UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Date of Report: November 17, 2017

(Date of earliest event reported)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)

☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

 

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

 

 

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Item 8.01

Other Events.

2019 Gas Transmission and Storage (“GT&S”) Rate Case

On November 17, 2017, Pacific Gas and Electric Company (the “Utility”), a subsidiary of PG&E Corporation, filed its 2019 GT&S rate case application with the California Public Utilities Commission (the “CPUC”), covering the years 2019 through 2021.  While the Utility has not formally proposed a fourth year for this rate case, it provided a revenue requirement and rates for 2022, in the event the CPUC adopts an additional year.

In its application, the Utility requested that the CPUC authorize a 2019 revenue requirement of $1.59 billion to recover anticipated costs of providing natural gas transmission and storage services beginning on January 1, 2019.  This corresponds to an increase of $289 million over the Utility’s 2018 adjusted authorized revenue requirement of $1.301 billion.  The Utility’s request also includes proposed revenue requirements of $1.73 billion for 2020, $1.91 billion for 2021, and $1.91 billion for 2022 if the CPUC orders a fourth year for the rate case period.

The requested rate base for 2019 is $4.66 billion, which corresponds to an increase of $0.95 billion over the 2018 adjusted authorized rate base of $3.71 billion.  These rate base amounts exclude approximately $576 million of capital spending subject to audit by the CPUC related to 2011 through 2014 expenditures in excess of amounts adopted in the 2011 GT&S rate case, also known as Gas Accord V (D.11-04-031).  The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be authorized by the CPUC and included in the Utility’s future rate base.  The Utility’s request also excludes rate base adjustments, that the Utility requested with the CPUC on November 14, 2017, resulting from the Internal Revenue Service’s (“IRS”) October 5, 2017 private letter ruling issued in connection with the CPUC’s final phase two decision in the 2015 GT&S rate case (the “final phase two decision”).  (As previously disclosed, the private letter ruling indicated that the final phase two decision rate base reduction was inconsistent with the IRS tax normalization requirements.  For more information about the 2015 GT&S rate case, see PG&E Corporation and the Utility’s annual report on Form 10-K for the year ended December 31, 2016, and their subsequent quarterly reports on Form 10-Q.)  The Utility’s request is based on capital expenditure forecasts of $971 million for 2019, $963 million for 2020, and $804 million for 2021 (which exclude common capital allocations).

The increase in revenue requirement is largely attributable to increased infrastructure investment and costs related to new natural gas storage safety and environmental regulations.  Such new regulations were issued by: (1) the California Division of Oil, Gas, and Geothermal Resources (“DOGGR”), which issued six new safety and reliability natural gas storage measures in 2016 in response to the 2015 Southern California natural gas storage leak in Aliso Canyon; (2) the U.S. Pipeline and Hazardous Materials Safety Administration (“PHMSA”), which issued interim final rules, effective January 18, 2017, that address pipeline safety issues and mandate certain reporting requirements for operators of underground natural gas storage facilities; and (3) the CPUC, which issued General Order 112-F that became effective on January 1, 2017, and requires additional expenditures in the areas of gas leak repair, leak survey, and high consequence area identification, among other things.

In addition, DOGGR is planning to complete its final rulemaking on new gas storage safety rules.  The draft rules, that were released for comments on May 19, 2017, include a requirement for natural gas storage operators to perform well integrity assessments every two years and to eliminate possible single points of failure from natural gas storage wells.  The implementation timeframe and requirements under the PHMSA’s proposed regulations currently are being challenged in federal courts.  In its application, the Utility proposes a new two-way Gas Storage Balancing Account to address uncertainty around the anticipated DOGGR regulations, and also proposes a new memorandum account to track costs related to other anticipated new regulations.

 

As a result of the existing and anticipated gas storage safety requirements, the Utility developed and proposed in its 2019 GT&S rate case application a natural gas storage strategy which includes the discontinuation (through closure or sale) of operations at two gas storage fields.  The discontinuation is expected to reduce long-term costs for customers and to reduce safety and environmental risks.

In addition to costs related to new natural gas storage safety and environmental regulations, the Utility proposed increased infrastructure investments over the 2019 to 2021 period to continue its efforts to improve overall system safety by: (1) making approximately 1,100 miles of transmission pipelines capable of in-line inspection; (2) performing in-line inspections of over 2,100 miles of transmission pipeline, or approximately one-third of total miles; (3) testing or replacing all pipeline without a test record (or with a test record that does not meet the Utility’s documentation requirements) by 2027; (4) replacing vintage pipeline for other safety or reliability issues; and (5) automating valves in areas where there is a significant potential impact.

The Utility expects a prehearing conference to be held in early 2018 to set a procedural schedule, including the dates for interested parties to submit testimony and for evidentiary hearings.

 

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

 

 

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