 | $ | 4,742 | $ | 50 | $ | 14,342 | $ | 252 | $ | 14,594 | |||||||||||||||
|
Net income
|
- | - | 1,450 | - | 1,450 | - | 1,450 | |||||||||||||||||||||
|
Other comprehensive loss
|
- | - | - | (39 | ) | (39 | ) | - | (39 | ) | ||||||||||||||||||
|
Common stock issued, net
|
19,242,980 | 823 | - | - | 823 | - | 823 | |||||||||||||||||||||
|
Stock-based compensation amortization
|
- | 65 | - | - | 65 | - | 65 | |||||||||||||||||||||
|
Common stock dividends declared
|
- | - | (862 | ) | - | (862 | ) | - | (862 | ) | ||||||||||||||||||
|
Tax expense from employee stock plans
|
- | (17 | ) | - | - | (17 | ) | - | (17 | ) | ||||||||||||||||||
|
Preferred stock dividend requirement of
|
||||||||||||||||||||||||||||
|
subsidiary
|
- | - | (14 | ) | - | (14 | ) | - | (14 | ) | ||||||||||||||||||
|
Balance at December 31, 2014
|
475,913,404 | $ | 10,421 | $ | 5,316 | $ | 11 | $ | 15,748 | $ | 252 | $ | 16,000 | |||||||||||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||||||||||||||||||
68
Pacific Gas and Electric Company
(in millions)
|
Year ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
Operating Revenues
|
||||||||||||
|
Electric
|
$ | 13,656 | $ | 12,489 | $ | 12,014 | ||||||
|
Natural gas
|
3,432 | 3,104 | 3,021 | |||||||||
|
Total operating revenues
|
17,088 | 15,593 | 15,035 | |||||||||
|
Operating Expenses
|
||||||||||||
|
Cost of electricity
|
5,615 | 5,016 | 4,162 | |||||||||
|
Cost of natural gas
|
954 | 968 | 861 | |||||||||
|
Operating and maintenance
|
5,635 | 5,742 | 6,045 | |||||||||
|
Depreciation, amortization, and decommissioning
|
2,432 | 2,077 | 2,272 | |||||||||
|
Total operating expenses
|
14,636 | 13,803 | 13,340 | |||||||||
|
Operating Income
|
2,452 | 1,790 | 1,695 | |||||||||
|
Interest income
|
8 | 8 | 6 | |||||||||
|
Interest expense
|
(720 | ) | (690 | ) | (680 | ) | ||||||
|
Other income, net
|
77 | 84 | 88 | |||||||||
|
Income Before Income Taxes
|
1,817 | 1,192 | 1,109 | |||||||||
|
Income tax provision
|
384 | 326 | 298 | |||||||||
|
Net Income
|
1,433 | 866 | 811 | |||||||||
|
Preferred stock dividend requirement
|
14 | 14 | 14 | |||||||||
|
Income Available for Common Stock
|
$ | 1,419 | $ | 852 | $ | 797 | ||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
69
Pacific Gas and Electric Company
|
Year ended December 31,
|
||||||||||||
|
(in millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Net Income
|
$ | 1,433 | $ | 866 | $ | 811 | ||||||
|
Other Comprehensive Income
|
||||||||||||
|
Pension and other postretirement benefit plans obligations (net of taxes of
|
||||||||||||
|
$6, $75, and $73, at respective dates)
|
(8 | ) | 106 | 109 | ||||||||
|
Total other comprehensive income (loss)
|
(8 | ) | 106 | 109 | ||||||||
|
Comprehensive Income
|
$ | 1,425 | $ | 972 | $ | 920 | ||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
70
Pacific Gas and Electric Company
(in millions)
|
Balance at December 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
$ | 55 | $ | 65 | ||||
|
Restricted cash
|
298 | 301 | ||||||
|
Accounts receivable
|
||||||||
|
Customers (net of allowance for doubtful accounts of $66 and $80 at
|
||||||||
|
December 31, 2014 and 2013, respectively)
|
960 | 1,091 | ||||||
|
Accrued unbilled revenue
|
776 | 766 | ||||||
|
Regulatory balancing accounts
|
2,266 | 1,124 | ||||||
|
Other
|
375 | 313 | ||||||
|
Regulatory assets
|
444 | 448 | ||||||
|
Inventories
|
||||||||
|
Gas stored underground and fuel oil
|
172 | 137 | ||||||
|
Materials and supplies
|
304 | 317 | ||||||
|
Income taxes receivable
|
168 | 563 | ||||||
|
Other
|
409 | 523 | ||||||
|
Total current assets
|
6,227 | 5,648 | ||||||
|
Property, Plant, and Equipment
|
||||||||
|
Electric
|
45,162 | 42,881 | ||||||
|
Gas
|
15,678 | 14,379 | ||||||
|
Construction work in progress
|
2,220 | 1,834 | ||||||
|
Total property, plant, and equipment
|
63,060 | 59,094 | ||||||
|
Accumulated depreciation
|
(19,120 | ) | (17,843 | ) | ||||
|
Net property, plant, and equipment
|
43,940 | 41,251 | ||||||
|
Other Noncurrent Assets
|
||||||||
|
Regulatory assets
|
6,322 | 4,913 | ||||||
|
Nuclear decommissioning trusts
|
2,421 | 2,342 | ||||||
|
Income taxes receivable
|
91 | 81 | ||||||
|
Other
|
864 | 814 | ||||||
|
Total other noncurrent assets
|
9,698 | 8,150 | ||||||
|
TOTAL ASSETS
|
$ | 59,865 | $ | 55,049 | ||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||
71
Pacific Gas and Electric Company
CONSOLIDATED BALANCE SHEETS
(in millions, except share amounts)
|
Balance at December 31,
|
||||||||
|
2014
|
2013
|
|||||||
|
LIABILITIES AND SHAREHOLDERS' EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Short-term borrowings
|
$ | 633 | $ | 914 | ||||
|
Long-term debt, classified as current
|
- | 539 | ||||||
|
Accounts payable
|
||||||||
|
Trade creditors
|
1,243 | 1,293 | ||||||
|
Regulatory balancing accounts
|
1,090 | 1,008 | ||||||
|
Other
|
444 | 432 | ||||||
|
Disputed claims and customer refunds
|
434 | 154 | ||||||
|
Interest payable
|
195 | 887 | ||||||
|
Other
|
1,604 | 1,382 | ||||||
|
Total current liabilities
|
5,643 | 6,609 | ||||||
|
Noncurrent Liabilities
|
||||||||
|
Long-term debt
|
14,700 | 12,717 | ||||||
|
Regulatory liabilities
|
6,290 | 5,660 | ||||||
|
Pension and other postretirement benefits
|
2,477 | 1,530 | ||||||
|
Asset retirement obligations
|
3,575 | 3,539 | ||||||
|
Deferred income taxes
|
8,773 | 8,042 | ||||||
|
Other
|
2,178 | 2,111 | ||||||
|
Total noncurrent liabilities
|
37,993 | 33,599 | ||||||
|
Commitments and Contingencies (Note 14)
|
||||||||
|
Shareholders' Equity
|
||||||||
|
Preferred stock
|
258 | 258 | ||||||
|
Common stock, $5 par value, authorized 800,000,000 shares, 264,374,809
|
||||||||
|
shares outstanding at December 31, 2014 and 2013
|
1,322 | 1,322 | ||||||
|
Additional paid-in capital
|
6,514 | 5,821 | ||||||
|
Reinvested earnings
|
8,130 | 7,427 | ||||||
|
Accumulated other comprehensive income
|
5 | 13 | ||||||
|
Total shareholders' equity
|
16,229 | 14,841 | ||||||
|
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
|
$ | 59,865 | $ | 55,049 | ||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||
72
Pacific Gas and Electric Company
(in millions)
|
Year ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
Cash Flows from Operating Activities
|
||||||||||||
|
Net income
|
$ | 1,433 | $ | 866 | $ | 811 | ||||||
|
Adjustments to reconcile net income to net cash provided by
|
||||||||||||
|
operating activities:
|
||||||||||||
|
Depreciation, amortization, and decommissioning
|
2,432 | 2,077 | 2,272 | |||||||||
|
Allowance for equity funds used during construction
|
(100 | ) | (101 | ) | (107 | ) | ||||||
|
Deferred income taxes and tax credits, net
|
731 | 1,103 | 684 | |||||||||
|
PSEP disallowed capital expenditures
|
116 | 196 | 353 | |||||||||
|
Other
|
226 | 299 | 236 | |||||||||
|
Effect of changes in operating assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
16 | (152 | ) | (40 | ) | |||||||
|
Inventories
|
(22 | ) | (10 | ) | (24 | ) | ||||||
|
Accounts payable
|
(55 | ) | 99 | (26 | ) | |||||||
|
Income taxes receivable/payable
|
395 | (377 | ) | (50 | ) | |||||||
|
Other current assets and liabilities
|
155 | (404 | ) | 272 | ||||||||
|
Regulatory assets, liabilities, and balancing accounts, net
|
(1,642 | ) | (202 | ) | 291 | |||||||
|
Other noncurrent assets and liabilities
|
(66 | ) | 22 | 256 | ||||||||
|
Net cash provided by operating activities
|
3,619 | 3,416 | 4,928 | |||||||||
|
Cash Flows from Investing Activities
|
||||||||||||
|
Capital expenditures
|
(4,833 | ) | (5,207 | ) | (4,624 | ) | ||||||
|
Decrease in restricted cash
|
3 | 29 | 50 | |||||||||
|
Proceeds from sales and maturities of nuclear decommissioning
|
||||||||||||
|
trust investments
|
1,336 | 1,619 | 1,133 | |||||||||
|
Purchases of nuclear decommissioning trust investments
|
(1,334 | ) | (1,604 | ) | (1,189 | ) | ||||||
|
Other
|
29 | 21 | 16 | |||||||||
|
Net cash used in investing activities
|
(4,799 | ) | (5,142 | ) | (4,614 | ) | ||||||
|
Cash Flows from Financing Activities
|
||||||||||||
|
Net issuances (repayments) of commercial paper, net of discount
|
||||||||||||
|
of $2, $2, and $3 at respective dates
|
(583 | ) | 542 | (1,021 | ) | |||||||
|
Proceeds from issuance of short-term debt, net of issuance costs
|
300 | - | - | |||||||||
|
Proceeds from issuance of long-term debt, net of premium,
|
||||||||||||
|
discount, and issuance costs of $14, $18, and $13 at respective dates
|
1,961 | 1,532 | 1,137 | |||||||||
|
Short-term debt matured
|
- | - | (250 | ) | ||||||||
|
Long-term debt matured or repurchased
|
(539 | ) | (861 | ) | (50 | ) | ||||||
|
Energy recovery bonds matured
|
- | - | (423 | ) | ||||||||
|
Preferred stock dividends paid
|
(14 | ) | (14 | ) | (14 | ) | ||||||
|
Common stock dividends paid
|
(716 | ) | (716 | ) | (716 | ) | ||||||
|
Equity contribution from PG&E Corporation
|
705 | 1,140 | 885 | |||||||||
|
Other
|
56 | (26 | ) | 28 | ||||||||
|
Net cash provided by (used in) financing activities
|
1,170 | 1,597 | (424 | ) | ||||||||
|
Net change in cash and cash equivalents
|
(10 | ) | (129 | ) | (110 | ) | ||||||
|
Cash and cash equivalents at January 1
|
65 | 194 | 304 | |||||||||
|
Cash and cash equivalents at December 31
|
$ | 55 | $ | 65 | $ | 194 | ||||||
|
Supplemental disclosures of cash flow information
|
||||||||||||
|
Cash received (paid) for:
|
||||||||||||
|
Interest, net of amounts capitalized
|
$ | (618 | ) | $ | (600 | ) | $ | (574 | ) | |||
|
Income taxes, net
|
500 | (62 | ) | 174 | ||||||||
|
Supplemental disclosures of noncash investing and financing
|
||||||||||||
|
activities
|
||||||||||||
|
Capital expenditures financed through accounts payable
|
$ | 339 | $ | 322 | $ | 362 | ||||||
|
Terminated capital leases
|
71 | - | 136 | |||||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||
73
Pacific Gas and Electric Company
(in millions)
|
Accumulated
|
||||||||||||||||||||||||
|
Additional
|
Other
|
Total
|
||||||||||||||||||||||
|
Preferred
|
Common
|
Paid-in
|
Reinvested
|
Comprehensive
|
Shareholders'
|
|||||||||||||||||||
|
Stock
|
Stock
|
Capital
|
Earnings
|
Income (Loss)
|
Equity
|
|||||||||||||||||||
|
Balance at December 31, 2011
|
$ | 258 | $ | 1,322 | $ | 3,796 | $ | 7,210 | $ | (202 | ) | $ | 12,384 | |||||||||||
|
Net income
|
- | - | - | 811 | - | 811 | ||||||||||||||||||
|
Other comprehensive income
|
- | - | - | - | 109 | 109 | ||||||||||||||||||
|
Equity contribution
|
- | - | 885 | - | - | 885 | ||||||||||||||||||
|
Tax benefit from employee stock plans
|
- | - | 1 | - | - | 1 | ||||||||||||||||||
|
Common stock dividend
|
- | - | - | (716 | ) | - | (716 | ) | ||||||||||||||||
|
Preferred stock dividend
|
- | - | - | (14 | ) | - | (14 | ) | ||||||||||||||||
|
Balance at December 31, 2012
|
258 | 1,322 | 4,682 | 7,291 | (93 | ) | 13,460 | |||||||||||||||||
|
Net income
|
- | - | - | 866 | - | 866 | ||||||||||||||||||
|
Other comprehensive income
|
- | - | - | - | 106 | 106 | ||||||||||||||||||
|
Equity contribution
|
- | - | 1,140 | - | - | 1,140 | ||||||||||||||||||
|
Tax expense from employee stock plans
|
- | - | (1 | ) | - | - | (1 | ) | ||||||||||||||||
|
Common stock dividend
|
- | - | - | (716 | ) | - | (716 | ) | ||||||||||||||||
|
Preferred stock dividend
|
- | - | - | (14 | ) | - | (14 | ) | ||||||||||||||||
|
Balance at December 31, 2013
|
258 | 1,322 | 5,821 | 7,427 | 13 | 14,841 | ||||||||||||||||||
|
Net income
|
- | - | - | 1,433 | - | 1,433 | ||||||||||||||||||
|
Other comprehensive loss
|
- | - | - | - | (8 | ) | (8 | ) | ||||||||||||||||
|
Equity contribution
|
- | - | 705 | - | - | 705 | ||||||||||||||||||
|
Tax expense from employee stock plans
|
- | - | (12 | ) | - | - | (12 | ) | ||||||||||||||||
|
Common stock dividend
|
- | - | - | (716 | ) | - | (716 | ) | ||||||||||||||||
|
Preferred stock dividend
|
- | - | - | (14 | ) | - | (14 | ) | ||||||||||||||||
|
Balance at December 31, 2014
|
$ | 258 | $ | 1,322 | $ | 6,514 | $ | 8,130 | $ | 5 | $ | 16,229 | ||||||||||||
|
See accompanying Notes to the Consolidated Financial Statements.
|
||||||||||||||||||||||||
74
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility 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.
This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s consolidated financial statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s consolidated financial statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility operate in one segment.
The consolidated financial statements have been prepared in accordance with GAAP and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, legal and regulatory contingencies, environmental remediation liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the consolidated financial statements are appropriate and reasonable. Actual results could differ materially from those estimates.
NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Regulation and Regulated Operations
As a regulated entity, the Utility collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s costs of service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.
The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below.
Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.
75
Revenue Recognition
The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements.
The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three years. In general, the Utility’s ability to recover revenue requirements authorized by the CPUC in these rates cases is independent, or “decoupled” from the volume of the Utility’s sales of electricity and natural gas services. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, revenue is recognized ratably over the year.
The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas; and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred.
The FERC authorizes the Utility’s revenue requirements in periodic (often annual) TO rate cases. The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled.
Cash and Cash Equivalents
Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value.
Restricted Cash
Restricted cash consists primarily of the Utility’s cash held in escrow pending the resolution of the remaining disputed claims made by electricity suppliers in the Utility’s proceeding under Chapter 11 of the U.S. Bankruptcy Code. (See Note 12 below.)
Allowance for Doubtful Accounts Receivable
PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value. The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.
Inventories
Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies. Natural gas stored underground represents gas that is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and then expensed or capitalized to plant, as appropriate, when consumed or installed.
The Utility also purchases GHG emission allowances that are recorded as inventory. They are carried at weighted-average cost and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets. The costs of the GHG emissions are expensed and recoverable through rates.
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Property, Plant, and Equipment
Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value. Historical costs include labor and materials, construction overhead, and AFUDC. (See “AFUDC” below.) The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:
|
Estimated Useful
|
Balance at December 31,
|
||||||||
|
(in millions, except estimated useful lives)
|
Lives (years)
|
2014
|
2013
|
||||||
|
Electricity generating facilities (1)
|
10 to 100
|
$ | 9,374 | $ | 9,116 | ||||
|
Electricity distribution facilities
|
10 to 55
|
26,633 | 25,333 | ||||||
|
Electricity transmission facilities
|
10 to 70
|
9,155 | 8,429 | ||||||
|
Natural gas distribution facilities
|
20 to 60
|
9,741 | 9,117 | ||||||
|
Natural gas transportation and storage facilities
|
7 to 65
|
5,937 | 5,265 | ||||||
|
Construction work in progress
|
2,220 | 1,834 | |||||||
|
Total property, plant, and equipment
|
63,060 | 59,094 | |||||||
|
Accumulated depreciation
|
(19,120 | ) | (17,843 | ) | |||||
|
Net property, plant, and equipment
|
$ | 43,940 | $ | 41,251 | |||||
|
(1) Balance includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted-average cost. Nuclear fuel in the reactor is expensed as itis used based on the amount of energy output. (See Note 14 below.)
|
The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property. This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.77% in 2014, 3.51% in 2013, and 3.63% in 2012. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.
AFUDC
AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $45 million and $100 million during 2014, $47 million and $101 million during 2013, and $49 million and $107 million during 2012.
77
Asset Retirement Obligations
Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.
The Utility adjusts its nuclear decommissioning obligation to reflect changes in the estimated costs of decommissioning its nuclear power facilities and records this as an adjustment to the ARO liability on its Consolidated Balance Sheets. The total nuclear decommissioning obligation accrued was $2.5 billion at December 31, 2014 and 2013. The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $3.5 billion at December 31, 2014 and 2013 (or $6.1 billion in future dollars). These estimates are based on the 2012 decommissioning cost studies, prepared in accordance with CPUC requirements.
The following table summarizes the changes in ARO liability during 2014 and 2013:
|
2014
|
2013
|
|||||||
|
ARO liability at beginning of year
|
$ | 3,538 | $ | 2,919 | ||||
|
Revision in estimated cash flows
|
(16 | ) | 596 | |||||
|
Accretion
|
163 | 130 | ||||||
|
Liabilities settled
|
(110 | ) | (107 | ) | ||||
|
ARO liability at end of year
|
$ | 3,575 | $ | 3,538 | ||||
The Utility has not recorded a liability related to certain ARO’s for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration or land to the conditions under certain agreements.
Disallowance of Plant Costs
PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated. The Utility recorded charges of $116 million, $196 million and $353 million in 2014, 2013, and 2012, respectively, for PSEP capital costs that are expected to exceed the CPUC’s authorized levels or that are specifically disallowed. (See “Enforcement and Litigation Matters” in Note 14 below).
78
Nuclear Decommissioning Trusts
The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.
The Utility classifies its investments held in the nuclear decommissioning trusts as “available-for-sale.” Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.
Gains and Losses on Debt Extinguishments
Deferred gains and losses on debt extinguishments are recorded to regulatory assets in current assets and regulatory assets in other noncurrent assets on the Consolidated Balance Sheets. Gains and losses on debt extinguishments associated with regulated operations are deferred and amortized over a period consistent with the recovery of costs through regulated rates. PG&E Corporation and the Utility recorded unamortized loss on debt extinguishments, net of gain, of $135 million, $157 million, and $163 million at December 31, 2014, 2013, and 2012, respectively. The amortization expense related to this loss was $22 million in 2014 and $23 million in both 2013 and 2012.
Variable Interest Entities
A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.
Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2014, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2014, it did not consolidate any of them.
PG&E Corporation affiliates previously entered into four tax equity agreements to fund residential and commercial retail solar energy installations with four separate privately held funds that were considered VIEs. Since PG&E Corporation was not the primary beneficiary of any of these VIEs, they were not consolidated. On July 2, 2014, PG&E Corporation disposed of its interest in the tax equity agreements and has no remaining commitment to fund these agreements.
Other Accounting Policies
For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies” in Note 14 of the Notes to the Consolidated Financial Statements.
79
Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2014 consisted of the following:
|
Pension
|
Other
|
Other
|
||||||||||||||
|
(in millions, net of income tax)
|
Benefits
|
Benefits
|
Investments
|
Total
|
||||||||||||
|
Beginning balance
|
$ | (7 | ) | 15 | 42 | 50 | ||||||||||
|
Other comprehensive income before reclassifications:
|
||||||||||||||||
|
Change in investments
|
||||||||||||||||
|
(net of taxes of $0, $0, and $4, respectively)
|
- | - | 5 | 5 | ||||||||||||
|
Unrecognized net actuarial loss
|
||||||||||||||||
|
(net of taxes of $404, $19, and $0, respectively)
|
(588 | ) | (28 | ) | - | (616 | ) | |||||||||
|
Unrecognized prior service cost
|
||||||||||||||||
|
(net of taxes of $0, $0, and $0, respectively)
|
1 | - | - | 1 | ||||||||||||
|
Transfer to regulatory account
|
||||||||||||||||
|
(net of taxes of $394, $19, and $0, respectively)
|
573 | 28 | - | 601 | ||||||||||||
|
Amounts reclassified from other comprehensive income:
|
||||||||||||||||
|
Amortization of prior service cost
|
||||||||||||||||
|
(net of taxes of $8, $9, and $0, respectively) (1)
|
12 | 14 | - | 26 | ||||||||||||
|
Amortization of net actuarial loss
|
||||||||||||||||
|
(net of taxes of $1, $1, and $0, respectively) (1)
|
1 | 1 | - | 2 | ||||||||||||
|
Transfer to regulatory account
|
||||||||||||||||
|
(net of taxes of $9, $10, and $0, respectively) (1)
|
(13 | ) | (15 | ) | - | (28 | ) | |||||||||
|
Realized gain on investments
|
||||||||||||||||
|
(net of taxes of $0, $0, and $20, respectively)
|
- | - | (30 | ) | (30 | ) | ||||||||||
|
Net current period other comprehensive loss
|
(14 | ) | - | (25 | ) | (39 | ) | |||||||||
|
Ending balance
|
$ | (21 | ) | 15 | 17 | 11 | ||||||||||
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2013 consisted of the following:
|
Pension
|
Other
|
Other
|
||||||||||||||
|
(in millions, net of income tax)
|
Benefits
|
Benefits
|
Investments
|
Total
|
||||||||||||
|
Beginning balance
|
$ | (28 | ) | (77 | ) | 4 | (101 | ) | ||||||||
|
Other comprehensive income before reclassifications:
|
||||||||||||||||
|
Change in investments
|
||||||||||||||||
|
(net of taxes of $0, $0, and $26, respectively)
|
- | - | 38 | 38 | ||||||||||||
|
Unrecognized net actuarial loss
|
||||||||||||||||
|
(net of taxes of $804, $35, and $0, respectively)
|
1,169 | 45 | - | 1,214 | ||||||||||||
|
Transfer to regulatory account
|
||||||||||||||||
|
(net of taxes of $790, $22, and $0, respectively)
|
(1,150 | ) | 31 | - | (1,119 | ) | ||||||||||
|
Amounts reclassified from other comprehensive income: (1)
|
||||||||||||||||
|
Amortization of prior service cost
|
||||||||||||||||
|
(net of taxes of $8, $10, and $0, respectively)
|
12 | 13 | - | 25 | ||||||||||||
|
Amortization of net actuarial loss
|
||||||||||||||||
|
(net of taxes of $45, $3, and $0, respectively)
|
66 | 3 | - | 69 | ||||||||||||
|
Transfer to regulatory account
|
||||||||||||||||
|
(net of taxes of $54, $0, and $0, respectively)
|
(76 | ) | - | - | (76 | ) | ||||||||||
|
Net current period other comprehensive income
|
21 | 92 | 38 | 151 | ||||||||||||
|
Ending balance
|
$ | (7 | ) | 15 | 42 | 50 | ||||||||||
(1) These components are included in the computation of net periodic pension and other postretirement benefit costs. (See Note 11 below for additional details.)
With the exception of other investments, there was no material difference between PG&E Corporation and the Utility for the information disclosed above.
80
New Accounting Pronouncements
Revenue Recognition Standard
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which amends existing revenue recognition guidance. The accounting standards update will be effective on 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 comprised of the following:
|
Balance at December 31,
|
Recovery
|
|||||||||||
|
(in millions)
|
2014
|
2013
|
Period
|
|||||||||
|
Pension benefits (1)
|
$ | 2,347 | $ | 1,444 | N/A | (4) | ||||||
|
Deferred income taxes (1)
|
2,390 | 1,835 |
47 years
|
|||||||||
|
Utility retained generation (2)
|
456 | 503 |
11 years
|
|||||||||
|
Environmental compliance costs (1)
|
717 | 628 |
32 years
|
|||||||||
|
Price risk management (1)
|
127 | 106 |
10 years
|
|||||||||
|
Electromechanical meters (3)
|
70 | 135 |
2 years
|
|||||||||
|
Unamortized loss, net of gain, on reacquired debt (1)
|
113 | 135 |
12 years
|
|||||||||
|
Other
|
102 | 127 |
Various
|
|||||||||
|
Total long-term regulatory assets
|
$ | 6,322 | $ | 4,913 | ||||||||
|
(1) Represents the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. Pension benefits also includes amounts that otherwise would be recorded to accumulated other comprehensive income/loss in the Consolidated Balance Sheets. (See Note 11 below.)
|
|
(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.
|
|
(3) Represents the expected future recovery of the net book value of electromechanical meters that were replaced with SmartMeter™ devices.
|
|
(4) The Utility expects to continuously recover pension benefits.
|
In general, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest. Accordingly, the Utility earns a return only on its regulatory assets for retained generation, regulatory assets for electromechanical meters, and regulatory assets for unamortized loss, net of gain, on reacquired debt.
81
Regulatory Liabilities
Long-term regulatory liabilities are comprised of the following:
|
Balance at December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
Cost of removal obligations (1)
|
$ | 4,211 | $ | 3,844 | ||||
|
Recoveries in excess of AROs (2)
|
754 | 748 | ||||||
|
Public purpose programs (3)
|
701 | 587 | ||||||
|
Other
|
624 | 481 | ||||||
|
Total long-term regulatory liabilities
|
$ | 6,290 | $ | 5,660 | ||||
(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.
(2) Represents the cumulative differences between ARO expenses and amounts collected in rates primarily for the decommissioning of the Utility’s nuclear generation facilities. Decommissioning costs recovered through rates are primarily placed in nuclear decommissioning trusts. This regulatory liability also represents the deferral of realized and unrealized gains and losses on the nuclear decommissioning trust investments. (See Note 10 below.)
(3) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.
82
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 actual customer billings, and (2) differences between incurred costs and customer billings. To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable. Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.
The Utility sells and delivers electricity and natural gas. The Utility also administers public purpose programs, primarily related to customer energy efficiency programs. The balancing accounts associated with these items will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.
Current regulatory balancing accounts receivable and payable are comprised of the following:
|
Receivable
|
||||||||
|
Balance at December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
Electric distribution
|
$ | 344 | $ | 102 | ||||
|
Utility generation
|
261 | 57 | ||||||
|
Gas distribution
|
566 | 70 | ||||||
|
Energy procurement
|
608 | 410 | ||||||
|
Public purpose programs
|
109 | 56 | ||||||
|
Other
|
378 | 429 | ||||||
|
Total regulatory balancing accounts receivable
|
$ | 2,266 | $ | 1,124 | ||||
|
Payable
|
||||||||
|
Balance at December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
Energy procurement
|
$ | 188 | $ | 298 | ||||
|
Public purpose programs
|
154 | 171 | ||||||
|
Other (1)
|
748 | 539 | ||||||
|
Total regulatory balancing accounts payable
|
$ | 1,090 | $ | 1,008 | ||||
83
NOTE 4: DEBT
Long-Term Debt
The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:
|
December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
PG&E Corporation
|
||||||||
|
Senior notes, 5.75%, due 2014
|
- | 350 | ||||||
|
Senior notes, 2.40%, due 2019
|
350 | - | ||||||
|
Less: current portion
|
- | (350 | ) | |||||
|
Total senior notes
|
350 | - | ||||||
|
Total PG&E Corporation long-term debt
|
350 | - | ||||||
|
Utility
|
||||||||
|
Senior notes:
|
||||||||
|
4.80% due 2014
|
- | 539 | ||||||
|
5.625% due 2017
|
700 | 700 | ||||||
|
8.25% due 2018
|
800 | 800 | ||||||
|
3.50% due 2020
|
800 | 800 | ||||||
|
4.25% due 2021
|
300 | 300 | ||||||
|
3.25% due 2021
|
250 | 250 | ||||||
|
2.45% due 2022
|
400 | 400 | ||||||
|
3.25% due 2023
|
375 | 375 | ||||||
|
3.85% due 2023
|
300 | 300 | ||||||
|
3.40% due 2024
|
350 | - | ||||||
|
3.75% due 2024
|
450 | - | ||||||
|
6.05% due 2034
|
3,000 | 3,000 | ||||||
|
5.80% due 2037
|
950 | 950 | ||||||
|
6.35% due 2038
|
400 | 400 | ||||||
|
6.25% due 2039
|
550 | 550 | ||||||
|
5.40% due 2040
|
800 | 800 | ||||||
|
4.50% due 2041
|
250 | 250 | ||||||
|
4.45% due 2042
|
400 | 400 | ||||||
|
3.75% due 2042
|
350 | 350 | ||||||
|
4.60% due 2043
|
375 | 375 | ||||||
|
5.125% due 2043
|
500 | 500 | ||||||
|
4.75% due 2044
|
675 | - | ||||||
|
4.30% due 2045
|
500 | - | ||||||
|
Less: current portion
|
- | (539 | ) | |||||
|
Unamortized discount, net of premium
|
(43 | ) | (51 | ) | ||||
|
Total senior notes, net of current portion
|
13,432 | 11,449 | ||||||
|
Pollution control bonds:
|
||||||||
|
Series 1996 C, E, F, 1997 B, variable rates (1), due 2026 (2)
|
614 | 614 | ||||||
|
Series 2004 A-D, 4.75%, due 2023 (3)
|
345 | 345 | ||||||
|
Series 2009 A-D, variable rates (1), due 2016 and 2026 (4)
|
309 | 309 | ||||||
|
Total pollution control bonds
|
1,268 | 1,268 | ||||||
|
Total Utility long-term debt, net of current portion
|
14,700 | 12,717 | ||||||
|
Total consolidated long-term debt, net of current portion
|
$ | 15,050 | $ | 12,717 | ||||
(1) At December 31, 2014, interest rates on these bonds and the related loans ranged from 0.01% to 0.02%.
(2) Each series of these bonds is supported by a separate letter of credit. In April 2014, the letters of credit were extended to April 1, 2019. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility
(3) The Utility has obtained credit support from an insurance company for these bonds.
(4) Each series of these bonds is supported by a separate direct-pay letter of credit. In June 2014, Series A and B letters of credit were extended to June 5, 2019. Series C and D letters expire on December 3, 2016 to coincide with the maturity of the underlying bonds. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent.
84
Pollution Control Bonds
The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility. Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant. In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sale agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding. The Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.
Short-term Borrowings
The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings under their revolving credit facilities and commercial paper programs at December 31, 2014:
|
Letters of
|
||||||||||||||||||
|
Termination
|
Facility
|
Credit
|
Commercial
|
Facility
|
||||||||||||||
|
(in millions)
|
Date
|
Limit
|
Outstanding
|
Paper
|
Availability
|
|||||||||||||
|
PG&E Corporation
|
April 2019
|
$ | 300 | $ | - | $ | - | $ | 300 | |||||||||
|
Utility
|
April 2019
|
3,000 | 84 | 333 | 2,583 | |||||||||||||
|
Total revolving credit facilities
|
$ | 3,300 | $ | 84 | $ | 333 | $ | 2,883 | ||||||||||
(1) Includes a $100 million sublimit for letters of credit and a $100 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
(2) Includes a $1.0 billion sublimit for letters of credit and a $300 million commitment for loans that are made available on a same-day basis and are repayable in full within 7 days.
For 2014, the average outstanding bank borrowings on PG&E Corporation’s revolving credit facility was $27 million and the maximum outstanding balance during the year was $260 million. In February 2014, PG&E Corporation repaid the full outstanding bank borrowings of $260 million and initiated borrowing under its commercial paper program established in January 2014. For the year ended December 31, 2014, PG&E Corporation’s average outstanding commercial paper balance was $118 million and the maximum outstanding balance during the period was $260 million. For 2014, the Utility’s average outstanding commercial paper balance was $609 million and the maximum outstanding balance during the year was $1.4 billion. The Utility did not have any bank borrowings in 2014.
85
Revolving Credit Facilities
In April 2014, PG&E Corporation and the Utility amended and restated their revolving credit facilities to extend their termination dates from April 1, 2018 to April 1, 2019. These agreements contain substantially similar terms as the original 2011 credit agreements. PG&E Corporation's and the Utility's revolving credit facilities may be used for working capital, the repayment of commercial paper, and other corporate purposes. At PG&E Corporation’s and the Utility’s request and at the sole discretion of each lender, the facilities may be extended for additional periods. Provided certain conditions are met, PG&E Corporation and the Utility have the right to increase, in one or more requests, given not more frequently than once a year, the aggregate lenders’ commitments under the revolving credit facilities by up to $100 million and $500 million, respectively, in the aggregate for all such increases.
Borrowings under the revolving credit facilities (other than swingline loans) bear interest based, at PG&E Corporation’s and the Utility’s election, on (1) a London Interbank Offered Rate plus an applicable margin or (2) the base rate plus an applicable margin. The base rate will equal the higher of the following: the administrative agent’s announced base rate, 0.5% above the federal funds rate, or the one-month LIBOR plus an applicable margin. Interest is payable quarterly in arrears, or earlier for loans with shorter interest periods. PG&E Corporation and the Utility also will pay a facility fee on the total commitments of the lenders under the revolving credit facilities. The applicable margins and the facility fees will be based on PG&E Corporation’s and the Utility’s senior unsecured debt ratings issued by Standard & Poor’s Rating Services and Moody’s Investor Service. Facility fees are payable quarterly in arrears.
PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes. In addition, the 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.
Commercial Paper Programs
For 2014, the average yield on outstanding PG&E Corporation and Utility commercial paper was 0.24% and 0.23%, respectively.
The borrowings from PG&E Corporation and the Utility’s commercial paper programs are used primarily to fund temporary financing needs. Liquidity support for these borrowings is provided by available capacity under their respective revolving credit facilities, as described above. PG&E Corporation and the Utility treat the amount of its outstanding commercial paper as a reduction to the amount available under its revolving credit facilities. The commercial paper may have maturities up to 365 days and ranks equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness. Commercial paper notes are sold at an interest rate dictated by the market at the time of issuance.
86
Other Short-term Borrowings
In May 2014, the Utility issued $300 million principal amount of Floating Rate Senior Notes due May 11, 2015.
Repayment Schedule
PG&E Corporation’s and the Utility’s combined long-term debt principal repayment amounts at December 31, 2014 are reflected in the table below:
|
except interest rates)
|
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
Total
|
|||||||||||||||||||||
|
PG&E Corporation
|
||||||||||||||||||||||||||||
|
Average fixed interest rate
|
- | - | - | - | 2.40 | % | - | 2.40 | % | |||||||||||||||||||
|
Fixed rate obligations
|
$ | - | $ | - | $ | - | $ | - | $ | 350 | $ | - | $ | 350 | ||||||||||||||
|
Utility
|
||||||||||||||||||||||||||||
|
Average fixed interest rate
|
- | - | 5.63 | % | 8.25 | % | - | 4.92 | % | 5.15 | % | |||||||||||||||||
|
Fixed rate obligations
|
$ | - | $ | - | $ | 700 | $ | 800 | $ | - | $ | 12,320 | $ | 13,820 | ||||||||||||||
|
Variable interest rate
|
||||||||||||||||||||||||||||
|
as of December 31, 2014
|
- | 0.01 | % | - | - | 0.01 | % | - | 0.01 | % | ||||||||||||||||||
|
Variable rate obligations (1)
|
$ | - | $ | 160 | $ | - | $ | - | $ | 763 | $ | - | $ | 923 | ||||||||||||||
|
Total consolidated debt
|
$ | - | $ | 160 | $ | 700 | $ | 800 | $ | 1,113 | $ | 12,320 | $ | 15,093 | ||||||||||||||
(1) These bonds, due in 2016 and 2026, are backed by separate letters of credit that expire on December 3, 2016, April 1, 2019, or June 5, 2019.
NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION
PG&E Corporation had 475,913,404 shares of common stock outstanding at December 31, 2014. PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2014.
In February 2014, 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. During 2014, PG&E Corporation sold 11 million shares under the February 2014 equity distribution agreement for cash proceeds of $496 million, exhausting the capacity under this agreement. This amount is net of commissions paid of $4 million.
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 2014, 8 million shares were issued for cash proceeds of $306 million under these plans.
87
Dividends
The Board of Directors of PG&E Corporation and the Utility declare dividends quarterly. Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid. For 2014, the Board of Directors of PG&E Corporation declared a quarterly common stock dividend of $0.455 per share.
Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%. In addition, the CPUC requires the Utility to maintain a capital structure composed of at least 52% equity on a weighted average over four years. PG&E Corporation and the Utility are in compliance with these restrictions. At December 31, 2014, the Utility had restricted net assets of $14.6 billion and was limited to $153 million of additional common stock dividends it could pay to PG&E Corporation at December 31, 2014.
Long-Term Incentive Plan
The PG&E Corporation LTIP permits various forms of share-based incentive awards, including restricted stock awards, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries. Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards. In May 2014, the 2006 LTIP was terminated and the 2014 LTIP became effective. A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 16,184,126 shares were available for future awards at December 31, 2014.
The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2014, 2013, and 2012:
|
2014
|
2013
|
2012
|
||||||||||
|
Restricted stock units
|
$ | 42 | $ | 36 | $ | 31 | ||||||
|
Performance shares
|
36 | 28 | 26 | |||||||||
|
Total compensation expense (pre-tax)
|
$ | 78 | $ | 64 | $ | 57 | ||||||
|
Total compensation expense (after-tax)
|
$ | 47 | $ | 38 | $ | 34 | ||||||
The amount of share-based compensation costs capitalized during 2014, 2013, and 2012 was immaterial. There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
88
Restricted Stock Units
Prior to 2014, restricted stock units generally vested over four years in 20% increments on the first business day of March in year one, two, and three, with the remaining 40% vesting on the first business day of March in year four. Restricted stock units granted in 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units. Compensation expense is generally recognized rateably over the vesting period based on grant-date fair value. The weighted average grant-date fair value for restricted stock units granted during 2014, 2013, and 2012 was $43.76, $42.92, and $42.17, respectively. The total fair value of restricted stock units that vested during 2014, 2013, and 2012 was $34 million, $30 million, and $18 million, respectively. The tax benefit from restricted stock units that vested during each period was not material. As of December 31, 2014, $51 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.77 years.
The following table summarizes restricted stock unit activity for 2014:
|
Number of
|
Weighted Average Grant-
|
|||||||
|
Restricted Stock Units
|
Date Fair Value
|
|||||||
|
Nonvested at January 1
|
2,300,021 | $ | 43.16 | |||||
|
Granted
|
1,092,035 | $ | 43.76 | |||||
|
Vested
|
(777,883 | ) | $ | 43.28 | ||||
|
Forfeited
|
(75,816 | ) | $ | 43.01 | ||||
|
Nonvested at December 31
|
2,538,357 | $ | 43.38 | |||||
Performance Shares
Performance shares generally will vest three years after the grant date. Upon vesting, performance shares are settled in shares of common stock based on PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period. Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled.
Compensation expense attributable to performance share is generally recognized rateably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model. The weighted average grant-date fair value for performance shares granted during 2014, 2013, and 2012 was $51.81, $33.45, and $41.93 respectively. There was no tax benefit associated with performance shares during each of these periods. As of December 31, 2014, $34 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.18 years.
The following table summarizes activity for performance shares in 2014:
|
Number of
|
Weighted Average Grant-
|
|||||||
|
Performance Shares
|
Date Fair Value
|
|||||||
|
Nonvested at January 1
|
1,791,320 | $ | 37.85 | |||||
|
Granted
|
843,185 | 51.81 | ||||||
|
Vested
|
(275,247 | ) | 41.94 | |||||
|
Forfeited (1)
|
(665,319 | ) | 42.34 | |||||
|
Nonvested at December 31
|
1,693,939 | $ | 42.37 | |||||
|
(1) Includes performance shares that expired with zero value as performance targets were not met.
|
||||||||
89
NOTE 6: PREFERRED STOCK
PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock. PG&E Corporation does not have any preferred stock outstanding.
The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock. At December 31, 2014 and December 31, 2013, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share. The Utility’s preferred stock outstanding are not subject to mandatory redemption. All outstanding preferred stock has a $25 par value.
At December 31, 2014, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share. The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2014, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.
Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series. The Utility paid $14 million of dividends on preferred stock in each of 2014, 2013, and 2012.
NOTE 7: EARNINGS PER SHARE
PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2014, 2013, and 2012.
|
Year Ended December 31,
|
||||||||||||
|
(in millions, except per share amounts)
|
2014
|
2013
|
2012
|
|||||||||
|
Income available for common shareholders
|
$ | 1,436 | $ | 814 | $ | 816 | ||||||
|
Weighted average common shares outstanding, basic
|
468 | 444 | 424 | |||||||||
|
Add incremental shares from assumed conversions:
|
||||||||||||
|
Employee share-based compensation
|
2 | 1 | 1 | |||||||||
|
Weighted average common share outstanding, diluted
|
470 | 445 | 425 | |||||||||
|
Total earnings per common share, diluted
|
$ | 3.06 | $ | 1.83 | $ | 1.92 | ||||||
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.
90
NOTE 8: INCOME TAXES
PG&E Corporation and the Utility use the liability method of accounting for income taxes. The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities. Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.
PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position. The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement. As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance represents an unrecognized tax benefit.
Investment tax credits are deferred and amortized to income over time. PG&E Corporation amortizes its investment tax credits over the projected investment recovery period. The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.
PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more. PG&E Corporation files a combined state income tax return in California. PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.
The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:
|
PG&E Corporation
|
Utility
|
|||||||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||||||||
|
(in millions)
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
||||||||||||||||||
|
Current:
|
||||||||||||||||||||||||
|
Federal
|
$ | (84 | ) | $ | (218 | ) | $ | (74 | ) | $ | (84 | ) | $ | (222 | ) | $ | (52 | ) | ||||||
|
State
|
(41 | ) | (26 | ) | 33 | (29 | ) | (23 | ) | 41 | ||||||||||||||
|
Deferred:
|
||||||||||||||||||||||||
|
Federal
|
396 | 552 | 374 | 426 | 604 | 404 | ||||||||||||||||||
|
State
|
78 | (35 | ) | (92 | ) | 75 | (28 | ) | (91 | ) | ||||||||||||||
|
Tax credits
|
(4 | ) | (5 | ) | (4 | ) | (4 | ) | (5 | ) | (4 | ) | ||||||||||||
|
Income tax provision
|
$ | 345 | $ | 268 | $ | 237 | $ | 384 | $ | 326 | $ | 298 | ||||||||||||
91
The following table describes net deferred income tax liabilities:
|
PG&E Corporation
|
Utility
|
|||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||
|
(in millions)
|
2014
|
2013
|
2014
|
2013
|
||||||||||||
|
Deferred income tax assets:
|
||||||||||||||||
|
Customer advances for construction
|
$ | 88 | $ | 90 | $ | 88 | $ | 90 | ||||||||
|
Reserve for damages
|
137 | 161 | 137 | 161 | ||||||||||||
|
Environmental reserve
|
111 | 152 | 111 | 152 | ||||||||||||
|
Compensation
|
107 | 167 | 36 | 102 | ||||||||||||
|
Net operating loss carryforward
|
1,177 | 890 | 946 | 670 | ||||||||||||
|
GHG allowances
|
56 | 108 | 56 | 108 | ||||||||||||
|
Other
|
74 | 135 | 100 | 128 | ||||||||||||
|
Total deferred income tax assets
|
$ | 1,750 | $ | 1,703 | $ | 1,474 | $ | 1,411 | ||||||||
|
Deferred income tax liabilities:
|
||||||||||||||||
|
Regulatory balancing accounts
|
$ | 512 | $ | 261 | $ | 512 | $ | 261 | ||||||||
|
Property related basis differences
|
8,683 | 8,048 | 8,666 | 8,038 | ||||||||||||
|
Income tax regulatory asset (1)
|
974 | 748 | 974 | 748 | ||||||||||||
|
Other
|
88 | 151 | 86 | 86 | ||||||||||||
|
Total deferred income tax liabilities
|
$ | 10,257 | $ | 9,208 | $ | 10,238 | $ | 9,133 | ||||||||
|
Total net deferred income tax liabilities
|
$ | 8,507 | $ | 7,505 | $ | 8,764 | $ | 7,722 | ||||||||
|
Classification of net deferred income tax liabilities:
|
||||||||||||||||
|
Included in current liabilities (assets)
|
$ | (6 | ) | $ | (318 | ) | $ | (9 | ) | $ | (320 | ) | ||||
|
Included in noncurrent liabilities
|
8,513 | 7,823 | 8,773 | 8,042 | ||||||||||||
|
Total net deferred income tax liabilities
|
$ | 8,507 | $ | 7,505 | $ | 8,764 | $ | 7,722 | ||||||||
(1) Represents the deferred income tax component of the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized in accordance with GAAP. (See Note 3 above.)
The following table reconciles income tax expense at the federal statutory rate to the income tax provision:
|
PG&E Corporation
|
Utility
|
|||||||||||||||||||||||
|
Year Ended December 31,
|
||||||||||||||||||||||||
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
|||||||||||||||||||
|
Federal statutory income tax rate
|
35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | 35.0 | % | ||||||||||||
|
Increase (decrease) in income
|
||||||||||||||||||||||||
|
tax rate resulting from:
|
||||||||||||||||||||||||
|
State income tax (net of
|
||||||||||||||||||||||||
|
federal benefit) (1)
|
1.4 | (3.1 | ) | (3.9 | ) | 1.6 | (2.2 | ) | (3.0 | ) | ||||||||||||||
|
Effect of regulatory treatment
|
||||||||||||||||||||||||
|
of fixed asset differences (2)
|
(15.0 | ) | (4.2 | ) | (4.1 | ) | (14.7 | ) | (3.8 | ) | (3.9 | ) | ||||||||||||
|
Tax credits
|
(0.7 | ) | (0.4 | ) | (0.6 | ) | (0.7 | ) | (0.4 | ) | (0.6 | ) | ||||||||||||
|
Benefit of loss carryback
|
(0.8 | ) | (1.1 | ) | (0.7 | ) | (0.8 | ) | (1.0 | ) | (0.4 | ) | ||||||||||||
|
Non deductible penalties
|
0.3 | 0.8 | 0.6 | 0.3 | 0.7 | 0.5 | ||||||||||||||||||
|
Other, net
|
(0.8 | ) | (2.2 | ) | (3.8 | ) | 0.4 | (0.9 | ) | (0.8 | ) | |||||||||||||
|
Effective tax rate
|
19.4 | % | 24.8 | % | 22.5 | % | 21.1 | % | 27.4 | % | 26.8 | % | ||||||||||||
|
(1) Includes the effect of state flow-through ratemaking treatment.
|
(2) Represents effect of federal flow-through ratemaking treatment including those deductions related to repairs and certain other property-related costs discussed below in the “2014 GRC Impact” section.
92
Unrecognized tax benefits
The following table reconciles the changes in unrecognized tax benefits:
|
PG&E Corporation
|
Utility
|
|||||||||||||||||||||||
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
|||||||||||||||||||
|
(in millions)
|
||||||||||||||||||||||||
|
Balance at beginning of year
|
$ | 666 | $ | 581 | $ | 506 | $ | 660 | $ | 575 | $ | 503 | ||||||||||||
|
Additions for tax position taken
|
||||||||||||||||||||||||
|
during a prior year
|
7 | 12 | 32 | 7 | 12 | 26 | ||||||||||||||||||
|
Reductions for tax position
|
||||||||||||||||||||||||
|
taken during a prior year
|
(9 | ) | (6 | ) | (13 | ) | (9 | ) | (6 | ) | (10 | ) | ||||||||||||
|
Additions for tax position
|
||||||||||||||||||||||||
|
taken during the current year
|
61 | 79 | 67 | 61 | 79 | 67 | ||||||||||||||||||
|
Settlements
|
(12 | ) | - | (11 | ) | (12 | ) | - | (11 | ) | ||||||||||||||
|
Balance at end of year
|
$ | 713 | $ | 666 | $ | 581 | $ | 707 | $ | 660 | $ | 575 | ||||||||||||
The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2014 for PG&E Corporation and the Utility was $20 million, with the remaining balance representing the potential deferral of taxes to later years.
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 (see “2014 GRC impact” below). As of December 31, 2014, it is reasonably possible that unrecognized tax benefits will decrease by approximately $330 million within the next 12 months, and most of this decrease would not impact net income.
Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income. For the years ended December 31, 2014, 2013, and 2012, these amounts were immaterial.
2014 GRC impact
The 2014 GRC decision authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes. For these temporary differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets or liabilities. Therefore, PG&E Corporation’s and the Utility’s effective income tax rates are impacted as these differences arise and reverse. PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates. In addition, recent guidance from the IRS allowed the Utility to deduct more repair costs than previously forecasted in the GRC. For the year ended December 31, 2014, the Utility recognized a reduction in income tax expense of $235 million consistent with a lower revenue requirement in the 2014 GRC and IRS guidance.
93
IRS settlements and years that remain subject to examination
PG&E Corporation participates in the Compliance Assurance Process, a real-time IRS audit intended to expedite resolution of tax matters. The Compliance Assurance Process audit culminates with a letter from the IRS indicating its acceptance of the return.
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 the 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.
The Tax Increase Prevention Act, signed into law on December 19, 2014, extended 50% bonus federal tax depreciation on qualified property placed into service in 2014.
Carryforwards
As of December 31, 2014, PG&E Corporation had approximately $4.1 billion of federal net operating loss carryforwards and $77 million of tax credit carryforwards, which will expire between 2029 and 2034. In addition, PG&E Corporation had approximately $219 million of loss carryforwards related to charitable contributions, which will expire between 2015 and 2019. PG&E Corporation had $123 million of California net operating loss carryforwards which will expire between 2033 and 2034 and $30 million of California credit carryforwards, some of which will expire in 2024 and others which will carryforward indefinitely. PG&E Corporation believes it is more likely than not the tax benefits associated with the federal net operating loss, charitable contributions, and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2014. As of December 31, 2014, PG&E Corporation had approximately $24 million of federal net operating loss carryforwards related to the tax benefit on employee stock plans that would be recorded in additional paid-in capital when used.
NOTE 9: DERIVATIVES
Use of Derivative Instruments
The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include forward contracts, swaps, futures, options, and CRRs.
These instruments are not held for speculative purposes and are subject to certain regulatory requirements. Customer rates are designed to recover the Utility’s reasonable costs of providing services, including the costs related to price risk management activities.
94
Price risk management activities that meet the definition of derivatives are recorded at fair value on the Consolidated Balance Sheets. As long as the current ratemaking mechanism discussed in Note 2, above, remains in place and the Utility’s price risk management activities are carried out in accordance with CPUC directives, the Utility expects to recover fully, in rates, all costs related to derivatives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.
Cash collateral paid or received is offset against the fair value of derivative instruments executed with the same counterparty under a master netting arrangement, where the right of offset and the intention to offset exist. Derivatives are presented in the Utility’s Consolidated Balance Sheets on a net basis; see below.
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. The fair value of these items is not reflected in the Consolidated Balance Sheets at fair value, eligible derivatives are accounted for under the accrual method of accounting.
Volume of Derivative Activity
At December 31, 2014 and 2013, respectively, the volumes of the Utility’s outstanding derivatives were as follows:
|
Contract Volume
|
|||||||||
|
Underlying Product
|
Instruments
|
2014
|
2013
|
||||||
|
Natural Gas (1) (MMBtus (2))
|
Forwards and Swaps
|
308,130,101 | 331,840,788 | ||||||
|
Options
|
164,418,002 | 260,262,916 | |||||||
|
Electricity (Megawatt-hours)
|
Forwards and Swaps
|
5,346,787 | 8,089,269 | ||||||
|
Congestion Revenue Rights (3)
|
224,124,341 | 250,922,591 | |||||||
(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 congestion costs based on demand when there is insufficient transmission capacity.
Presentation of Derivative Instruments in the Financial Statements
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 | ) | ||||||||||
|
Total commodity risk
|
$ | 33 | $ | - | $ | 54 | $ | 87 | ||||||||
95
At December 31, 2013, 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
|
$ | 42 | $ | (10 | ) | $ | 16 | $ | 48 | |||||||
|
Other noncurrent assets – other
|
99 | (4 | ) | - | 95 | |||||||||||
|
Current liabilities – other
|
(122 | ) | 10 | 69 | (43 | ) | ||||||||||
|
Noncurrent liabilities – other
|
(110 | ) | 4 | 2 | (104 | ) | ||||||||||
|
Total commodity risk
|
$ | (91 | ) | $ | - | $ | 87 | $ | (4 | ) | ||||||
Gains and losses recorded on the Utility’s derivatives were as follows:
|
Commodity Risk
|
||||||||||||
|
For the year ended December 31,
|
||||||||||||
|
(in millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Unrealized gain/(loss) - regulatory assets and liabilities (1)
|
$ | 124 | $ | 238 | $ | 391 | ||||||
|
Realized loss - cost of electricity (2)
|
(83 | ) | (178 | ) | (486 | ) | ||||||
|
Realized loss - cost of natural gas (2)
|
(8 | ) | (22 | ) | (38 | ) | ||||||
|
Total commodity risk
|
$ | 33 | $ | 38 | $ | (133 | ) | |||||
(1) Unrealized gains and losses on commodity risk-related derivative instruments are recorded to regulatory assets or liabilities, rather than being recorded to the Consolidated Statements of Income. These amounts exclude the impact of cash collateral postings.
(2) These amounts are fully passed through to customers in rates. Accordingly, net income was not impacted by realized amounts on these instruments.
Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.
The majority of the Utility’s derivatives contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies. At December 31, 2014, the Utility’s credit rating was investment grade. If the Utility’s credit rating were to fall below investment grade, the Utility would be required to post additional cash immediately to fully collateralize some of its net liability derivative positions.
The additional cash collateral that the Utility would be required to post if the credit risk-related contingency features were triggered was as follows:
|
Balance at December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
Derivatives in a liability position with credit risk-related
|
||||||||
|
contingencies that are not fully collateralized
|
$ | (47 | ) | $ | (79 | ) | ||
|
Related derivatives in an asset position
|
- | 4 | ||||||
|
Collateral posting in the normal course of business related to
|
||||||||
|
these derivatives
|
44 | 65 | ||||||
|
Net position of derivative contracts/additional collateral
|
||||||||
|
posting requirements (1)
|
$ | (3 | ) | $ | (10 | ) | ||
(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.
96
NOTE 10: 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.
97
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 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)
|
||||||||||||||||||||
|
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)
|
||||||||||||||||||||
|
Electricity
|
$ | 47 | $ | 5 | $ | 163 | $ | (52 | ) | $ | 163 | |||||||||
|
Gas
|
- | 3 | - | - | 3 | |||||||||||||||
|
Total liabilities
|
$ | 47 | $ | 8 | $ | 163 | $ | (52 | ) | $ | 166 | |||||||||
(2) Represents amount before deducting $324 million, primarily related to deferred taxes on appreciation of investment value.
98
|
Fair Value Measurements
|
||||||||||||||||||||
|
At December 31, 2013
|
||||||||||||||||||||
|
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Netting (1)
|
Total
|
|||||||||||||||
|
Assets:
|
||||||||||||||||||||
|
Money market investments
|
$ | 226 | $ | - | $ | - | $ | - | $ | 226 | ||||||||||
|
Nuclear decommissioning trusts
|
||||||||||||||||||||
|
Money market investments
|
38 | - | - | - | 38 | |||||||||||||||
|
U.S. equity securities
|
1,046 | 11 | - | 1,057 | ||||||||||||||||
|
Non-U.S. equity securities
|
457 | - | - | - | 457 | |||||||||||||||
|
U.S. government and agency securities
|
760 | 156 | - | - | 916 | |||||||||||||||
|
Municipal securities
|
- | 25 | - | - | 25 | |||||||||||||||
|
Other fixed-income securities
|
- | 162 | - | - | 162 | |||||||||||||||
|
Total nuclear decommissioning trusts (2)
|
2,301 | 354 | - | - | 2,655 | |||||||||||||||
|
Price risk management instruments
|
||||||||||||||||||||
|
(Note 9)
|
||||||||||||||||||||
|
Electricity
|
2 | 27 | 107 | 3 | 139 | |||||||||||||||
|
Gas
|
- | 5 | - | (1 | ) | 4 | ||||||||||||||
|
Total price risk management instruments
|
2 | 32 | 107 | 2 | 143 | |||||||||||||||
|
Rabbi trusts
|
||||||||||||||||||||
|
Fixed-income securities
|
- | 39 | - | - | 39 | |||||||||||||||
|
Life insurance contracts
|
- | 70 | - | - | 70 | |||||||||||||||
|
Total rabbi trusts
|
- | 109 | - | - | 109 | |||||||||||||||
|
Long-term disability trust
|
||||||||||||||||||||
|
Money market investments
|
9 | - | - | - | 9 | |||||||||||||||
|
U.S. equity securities
|
- | 14 | - | - | 14 | |||||||||||||||
|
Non-U.S. equity securities
|
- | 12 | - | - | 12 | |||||||||||||||
|
Fixed-income securities
|
- | 122 | - | - | 122 | |||||||||||||||
|
Total long-term disability trust
|
9 | 148 | - | - | 157 | |||||||||||||||
|
Other investments
|
84 | - | - | - | 84 | |||||||||||||||
|
Total assets
|
$ | 2,622 | $ | 643 | $ | 107 | $ | 2 | $ | 3,374 | ||||||||||
|
Liabilities:
|
||||||||||||||||||||
|
Price risk management instruments
|
||||||||||||||||||||
|
(Note 9)
|
||||||||||||||||||||
|
Electricity
|
$ | 19 | $ | 72 | $ | 137 | $ | (84 | ) | $ | 144 | |||||||||
|
Gas
|
1 | 3 | - | (1 | ) | 3 | ||||||||||||||
|
Total liabilities
|
$ | 20 | $ | 75 | $ | 137 | $ | (85 | ) | $ | 147 | |||||||||
(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.
(2) Represents amount before deducting $313 million, primarily related to deferred taxes on appreciation of investment value.
99
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 year ended December 31, 2014 and 2013.
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.
Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1. 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 CAISO-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 CAISO auction and between auction dates; therefore, the Utility uses models to forecast CRR prices for those periods not covered in the auctions.
100
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 9 above.)
|
Fair Value at
|
|||||||||||||
|
(in millions)
|
December 31, 2014
|
||||||||||||
|
Fair Value Measurement
|
Assets
|
Liabilities
|
Valuation Technique
|
Unobservable 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
|
Fair Value at
|
|||||||||||||
|
(in millions)
|
December 31, 2013
|
||||||||||||
|
Fair Value Measurement
|
Assets
|
Liabilities
|
Valuation Technique
|
Unobservable Input
|
Range (1)
|
||||||||
|
Congestion revenue rights
|
$ | 107 | $ | 32 |
Market approach
|
CRR auction prices
|
$ | (6.47) - 12.04 | |||||
|
Power purchase agreements
|
$ | - | $ | 105 |
Discounted cash flow
|
Forward prices
|
$ | 23.43 - 51.75 | |||||
101
Level 3 Reconciliation
The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2014 and 2013, respectively:
|
Price Risk Management Instruments
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
Liability balance as of January 1
|
$ | (30 | ) | $ | (79 | ) | ||
|
Realized and unrealized gains:
|
||||||||
|
Included in regulatory assets and liabilities or balancing accounts (1)
|
99 | 49 | ||||||
|
Asset (liability) balance as of December 31
|
$ | 69 | $ | (30 | ) | |||
(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 December 31, 2014 and 2013, 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 December 31, 2014 and 2013.
|
The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):
|
At December 31,
|
||||||||||||||||
|
2014
|
2013
|
|||||||||||||||
|
(in millions)
|
Carrying Amount
|
Level 2 Fair Value
|
Carrying Amount
|
Level 2 Fair Value
|
||||||||||||
|
Debt (Note 4)
|
||||||||||||||||
|
PG&E Corporation
|
$ | 350 | $ | 352 | $ | 350 | $ | 354 | ||||||||
|
Utility
|
13,778 | 15,851 | 12,334 | 13,444 | ||||||||||||
102
Available for Sale Investments
The following table provides a summary of available-for-sale investments:
|
Total
|
Total
|
|||||||||||||||
|
Amortized
|
Unrealized
|
Unrealized
|
Total Fair
|
|||||||||||||
|
(in millions)
|
Cost
|
Gains
|
Losses
|
Value
|
||||||||||||
|
As of December 31, 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 | |||||||
|
As of December 31, 2013
|
||||||||||||||||
|
Nuclear decommissioning trusts
|
||||||||||||||||
|
Money market investments
|
$ | 38 | $ | - | $ | - | $ | 38 | ||||||||
|
Equity securities
|
||||||||||||||||
|
U.S.
|
246 | 811 | - | 1,057 | ||||||||||||
|
Non-U.S.
|
215 | 242 | - | 457 | ||||||||||||
|
Debt securities
|
||||||||||||||||
|
U.S. government and agency securities
|
870 | 51 | (5 | ) | 916 | |||||||||||
|
Municipal securities
|
24 | 2 | (1 | ) | 25 | |||||||||||
|
Other fixed-income securities
|
163 | 1 | (2 | ) | 162 | |||||||||||
|
Total nuclear decommissioning trusts (1)
|
1,556 | 1,107 | (8 | ) | 2,655 | |||||||||||
|
Other investments
|
13 | 71 | - | 84 | ||||||||||||
|
Total (1)
|
$ | 1,569 | $ | 1,178 | $ | (8 | ) | $ | 2,739 | |||||||
(1) Represents amounts before deducting $324 million and $313 million at December 31, 2014 and 2013, 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)
|
December 31, 2014
|
|||
|
Less than 1 year
|
$ | 17 | ||
|
1–5 years
|
466 | |||
|
5–10 years
|
263 | |||
|
More than 10 years
|
384 | |||
|
Total maturities of debt securities
|
$ | 1,130 | ||
The following table provides a summary of activity for the debt and equity securities:
|
2014
|
2013
|
2012
|
||||||||||
|
(in millions)
|
||||||||||||
|
Proceeds from sales and maturities of nuclear decommissioning trust
|
||||||||||||
|
investments
|
$ | 1,336 | $ | 1,619 | $ | 1,133 | ||||||
|
Gross realized gains on sales of securities held as available-for-sale
|
118 | 94 | 19 | |||||||||
|
Gross realized losses on sales of securities held as available-for-sale
|
(12 | ) | (13 | ) | (17 | ) | ||||||
103
NOTE 11: EMPLOYEE BENEFIT PLANS
Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)
PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”). The trusts underlying certain of these plans are qualified trusts under the Internal Revenue Code of 1986, as amended. If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations. PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements. Based upon current assumptions and available information, the Utility’s minimum funding requirements related to its pension plans is zero.
PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees. PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.
Change in Plan Assets, Benefit Obligations, and Funded Status
The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2014 and 2013:
Pension Plan
|
2014
|
2013
|
|||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
$ | 12,527 | $ | 12,141 | ||||
|
Actual return on plan assets
|
1,946 | 673 | ||||||
|
Company contributions
|
332 | 323 | ||||||
|
Benefits and expenses paid
|
(589 | ) | (610 | ) | ||||
|
Fair value of plan assets at end of year
|
$ | 14,216 | $ | 12,527 | ||||
|
Change in benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 14,077 | $ | 15,541 | ||||
|
Service cost for benefits earned
|
383 | 468 | ||||||
|
Interest cost
|
695 | 627 | ||||||
|
Actuarial (gain) loss
|
2,131 | (1,950 | ) | |||||
|
Plan amendments
|
(1 | ) | - | |||||
|
Transitional costs
|
- | 1 | ||||||
|
Benefits and expenses paid
|
(589 | ) | (610 | ) | ||||
|
Benefit obligation at end of year (1)
|
$ | 16,696 | $ | 14,077 | ||||
|
Funded Status:
|
||||||||
|
Current liability
|
$ | (6 | ) | $ | (6 | ) | ||
|
Noncurrent liability
|
(2,474 | ) | (1,544 | ) | ||||
|
Net liability at end of year
|
$ | (2,480 | ) | $ | (1,550 | ) | ||
(1) PG&E Corporation’s accumulated benefit obligation was $14.9 billion and $12.6 billion at December 31, 2014 and 2013, respectively.
104
Postretirement Benefits Other than Pensions
|
2014
|
2013
|
|||||||
|
Change in plan assets:
|
||||||||
|
Fair value of plan assets at beginning of year
|
$ | 1,892 | $ | 1,758 | ||||
|
Actual return on plan assets
|
241 | 64 | ||||||
|
Company contributions
|
57 | 145 | ||||||
|
Plan participant contribution
|
63 | 64 | ||||||
|
Benefits and expenses paid
|
(161 | ) | (139 | ) | ||||
|
Fair value of plan assets at end of year
|
$ | 2,092 | $ | 1,892 | ||||
|
Change in benefit obligation:
|
||||||||
|
Benefit obligation at beginning of year
|
$ | 1,597 | $ | 1,940 | ||||
|
Service cost for benefits earned
|
45 | 53 | ||||||
|
Interest cost
|
76 | 74 | ||||||
|
Actuarial (gain) loss
|
166 | (415 | ) | |||||
|
Benefits paid
|
(140 | ) | (123 | ) | ||||
|
Federal subsidy on benefits paid
|
4 | 4 | ||||||
|
Plan participant contributions
|
63 | 64 | ||||||
|
Benefit obligation at end of year
|
$ | 1,811 | $ | 1,597 | ||||
|
Funded Status: (1)
|
||||||||
|
Noncurrent asset
|
$ | 368 | $ | 352 | ||||
|
Noncurrent liability
|
(87 | ) | (57 | ) | ||||
|
Net asset at end of year
|
$ | 281 | $ | 295 | ||||
(1) At December 31, 2014 and 2013, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
105
Components of Net Periodic Benefit Cost
Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:
Pension Plan
|
2014
|
2013
|
2012
|
||||||||||
|
Service cost
|
$ | 383 | $ | 468 | $ | 396 | ||||||
|
Interest cost
|
695 | 627 | 658 | |||||||||
|
Expected return on plan assets
|
(807 | ) | (650 | ) | (598 | ) | ||||||
|
Amortization of prior service cost
|
20 | 20 | 20 | |||||||||
|
Amortization of net actuarial loss
|
2 | 111 | 123 | |||||||||
|
Net periodic benefit cost
|
293 | 576 | 599 | |||||||||
|
Less: transfer to regulatory account (1)
|
42 | (238 | ) | (301 | ) | |||||||
|
Total expense recognized
|
$ | 335 | $ | 338 | $ | 298 | ||||||
|
(1) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.
|
Postretirement Benefits Other than Pensions
|
2014
|
2013
|
2012
|
||||||||||
|
Service cost
|
$ | 45 | $ | 53 | $ | 49 | ||||||
|
Interest cost
|
76 | 74 | 83 | |||||||||
|
Expected return on plan assets
|
(103 | ) | (79 | ) | (77 | ) | ||||||
|
Amortization of transition obligation
|
- | - | 24 | |||||||||
|
Amortization of prior service cost
|
23 | 23 | 25 | |||||||||
|
Amortization of net actuarial loss
|
2 | 6 | 6 | |||||||||
|
Net periodic benefit cost
|
$ | 43 | $ | 77 | $ | 110 | ||||||
There was no material difference between PG&E Corporation and the Utility for the information disclosed above.
106
Components of Accumulated Other Comprehensive Income
PG&E Corporation and the Utility record unrecognized prior service costs, unrecognized gains and losses, and unrecognized net transition obligations related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax. In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions. For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income. For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income. As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).
The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2015 are as follows:
|
(in millions)
|
Pension Plan
|
PBOP Plans
|
||||
|
Unrecognized prior service cost
|
$ | 15 | $ | 19 | ||
|
Unrecognized net loss
|
11 | 4 | ||||
|
Total
|
$ | 26 | $ | 23 | ||
There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.
Valuation Assumptions
In 2014, PG&E Corporation and the Utility adopted the Society of Actuaries 2014 Mortality Tables Report (RP-2014) and Mortality Improvement Scale (MP-2014 with modifications), which updated the mortality assumptions used for measuring retirement plan obligations. This new mortality table and improvement scale extends the assumed life expectancy of plan participants, resulting in an increase in PG&E Corporation’s and the Utility’s accrued benefit cost as of December 31, 2014. Total pension and postretirement benefit obligation increased $82 million and $18 million in 2014, respectively.
The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs. The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost.
|
Pension Plan
|
PBOP Plans
|
|||||||||||||||||||||||
|
December 31,
|
December 31,
|
|||||||||||||||||||||||
|
2014
|
2013
|
2012
|
2014
|
2013
|
2012
|
|||||||||||||||||||
|
Discount rate
|
4.00 | % | 4.89 | % | 3.98 | % | 3.89 - 4.09 | % | 4.70 - 5.00 | % | 3.75 - 4.08 | % | ||||||||||||
|
Rate of future compensation
|
||||||||||||||||||||||||
|
increases
|
4.00 | % | 4.00 | % | 4.00 | % | - | - | - | |||||||||||||||
|
Expected return on plan
|
||||||||||||||||||||||||
|
assets
|
6.20 | % | 6.50 | % | 5.40 | % | 3.30 - 6.70 | % | 3.50 - 6.70 | % | 2.90 - 6.10 | % | ||||||||||||
107
The assumed health care cost trend rate as of December 31, 2014 was 7.5%, decreasing gradually to an ultimate trend rate in 2024 and beyond of approximately 3.5%. A one-percentage-point change in assumed health care cost trend rate would have the following effects:
|
One-Percentage-Point
|
One-Percentage-Point
|
|||||||
|
(in millions)
|
Increase
|
Decrease
|
||||||
|
Effect on postretirement benefit obligation
|
$ | 107 | $ | (108 | ) | |||
|
Effect on service and interest cost
|
8 | (8 | ) | |||||
Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets. Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate. Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate. For the pension plan, the assumed return of 6.2% compares to a ten-year actual return of 9.3%. The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 715 Aa-grade non-callable bonds at December 31, 2014. This yield curve has discount rates that vary based on the duration of the obligations. The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.
Investment Policies and Strategies
The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations. Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended. PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.
The trusts asset allocations are meant to manage volatility, reduce costs, and diversify its holdings. Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility. In addition to affecting the trusts’s fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields. To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return. Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, REITS, global listed infrastructure equities, and private real estate funds. Absolute return investments include hedge fund portfolios.
Target allocations for equity investments have generally declined in favor of longer-maturity fixed-income investments and real assets as a means of dampening future funded status volatility. Derivative instruments such as equity index futures contracts are used to maintain existing equity exposure while adding exposure to fixed-income securities. In addition, derivative instruments such as equity index futures and fixed income futures are used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are also used to hedge a portion of the currency of the global equity investments.
The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:
|
Pension Plan
|
PBOP Plans
|
|||||||||||||||||||||||
|
2015
|
2014
|
2013
|
2015
|
2014
|
2013
|
|||||||||||||||||||
|
Global equity
|
25 | % | 25 | % | 25 | % | 31 | % | 30 | % | 28 | % | ||||||||||||
|
Absolute return
|
5 | % | 5 | % | 5 | % | 3 | % | 3 | % | 4 | % | ||||||||||||
|
Real assets
|
10 | % | 10 | % | 10 | % | 8 | % | 8 | % | 8 | % | ||||||||||||
|
Fixed income
|
60 | % | 60 | % | 60 | % | 58 | % | 59 | % | 60 | % | ||||||||||||
|
Total
|
100 | % | 100 | % | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||||||
PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets. The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation. Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.
108
Fair Value Measurements
The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2014 and 2013.
|
Fair Value Measurements
|
||||||||||||||||||||||||
|
At December 31,
|
||||||||||||||||||||||||
|
2014
|
2013
|
|||||||||||||||||||||||
|
(in millions)
|
Level 1
|
Level 2
|
Level 3
|
Total
|
Level 1
|
Level 2
|
Level 3
|
Total
|
||||||||||||||||
|
Pension Plan:
|
||||||||||||||||||||||||
|
Short-term investments
|
$
|
352
|
$
|
311
|
$
|
-
|
$
|
663
|
$
|
70
|
$
|
-
|
$
|
-
|
$
|
70
|
||||||||
|
Global equity
|
918
|
2,311
|
-
|
3,229
|
1,123
|
2,363
|
-
|
3,486
|
||||||||||||||||
|
Absolute return
|
-
|
-
|
577
|
577
|
-
|
-
|
554
|
554
|
||||||||||||||||
|
Real assets
|
620
|
-
|
675
|
1,295
|
562
|
-
|
544
|
1,106
|
||||||||||||||||
|
Fixed-income
|
2,068
|
5,718
|
638
|
8,424
|
1,448
|
5,104
|
625
|
7,177
|
||||||||||||||||
|
Total
|
$
|
3,958
|
$
|
8,340
|
$
|
1,890
|
$
|
14,188
|
$
|
3,203
|
$
|
7,467
|
$
|
1,723
|
$
|
12,393
|
||||||||
|
PBOP Plans:
|
||||||||||||||||||||||||
|
Short-term investments
|
$
|
28
|
$
|
-
|
$
|
-
|
$
|
28
|
$
|
31
|
$
|
-
|
$
|
-
|
$
|
31
|
||||||||
|
Global equity
|
124
|
549
|
-
|
673
|
127
|
504
|
-
|
631
|
||||||||||||||||
|
Absolute return
|
-
|
-
|
55
|
55
|
-
|
-
|
53
|
53
|
||||||||||||||||
|
Real assets
|
72
|
-
|
49
|
121
|
67
|
-
|
38
|
105
|
||||||||||||||||
|
Fixed-income
|
163
|
1,055
|
1
|
1,219
|
137
|
936
|
2
|
1,075
|
||||||||||||||||
|
Total
|
$
|
387
|
$
|
1,604
|
$
|
105
|
$
|
2,096
|
$
|
362
|
$
|
1,440
|
$
|
93
|
$
|
1,895
|
||||||||
|
Total plan assets at fair value
|
$
|
16,284
|
$
|
14,288
|
||||||||||||||||||||
In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net assets of $24 million and $131 million at December 31, 2014 and 2013, respectively. These net assets and net liabilities were comprised primarily of cash, accounts receivable, accounts payable, and deferred taxes.
Valuation Techniques
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above. All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.
Short-Term Investments
Historically, short-term investments consisted primarily of commingled funds of U.S. government short-term securities that were considered Level 1 assets and valued at the net asset value of $1 per unit.
In 2014, PG&E began diversifying these short-term investments across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.
109
Global Equity
The global equity category includes investments in common stock, equity-index futures, and commingled funds comprised of equity securities spread across multiple industries and regions of the world. Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets. These equity investments are generally valued based on unadjusted prices in active markets for identical securities. Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets. Commingled funds are valued using a net asset value per share and are maintained by investment companies for large institutional investors and are not publicly traded. Commingled funds are comprised primarily of underlying equity securities that are publicly traded on exchanges, and price quotes for the assets held by these funds are readily observable and available. Commingled funds are categorized as Level 1 and Level 2 assets.
Absolute Return
The absolute return category includes portfolios of hedge funds that are valued using a net asset value per share based on a variety of proprietary and non-proprietary valuation methods, including unadjusted prices for publicly-traded securities in active markets. Hedge funds are considered Level 3 assets.
Real Assets
The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds. The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets. Private real estate funds are valued using a net asset value per share derived using appraisals, pricing models, and valuation inputs that are unobservable and are considered Level 3 assets.
Fixed-Income
The fixed-income category includes U.S. government securities, corporate securities, and other fixed-income securities.
U.S. government fixed-income primarily consists of U.S. Treasury notes and U.S. government bonds that are valued based on quoted market prices or evaluated pricing data for similar securities adjusted for observable differences. These securities are categorized as Level 1 or Level 2 assets.
Corporate fixed-income primarily includes investment grade bonds of U.S. issuers across multiple industries that are valued based on a compilation of primarily observable information or broker quotes in non-active markets. The fair value of corporate bonds is determined using recently executed transactions, market price quotations (where observable), bond spreads or credit default swap spreads obtained from independent external parties such as vendors and brokers adjusted for any basis difference between cash and derivative instruments. These securities are classified as Level 2 assets. Corporate fixed-income also includes commingled funds that are valued using a net asset value per share and are comprised of corporate debt instruments. Commingled funds are considered Level 2 assets. Corporate fixed-income also includes privately placed debt portfolios which are valued using a net asset value per share using pricing models and valuation inputs that are unobservable and are considered Level 3 assets.
Other fixed-income primarily includes pass-through and asset-backed securities. Pass-through securities are valued based on benchmark yields created using observable market inputs and are Level 2 assets. Asset-backed securities are primarily valued based on broker quotes and are considered Level 2 assets. Other fixed-income also includes municipal bonds and Treasury futures. Municipal bonds are valued based on a compilation of primarily observable information or broker quotes in non-active markets and are considered Level 2 assets. Futures are valued based on unadjusted prices in active markets and are Level 1 assets.
110
Transfers Between Levels
Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. No material transfers between levels occurred in the years ended December 31, 2014 and 2013.
Level 3 Reconciliation
The following table is a reconciliation of changes in the fair value of instruments for pension and other benefit plans that have been classified as Level 3 for the years ended December 31, 2014 and 2013:
|
Pension Plan
|
||||||||||||||||
|
(in millions)
|
Absolute
|
Fixed-
|
||||||||||||||
|
For the year ended December 31, 2014
|
Return
|
Income
|
Real Assets
|
Total
|
||||||||||||
|
Balance at beginning of year
|
$ | 554 | $ | 625 | $ | 544 | $ | 1,723 | ||||||||
|
Actual return on plan assets:
|
||||||||||||||||
|
Relating to assets still held at the reporting date
|
23 | 24 | 54 | 101 | ||||||||||||
|
Relating to assets sold during the period
|
- | 4 | - | 4 | ||||||||||||
|
Purchases, issuances, sales, and settlements:
|
||||||||||||||||
|
Purchases
|
- | 1 | 78 | 79 | ||||||||||||
|
Settlements
|
- | (16 | ) | (1 | ) | (17 | ) | |||||||||
|
Balance at end of year
|
$ | 577 | $ | 638 | $ | 675 | $ | 1,890 | ||||||||
|
Pension Plan
|
||||||||||||||||
|
(in millions)
|
Absolute
|
Fixed-
|
||||||||||||||
|
For the year ended December 31, 2013
|
Return
|
Income
|
Real Assets
|
Total
|
||||||||||||
|
Balance at beginning of year
|
$ | 513 | $ | 611 | $ | 285 | $ | 1,409 | ||||||||
|
Actual return on plan assets:
|
||||||||||||||||
|
Relating to assets still held at the reporting date
|
37 | 1 | 49 | 87 | ||||||||||||
|
Relating to assets sold during the period
|
4 | - | (3 | ) | 1 | |||||||||||
|
Purchases, issuances, sales, and settlements:
|
||||||||||||||||
|
Purchases
|
- | 20 | 352 | 372 | ||||||||||||
|
Settlements
|
- | (7 | ) | (139 | ) | (146 | ) | |||||||||
|
Balance at end of year
|
$ | 554 | $ | 625 | $ | 544 | $ | 1,723 | ||||||||
111
|
PBOP Plans
|
||||||||||||||||
|
(in millions)
|
Absolute
|
Fixed-
|
||||||||||||||
|
For the year ended December 31, 2014
|
Return
|
Income
|
Real Assets
|
Total
|
||||||||||||
|
Balance at beginning of year
|
$ | 53 | $ | 2 | 38 | $ | 93 | |||||||||
|
Actual return on plan assets:
|
||||||||||||||||
|
Relating to assets still held at the reporting date
|
2 | - | 4 | 6 | ||||||||||||
|
Relating to assets sold during the period
|
- | - | - | - | ||||||||||||
|
Purchases, issuances, sales, and settlements:
|
||||||||||||||||
|
Purchases
|
- | - | 7 | 7 | ||||||||||||
|
Settlements
|
- | (1 | ) | - | (1 | ) | ||||||||||
|
Balance at end of year
|
$ | 55 | $ | 1 | $ | 49 | $ | 105 | ||||||||
|
PBOP Plans
|
||||||||||||||||
|
(in millions)
|
Absolute
|
Fixed-
|
||||||||||||||
|
For the year ended December 31, 2013
|
Return
|
Income
|
Real Assets
|
Total
|
||||||||||||
|
Balance at beginning of year
|
$ | 49 | $ | 1 | 28 | $ | 78 | |||||||||
|
Actual return on plan assets:
|
||||||||||||||||
|
Relating to assets still held at the reporting date
|
4 | - | 3 | 7 | ||||||||||||
|
Relating to assets sold during the period
|
- | - | - | - | ||||||||||||
|
Purchases, issuances, sales, and settlements:
|
||||||||||||||||
|
Purchases
|
12 | 1 | 21 | 34 | ||||||||||||
|
Settlements
|
(12 | ) | - | (14 | ) | (26 | ) | |||||||||
|
Balance at end of year
|
$ | 53 | $ | 2 | $ | 38 | $ | 93 | ||||||||
There were no material transfers out of Level 3 in 2014 and 2013.
112
Cash Flow Information
Employer Contributions
PG&E Corporation and the Utility contributed $332 million to the pension benefit plans and $57 million to the other benefit plans in 2014. These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements. None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2014. The Utility’s pension benefits met all the funding requirements under ERISA. PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $61 million to the pension plan and other postretirement benefit plans, respectively, for 2015.
Benefits Payments and Receipts
As of December 31, 2014, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:
|
Pension
|
PBOP
|
Federal
|
||||||||||
|
(in millions)
|
Plan
|
Plans
|
Subsidy
|
|||||||||
|
2015
|
$ | 653 | $ | 91 | $ | (7 | ) | |||||
|
2016
|
696 | 96 | (8 | ) | ||||||||
|
2017
|
737 | 102 | (8 | ) | ||||||||
|
2018
|
775 | 109 | (9 | ) | ||||||||
|
2019
|
812 | 115 | (10 | ) | ||||||||
|
Thereafter in the succeeding five years
|
4,545 | 614 | (29 | ) | ||||||||
There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above. There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.
Retirement Savings Plan
PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended. This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants. Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $80 million, $71 million, and $67 million in 2014, 2013, and 2012, respectively.
There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.
113
NOTE 12: 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. These claims, which the Utility disputes, are being addressed in various FERC and judicial proceedings in which the State of California, the Utility, and other electricity purchasers are seeking refunds from electricity suppliers, including governmental entities, for overcharges incurred in the CAISO and the California Power Exchange wholesale electricity markets during this period.
While the FERC and judicial proceedings are pending, the Utility has pursued, and continues to pursue, settlements with electricity suppliers. The Utility 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. These settlement agreements provide that the amounts payable by the parties are, in some instances, subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC.
Any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers through resolution of the remaining disputed claims, either through settlement or through the conclusion of the various FERC and judicial proceedings, are refunded to customers through rates in future periods.
Interest accrues on the remaining net disputed claims at the FERC-ordered rate, which is higher than the rate earned by the Utility on the escrow balance. Although the Utility has been collecting the difference between the accrued interest and the earned interest from customers in rates, these collections are not held in escrow. If the amount of accrued interest is greater than the amount of interest ultimately determined to be owed on the remaining net disputed claims, the Utility would refund to customers any excess interest collected. The amount of any interest that the Utility may be required to pay will depend on the final determined amount of the remaining net disputed claims and when such interest is paid.
In July 2014, a settlement agreement between the Utility and an electric supplier became effective, resolving a portion of the Utility’s disputed claims. The settlement will result in refunds to customers of $312 million and will be returned through rates in future periods. The Utility is uncertain when and how the remaining disputed claims will be resolved.
In August 2014, the Utility received a letter from the California Power Exchange clarifying its ultimate intent to offset the Utility’s remaining disputed claims principal and interest balances through net settlement. Accordingly, the Utility has presented $434 million of net Disputed claims and customer refunds on the Consolidated Balance Sheets at December 31, 2014, which includes both principal and interest. At December 31, 2013, the Consolidated Balance Sheets reflected $154 million of Disputed claims and customer refunds and $710 million of Interest payable.
At December 31, 2014 and 2013, the Utility held $291 million, respectively, in escrow, including earned interest, for payment of the remaining net disputed claims liability. These amounts are included within restricted cash on the Consolidated Balance Sheets.
114
NOTE 13: RELATED PARTY AGREEMENTS AND TRANSACTIONS
The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services. Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services. PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies. Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.
The Utility’s significant related party transactions were:
|
Year Ended December 31,
|
||||||||||||
|
(in millions)
|
2014
|
2013
|
2012
|
|||||||||
|
Utility revenues from:
|
||||||||||||
|
Administrative services provided to PG&E Corporation
|
$ | 5 | $ | 7 | $ | 7 | ||||||
|
Utility expenses from:
|
||||||||||||
|
Administrative services received from PG&E Corporation
|
$ | 54 | $ | 45 | $ | 50 | ||||||
|
Utility employee benefit due to PG&E Corporation
|
70 | 57 | 51 | |||||||||
At December 31, 2014 and 2013, the Utility had receivables of $17 million and $22 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $20 million and $17 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.
NOTE 14: 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. See “Purchase Commitments” below. PG&E Corporation has financial commitments described in “Other Commitments” below.
Enforcement and Litigation Matters
On September 9, 2010, a natural gas transmission pipeline owned and operated by the Utility ruptured in San Bruno, California. The ensuing explosion and fire resulted in the deaths of eight people, numerous personal injuries, and extensive property damage. PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows have been materially affected by the costs the Utility has incurred related to shareholder funded safety work, the ongoing regulatory investigations, and civil lawsuits that commenced following the San Bruno accident.
115
CPUC Investigations Regarding the Utility’s Gas Transmission System and the San Bruno Accident
There are three CPUC investigative enforcement proceedings pending against the Utility. These investigations relate 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 San Bruno accident.
On September 2, 2014, the assigned CPUC ALJs issued their presiding officer decisions in the three investigative enforcement proceedings pending against the Utility related to the Utility’s natural gas transmission operations and practices and the San Bruno accident. The ALJs determined that the Utility committed approximately 3,700 violations of law, rules and regulations. The ALJs jointly issued a decision calling for total fines and disallowances of $1.4 billion on the Utility to address all violations, allocated as follows: (1) $950 million fine to be paid to the State General Fund, (2) $400 million refund to ratepayers of previously authorized revenues, and (3) remedial measures that the ALJs estimate will cost the Utility at least $50 million. The ALJs’ decisions are not the final decisions of the CPUC. Three CPUC Commissioners have requested that the CPUC review the decisions. It is possible that one or more Commissioners will issue an alternate penalty decision for consideration by the CPUC. In addition, the Utility and other parties, including the SED, TURN, the ORA, the City and County of San Francisco, and the City of San Bruno have appealed the presiding officer decisions.
In its appeals, the Utility argued that the penalties imposed and the findings and conclusions on which they are based do not meet applicable legal standards, are based on the misapplication of California law and regulations, and are unconstitutional. The Utility has asked the CPUC to order the Utility to pay a significantly reduced penalty that is reasonable and proportionate in light of the nature of the violations and that takes into account the substantial unrecovered amounts the Utility has already spent and forecasts that it will spend on gas system safety. The Utility requested that it be allowed 180 days to raise the funds it may be ordered to pay to the State General Fund rather than the 40 days specified in the decision. The Utility also argued that the entire penalty should go toward funding investments in the Utility’s gas transmission system. TURN, the ORA, and the City and County of San Francisco jointly filed an appeal urging the CPUC to disallow the Utility’s recovery of remaining PSEP costs of $877 million and to require the Utility to pay $473 million to the State General Fund. These parties also argue that the record in the investigative proceedings would support an even larger penalty than stated in the decision. The City of San Bruno appealed the rejection of its proposals for the appointment of an independent monitor to oversee the Utility’s natural gas operations and for the establishment of a pipeline safety trust. It is uncertain when the final outcome of the investigations will be determined.
While the various appeals and requests for review of the presiding officer decisions are unresolved there continues to be significant uncertainty about the ultimate forms and amounts of penalties (including fines) that will be imposed on the Utility. At December 31, 2014, the Consolidated Balance Sheets included an accrual of $200 million in other current liabilities for the minimum amount of fines deemed probable. The impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements will depend on the amounts and forms of penalties that are ultimately adopted by the CPUC. Fines payable to the State General Fund or refunds of revenues would be charged to net income when it is probable that such fines or refunds will be imposed and the amounts can be reasonably estimated. A disallowance of previously authorized and incurred capital costs would be charged to net income when the disallowance is probable and the amount can be reasonably estimated. Penalties in the form of future disallowed costs would be charged to net income in the period during which the actual costs are incurred. Although PG&E Corporation and the Utility believe it is probable that the CPUC will impose total penalties materially in excess of the $200 million previously accrued, they are unable to make a better estimate due to the variety of potential combinations of amounts and forms of penalties that could ultimately be imposed on the Utility and uncertainty about the timing of recognition. PG&E Corporation and the Utility believe the final outcome of the investigations will have a material impact on their financial condition, results of operations, and cash flows.
116
Federal Criminal Indictment
On July 29, 2014, a federal grand jury in the Northern District of California returned a 28-count superseding criminal indictment against the Utility in federal district court replacing the indictment that had been returned on April 1, 2014. The superseding indictment charges 27 felony counts (increased from 12 counts charged in the original indictment) alleging that the Utility knowingly and willfully violated minimum safety standards under the Natural Gas Pipeline Safety Act relating to record keeping, pipeline integrity management, and identification of pipeline threats. The superseding indictment also includes one felony count charging that the Utility illegally obstructed the NTSB’s investigation into the cause of the San Bruno accident. The maximum statutory fine for each felony count is $500,000, for total fines of $14 million. The superseding indictment also alleges 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 alternate fine would be approximately $1.13 billion.
The Utility entered a plea of not guilty. The Utility believes that criminal charges and the alternate 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. A status conference is scheduled to be held in court on March 9, 2015. PG&E Corporation and the Utility have not accrued any charges for criminal fines in their consolidated financial statements as such amounts are not considered to be probable.
Other Enforcement Matters
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.
Improper CPUC Communications
On September 15, 2014, the Utility notified the CPUC and the ALJ overseeing the 2015 GT&S rate case that it believes certain communications between the Utility and CPUC personnel relating to the 2015 GT&S rate case violated the CPUC’s rules regarding 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 discovered the communications as part of an internal review of communications between the Utility and the CPUC undertaken after the City of San Bruno filed a motion at the CPUC in late July 2014 alleging that various email communications between the Utility’s employees and CPUC personnel violated the ex parte communication rules with respect to the pending CPUC investigative enforcement proceedings against the Utility. The Utility believes that the communications cited by San Bruno in its July 2014 motion are not prohibited ex parte communications. The CPUC has not yet addressed San Bruno’s motion and its request that the CPUC penalize the Utility.)
On November 20, 2014, the CPUC issued a decision imposing a fine of $1.05 million on the Utility and disallowing up to the entire amount of the revenue increase that would have been collected from ratepayers over the five-month period between March 2015 and August 2015. The exact amount of the revenue disallowance will be determined in the CPUC’s final decision in the GT&S rate case expected to be issued in August 2015. In addition, the decision prohibits the Utility from engaging in any oral or written ex parte communications, as well as procedural communications, with Commissioners or their advisors in any rate-setting proceeding and requires the Utility to report communications with senior CPUC staff, in any rate-setting or adjudicatory proceeding before the CPUC, for one year from the effective date of the decision. With respect to the GT&S rate case, the ban will be in effect until the resolution of the GT&S rate case or one year from the effective date of the decision, whichever is later. The Utility and other parties have requested that the CPUC reconsider its decision. The ORA, TURN, and the City of San Bruno argue that the applicable law supports the imposition of a fine ranging from $2.5 million to $250 million. It is uncertain when the CPUC will address these applications for rehearing.
117
In October and December 2014, the Utility notified the CPUC of additional email communications between the Utility and CPUC personnel regarding various matters (not limited to the GT&S rate case), that the Utility believes may constitute or describe ex parte communications. As of January 30, 2015, the Utility had provided copies of approximately 65,000 email communications between the CPUC and the Utility to the CPUC and the City of San Bruno. It is uncertain whether any of these email communications will be challenged as prohibited ex parte communications or as improper or illegal.
The Utility believes it is probable that CPUC enforcement actions will be taken in connection with these additional ex parte communications but 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. It is also possible that other parties may request that the CPUC rescind decisions or take other action in open or closed proceedings to address ex parte communications that they may allege occurred regarding substantive issues in those proceedings. For example, TURN and the ORA have filed petitions to request that the CPUC rescind a $29 million shareholder incentive awarded to the Utility in 2010 for the successful implementation of the Utility’s 2006-2008 energy efficiency programs based on their allegation that prohibited ex parte communications tainted the decision. It is uncertain whether the CPUC will grant these petitions or whether parties will request the CPUC to take action in other proceedings. It is also uncertain whether the ex parte communication issues will affect the outcome of other pending legal matters, ratemaking or regulatory proceedings, investigations and enforcement matters.
Finally, the U.S. Attorney’s Office in San Francisco and the California Attorney General’s office have begun investigations in connection with these communications. The Utility is cooperating with the federal and state investigators. It is uncertain whether any charges will be brought against the Utility.
Gas Safety Citation Program
The SED, the division of the CPUC primarily responsible for overseeing the safety of electric and natural gas utility operations in California, conducts periodic audits of the Utility’s operating practices and investigates potential violations. In December 2011 the CPUC adopted a gas safety citation program and delegated authority to the SED to issue citations and impose fines on California gas corporations, such as the Utility, for violations of certain state and federal regulations that relate to the safety of natural gas facilities and operating practices. The California gas corporations are required to inform the SED of self-identified or self-corrected violations. 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.
Since the gas safety program became effective, the Utility has filed approximately 84 self-reports and the SED has imposed fines ranging from $50,000 to $16.8 million (including the $10.85 million fine related to an explosion in Carmel, California that is discussed below) for violations identified through self-reports, SED investigations and audits. The SED recently has stated that it will not conduct further investigations into 65 self-reports the Utility had filed through December 31, 2014. The Utility believes it is probable that the SED will impose fines or take other enforcement action with respect to some of the Utility’s remaining self-reports or other self-reports that the Utility has filed since January 1, 2015. The Utility believes it is reasonably possible that the SED will impose fines on the Utility based on allegations of noncompliance 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 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.
Carmel Incident
On March 3, 2014, a vacant house in Carmel, California was severely damaged due to a natural gas explosion while the Utility’s employees were performing work to upgrade the main natural gas distribution pipeline in the area. There were no injuries or fatalities. The SED conducted an investigation of the incident and alleged that the Utility committed two violations of certain natural gas safety regulations by failing to follow procedures to update records, to provide its welding crew with accurate information, and to take steps to make safe any actual or potential hazard to life or property. On November 20, 2014, the SED issued a citation to the Utility that included a fine of $10.85 million for these alleged violations. The Utility recorded this amount as an expense for 2014. The Utility has appealed the citation to the CPUC. The SED has requested that the CPUC dismiss the Utility’s appeal as untimely. The CPUC has not yet addressed the SED’s request. In addition, the Utility was informed that the U.S. Attorney’s Office was investigating the Carmel incident. It is uncertain whether any charges will be brought against the Utility.
118
CPUC Investigation Regarding Natural Gas Distribution Facilities Record-Keeping
On November 20, 2014, the CPUC issued an order instituting a new 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. (See “Carmel Incident” above.) On December 22, 2014, as directed by the CPUC, the Utility submitted a report that explained why the Utility believes the SED’s investigative findings do not constitute violations of law and also outlined the various programs, measures and actions the Utility has undertaken to continuously improve its distribution record keeping practices.
PG&E Corporation and the Utility believe it is reasonably possible that the CPUC will impose fines on the Utility or take other enforcement action in connection with this matter, but are unable to reasonably estimate the amount or range of future loss contingencies.
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 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.
Pipeline Safety Enhancement Plan
On November 20, 2014, the CPUC approved the settlement agreement (submitted in July 2014) among the Utility, ORA, and TURN to resolve the Utility’s PSEP Update application. The CPUC decision approved total PSEP-related revenue requirements (2012-2014) of $223 million, subject to refund, that reflect a $23 million reduction to expense funding, as compared to the amount requested in the Utility’s application. (PG&E Corporation’s and the Utility’s 2014 consolidated financial statements reflect this reduction.) In accordance with the settlement agreement, the CPUC decision did not adopt any reduction to the Utility’s request for authorization of total PSEP capital costs of $766 million. The Utility previously recorded cumulative charges of $549 million for PSEP-related capital costs that are expected to exceed the authorized amount. During the quarter ended December 31, 2014, the Utility recorded an additional charge for $116 million for PSEP capital costs that are expected to exceed the authorized amounts, bringing the total cumulative charge to $665 million. $209 million is expected to be incurred in 2015 and beyond. At December 31, 2014, approximately $549 million of PSEP-related capital costs is recorded in property, plant, and equipment on the Consolidated Balance Sheets. The Utility would be required to record charges in future periods to the extent PSEP-related capital costs are higher than currently expected or if the Utility was required to refund previously authorized PSEP-related capital and expense amounts and/or revenue requirements.
119
Other Legal and Regulatory Contingencies
PG&E Corporation and the Utility are subject to various laws and regulations and, in the normal course of business, are named as parties in a number of claims and lawsuits. In addition, penalties may be incurred for failure to comply with federal, state, or local laws and regulations. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessment of whether a loss is probable or reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred.
Accruals for other legal and regulatory contingencies (excluding amounts related to natural gas matters above) totaled $55 million at December 31, 2014 and $43 million at December 31, 2013. These amounts are included in other current liabilities in the Consolidated Balance Sheets. The estimated reasonably possible range of loss for these matters in excess of the recorded accrual is not material. 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
Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities is subjective and requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is composed of the following:
|
Balance at
|
||||||||
|
(in millions)
|
December 31, 2014
|
December 31, 2013
|
||||||
|
Topock natural gas compressor station (1)
|
$ | 291 | $ | 264 | ||||
|
Hinkley natural gas compressor station (1)
|
158 | 190 | ||||||
|
Former manufactured gas plant sites owned by the Utility or third parties
|
257 | 184 | ||||||
|
Utility-owned generation facilities (other than fossil fuel-fired),
other facilities, and third-party disposal sites
|
150 | 160 | ||||||
|
Fossil fuel-fired generation facilities and sites
|
98 | 102 | ||||||
|
Total environmental remediation liability
|
$ | 954 | $ | 900 | ||||
At December 31, 2014 the Utility expected to recover $663 million of its environmental remediation liability through various ratemaking mechanisms authorized by the CPUC. One of these mechanisms allows the Utility rate recovery for 90% of its hazardous substance remediation costs for certain approved sites (including the Topock site) without a reasonableness review. The Utility may incur environmental remediation costs that it does not seek to recover in rates, such as the costs associated with the Hinkley site.
120
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 subject to the regulatory authority of the Regional Board. In 2013, the Regional Board certified a final environmental report evaluating the Utility’s proposed remedial methods to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. On January 22, 2015, the Regional Board issued a preliminary draft clean-up and abatement order that proposes that the Utility continue and improve its remedial treatment methods evaluated in the environmental report, along with a proposed monitoring and reporting program and proposed deadlines in 2021 and 2026 to meet specified interim clean-up targets. Comments by the Utility and the public are due on March 13, 2015. The Regional Board is tentatively scheduled to consider final adoption of the clean-up and abatement order at its September 2015 meeting.
The Utility’s environmental remediation liability at December 31, 2014 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. As the comment process continues and the final order and permits are issued, the Utility expects to obtain additional information about the total costs associated with implementing the final remedy and performing related activities and the best estimate of future costs may be subject to further changes. 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 subject to the regulatory authority of the California Department of Toxic Substances Control and the U.S. Department of the Interior. In September 2014, the Utility submitted its 90% remedial design plan to regulatory authorities and expects to submit its final remedial design plan in mid-2015, which would seek approval to begin construction of an in-situ groundwater treatment system that will convert hexavalent chromium into a non-toxic and non-soluble form of chromium. The Utility has implemented 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. The Utility’s environmental remediation liability at December 31, 2014 reflects its best estimate of probable future costs associated with its final remediation plan. Future costs will depend on many factors, including the extent of work to be performed to implement the final groundwater remedy and the Utility’s required time frame for remediation. Future changes in cost estimates and the assumptions on which they are based may have a material impact on future financial condition and cash flows.
121
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.
Nuclear Insurance
The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities. NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.6 billion per non-nuclear incident for Diablo Canyon. Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of December 31, 2014, the current maximum aggregate annual retrospective premium obligation for the Utility is approximately $51 million.
NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. Certain acts of terrorism may be “certified” by the Secretary of the Treasury. If damages are caused by certified acts of terrorism, NEIL can obtain compensation from the federal government and will provide up to its full policy limit of $3.2 billion for each insured loss. In contrast, NEIL would treat all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share the $3.2 billion policy limit amount.
Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $13.6 billion. The Utility purchased the maximum available public liability insurance of $375 million for Diablo Canyon. The balance of the $13.6 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors. The Utility may be assessed up to $255 million per nuclear incident under this program, with payments in each year limited to a maximum of $38 million per incident. Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before September 10, 2018.
The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility. The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $375 million per incident. In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents, covering liabilities in excess of the liability insurance.
122
Purchase Commitments
The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2014:
|
Power Purchase Agreements
|
||||||||||||||||||||||||
|
Renewable
|
Qualifying
|
Natural
|
Nuclear
|
|||||||||||||||||||||
|
(in millions)
|
Energy
|
Facility
|
Other
|
Gas
|
Fuel
|
Total
|
||||||||||||||||||
|
2015
|
$ | 2,145 | $ | 601 | $ | 820 | $ | 544 | $ | 138 | $ | 4,248 | ||||||||||||
|
2016
|
2,185 | 525 | 766 | 164 | 129 | 3,769 | ||||||||||||||||||
|
2017
|
2,187 | 418 | 758 | 107 | 131 | 3,601 | ||||||||||||||||||
|
2018
|
2,063 | 382 | 731 | 107 | 115 | 3,398 | ||||||||||||||||||
|
2019
|
2,053 | 304 | 706 | 107 | 109 | 3,279 | ||||||||||||||||||
|
Thereafter
|
30,289 | 1,217 | 2,390 | 648 | 429 | 34,973 | ||||||||||||||||||
|
Total purchase commitments
|
$ | 40,922 | $ | 3,447 | $ | 6,171 | $ | 1,677 | $ | 1,051 | $ | 53,268 | ||||||||||||
Third-Party Power Purchase Agreements
In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity. The price of purchased power may be fixed or variable. Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.
Renewable Energy Power Purchase Agreements – In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate. The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow significantly. As of December 31, 2014, renewable energy contracts expire at various dates between 2016 and 2043.
Qualifying Facility Power Purchase Agreement – The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law. Several of these agreements are treated as capital leases. At December 31, 2014 and 2013, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $74 million and $97 million including accumulated amortization of $128 million and $176 million. The present value of the future minimum lease payments due under these agreements included $20 million and $23 million in Current Liabilities and $54 million and $74 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2014, QF contracts in operation expire at various dates between 2015 and 2028.
Other Power Purchase Agreements – The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements. The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power. As of December 31, 2014, other power purchase agreements expire at various dates between 2015 and 2033.
The costs incurred for all power purchases and electric capacity amounted to $3.6 billion in 2014, $3.0 billion in 2013, and $2.3 billion in 2012.
123
Natural Gas Supply, Transportation, and Storage Commitments
The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities. These purchase agreements expire at various dates between 2015 and 2026. The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins. In addition, the Utility has contracted for natural gas storage services in northern California in order to more reliably meet customers’ loads.
Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $1.4 billion in 2014, $1.6 billion in 2013, and $1.3 billion in 2012.
Nuclear Fuel Agreements
The Utility has entered into several purchase agreements for nuclear fuel. These agreements expire at various dates between 2015 and 2025 and are intended to ensure long-term nuclear fuel supply. The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply. Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.
Payments for nuclear fuel amounted to $105 million in 2014, $162 million in 2013, and $118 million in 2012.
Other Commitments
PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2015 and 2052. At December 31, 2014, the future minimum payments related to these commitments were as follows:
|
Operating Leases
|
||||
|
2015
|
$ | 44 | ||
|
2016
|
43 | |||
|
2017
|
33 | |||
|
2018
|
30 | |||
|
2019
|
27 | |||
|
Thereafter
|
183 | |||
|
Total minimum lease payments
|
$ | 360 | ||
Payments for other commitments related to operating leases amounted to $42 million in 2014, $40 million in 2013, and $32 million in 2012. Certain leases on office facilities contain escalation clauses requiring annual increases in rent. The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index. Most leases contain extension operations ranging between one and five years.
124
|
Quarter ended
|
||||||||||||||||
|
(in millions, except per share amounts)
|
December 31
|
September 30
|
June 30
|
March 31
|
||||||||||||
|
2014
|
||||||||||||||||
|
PG&E CORPORATION
|
||||||||||||||||
|
Operating revenues (1)
|
$ | 4,308 | $ | 4,939 | $ | 3,952 | $ | 3,891 | ||||||||
|
Operating income
|
383 | 1,065 | 518 | 484 | ||||||||||||
|
Income tax provision
|
35 | 115 | 104 | 91 | ||||||||||||
|
Net income (2)
|
135 | 814 | 271 | 230 | ||||||||||||
|
Income available for common shareholders
|
131 | 811 | 267 | 227 | ||||||||||||
|
Comprehensive income
|
120 | 796 | 260 | 235 | ||||||||||||
|
Net earnings per common share, basic
|
0.28 | 1.72 | 0.57 | 0.49 | ||||||||||||
|
Net earnings per common share, diluted
|
0.27 | 1.71 | 0.57 | 0.49 | ||||||||||||
|
Common stock price per share:
|
||||||||||||||||
|
High
|
54.98 | 48.07 | 48.23 | 44.73 | ||||||||||||
|
Low
|
44.38 | 43.00 | 42.37 | 39.60 | ||||||||||||
|
UTILITY
|
||||||||||||||||
|
Operating revenues (1)
|
$ | 4,308 | $ | 4,939 | $ | 3,951 | $ | 3,890 | ||||||||
|
Operating income
|
383 | 1,059 | 525 | 485 | ||||||||||||
|
Income tax provision
|
59 | 115 | 110 | 100 | ||||||||||||
|
Net income (2)
|
162 | 793 | 250 | 228 | ||||||||||||
|
Income available for common stock
|
158 | 790 | 246 | 225 | ||||||||||||
|
Comprehensive income
|
154 | 793 | 250 | 228 | ||||||||||||
|
2013
|
||||||||||||||||
|
PG&E CORPORATION
|
||||||||||||||||
|
Operating revenues
|
$ | 3,975 | $ | 4,175 | $ | 3,776 | $ | 3,672 | ||||||||
|
Operating income
|
333 | 291 | 636 | 502 | ||||||||||||
|
Income tax (benefit) provision
|
25 | (24 | ) | 153 | 114 | |||||||||||
|
Net income (2)
|
90 | 164 | 332 | 242 | ||||||||||||
|
Income available for common shareholders
|
86 | 161 | 328 | 239 | ||||||||||||
|
Comprehensive income
|
210 | 165 | 352 | 252 | ||||||||||||
|
Net earnings per common share, basic
|
0.19 | 0.36 | 0.74 | 0.55 | ||||||||||||
|
Net earnings per common share, diluted
|
0.19 | 0.36 | 0.74 | 0.55 | ||||||||||||
|
Common stock price per share:
|
||||||||||||||||
|
High
|
42.75 | 46.37 | 48.44 | 44.53 | ||||||||||||
|
Low
|
40.07 | 40.76 | 43.59 | 40.47 | ||||||||||||
|
UTILITY
|
||||||||||||||||
|
Operating revenues
|
$ | 3,973 | $ | 4,174 | $ | 3,775 | $ | 3,671 | ||||||||
|
Operating income
|
360 | 292 | 635 | 503 | ||||||||||||
|
Income tax (benefit) provision
|
65 | (20 | ) | 160 | 121 | |||||||||||
|
Net income (2)
|
138 | 162 | 329 | 237 | ||||||||||||
|
Income available for common stock
|
134 | 159 | 325 | 234 | ||||||||||||
|
Comprehensive income
|
231 | 166 | 333 | 242 | ||||||||||||
|
(1) In the third quarter 2014, the Utility recorded an increase to base revenues as authorized by the CPUC in the 2014 GRC decision.
|
(2) The Utility recorded a charge to net income of $116 million in the fourth quarter of 2014 and $196 million in the third quarter of 2013 for PSEP capital costs that are forecasted to exceed the authorized amounts. (See Note 14 of the Notes to the Consolidated Financial Statements in Item 8.)
125
Management of PG&E Corporation and Utility is responsible for establishing and maintaining adequate internal control over financial reporting. PG&E Corporation’s and the Utility’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, or GAAP. Internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of PG&E Corporation and the Utility, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures are being made only in accordance with authorizations of management and directors of PG&E Corporation and the Utility, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its assessment and those criteria, management has concluded that PG&E Corporation and the Utility maintained effective internal control over financial reporting as of December 31, 2014.
Deloitte & Touche LLP, an independent registered public accounting firm, has audited PG&E Corporation’s and the Utility’s internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
126
To the Board of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
San Francisco, California
We have audited the internal control over financial reporting of PG&E Corporation and subsidiaries (the “Company”) and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s and the Utility’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s and the Utility’s internal control over financial reporting based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audits included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company and the Utility maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and the Utility and our report dated February 10, 2015 expressed an unqualified opinion on those financial statements and includes an explanatory paragraph relating to three investigative enforcement proceedings pending with the California Public Utilities Commission that may result in material amounts of penalties.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 10, 2015
127
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
San Francisco, California
We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) and of Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2014 and 2013, and the Company’s related consolidated statements of income, comprehensive income, equity, and cash flows and the Utility’s related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s and the Utility’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PG&E Corporation and subsidiaries and of Pacific Gas and Electric Company and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 14 to the consolidated financial statements, there are three investigative enforcement proceedings pending with the California Public Utilities Commission that may result in material amounts of penalties.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s and the Utility’s internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 10, 2015 expressed an unqualified opinion on the Company’s and the Utility’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 10, 2015
128
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A. CONTROLS AND PROCEDURES
Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of December 31, 2014, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports that the companies file or submit under the 1934 Act is 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 1934 Act 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 December 31, 2014 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.
Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management’s report, together with the report of the independent registered public accounting firm, appears in Item 8 of this report under the heading “Management’s Report on Internal Control Over Financial Reporting” and “Report of Independent Registered Public Accounting Firm.”
ITEM 9B. OTHER INFORMATION
Not applicable.
129
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information regarding executive officers of PG&E Corporation and the Utility is set forth under “Executive Officers of the Registrants” at the end of Part I of this report. Other information regarding directors is set forth under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference. Information regarding compliance with Section 16 of the Exchange Act is included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
Website Availability of Code of Ethics, Corporate Governance and Other Documents
The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and the Utility’s website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and the Utility applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers and other executive officers, (2) PG&E Corporation’s and the Utility’s corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.
If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and the Utility that apply to their respective Chief Executive Officers, Chief Financial Officers, or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within four business days of the waiver.
Procedures for Shareholder Recommendations of Nominees to the Boards of Directors
During 2014, there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2014 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.
Audit Committees and Audit Committee Financial Expert
Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is set forth under the headings “Corporate Governance – Board Committee Duties – Audit Committees” and “Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
Information responding to Item 11, for each of PG&E Corporation and the Utility, is set forth under the headings “Compensation Discussion and Analysis,” “Compensation Committee Report,” “Summary Compensation Table - 2014,” “Grants of Plan-Based Awards in 2014,” “Outstanding Equity Awards at Fiscal Year End - 2014,” “Option Exercises and Stock Vested During 2014,” “Pension Benefits – 2014,” “Non-Qualified Deferred Compensation – 2014,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “Compensation of Non-Employee Directors – 2014 Director Compensation” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
130
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility is set forth under the headings “Share Ownership Information – Security Ownership of Management” and “Share Ownership Information – Principal Shareholders” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
Equity Compensation Plan Information
The following table provides information as of December 31, 2014 concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.
|
(a)
|
(b)
|
(c)
|
|||||||
|
Plan Category
|
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights
|
Weighted Average Exercise Price of Outstanding Options, Warrants and Rights
|
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
|
||||||
|
Equity compensation plans approved by shareholders
|
6,303,612
|
(1)
|
$ 34.83
|
(2)
|
16,184,126
|
(3)
|
|||
|
Equity compensation plans not approved by shareholders
|
-
|
-
|
-
|
||||||
|
Total equity compensation plans
|
6,303,612
|
(1)
|
$ 34.83
|
(2)
|
16,184,126
|
(3)
|
|||
(1) Includes 45,660 phantom stock units, 2,571,530 restricted stock units and 3,659,066 performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. For performance shares, amounts reflected in this table assume payout in shares at 200% of target or, for performance shares granted in 2012, reflects the actual payout percentage of 35%. The actual number of shares issued can range from 0% to 200% of target depending on achievement of total shareholder return objectives. Also, restricted stock units and performance shares are generally settled in net shares. Upon vesting, shares with a value equal to required tax withholding will be withheld and, in lieu of issuing the shares, taxes will be paid on behalf of employees. Shares not issued due to share withholding or performance achievement below maximum will be available again for issuance.
(2) This is the weighted average exercise price for the 26,756 options outstanding as of December 31, 2014.
(3) Represents the total number of shares available for issuance under all of PG&E Corporation’s equity compensation plans as of December 31, 2014. Stock-based awards granted under these plans include restricted stock units, performance shares and phantom stock units. The 2014 LTIP, which became effective on May 12, 2014, authorizes up to 17 million shares to be issued pursuant to awards granted under the 2014 LTIP, less approximately 2.7 million shares for awards granted under the 2006 LTIP from January 1, 2014 through May 11, 2014. In addition, if any awards outstanding under the 2006 LTIP at December 31, 2013 are cancelled, forfeited or expire without being settled in full, shares of stock allocable to the terminated portion of such awards shall again be available for issuance under the 2014 LTIP.
For more information, see Note 5: Common Stock and Share-Based Compensation of the Notes to the Consolidated Financial Statements appearing in Item 8.
ITEM 13. Certain Relationships and Related Transactions, and Director Independence
Information responding to Item 13, for each of PG&E Corporation and the Utility, is included under the headings “Related Party Transactions” and “Corporate Governance – Board and Director Independence and Qualifications” and “Corporate Governance – Committee Membership” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
ITEM 14. Principal Accountant Fees and Services
Information responding to Item 14, for each of PG&E Corporation and the Utility, is set forth under the heading “Information Regarding the Independent Registered Public Accounting Firm for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2015 Annual Meetings of Shareholders, which information is incorporated herein by reference.
131
ITEM 15. Exhibits and Financial Statement Schedules
(a) The following documents are filed as a part of this report:
1. The following consolidated financial statements, supplemental information and report of independent registered public accounting firm are filed as part of this report in Item 8:
Consolidated Statements of Income for the Years Ended December 31, 2014, 2013, and 2012 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013, and 2012 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Balance Sheets at December 31, 2014 and 2013 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013, and 2012 for each of PG&E Corporation and Pacific Gas and Electric Company.
Consolidated Statements of Equity for the Years Ended December 31, 2014, 2013, and 2012 for PG&E Corporation.
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2014, 2013, and 2012 for Pacific Gas and Electric Company.
Notes to the Consolidated Financial Statements.
Quarterly Consolidated Financial Data (Unaudited).
Management’s Report on Internal Controls
Reports of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
2. The following financial statement schedules are filed as part of this report:
Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).
I—Condensed Financial Information of Parent as of December 31, 2014 and 2013 and for the Years Ended December 31, 2014, 2013, and 2012.
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2014, 2013, and 2012.
132
3. Exhibits required by Item 601 of Regulation S-K
|
Exhibit Number
|
Exhibit Description
|
|
|
3.1
|
Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
|
|
|
3.2
|
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
|
|
|
3.3
|
Bylaws of PG&E Corporation amended as of February 19, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 3.1)
|
|
|
3.4
|
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws of Pacific Gas and Electric Company amended as of February 19, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-2348), Exhibit 3.2)
|
|
|
4.1
|
Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
|
|
|
4.2
|
First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.3
|
Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.4
|
Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.5
|
Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)
|
133
|
4.6
|
Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.7
|
Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.8
|
Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.9
|
Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.10
|
Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.11
|
Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.12
|
Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.13
|
Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.14
|
Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.15
|
Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.16
|
Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
|
134
|
4.17
|
Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.18
|
Twentieth Supplemental Indenture dated as of November 12, 2013 relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.19
|
Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.20
|
Twenty-Second Supplemental Indenture, dated as of May 12, 2014, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due May 11, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 12, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.21
|
Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.22
|
Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.23
|
Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 (File No. 333-193880), Exhibit 4.1)
|
|
|
4.24
|
First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.25
|
Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.26
|
First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)
|
|
|
10.1
|
Amended and restated credit agreement dated April 1, 2013 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, RBS Securities Inc. 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) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, 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, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
|
10.2
|
Amended and restated credit agreement dated April 1, 2013 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, RBS Securities Inc. 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) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, 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, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2013 (File No. 1-2348), Exhibit 10.2)
|
|
|
10.3
|
Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
|
|
|
10.4
|
Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
|
135
|
10.5
|
*
|
Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1)
|
|
10.6
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.4)
|
|
10.7
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.5)
|
|
10.8
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.3)
|
|
10.9
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2)
|
|
10.10
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3)
|
|
10.11
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.5)
|
|
10.12
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.6)
|
|
10.13
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.4)
|
|
10.14
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4)
|
|
10.15
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5)
|
|
10.16
|
*
|
Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4)
|
|
10.17
|
*
|
Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18)
|
|
10.18
|
*
|
Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.18)
|
136
|
10.19
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2)
|
|
10.20
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21)
|
|
10.21
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7)
|
|
10.22
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8)
|
|
10.23
|
*
|
Separation Agreement between PG&E Corporation and Greg Pruett dated August 8, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2014 (File No. 1-12609), Exhibit 10.1)
|
|
10.24
|
*
|
Separation Agreement between Pacific Gas and Electric Company and Thomas Bottorff dated September 17, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.2)
|
|
10.25
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Steven Malnight dated February 22, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.3)
|
|
10.26
|
*
|
Amended and Restated Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.6)
|
|
10.27
|
*
|
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
|
|
10.28
|
*
|
PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
10.29
|
*
|
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)
|
|
10.30
|
*
|
PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
|
|
10.31
|
*
|
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.1)
|
|
10.32
|
*
|
Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)
|
137
|
10.33
|
*
|
Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)
|
|
10.34
|
*
|
PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609, Exhibit 10.31)
|
|
10.35
|
*
|
PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12609), Exhibit 10.2)
|
|
10.36
|
*
|
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)
|
|
10.37
|
*
|
Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 5, 2015
|
|
10.38
|
*
|
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
|
|
10.39
|
*
|
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
|
|
10.40
|
*
|
Resolution of the PG&E Corporation Board of Directors dated September 16, 2014, adopting director compensation arrangement effective January 1, 2015
|
|
10.41
|
*
|
Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012) (File No. 1-12609), Exhibit 10.36)
|
|
10.42
|
*
|
Resolution of the Pacific Gas and Electric Company Board of Directors dated September 16, 2014, adopting director compensation arrangement effective January 1, 2015
|
|
10.43
|
*
|
Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2012) (File No. 1-12609), Exhibit 10.37)
|
|
10.44
|
*
|
PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2015
|
|
10.45
|
*
|
PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.40)
|
|
10.46
|
*
|
PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
|
138
|
10.47
|
*
|
Form of Restricted Stock Unit Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.2)
|
|
10.48
|
*
|
Form of Restricted Stock Unit Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.3)
|
|
10.49
|
*
|
Form of Restricted Stock Unit Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.1)
|
|
10.50
|
*
|
Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1)
|
|
10.51
|
*
|
Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2)
|
|
10.52
|
*
|
Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No. 1-12609), Exhibit 10.3)
|
|
10.53
|
*
|
Form of Restricted Stock Unit Agreement for 2013 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
10.54
|
*
|
Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99.1)
|
|
10.55
|
*
|
Form of Performance Share Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.3)
|
|
10.56
|
*
|
Form of Performance Share Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.4)
|
|
10.57
|
*
|
Form of Performance Share Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.2)
|
|
10.58
|
*
|
Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2)
|
|
10.59
|
*
|
PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)
|
|
10.60
|
*
|
PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
|
139
|
10.61
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of May 12, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No. 1-12609), Exhibit 10.2)
|
|
10.62
|
*
|
PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6)
|
|
10.63
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.5)
|
|
10.64
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51)
|
|
10.65
|
*
|
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
|
|
10.66
|
*
|
Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
|
|
10.67
|
*
|
PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
|
|
10.68
|
*
|
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
|
|
10.69
|
*
|
PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)
|
|
10.70
|
*
|
Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
|
|
10.71
|
*
|
Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
|
|
12.1
|
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
|
140
|
12.2
|
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
|
|
|
12.3
|
Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
|
|
|
21
|
Subsidiaries of the Registrant
|
|
|
23
|
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
|
|
|
24
|
Powers of Attorney
|
|
|
31.1
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
31.2
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
32.1
|
**
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32.2
|
**
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
|
|
101.INS
|
XBRL Instance Document
|
|
|
101.SCH
|
XBRL Taxonomy Extension Schema Document
|
|
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
101.LAB
|
XBRL Taxonomy Extension Labels Linkbase Document
|
|
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
*
|
Management contract or compensatory agreement.
|
|
|
**
|
Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
|
141
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2014 to be signed on their behalf by the undersigned, thereunto duly authorized.
|
PG&E CORPORATION
|
PACIFIC GAS AND ELECTRIC COMPANY
|
||
|
(Registrant)
|
(Registrant)
|
||
|
ANTHONY F. EARLEY, JR.
|
CHRISTOPHER P. JOHNS
|
||
|
Anthony F. Earley, Jr.
|
Christopher P. Johns
|
||
|
By:
|
Chairman of the Board, Chief Executive Officer, and President
|
By:
|
President
|
|
Date:
|
February 10, 2015
|
Date:
|
February 10, 2015
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|||
|
A. Principal Executive Officers
|
|||||
|
ANTHONY F. EARLEY, JR.
|
Chairman of the Board, Chief Executive Officer, and
|
February 10, 2015
|
|||
|
Anthony F. Earley, Jr.
|
President (PG&E Corporation)
|
||||
|
CHRISTOPHER P. JOHNS
|
President
|
February 10, 2015
|
|||
|
Christopher P. Johns
|
(Pacific Gas and Electric Company)
|
||||
|
|
|||||
|
B. Principal Financial Officers
|
|||||
|
KENT M. HARVEY
|
Senior Vice President and Chief Financial Officer (PG&E Corporation)
|
February 10, 2015
|
|||
|
Kent M. Harvey
|
|||||
|
DINYAR B. MISTRY
|
Vice President, Chief Financial Officer, and Controller
|
February 10, 2015
|
|||
|
Dinyar B. Mistry
|
(Pacific Gas and Electric Company)
|
||||
|
C. Principal Accounting Officer
|
|||||
|
DINYAR B. MISTRY
|
Vice President and Controller (PG&E Corporation)
|
February 10, 2015
|
|||
|
Dinyar B. Mistry
|
Vice President, Chief Financial Officer, and Controller
|
||||
|
(Pacific Gas and Electric Company)
|
142
|
D. Directors
|
|||||
|
*
|
LEWIS CHEW
|
Director
|
February 10, 2015
|
||
|
Lewis Chew
|
|||||
|
*
|
ANTHONY F. EARLEY, JR.
|
Director
|
February 10, 2015
|
||
|
Anthony F. Earley, Jr.
|
|||||
|
*
|
FRED J. FOWLER
|
Director
|
February 10, 2015
|
||
|
Fred J. Fowler
|
|||||
|
*
|
MARYELLEN C. HERRINGER
|
Director
|
February 10, 2015
|
||
|
Maryellen C. Herringer
|
|||||
|
*
|
CHRISTOPHER P. JOHNS
|
Director (Pacific Gas and Electric Company only)
|
February 10, 2015
|
||
|
Christopher P. Johns
|
|||||
|
*
|
RICHARD C. KELLY
|
Director
|
February 10, 2015
|
||
|
Richard C. Kelly
|
|||||
|
*
|
ROGER H. KIMMEL
|
Director
|
February 10, 2015
|
||
|
Roger H. Kimmel
|
|||||
|
*
|
RICHARD A. MESERVE
|
Director
|
February 10, 2015
|
||
|
Richard A. Meserve
|
|||||
|
*
|
FORREST E. MILLER
|
Director
|
February 10, 2015
|
||
|
Forrest E. Miller
|
|||||
|
*
|
ROSENDO G. PARRA
|
Director
|
February 10, 2015
|
||
|
Rosendo G. Parra
|
|||||
|
*
|
BARBARA L. RAMBO
|
Director
|
February 10, 2015
|
||
|
Barbara L. Rambo
|
|||||
|
*
|
BARRY LAWSON WILLIAMS
|
Director
|
February 10, 2015
|
||
|
Barry Lawson Williams
|
|||||
|
*By:
|
HYUN PARK
|
||||
|
HYUN PARK, Attorney-in-Fact
|
143
To the Board of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company
San Francisco, California
We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the “Company”) and Pacific Gas and Electric Company and subsidiaries (the “Utility”) as of December 31, 2014 and 2013, and for each of the three years in the period ended December 31, 2014, and the Company's and the Utility’s internal control over financial reporting as of December 31, 2014, and have issued our reports thereon dated February 10, 2015 (which report on the consolidated financial statements expresses an unqualified opinion and includes an explanatory paragraph relating to three investigative enforcement proceedings pending with the California Public Utilities Commission that may result in material amounts of penalties); such reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedules of the Company and Utility listed in Item 15. These consolidated financial statement schedules are the responsibility of the Company's and the Utility’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
San Francisco, California
February 10, 2015
144
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
|
Years Ended December 31,
|
||||||||||||
|
(in millions, except per share amounts)
|
2014
|
2013
|
2012
|
|||||||||
|
Administrative service revenue
|
$ | 51 | $ | 41 | $ | 43 | ||||||
|
Operating expenses
|
(53 | ) | (42 | ) | (41 | ) | ||||||
|
Interest income
|
1 | 1 | 1 | |||||||||
|
Interest expense
|
(14 | ) | (25 | ) | (22 | ) | ||||||
|
Other expense
|
(1 | ) | (57 | ) | (39 | ) | ||||||
|
Equity in earnings of subsidiaries
|
1,413 | 848 | 817 | |||||||||
|
Income before income taxes
|
1,397 | 766 | 759 | |||||||||
|
Income tax benefit
|
39 | 48 | 57 | |||||||||
|
Net income
|
$ | 1,436 | $ | 814 | $ | 816 | ||||||
|
Other Comprehensive Income
|
||||||||||||
|
Pension and other postretirement benefit plans obligations (net of taxes of $10,
|
||||||||||||
|
$80, and $72, at respective dates)
|
$ | (14 | ) | $ | 113 | $ | 108 | |||||
|
Net change in investments (net of taxes of $17, $26, and $3, at respective dates)
|
(25 | ) | 38 | 4 | ||||||||
|
Total other comprehensive income (loss)
|
(39 | ) | 151 | 112 | ||||||||
|
Comprehensive Income
|
$ | 1,397 | $ | 965 | $ | 928 | ||||||
|
Weighted Average Common Shares Outstanding, Basic
|
468 | 444 | 424 | |||||||||
|
Weighted Average Common Shares Outstanding, Diluted
|
470 | 445 | 425 | |||||||||
|
Earnings per common share, basic
|
$ | 3.07 | $ | 1.83 | $ | 1.92 | ||||||
|
Earnings per common share, diluted
|
$ | 3.06 | $ | 1.83 | $ | 1.92 | ||||||
145
PG&E CORPORATION
SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED BALANCE SHEETS
|
Balance at December 31,
|
||||||||
|
(in millions)
|
2014
|
2013
|
||||||
|
ASSETS
|
||||||||
|
Current Assets
|
||||||||
|
Cash and cash equivalents
|
$ | 96 | $ | 231 | ||||
|
Advances to affiliates
|
31 | 30 | ||||||
|
Income taxes receivable
|
29 | 13 | ||||||
|
Other
|
38 | 86 | ||||||
|
Total current assets
|
194 | 360 | ||||||
|
Noncurrent Assets
|
||||||||
|
Equipment
|
2 | 2 | ||||||
|
Accumulated depreciation
|
(1 | ) | (1 | ) | ||||
|
Net equipment
|
1 | 1 | ||||||
|
Investments in subsidiaries
|
16,003 | 14,711 | ||||||
|
Other investments
|
117 | 110 | ||||||
|
Income taxes receivable
|
- | 5 | ||||||
|
Deferred income taxes
|
260 | 188 | ||||||
|
Total noncurrent assets
|
16,381 | 15,015 | ||||||
|
Total Assets
|
$ | 16,575 | $ | 15,375 | ||||
|
LIABILITIES AND SHAREHOLDERS’ EQUITY
|
||||||||
|
Current Liabilities
|
||||||||
|
Short-term borrowings
|
$ | - | $ | 260 | ||||
|
Long-term debt classified as current
|
- | 350 | ||||||
|
Accounts payable – other
|
67 | 66 | ||||||
|
Other
|
269 | 230 | ||||||
|
Total current liabilities
|
336 | 906 | ||||||
|
Noncurrent Liabilities
|
||||||||
|
Long-term debt
|
350 | - | ||||||
|
Other
|
141 | 127 | ||||||
|
Total noncurrent liabilities
|
491 | 127 | ||||||
|
Common Shareholders’ Equity
|
||||||||
|
Common stock
|
10,421 | 9,550 | ||||||
|
Reinvested earnings
|
5,316 | 4,742 | ||||||
|
Accumulated other comprehensive loss
|
11 | 50 | ||||||
|
Total common shareholders’ equity
|
15,748 | 14,342 | ||||||
|
Total Liabilities and Shareholders’ Equity
|
$ | 16,575 | $ | 15,375 | ||||
146
PG&E CORPORATION
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)
CONDENSED STATEMENTS OF CASH FLOWS
(in millions)
|
Year Ended December 31,
|
||||||||||||
|
2014
|
2013
|
2012
|
||||||||||
|
Cash Flows from Operating Activities:
|
||||||||||||
|
Net income
|
$ | 1,436 | $ | 814 | $ | 816 | ||||||
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
||||||||||||
|
Stock-based compensation amortization
|
65 | 54 | 51 | |||||||||
|
Equity in earnings of subsidiaries
|
(1,413 | ) | (848 | ) | (817 | ) | ||||||
|
Deferred income taxes and tax credits, net
|
(72 | ) | (10 | ) | (31 | ) | ||||||
|
Noncurrent income taxes receivable/payable
|
5 | - | (6 | ) | ||||||||
|
Current income taxes receivable/payable
|
(16 | ) | 20 | (82 | ) | |||||||
|
Other
|
43 | (20 | ) | 20 | ||||||||
|
Net cash provided by (used in) operating activities
|
48 | 10 | (49 | ) | ||||||||
|
Cash Flows From Investing Activities:
|
||||||||||||
|
Investment in subsidiaries
|
(978 | ) | (1,371 | ) | (1,023 | ) | ||||||
|
Dividends received from subsidiaries (1)
|
716 | 716 | 716 | |||||||||
|
Proceeds from tax equity investments
|
368 | 275 | 228 | |||||||||
|
Other
|
- | (8 | ) | - | ||||||||
|
Net cash provided by (used in) investing activities
|
106 | (388 | ) | (79 | ) | |||||||
|
Cash Flows From Financing Activities:
|
||||||||||||
|
Borrowings under revolving credit facilities
|
- | 140 | 120 | |||||||||
|
Repayments under revolving credit facilities
|
(260 | ) | - | - | ||||||||
|
Proceeds from issuance of long-term debt, net of discount and issuance costs of $3 in 2014
|
347 | - | - | |||||||||
|
Repayments of long-term debt
|
(350 | ) | - | - | ||||||||
|
Common stock issued
|
802 | 1,045 | 751 | |||||||||
|
Common stock dividends paid (2)
|
(828 | ) | (782 | ) | (746 | ) | ||||||
|
Other
|
- | (1 | ) | 1 | ||||||||
|
Net cash provided by (used in) financing activities
|
(289 | ) | 402 | 126 | ||||||||
|
Net change in cash and cash equivalents
|
(135 | ) | 24 | (2 | ) | |||||||
|
Cash and cash equivalents at January 1
|
231 | 207 | 209 | |||||||||
|
Cash and cash equivalents at December 31
|
$ | 96 | $ | 231 | $ | 207 | ||||||
|
Supplemental disclosures of cash flow information
|
||||||||||||
|
Cash received (paid) for:
|
||||||||||||
|
Interest, net of amounts capitalized
|
$ | (15 | ) | $ | (23 | ) | $ | (20 | ) | |||
|
Income taxes, net
|
1 | 21 | (60 | ) | ||||||||
|
Supplemental disclosures of noncash investing and financing
|
||||||||||||
|
activities
|
||||||||||||
|
Noncash common stock issuances
|
21 | 22 | 22 | |||||||||
|
Common stock dividends declared but not yet paid
|
$ | 217 | $ | 208 | $ | 196 | ||||||
|
(1) Because of its nature as a holding company, PG&E Corporation classifies dividends received from subsidiaries an investing cash flow.
|
|
(2) In January, April, July, and October of 2014, 2013, and 2012, respectively, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.
|
147
PG&E Corporation
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
|
Additions
|
||||||||||||||||||||
|
Description
|
Balance at Beginning of Period
|
Charged to Costs and Expenses
|
Charged to Other Accounts
|
Deductions (2)
|
Balance at End of Period
|
|||||||||||||||
|
Valuation and qualifying accounts deducted from assets:
|
||||||||||||||||||||
|
2014:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 80 | $ | 41 | $ | - | $ | 55 | $ | 66 | ||||||||||
|
2013:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 87 | $ | 53 | $ | - | $ | 60 | $ | 80 | ||||||||||
|
2012:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 81 | $ | 66 | $ | - | $ | 60 | $ | 87 | ||||||||||
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
148
Pacific Gas and Electric Company
SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2014, 2013, and 2012
|
Additions
|
||||||||||||||||||||
|
Description
|
Balance at Beginning of Period
|
Charged to Costs and Expenses
|
Charged to Other Accounts
|
Deductions (2)
|
Balance at End of Period
|
|||||||||||||||
|
Valuation and qualifying accounts deducted from assets:
|
||||||||||||||||||||
|
2014:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 80 | $ | 41 | $ | - | $ | 55 | $ | 66 | ||||||||||
|
2013:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 87 | $ | 53 | $ | - | $ | 60 | $ | 80 | ||||||||||
|
2012:
|
||||||||||||||||||||
|
Allowance for uncollectible accounts (1)
|
$ | 81 | $ | 66 | $ | - | $ | 60 | $ | 87 | ||||||||||
(1) Allowance for uncollectible accounts is deducted from “Accounts receivable – Customers.”
(2) Deductions consist principally of write-offs, net of collections of receivables previously written off.
149
EXHIBIT INDEX
|
Exhibit Number
|
Exhibit Description
|
|
|
3.1
|
Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
|
|
|
3.2
|
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
|
|
|
3.3
|
Bylaws of PG&E Corporation amended as of February 19, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 3.1)
|
|
|
3.4
|
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
|
|
|
3.5
|
Bylaws of Pacific Gas and Electric Company amended as of February 19, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-2348), Exhibit 3.2)
|
|
|
4.1
|
Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
|
|
|
4.2
|
First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.3
|
Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.4
|
Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.5
|
Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)
|
150
|
4.6
|
Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.7
|
Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.8
|
Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.9
|
Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.10
|
Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.11
|
Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.12
|
Thirteenth Supplemental Indenture dated as of May 13, 2011, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.25% Senior Notes due May 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 13, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.13
|
Fourteenth Supplemental Indenture dated as of September 12, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company's 3.25% Senior Notes due September 15, 2021 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 12, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.14
|
Sixteenth Supplemental Indenture dated as of December 1, 2011 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.50% Senior Notes due December 15, 2041 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 1, 2011 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.15
|
Seventeenth Supplemental Indenture dated as of April 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.45% Senior Notes due April 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 16, 2012 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.16
|
Eighteenth Supplemental Indenture dated as of August 16, 2012 relating to the issuance of $400,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 2.45% Senior Notes due August 15, 2022 and $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due August 15, 2042 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 16, 2012 (File No. 1-2348), Exhibit 4.1)
|
151
|
4.17
|
Nineteenth Supplemental Indenture dated as of June 14, 2013 relating to the issuance of $375,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.25% Senior Notes due June 15, 2023 and $375,000,000 aggregate principal amount of its 4.60% Senior Notes due June 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 14, 2013 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.18
|
Twentieth Supplemental Indenture dated as of November 12, 2013 relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.85% Senior Notes due November 15, 2023 and $500,000,000 aggregate principal amount of its 5.125% Senior Notes due November 15, 2043 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 12, 2013 (File No. 1-2348), Exhibit 4.1)
|
|
|
4.19
|
Twenty-First Supplemental Indenture, dated as of February 21, 2014, relating to the issuance of $450,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.75% Senior Notes due February 15, 2024 and $450,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated February 21, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.20
|
Twenty-Second Supplemental Indenture, dated as of May 12, 2014, relating to the issuance of $300,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due May 11, 2015 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated May 12, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.21
|
Twenty-Third Supplemental Indenture, dated as of August 18, 2014, relating to the issuance of $350,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.40% Senior Notes due August 15, 2024 and $225,000,000 aggregate principal amount of its 4.75% Senior Notes due February 15, 2044 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated August 18, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.22
|
Twenty-Fourth Supplemental Indenture, dated as of November 6, 2014, relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 4.30% Senior Notes due March 15, 2045 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 6, 2014 (File No. 12348), Exhibit 4.1)
|
|
|
4.23
|
Senior Note Indenture, dated as of February 10, 2014, between PG&E Corporation and U.S. Bank National Association (incorporated by reference to PG&E Corporation’s Form S-3 (File No. 333-193880), Exhibit 4.1)
|
|
|
4.24
|
First Supplemental Indenture, dated as of February 27, 2014, relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 2.40% Senior Notes due March 1, 2019 (incorporated by reference to PG&E Corporation’s Form 8-K dated February 27, 2014 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.25
|
Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)
|
|
|
4.26
|
First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)
|
|
|
10.1
|
Amended and restated credit agreement dated April 1, 2013 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, RBS Securities Inc. 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) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, 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, and Sumitomo Mitsui Banking Corporation (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
|
10.2
|
Amended and restated credit agreement dated April 1, 2013 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, RBS Securities Inc. 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) The Royal Bank of Scotland plc and Wells Fargo Bank, National Association as co-documentation agents and lenders, 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, and Sumitomo Mitsui Banking Corporation (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2013 (File No. 1-2348), Exhibit 10.2)
|
|
|
10.3
|
Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
|
|
|
10.4
|
Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)
|
152
|
10.5
|
*
|
Letter regarding Compensation Agreement between PG&E Corporation and Anthony F. Earley, Jr. dated August 8, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.1)
|
|
10.6
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.4)
|
|
10.7
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.5)
|
|
10.8
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.3)
|
|
10.9
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011(incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.2)
|
|
10.10
|
*
|
Restricted Stock Unit Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.3)
|
|
10.11
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2014 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.5)
|
|
10.12
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.6)
|
|
10.13
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation for 2012 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.4)
|
|
10.14
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.4)
|
|
10.15
|
*
|
Performance Share Agreement between Anthony F. Earley, Jr. and PG&E Corporation dated September 13, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2011 (File No. 1-12609), Exhibit 10.5)
|
|
10.16
|
*
|
Restricted Stock Unit Agreement between Christopher P. Johns and PG&E Corporation dated May 9, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2011 (File No. 1-12609), Exhibit 10.4)
|
|
10.17
|
*
|
Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.18)
|
|
10.18
|
*
|
Letter regarding Compensation Arrangement between PG&E Corporation and John R. Simon dated March 9, 2007 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.18)
|
153
|
10.19
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Jesus Soto, Jr. dated April 4, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.2)
|
|
10.20
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Edward D. Halpin dated February 3, 2012 for employment starting April 1, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2012 (File No. 1-2348), Exhibit 10.21)
|
|
10.21
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Karen Austin dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.7)
|
|
10.22
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Nick Stavropoulos dated April 29, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2011 (File No. 1-2348), Exhibit 10.8)
|
|
10.23
|
*
|
Separation Agreement between PG&E Corporation and Greg Pruett dated August 8, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2014 (File No. 1-12609), Exhibit 10.1)
|
|
10.24
|
*
|
Separation Agreement between Pacific Gas and Electric Company and Thomas Bottorff dated September 17, 2014 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.2)
|
|
10.25
|
*
|
Letter regarding Compensation Agreement between Pacific Gas and Electric Company and Steven Malnight dated February 22, 2012 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended September 30, 2014 (File No. 1-2348), Exhibit 10.3)
|
|
10.26
|
*
|
Amended and Restated Restricted Stock Unit Agreement between C. Lee Cox and PG&E Corporation for 2013 grant under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.6)
|
|
10.27
|
*
|
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)
|
|
10.28
|
*
|
PG&E Corporation 2005 Supplemental Retirement Savings Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
10.29
|
*
|
PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)
|
|
10.30
|
*
|
PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
|
|
10.31
|
*
|
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2014 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.1)
|
|
10.32
|
*
|
Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)
|
154
|
10.33
|
*
|
Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)
|
|
10.34
|
*
|
PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of January 1, 2013 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012 (File No. 1-12609, Exhibit 10.31)
|
|
10.35
|
*
|
PG&E Corporation Defined Contribution Executive Supplemental Retirement Plan, as amended effective September 17, 2013 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2013 (File No. 1-12609), Exhibit 10.2)
|
|
10.36
|
*
|
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)
|
|
10.37
|
*
|
Amendment to the Postretirement Life Insurance Plan of the Pacific Gas and Electric Company, effective February 5, 2015
|
|
10.38
|
*
|
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company as amended and restated on February 14, 2012 (incorporated by reference to Pacific Gas and Electric Company's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-2348), Exhibit 10.7)
|
|
10.39
|
*
|
PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)
|
|
10.40
|
*
|
Resolution of the PG&E Corporation Board of Directors dated September 16, 2014, adopting director compensation arrangement effective January 1, 2015
|
|
10.41
|
*
|
Resolution of the PG&E Corporation Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2012) (File No. 1-12609), Exhibit 10.36)
|
|
10.42
|
*
|
Resolution of the Pacific Gas and Electric Company Board of Directors dated September 16, 2014, adopting director compensation arrangement effective January 1, 2015
|
|
10.43
|
*
|
Resolution of the Pacific Gas and Electric Company Board of Directors dated September 19, 2012, adopting director compensation arrangement effective January 1, 2013 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2012) (File No. 1-12609), Exhibit 10.37)
|
|
10.44
|
*
|
PG&E Corporation 2014 Long-Term Incentive Plan effective May 12, 2014 and amended effective January 1, 2015
|
|
10.45
|
*
|
PG&E Corporation 2006 Long-Term Incentive Plan, as amended effective January 1, 2013 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2012 (File No. 1-12609), Exhibit 10.40)
|
|
10.46
|
*
|
PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
|
155
|
10.47
|
*
|
Form of Restricted Stock Unit Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.2)
|
|
10.48
|
*
|
Form of Restricted Stock Unit Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.3)
|
|
10.49
|
*
|
Form of Restricted Stock Unit Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.1)
|
|
10.50
|
*
|
Form of Restricted Stock Unit Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.1)
|
|
10.51
|
*
|
Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2)
|
|
10.52
|
*
|
Form of Restricted Stock Unit Agreement for 2014 grants to directors under the PG&E Corporation 2014 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No. 1-12609), Exhibit 10.3)
|
|
10.53
|
*
|
Form of Restricted Stock Unit Agreement for 2013 grants to directors under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2013 (File No. 1-12609), Exhibit 10.1)
|
|
10.54
|
*
|
Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 99.1)
|
|
10.55
|
*
|
Form of Performance Share Agreement for 2014 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2014 (File No. 1-12609), Exhibit 10.3)
|
|
10.56
|
*
|
Form of Performance Share Agreement for 2013 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2013 (File No. 1-12609), Exhibit 10.4)
|
|
10.57
|
*
|
Form of Performance Share Agreement for 2012 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.2)
|
|
10.58
|
*
|
Form of Performance Share Agreement for 2011 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2011 (File No. 1-12609), Exhibit 10.2)
|
|
10.59
|
*
|
PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)
|
|
10.60
|
*
|
PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)
|
156
|
10.61
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of May 12, 2014 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended June 30, 2014 (File No. 1-12609), Exhibit 10.2)
|
|
10.62
|
*
|
PG&E Corporation 2012 Officer Severance Policy, effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.6)
|
|
10.63
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of March 1, 2012 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 2012 (File No. 1-12609), Exhibit 10.5)
|
|
10.64
|
*
|
PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2010 (File No. 1-12609), Exhibit 10.51)
|
|
10.65
|
*
|
PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)
|
|
10.66
|
*
|
Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)
|
|
10.67
|
*
|
PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
|
|
10.68
|
*
|
PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)
|
|
10.69
|
*
|
PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)
|
|
10.70
|
*
|
Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)
|
|
10.71
|
*
|
Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)
|
|
12.1
|
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
|
157
|
12.2
|
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
|
|
|
12.3
|
Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation
|
|
|
21
|
Subsidiaries of the Registrant
|
|
|
23
|
Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
|
|
|
24
|
Powers of Attorney
|
|
|
31.1
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
31.2
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
32.1
|
**
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
|
|
32.2
|
**
|
Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002
|
|
101.INS
|
XBRL Instance Document
|
|
|
101.SCH
|
XBRL Taxonomy Extension Schema Document
|
|
|
101.CAL
|
XBRL Taxonomy Extension Calculation Linkbase Document
|
|
|
101.LAB
|
XBRL Taxonomy Extension Labels Linkbase Document
|
|
|
101.PRE
|
XBRL Taxonomy Extension Presentation Linkbase Document
|
|
101.DEF
|
XBRL Taxonomy Extension Definition Linkbase Document
|
|
|
*
|
Management contract or compensatory agreement.
|
|
|
**
|
Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
|
158