UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

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

Date of Report: June 23, 2016

(Date of earliest event reported)

Commission File Number	Exact Name of Registrant as specified in its charter	State or Other Jurisdiction of Incorporation or Organization	IRS Employer Identification Number
1-12609	PG&E CORPORATION	California	94-3234914
1-2348	PACIFIC GAS AND ELECTRIC COMPANY	California	94-0742640


77 Beale Street P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (415) 973-1000 (Registrant's telephone number, including area code)		77 Beale Street P.O. Box 770000 San Francisco, California 94177 (Address of principal executive offices) (Zip Code) (415) 973-7000 (Registrant's telephone number, including area code)

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))

Item 8.01

Other Events

Pacific Gas and Electric Company’s (“Utility”) 2015 Gas Transmission and Storage (“GT&S”) Rate Case

On June 23, 2016, the California Public Utilities Commission (“CPUC”) approved a revised alternate proposed decision in the Utility’s 2015 GT&S rate case (the “Decision”). The Decision adopts the revenue requirements that the Utility will be authorized to collect through rates beginning August 1, 2016, to recover its costs of gas transmission and storage services for the 2015 GT&S rate case period. These rates will be subject to a future adjustment for the $850 million shareholder-funded safety-related expenditures imposed in the San Bruno Penalty Decision. (As previously disclosed, the San Bruno Penalty Decision disallows the Utility from recovering $850 million of costs associated with future pipeline safety-related projects and programs to be designated by the CPUC.)

In this Decision, the CPUC determines it will issue a second decision to reduce the authorized revenue requirements for the $850 million San Bruno penalty after considering comments from parties on (i) which programs and projects should be considered safety-related, and (ii) whether the percentage of the disallowance that should be applied to capital expenditures as opposed to expense should be changed. (The San Bruno Penalty Decision determined that a minimum of $689 million of the $850 million penalty should be applied to capital expenditures.) Opening briefs on allocation of the $850 million San Bruno penalty are due on July 7, 2016 and reply briefs are due on July 14, 2016. The second decision is expected to be issued within 90 days of the reply briefs.

The Decision adopts an “interim” 2015 revenue requirement of $1.046 billion, compared to the Utility’s request of $1.263 billion. This “interim” revenue requirement will be further reduced for the disallowance associated with the 5-month delay caused by the Utility’s violation of the CPUC ex parte communication rules in this proceeding. The Decision indicates that the proper sequence for applying the penalties is to first reduce the adopted revenue requirement by the $850 million San Bruno penalty to determine the final revenue requirement to be collected from customers, and then apply the ex parte disallowance so that five-twelfths of the 2015 revenue increase is shareholder-funded. As a result, the Decision includes a “placeholder” ex parte disallowance of $138 million in 2015, subject to true-up after the revenue requirement is adjusted for the $850 million San Bruno penalty. Including the impact of this “placeholder” ex parte disallowance, the adopted 2015 revenue requirement is $908 million, an increase of $193 million or 27 percent over the 2014 authorized amount of $715 million, compared to the $548 million increase requested by the Utility.

In addition, due to the delay in issuing this Decision, the CPUC adopts a third year of attrition revenues for 2018. Excluding the impact of the $850 million San Bruno penalty, this Decision adopts a 2016 revenue requirement of $1.110 billion, a 2017 revenue requirement of $1.220 billion, and a 2018 revenue requirement of $1.324 billion. These amounts reflect attrition increases of $64 million in 2016 (excluding the $138 million “placeholder” ex parte disallowance for 2015), $110 million in 2017 and $104 million in 2018, compared to the Utility’s requested attrition increases of $83 million for 2016 and $142 million for 2017. Including the $138 million “placeholder” ex parte disallowance in 2015, the attrition increase is $202 million for 2016.

The following table shows the revenue requirement amounts requested by the Utility in the 2015 GT&S rate case and the revenue requirement amounts adopted in this Decision, subject to future adjustments for the $850 million San Bruno penalty:

(in millions)	2015			2016		2017		2018
Utility Requested Revenue Requirement	$	1,263		$	1,346	$	1,488	$	N/A

Adopted Revenue Requirement		1,046			1,110		1,220		1,324
“Placeholder” Ex Parte Penalty		(138	)
Adopted Revenue Requirement before San Bruno Penalty disallowances		908			1,110		1,220		1,324

In 2015, the Utility’s GT&S revenues were approximately $550 million. The Decision authorizes the Utility to collect, over a 36-month period, the difference between adopted revenue requirements and amounts previously collected in rates, retroactive to January 1, 2015. Due to the uncertainty regarding the revenue requirement the CPUC will ultimately adopt in its second decision, after allocation of the $850 million San Bruno penalty (and the resulting adjustment of the ex parte disallowance), the Utility will not be able to record a true-up of revenues under-collected since January 1, 2015 until after such second decision is issued. In addition, accounting rules allow the Utility to recognize revenues in a given year only if they will be collected from customers within 24 months of the end of that year. As a result, the Utility may not be able to complete recording the full true-up of under-collected revenues until 2017.

The Decision adopts capital expenditures of roughly $700 million to $800 million per year through 2018 and authorizes weighted average rate base of $2.9 billion in 2015, $3.3 billion in 2016, $3.6 billion in 2017, and $4.2 billion in 2018. The authorized weighted average rate base reflects the removal of $696 million of capital spending in 2011-2014 in excess of the amount adopted in the 2011 GT&S rate case decision, and does not reflect the impact of the $850 million San Bruno penalty or the Line 407 project (see below). The Decision permanently disallows $120 million of the 2011-2014 capital expenditures and orders that the remaining $576 million be subject to a third party audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery of the $576 million in a future proceeding.

The Decision establishes one-way balancing accounts for Work Required by Others and for Engineering Critical Assessments (“ECA”), for stations installed before January 1, 1956. ECA work on stations installed on or after January 1, 1956 shall be borne by shareholders. The Decision defers cost recovery for the Hydrostatic Station Testing and Critical Documents Program. The Utility is authorized to establish memorandum accounts to track work associated with Hydrostatic Station Testing and the Critical Document Program related to facilities built on or before December 31, 1955 and seek recovery in a subsequent application. The Decision also directs the Utility to perform hydrostatic tests on 680 miles of pipelines over the rate case period. The Utility is authorized to establish a new Hydrostatic Testing Memorandum Account to track any expenditure above authorized expenses and may seek recovery of these costs in a future application. The Decision rejects the Utility’s request for a two-way balancing account for the Transmission Integrity Management Program, and instead establishes a one-way balancing account. In addition, the Utility may establish a new Transmission Integrity Management Program Memorandum Account to track costs associated with implementing any new transmission integrity management statutes or rules. The Decision establishes a cost cap for the inoperable valve program, requiring that shareholders fund any costs above the capped amount. The Decision also includes disallowances for specific types of work requested by the Utility, including hydrostatic tests of pipelines (including pipelines in stations) installed after 1955 for which pressure test records are missing, the updating or creation of critical documents associated with stations constructed after 1955, and components of the casings mitigation program, the integrity management direct assessment program, and the shallow pipe program. The Decision requires that these disallowances apply through 2018. The Utility is still evaluating the impact of these provisions.

In addition, the Decision denies the Utility’s request for full balancing account treatment for recovery of authorized transportation and storage revenue requirements, and instead continues the revenue sharing mechanism authorized in the 2011 GT&S rate case that subjects a portion of the Utility’s transportation and storage revenue requirement to market risk.

The Decision also authorizes cost recovery of up to $157 million for the construction of Line 407, a 25.5 mile 30-inch pipeline in the Sacramento Valley expected to be built during this rate case period, corresponding to the Utility’s request for this project. The authorized cost recovery will begin when Line 407 is completed and becomes operational, subject to refund upon a reasonableness review in the Utility’s next GT&S rate case. Costs exceeding $157 million must be recorded in a separate memorandum account, and the Utility may seek recovery in the next GT&S rate case, subject to a reasonableness review. Since the Decision does not include any revenue requirement for this project, Line 407 revenues and the associated rate base will be incremental for this rate case period.

With the addition of a third attrition year, the Utility’s next GT&S cycle will begin in 2019. The Decision requires the Utility to file its next GT&S application in 2017.

For more information about the 2015 GT&S rate case and the San Bruno Penalty Decision, see PG&E Corporation and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2015 and their joint Quarterly Report on Form 10-Q for the quarter ended March 31, 2016.

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.

	PG&E CORPORATION

	By:	/s/ JASON P. WELLS
Dated: June 26, 2016		JASON P. WELLS
		Senior Vice President and Chief Financial Officer

	PACIFIC GAS AND ELECTRIC COMPANY

	By:	/s/ DAVID S. THOMASON
Dated: June 26, 2016		DAVID S. THOMASON
		Vice President, Chief Financial Officer and Controller