ENFORCEMENT AND LITIGATION MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to the enforcement and litigation matters described in ~~Note 9~~Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1. The outcome of these matters, individually or in the aggregate, could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows. In addition, PG&E Corporation and the Utility are involved in other enforcement and litigation matters described in the ~~2017~~2018 Form 10-K and “Part II. Other Information, Item 1. Legal Proceedings.”

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the NRC and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may affect PG&E ~~Corporation's~~Corporation’s and the ~~Utility's~~Utility’s financial condition, results of operations, and cash flows. Discussed below are significant regulatory developments that have occurred since filing the ~~2017~~2018 Form 10-K.

Application for a Waiver of the Capital Structure Condition

The CPUC’s capital structure decisions require the Utility to maintain a 52% equity ratio on average over the period that the authorized capital structure is in place, and to file an application for a waiver to the capital structure condition if an adverse financial event reduces its equity ratio by 1% or more. The CPUC’s decisions state that the Utility shall not be considered in violation of these conditions during the period the waiver application is pending resolution. Due to the net charges recorded in connection with the 2018 Camp fire and the 2017 Northern California wildfires as of December 31, 2018, the Utility submitted to the CPUC an application for a waiver of the capital structure condition on February 28, 2019. The waiver is subject to CPUC approval. The Utility is unable to predict the timing and outcome of its waiver application.

2020 Cost of Capital Proceeding

On April 22, 2019, the Utility filed an application with the CPUC, requesting that the CPUC 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 beginning on January 1, 2020. In its application, the Utility requested that the CPUC approve the Utility’s proposed capital structure (i.e., the relative weightings of common equity, preferred equity, and debt), as well as the proposed return on equity, proposed cost of preferred stock, and proposed cost of debt. The Utility requested a 16% rate of return on equity for 2020, which would result in a $1.2 billion increase in its revenue requirement. The estimated revenue increase is based on the current rate base and does not reflect projected infrastructure investments in 2019 and beyond (see below).

The following table compares the currently authorized capital structure and rates of return which will remain in effect through 2019 with those requested in the Utility’s application for 2020:



	2019 Currently Authorized						2020 Requested
	Cost		Capital Structure		Weighted Cost		Cost		Capital Structure		Weighted Cost
Return on common equity	10.25	%	52.00	%	5.33	%	16.00	%	52.00	%	8.32	%
Preferred stock	5.60	%	1.00	%	0.06	%	5.52	%	0.50	%	0.03	%
Long-term debt	4.89	%	47.00	%	2.30	%	5.16	%	47.50	%	2.45	%
Weighted average cost of capital					7.69	%					10.80	%

The proposed cost of capital and capital structure will be essential for the Utility to attract new investment capital to upgrade, maintain, and modernize its critical energy infrastructure. The Utility indicated in its application that, over the next four years (2019-2022), the Utility expects to fund up to $28 billion in energy infrastructure investments, including $21 billion in electric and gas safety and reliability and system hardening, $4 billion in new gas pipelines and electric powerlines, $1 billion in power generation, and $2 billion in information technology, equipment and facilities.

The Utility indicated in its application that its requested ROE reflects the wildfire-related challenges that the Utility is facing. The Utility proposed to amend its cost of capital application with an updated cost of capital if the CPUC or the California legislature implemented actions to materially reduce the extent of the wildfire risk-related challenges and structural problems facing customers, the Utility, and its shareholders. The Utility also proposed to file a new cost of capital application with the CPUC on or about the time it emerges from its Chapter 11 proceeding. The Utility requested in its cost of capital application that the annual cost of capital adjustment mechanism be continued, although its normal operation could be superseded by a new cost of capital application. (The annual cost of capital adjustment mechanism is a tool to modify the cost of long-term debt and cost of equity authorized by the CPUC based on changes in interest rates.)

Revenue Requirements

For 2020, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $844 million for electric generation and distribution and $229 million gas distribution operations, assuming 2017 authorized rate base amounts. The revenues for the gas transmission and storage operations would increase by approximately $159 million, assuming 2018 authorized rate base amounts. However, if the CPUC subsequently approves different electric and gas rate base amounts for the Utility in its 2019 GT&S Rate Case and its 2020 GRC, both currently pending before the CPUC, the revenue requirement changes resulting from the Utility’s requested 2020 ROE may differ from the amounts reflected in this cost of capital application.

The following table compares the revenue requirement amounts currently authorized in the Utility’s 2015 GT&S rate case and the 2017 GRC, with those requested in the Utility’s 2020 cost of capital application:



Revenue Requirement (in millions)	Authorized in 2017 GRC and 2015 GT&S		Requested in 2020 Cost of Capital Application
Electric generation and distribution	$	6,266	$	7,110
Gas distribution	1,739		1,968
Gas transmission and storage	$	1,269	$	1,428

The Utility is unable to predict the timing and outcome of this proceeding.

As disclosed in “Application for a Waiver of the Capital Structure Condition”above, due to the net charges recorded in connection with the 2018 Camp Fire and the 2017 Northern California wildfires as of December 31, 2018, on February 28, 2019, the Utility submitted to the CPUC an application for a waiver of the capital structure condition. The 2020 cost of capital application does not modify that request.

2017 General Rate Case

On May 11, 2017, the CPUC issued a final decision in the Utility’s 2017 GRC, which determined the annual amount of base revenues (or “revenue requirements”) that the Utility is authorized to collect from customers from 2017 through 2019 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. The final decision approved, with certain modifications, the settlement agreement that the Utility, ~~Cal PA,~~PAO, TURN, and 12 other intervening parties jointly submitted to the CPUC on August 3, 2016. Consistent with the amounts proposed in the settlement agreement, the final decision approved a revenue requirement increase of $88 million for 2017, with additional increases of $444 million in 2018 and $361 million in 2019.

On September 24, 2018, the CPUC approved the ~~Utility's~~Utility’s advice letter proposal to make a one-time reduction to revenues by approximately $21 million. This advice letter was directed by an ALJ ruling in response to the ~~Utility's~~Utility’s $300 million expense reduction announcement in January 2017.

Also, as a result of the Tax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the CPUC’s final decision in the 2017 GRC. The PFM, if adopted, would reduce revenue requirements by $267 million and $296 million for 2018 and 2019 respectively, and increase rate base by $199 million and $425 million for 2018 and 2019, respectively. The Utility cannot predict the timing and outcome of this PFM.

~~Finally, the CPUC continues its review of the Utility's update of the cost effectiveness study for the SmartMeter~~^TM ~~Upgrade project.~~ The Utility provided an update of the cost effectiveness study for the SmartMeter^TM Upgrade project to the CPUC on July 10, 2017. On ~~August 9, 2018,~~January 31, 2019, the CPUC extended the statutory deadline for the 2017 GRC to ~~February~~August 9, 2019, in order to allow for comments and CPUC action on any PD on the SmartMeter^TM upgrade cost effectiveness study. The Utility cannot predict the timing and outcome of any CPUC action in connection with this study and its impact on the 2017 GRC revenue requirement and rate base.

For more information, see the ~~2017~~2018 Form 10-K.

~~Risk Assessment Mitigation Phase Filing~~

On November 30, 2017, the Utility filed its first RAMP report with the CPUC in advance of its 2020 GRC application. The RAMP is a new CPUC requirement directing each large investor-owned energy utility to submit a report describing how it assesses its risks and how it plans to mitigate and minimize such risks in advance of the utility’s GRC application. The Utility's RAMP report informed the CPUC of the Utility’s top safety-related risks, risk assessment procedures, and proposed mitigations of those risks for 2020-2022.

On April 3, 2018, the SED released a report assessing the Utility's RAMP report. The SED report requested, among other items, an updated risk analysis regarding wildfire risk mitigation strategies in the Utility’s 2020 GRC. A workshop on the report was held on April 17, 2018, and the parties submitted opening and reply comments on May 10, 2018, and May 24, 2018, respectively. The RAMP results will be incorporated in the Utility’s 2020 GRC.

2020 General Rate Case

On ~~June 4,~~December 13, 2018, the Utility submitted a letter to the CPUC requesting an extension of up to four months, from September 1, 2018, to January 1, 2019, to file its 2020 GRC application. The Utility requested this extension due to extraordinary uncertainties related to the 2017 Northern California wildfires that could significantly impact the content of the rate case application. On June 29, 2018, the CPUC granted the Utility’s extension request to filefiled its 2020 GRC application ~~no later than January 1, 2019. On October 15, 2018,~~with the CPUC. In the 2020 GRC, the Utility ~~notified~~has requested that the CPUC determine the annual amount of base revenues (or “revenue requirements”) that the Utility ~~anticipates submitting~~will be authorized to collect from customers from 2020 through 2022 to recover its anticipated costs for electric distribution, natural gas distribution, and electric generation operations and to provide the Utility an opportunity to earn its authorized rate of return. The Utility’s request also reflects an updated capital forecast for 2018 and 2019. The 2020 GRC application also includes recorded costs for 2017 and updated forecasts for the proposed mitigations for the period 2018 through 2022 for the Utility’s top safety-related risks as presented in the Utility’s November 2017 RAMP report.

For 2020, the Utility has requested base revenues of $9.6 billion, an increase of $1.1 billion, or 12.4%, as compared to authorized base revenues for 2019. The requested weighted average rate base for 2020 is approximately $30 billion, which corresponds to an increase of $2.7 billion over the 2019 authorized rate base of $27.3 billion. The Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s authorized revenues in 2021 and 2022 by $454 million and $486 million, respectively. Over the 2020-2022 GRC period, the Utility plans to make average annual capital investments of approximately $4.5 billion in electric distribution, natural gas distribution and electric generation infrastructure, and to improve safety, reliability, and customer service.



Line of Business: (in millions)	Amounts Requested in the GRC Application		Amounts Currently Authorized for 2019 ⁽¹⁾		Increase (Decrease) to 2019 Authorized Amounts
Electric distribution	$	5,113	$	4,364	$	749
Gas distribution	2,097		1,963		134
Electric generation	2,366		2,191		175
Total revenue requirements	$	9,576	$	8,518	$	1,058

⁽¹⁾These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.



Cost Category: (in millions)	Amounts Requested in the GRC Application			Amounts Currently Authorized for 2019⁽¹⁾			Increase (Decrease) to 2019 Authorized Amounts
Operations and maintenance	$	2,156		$	1,946		$	210
Customer services	319			338			(19		)
Administrative and general	1,315			953			361
Less: Revenue credits	(196		)	(152		)	(44		)
Franchise fees, taxes other than income, and other adjustments	236			181			55
Depreciation, return, and income taxes	5,747			5,252			495
Total revenue requirements	$	9,576		$	8,518		$	1,058

⁽¹⁾These amounts include revenues from the Utility’s 2017 GRC decision adjusted for attrition year increases, cost of capital, and reductions due to the Tax Act.

⁽²⁾These amounts may appear not to tie due to small rounding differences.



Revenue requirement drivers	Increase to 2019 Authorized Amounts
Community Wildfire Safety Program	6.8	%
Liability insurance ⁽¹⁾	3.2	%
Core gas and electric operations	2.4	%
Total proposed revenue requirement increase	12.4	%

⁽¹⁾The Utility’s GRC forecast indicates that future liability insurance premium costs will be approximately $355 million in 2020

Among other things, the Utility proposed to invest a total of approximately $5 billion (including approximately $3 billion for capital expenditures) between 2018 and 2022 on CWSP measures. Through this program, the Utility proposes to bolster wildfire prevention, risk monitoring, emergency response efforts, and add new and enhanced safety measures, increase vegetation management and harden its electric system to help further reduce wildfire risks.

In addition, the Utility requested authorization to establish several new balancing accounts, including:

a two-way electric and gas Risk Transfer Balancing Account to record the difference between the amounts adopted for liability insurance premiums and the Utility’s actual costs; this two-way account would allow the Utility to pass-through actual insurance costs for up to $2 billion in coverage and return to customers any overcollection if forecast costs exceed actuals costs; and

a two-way Wildfire Safety Balancing Account to track and record actual incremental expenses and capital revenue requirements associated with the incremental costs of fire risk mitigation work that are not already addressed and recorded in another account; this would include the costs associated with overhead system hardening, enhanced vegetation management, and other incremental costs of wildfire mitigations that are approved by the CPUC in the Utility’s annual wildfire mitigation plan. In accordance with SB 901, the Utility submitted its first Wildfire Safety Plan to the CPUC ~~between December 10,~~on February 6, 2019.

This GRC proposal did not request funding for potential lawsuits or claims resulting from the 2018 Camp fire and ~~December 20, 2018.~~2017 Northern California wildfires. Also, the Utility is not seeking recovery of compensation of PG&E Corporation’s and the Utility’s officers. In addition, the Chapter 11 Cases may require a change to the scope of work that the Utility proposes to accomplish in the 2020 GRC period. The Utility also may seek or may be required to update the scope of work for the 2019 Wildfire Safety Plan after such a plan is approved by the CPUC.

In its application, the Utility requests that the CPUC issue a final decision by March 2020 and that the 2020 GRC rates be effective January 1, 2020. On March 8, 2019, the CPUC issued a ruling addressing the schedule and scope of the 2020 GRC. A proposed decision is expected in the first quarter of 2020.

2015 Gas Transmission and Storage Rate Case

In its final decisions in the ~~Utility's~~Utility’s 2015 GT&S rate case, the CPUC excluded from rate base $696 million of capital spending in 2011 through 2014. This was the amount recorded in excess of the amount adopted in the 2011 GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The Utility would be required to take a charge in the future if the CPUC’s audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process. The ~~decision established new one-way balancing accounts to track certain costs, as well as various cost caps that will increase~~Utility cannot predict the ~~risk~~timing and outcome of ~~disallowance over~~ the ~~current rate case cycle.~~audit.

As a result of the Tax Act, on March 30, 2018, the Utility submitted to the CPUC a PFM of the ~~CPUC's~~CPUC’s final decision in the 2015 GT&S rate case proposing to reduce revenue requirements by $58 million and increase rate base by $12 million for 2018 (excluding the impacts of an approximately $7 million increase in revenue requirement and a $60 million increase in rate base associated with the ~~Utility's~~Utility’s private letter ruling advice letter approved by the CPUC on July 18, 2018). The Utility cannot predict the timing and outcome of this PFM.

In August 2016 and January 2017, TURN, Cal PA and Indicated Shippers filed applications for rehearing of the CPUC decisions in the Utility's 2015 GT&S rate case. The Utility cannot predict whether the CPUC will grant the applications for rehearing or adopt the parties’ recommendations.

For more information, see the ~~2017~~2018 Form 10-K.

2019 Gas Transmission and Storage Rate Case

On November 17, 2017, the Utility filed its 2019 GT&S rate case application with the CPUC for the years 2019 through 2021. ~~While the~~The Utility ~~has not formally proposed a fourth year for this rate case, it~~also provided a revenue requirement and rates for 2022, in the event the CPUC adopts an additional year. On October 1, 2018, the Utility entered into a stipulation with ~~Cal PA~~PAO that, if approved, would extend the rate case cycle through 2022 as recommended by ~~Cal PA.~~PAO.

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 authorized revenue requirement of $1.30 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 Utility subsequently revised its forecast revenue requirement as a result of the Tax Act and other forecast updates, including significant reductions in the areas of gas storage facilities and gas system operations programs. The revised revenue requirements are as follows: $1.48 billion for 2019, $1.59 billion for 2020, $1.69 billion for 2021, and $1.68 billion for 2022. The revised 2019 requested revenue requirement corresponds to an increase of $184 million over the Utility’s 2018 authorized revenue requirement.

The requested rate base for 2019 is ~~$4.66~~$4.75 billion, which corresponds to an increase of ~~$0.95~~$1.04 billion over the 2018 ~~authorized~~adopted rate base of $3.71 billion. ~~These~~The Utility’s request is based on capital expenditure forecasts of $829 million for 2019, $872 million for 2020, and $830 million for 2021 (which exclude common capital allocations). The requested 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. The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be ~~authorized~~approved 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 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 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 requested increase in revenue requirement is largely attributable to increased infrastructure investment and costs related to new natural gas storage safety and environmental regulations issued by DOGGR, the Pipeline and Hazardous Materials Safety Administration, and the CPUC.

~~As a result of the Tax Act, on March 30, 2018, the Utility submitted updated testimony~~In response to the ~~CPUC. The updated testimony, including~~Utility’s application, parties proposed various forecast reductions. For example, the private letter ruling advice letter, reduces the Utility's previously forecasted revenue requirement by $25 million for 2019, $30 million for 2020, $22 million for 2021, and $5 million for 2022, and increases rate base by $188 million for 2019, $254 million for 2020, $378 million for 2021, and $469 million for 2022.

~~In testimony submitted to the CPUC on June 29, 2018, Cal PA~~PAO recommended a 2019 revenue requirement of $1.35 billion, an increase of $45 million over 2018 adopted amounts. ~~All other parties filed testimony on July 20, 2018.~~ TURN proposed widespread reductions in forecast costs and recommended capital and expense disallowances of more than $500 million associated with either work completed at a cost greater than adopted in the 2015 GT&S rate case or work that was approved in the 2015 GT&S rate case and is being requested again in the 2019 GT&S rate case. One other party, Indicated Shippers, made proposals for significant capital and expense reductions in the forecast related to transmission pipe and storage.million.

~~Evidentiary hearings concluded on October 12, 2018. The Utility will file opening briefs on November 14, 2018 and reply briefs on December 14, 2018.~~ A ~~later~~second phase of the proceeding ~~will address the reasonableness of certain recorded capital expenditures associated with Line 407, as required by the 2015 GT&S rate case decision. The later phase will also address~~addressed the removal of officer compensation costs from the revenue requirement, which is required by ~~the passage of~~ SB 901. ~~(See “Legislative~~On March 1, 2019, the Utility, PAO and ~~Regulatory Initiatives” below.)~~TURN submitted a joint stipulation to the CPUC proposing to reduce the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $455,000 for total operating expenses and capital expenditures of $617 million and $829 million, respectively. The Utility is unable to predict the timing and outcome of this proceeding.

For more information, see the ~~2017~~2018 Form 10-K.

Transmission Owner Rate Cases

Transmission Owner Rate Cases for 2015 and 2016 (the “TO16” and “TO17” rate cases, respectively)

On January 8, 2018, the Ninth Circuit Court of Appeals issued an opinion granting an appeal of FERC’s decisions in the TO16 and TO17 rate cases that had granted the Utility a 50 basis point ROE incentive adder for its continued participation in the CAISO. Those rate case decisions have been remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion. If FERC concludes on remand that the Utility should no longer be authorized to receive the 50 basis point ROE incentive adder, the Utility would incur a refund obligation of $1 million and $8.5 million for TO16 and TO17, respectively. Alternatively, if FERC again concludes that the Utility should receive the 50 basis point ROE incentive adder and provides the additional explanation that the Ninth Circuit found the FERC’s prior decisions lacked, then the Utility would not owe any refunds for this issue for TO16 or TO17.

On February 28, 2018, the Utility filed a motion to establish procedures on remand requesting a hearing and additional briefing on the issues identified in the Ninth Circuit ~~Court's~~Court’s opinion. On August 20, 2018, FERC issued an order granting the ~~Utility's~~Utility’s motion to allow for additional briefing. The order also consolidated the TO18 rate case with TO16 and TO17 for this issue. The Utility filed briefs on September 19, 2018 and reply briefs on October 10, 2018. The Utility is unable to predict the timing and outcome of FERC’s decision.

Transmission Owner Rate Case for 2017 (the “TO18” rate case)

On July 29, 2016, the Utility filed its TO18 rate case at the FERC requesting a 2017 retail electric transmission revenue requirement of $1.72 billion, a $387 million increase over the 2016 revenue requirement of $1.33 billion. The forecasted network transmission rate base for 2017 was $6.7 billion. The Utility is seeking a return on equity of 10.9%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted that it would make investments of $1.30 billion in 2017 in various capital projects.

On September 30, 2016, the FERC issued an order accepting the Utility’s July 2016 filing and set it for hearing, but held the hearing procedures in abeyance for settlement procedures. The order set an effective date for rates of March 1, 2017, and made the rates subject to refund following resolution of the case. On March 17, 2017, the FERC issued an order terminating the settlement procedures due to an impasse in the settlement negotiations reported by the parties. During the hearings held in January 2018, the Utility, intervenors, and the FERC trial staff, addressed questions relating to return on equity, capital structure, depreciation rates, capital additions, rate base, operating and maintenance expense, administrative and general expense, and the allocation of common, general and intangible costs.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing an ROE of 9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.96% compared to the Utility’s request of 3.25%. The ALJ also rejected the Utility's method of allocating common plant between CPUC and FERC jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility's rate base and revenue requirement. The Utility and intervenors filed initial briefs on October 31, 2018, in response to the ALJ's recommendations. The Utility expects FERC to issue a final decision in mid-2019.

Additionally, on March 31, 2017, intervenors in the TO18 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO18 rate case. On November 16, 2017, the FERC dismissed the complaint. On December 18, 2017, the complainants filed a request for a rehearing of that order, which the FERC denied on May 17, 2018.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case proposing a ROE of 9.13% compared to the Utility’s request of 10.90%, and an estimated composite depreciation rate of 2.83% compared to the Utility’s request of 3.25%. The ALJ also rejected the Utility’s method of allocating common plant between CPUC and FERC jurisdiction. In addition, the ALJ proposed to reduce forecasted capital and expense spending to actual costs incurred for the rate case period. Further, the ALJ proposed to remove certain items from the Utility’s rate base and revenue requirement. The Utility and intervenors filed initial briefs on October 31, 2018, and reply briefs on November 20, 2018, in response to the ALJ’s recommendations. The Utility expects FERC to issue a decision in mid-2019, but expects one or more parties to seek rehearing of that decision and then appeal it to the courts. The Utility is unable to predict the timing of when a final decision will be issued.

Transmission Owner Rate Case for 2018 (the “TO19” rate case)

On July 27, 2017, the Utility filed its TO19 rate case at the FERC requesting a 2018 retail electric transmission revenue requirement of $1.79 billion, a $74 million increase over the proposed 2017 revenue requirement of $1.72 billion. The forecasted network transmission rate base for 2018 is $6.9 billion. The Utility is seeking an ROE of 10.75%, which includes an incentive component of 50 basis points for the Utility’s continuing participation in the CAISO. In the filing, the Utility forecasted capital expenditures of approximately $1.4 billion. On September 28, 2017, the FERC issued an order accepting the Utility’s July 2017 filing, subject to hearing and refund, and established March 1, 2018, as the effective date for rate changes. FERC also ordered that the hearings be held in abeyance pending settlement discussion among the parties. On May 14, 2018, the Utility filed a proposal to reflect the impact of the Tax Act on its TO tariff rates effective March 1, 2018, in the resolution of the TO19 rate case. The tax impact reduces the TO19 requested revenue requirement from $1.79 billion to $1.66 billion.

On September 29, 2017, intervenors in the TO19 rate case filed a complaint at the FERC alleging that the Utility failed to justify its proposed rate increase in the TO19 rate case. On October 17, 2017, the Utility requested that the FERC dismiss the complaint. On May 17, 2018, the FERC issued an order setting the complaint for hearing, settlement judge procedures, and consolidation with the TO19 proceeding.

On September 21, 2018, the Utility filed an all-party settlement with FERC in connection with TO19. As part of the settlement,

the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined in the TO18 final decision. Additionally, if FERC determines that the Utility is not entitled to the 50 basis point incentive adder for the ~~Utility's~~Utility’s continued CAISO participation, than the Utility would be obligated to make a refund to customers of approximately $25 million.

~~For more information on~~ On December 20, 2018, FERC issued an order approving the ~~TO rate cases, see the 2017 Form 10-K.~~all-party settlement.

Transmission Owner Rate Case for 2019 (the “TO20” rate case)

On October 1, 2018, the Utility filed its TO20 rate case at FERC requesting approval of a formula rate for the costs associated with the ~~Utility's~~Utility’s electric transmission facilities. On November 30, 2018, the FERC issued an order accepting the Utility’s October 2018 filing, subject to hearings and refund, and established May 1, 2019, as the effective date for rate changes. FERC also ordered that the hearings will be held in abeyance pending settlement discussions among the parties. The Utility is unable to predict the timing and outcome of settlement discussions.

The formula rate ~~would replace~~replaces the ~~"stated rate"~~“stated rate” methodology that the Utility used in its previous TO rate case filings. ~~If approved, the~~The formula rate methodology ~~would~~ still ~~include~~includes an authorized revenue requirement and rate base for a given year, but it ~~would~~ also ~~provide~~provides for an annual update of the following ~~year's~~year’s revenue requirement and rates in accordance with the terms of the FERC-approved formula. Under the formula rate mechanism, transmission revenues, including ~~CWIP,~~Construction Work in Progress, will be updated to the actual cost of service annually. Differences between amounts collected and determined under the formula rate will be either collected from or refunded to customers.

In the filing, the Utility forecasts a 2019 retail electric transmission revenue requirement of $1.96 billion. The proposed amount reflects an approximately 9.5% increase over the as-filed TO19 requested revenue requirement of $1.79 billion (a subsequent reduction to $1.66 billion was identified as a result of the Tax Act). The Utility forecasts that it will make investments of approximately $1.1 billion and $0.7 billion for 2018 and 2019, respectively, for various capital projects to be placed in service before the end of 2019. Including projects to be placed in service beyond 2019, the Utility forecasts total electric transmission capital expenditures of $1.4 billion in 2018 and $1.4 billion in 2019. The ~~Utility's~~Utility’s forecasted rate base for 2019 is approximately $8 billion on a weighted average basis, compared to the ~~Utility's~~Utility’s forecasted rate base of $6.9 billion in 2018. The Utility has requested that FERC approve a 12.5% return on equity (which includes an incentive component of 50 basis points for the ~~Utility's~~Utility’s continuing participation in the CAISO), an increase from the 10.75% (also ~~including~~inclusive of a 50 basis point CAISO incentive adder) requested in its TO19 rate case.

The ~~Utility requested that FERC accept its formula rate filing to become effective~~parties conducted a settlement conference on December 1, 2018, and suspend the use of the new rates until January 1, 2019, to facilitate a calendar year true-up period corresponding to the Utility’s FERC Form 1 reporting. As a result, under the Utility’s formula rate, the rates in effect from TO19 would continue to be used until January 1,March 14 - 15, 2019. ~~FERC may decide to suspend the TO20 rates~~The next settlement conference is scheduled for a longer period of time, up to a maximum of five months from the effective date. If FERC adopts the maximum five-month suspension, TO20 rates would go into effect on May 1, 2019. In the event of a delay in the effective date of TO20 rates, the first true-up mechanism would be applied to the period beginning on the effective date through the end ofJune 13 - 14, 2019.

The ~~Utility cannot predict the timing and outcome of FERC’s response. Following FERC’s acceptance of the Utility’s formula rate request, the~~ Utility expects to file an annual update to its TO tariff on or before December 1 of each year beginning in 2019, for rates and charges to become effective January 1 of the following year, consistent with the formula rate.

~~Diablo Canyon Nuclear Power Plant~~

~~Joint Proposal for Plant Retirement~~

~~On August 11, 2016,~~For more information on the ~~Utility submitted an application to~~TO rate cases, see the CPUC to retire Diablo Canyon at the expiration of its current operating licenses in 2024 and 2025 and replace it with a portfolio of energy efficiency and GHG-free resources. The application implements a joint proposal between the Utility and the Friends of the Earth, Natural Resources Defense Council, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees, and Alliance for Nuclear Responsibility (together, the “Joint Parties”).2018 Form 10-K.

~~On January 11, 2018, the CPUC issued a final decision in the Utility’s proposal to retire Diablo Canyon Unit 1 by 2024 and Unit 2 by 2025. The CPUC also:~~

~~deferred consideration of replacement resources to the CPUC’s Integrated Resource Planning proceeding;~~

~~authorized rate recovery for up to $211.3 million (compared with the $352.1 million requested by the Utility) for an employee retention program;~~

~~authorized rate recovery for an employee retraining program of $11.3 million requested by the Utility;~~

~~rejected rate recovery of the proposed $85 million for the community impacts mitigation program on the grounds that rate recovery for such a program requires legislative authorization;~~

authorized rate recovery of $18.6 million of the total Diablo Canyon license renewal cost of $53 million and rate recovery of cancelled project costs equal to 100% of direct costs incurred prior to June 30, 2016, and 25% of direct costs incurred after June 30, 2016, based on a settlement agreement among the Utility, the Joint Parties, and certain other parties that the Utility filed with the CPUC in May 2017; and

~~approved the amortization of the book value for Diablo Canyon consistent with the Diablo Canyon closure schedule.~~

On March 7, 2018, the Utility submitted a request to the NRC to withdraw its Diablo Canyon license renewal application. On April 16, 2018, the NRC granted the Utility’s request to withdraw its license renewal application.

~~On October 16, 2018, in response to SB 1090, the CPUC issued a proposed decision addressing the key remaining goals of the Diablo Canyon joint proposal agreement, including:~~

~~approving the community impact mitigation settlement of $85 million, originally proposed in the joint settlement agreement;~~

~~deferring implementation to its Integrated Resource Planning to ensure that there is no increase in GHG emissions as a result of the Diablo Canyon retirement; and~~

~~approving full funding of the $352.1 million Diablo Canyon employee retention program, originally proposed in the joint settlement agreement.~~

~~California State Lands Commission Lands Lease~~

On June 28, 2016, the California State Lands Commission approved a new lands lease for the intake and discharge structures at Diablo Canyon to run concurrently with Diablo Canyon’s current operating licenses until Diablo Canyon Unit 2 ceases operations in August 2025. The Utility believes that the approval of the new lease will ensure sufficient time for the Utility to identify and bring online a portfolio of GHG-free replacement resources. The Utility intends to submit a future lease extension request to address the period of time required for plant decommissioning, which under NRC regulations can take as long as 60 years. On August 28, 2016, the World Business Academy filed a writ in the Los Angeles Superior Court asserting that the State Lands Commission committed legal error when it determined that the short-term lease extension for an existing facility was exempt from review under the California Environmental Quality Act, as well as alleging that the State Lands Commission should be required to perform an environmental review of the new lands lease. On July 11, 2017, in Los Angeles Superior Court, the judge dismissed the petition on all grounds, ruling that the State Lands Commission properly determined the short-term lease extension was subject to the existing facilities exemption under the California Environmental Quality Act. The World Business Academy appealed this decision. On June 13, 2018, the California Court of Appeals affirmed the Superior Court ruling. On August 29, 2018, the California Supreme Court denied a petition for review filed by the World Business Academy, rendering the California State Lands Commission's approval of the new lands lease for Diablo Canyon final and non-appealable.

~~Asset Retirement Obligations~~Nuclear Decommissioning Cost Triennial Proceeding

The Utility expects that the decommissioning of Diablo Canyon will take many years after the expiration of its current operating licenses. Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are conducted every three years in conjunction with the NDCTP. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

~~While~~On December 13, 2018, the ~~adopted 2015 NDCTP forecast includes employee severance program estimates, it does not include estimated costs related~~Utility submitted its updated decommissioning cost estimate to ~~employee retention and retraining and development programs, and~~ the San Luis Obispo County community mitigation program, which were approved in the CPUC’s final decision and in SB 1090. The employee retraining program costs will be included in the 2018 NDCTP forecast. The Utility intends to conductCPUC for Diablo Canyon based on a site-specific decommissioning ~~study~~analysis.

On February 14, 2019, the CPUC issued a Scoping Memo authorizing addressing the scope of the NDCTP Proceeding to ~~update~~include reasonableness reviews of the ~~2015 NDCTP forecast~~decommissioning cost estimates, ratemaking proposals, proposed milestone framework, plans to address host community needs, and reasonableness of preforming planning activities pre-shutdown including the proposed rate of recovery of these pre-planning activities addressed in Application 18-07-013.

On March 7, 2019, the CPUC amended the scoping memo to ~~submit~~combine A.18-07-013, which seeks authorization for the ~~study, along~~Utility to establish the Diablo Canyon Decommissioning Memorandum Account to track funding for pre-shutdown decommissioning planning activities with the NDCTP ~~application,~~A.18-12-008. The CPUC approved the Utility to establish an interim mechanism to track decommissioning planning activity expenses in the Diablo Canyon Decommissioning Memorandum Account. Any Memorandum Account recovery of such expenses is subject to the authorization and approval of the CPUC ~~by the end of December 2018.~~which will be determined in this year’s NDCTP Proceeding.

The Utility ~~expects~~seeks to ~~file its 2018 NDCTP application in December 2018. For more information, see "Asset Retirement Obligations" in Note 2~~collect $383.7 million and $3.9 million for the funding of Diablo Canyon tax qualified trust and Humboldt Bay tax qualified trust, respectively, commencing January 1, 2020. Additionally, the ~~Notes~~Utility seeks cost recovery of pre-planning activities commencing January 1, 2020, of $30 million for the 3-year period 2020 to 2022 and a $44 million revenue requirements for the ~~Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.~~2-year period 2023 to 2024; by an annual expense only balancing account.

Wildfire Expense Memorandum Account

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA ~~for the purpose of tracking~~to track specific incremental wildfire liability costs effective as of July 26, 2017. In the WEMA, the Utility can record costs related to wildfires, including: (1) payments to satisfy wildfire claims, including any deductibles, co-insurance and other insurance expense paid by the Utility but excluding costs that have already been forecasted and adopted in the Utility’s GRC; (2) outside legal costs incurred in the defense of wildfire claims; (3) insurance premium costs not in rates; and (4) the cost of financing these amounts. Insurance proceeds, as well as any payments received from third parties, or through FERC authorized rates, will be credited to the WEMA as they are received. The WEMA will not include the Utility’s costs for fire response and infrastructure costs which are tracked in the CEMA. The decision does not grant the Utility rate recovery of any ~~wildfire related~~wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. (See Notes 34 and 910 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

As of March 31, 2019, the Condensed Consolidated Financial Statements include long-term regulatory assets of $111 million, consisting of insurance premium costs that are probable of recovery. Should PG&E Corporation and the Utility conclude in future periods that recovery of insurance premiums in excess of amounts included in authorized revenue requirements is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached.

Catastrophic Event Memorandum Account Applications

The CPUC allows utilities to recover the reasonable, incremental costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities through a CEMA. In 2014, the CPUC directed the Utility to perform additional fire prevention and vegetation management work in response to the severe drought in California. The costs associated with this work are tracked in the CEMA. While the Utility believes such costs are recoverable through CEMA, its CEMA applications are subject to CPUC review and approval. For more information see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

2016 CEMA Application

In 2016, the Utility submitted a request to the CPUC to authorize recovery under the CEMA tariff for a revenue requirement increase of approximately $146 million for recorded capital and expense costs related to the 2015 drought mitigations and emergency response activities for declared disasters that occurred from December 2012 through March 2016. On January 4, 2018, ~~Cal PA,~~PAO, TURN, and the Utility filed an all-party motion with the CPUC seeking approval of an all-party settlement agreement. The settlement agreement proposed that the Utility’s total CEMA revenue requirement request be reduced by $29 million, from $146 million to $117 million. On June 21, 2018, the CPUC approved the settlement agreement authorizing the Utility to recover $117 million in connection with its 2016 CEMA application.

2018 CEMA Application

On March 30, 2018, the Utility submitted to the CPUC its 2018 CEMA application requesting cost recovery of $183 million in connection with seven catastrophic events that included fire and storm declared emergencies from mid-2016 through early 2017, as well as $405 million related to work performed in 2016 and 2017 to cut back or remove dead or dying trees that were exposed to years of drought conditions and bark beetle infestation. ~~Also, the~~The 2018 CEMA application originally sought cost recovery of $555 million on a forecast basis, subject to true-up if actual costs were greater or less than the forecast, for additional tree mortality and fire risk mitigation work anticipated in 2018 and 2019. On October 12, 2018, the Utility notified the CPUC and other parties that $180 million of the forecasted 2018 and 2019 fire risk mitigation costs would be removed from

CEMA and instead pursued in the FHPMA. Upon removal of the $180 million, the ~~Utility's~~Utility’s forecast of costs for 2018 and 2019 sought in the application would be approximately $375 million.

The 2018 CEMA application does not include costs related to the 2015 Butte fire, or the ~~October~~ 2017 Northern California ~~wildfires.~~wildfires, or the 2018 Camp fire.

A prehearing conference was held on July 10, 2018, which covered issues related to schedule, scope of costs, interim rate relief, and the engagement of an independent auditor to review tree mortality mitigation costs. On July 25, 2018, the Utility filed a motion for interim rate relief, to authorize collection in rates beginning January 1, 2019, for $441 million of costs incurred in 2016 and 2017 related to storm and wildfire response and mandated tree mortality work. On August 10, 2018, the CPUC issued a scoping memo and procedural schedule. As directed in the scoping memo, opening and reply briefs on the Utility's request related to recovery of costs on a forecast basis were filed on August 31, 2018, and September 14, 2018, respectively. On November 2, 2018, the assigned ALJ denied the ~~Utility's~~Utility’s July 25, 2018 motion requesting interim rate relief for $441 million, which represents 75% of the costs incurred in 2016 and 2017 related to storms, wildfires and tree mortality response work. Subsequently, on December 4, 2018, the Utility filed a renewed motion for interim rate relief, due to worsening financial conditions. The renewed motion for interim relief sought approximately $588 million, which represents 100% of the total costs incurred in 2016 and 2017 for the activities referenced above. The Utility requested that cost recovery occur over a one-year period, with the amounts collected to be subject to refund based on the authorized amount in the proceeding.

On April 25, 2019, the CPUC adopted a decision granting the Utility’s request for interim rate ~~relief.~~relief but allowing for recovery of $373 million of costs (63% of the total costs incurred in 2016 and 2017), and denying cost recovery on a forecast basis. Costs included in the interim rate relief are subject to audit and refund.

PG&E Corporation and the Utility are unable to predict the timing and outcome of ~~this~~the overall proceeding.

Fire Hazard Prevention Memorandum Account

The CPUC allows utilities to track and record costs associated with ~~the implementation of~~implementing regulations and requirements adopted toprotect the public from potential fire hazards associated with overhead ~~powerline~~power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. The Utility currently is authorized to track such costs in the FHPMA through the end of 2019. During ~~the nine months ended September 30,~~ 2018, the Utility ~~has~~ recorded ~~$76~~$262 million of costs to the FHPMA, corresponding to vegetation management work performed to comply with CPUC December 2017 fire safety regulations. While the Utility believes such costs are recoverable, rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC. ~~(See Note 3~~

Fire Risk Mitigation Memorandum Account

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred as of January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was set forth in SB 901 to capture costs incurred in advance of the ~~Notes~~CPUC’s approval of the Utility’s Wildfire Safety Plan. The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Safety Plan to record costs of wildfire mitigation activities identified after such approval. As of March 31, 2019, the ~~Condensed Consolidated Financial Statements~~Utility incurred $55 million of costs to FRMMA. The Utility will seek recovery of the FRMMA balance in ~~Item 1.)~~a future application.

Other Regulatory Proceedings

2019 Wildfire Safety Program

On October 25, 2018, the CPUC opened an OIR to implement the provisions of SB 901 related to electric utility wildfire mitigation plans. This OIR provided guidance on the form and content of the initial wildfire mitigation plans, provided a venue for review of the initial plans, and developed and refined the content of and process for review and implementation of wildfire mitigation plans to be filed in future years. In this proceeding the CPUC will consider, among other things, how to interpret and apply SB 901’s list of required plan elements, as well as whether additional elements beyond those required in SB 901 should be included in the wildfire mitigation plans. SB 901 also requires, among other things, that such plans include a description of the preventive strategies and programs to be adopted by an electrical corporation to minimize the risk of its electrical lines and equipment causing catastrophic wildfires, including the consideration of dynamic climate change risks, plans for vegetation management, and plans for inspections of the electrical corporation’s electrical infrastructure. The scope of this proceeding does not include utility recovery of costs related to wildfire mitigation plans, which SB 901 requires to be addressed in separate rate recovery applications.

On February 6, 2019, the Utility filed its wildfire mitigation plan (the “2019 Wildfire Safety Plan”) with the CPUC. The 2019 Wildfire Safety Plan also describes forecasted work and investments in 2019 that are designed to help further reduce the potential for wildfire ignitions associated with the Utility’s electrical equipment in high fire-threat areas. The 2019 Wildfire Safety Plan specifically addresses wildfire risk factors that occur most frequently and have potential to start or spread a fire. The 2019 Wildfire Safety Plan focuses on the measures of the Utility proposes to take in 2019, but includes longer-term plans, while acknowledging that the Utility may modify these plans based upon new information or conditions as the Utility implements these measures. The new and ongoing safety measures being pursued include:

Installing nearly 600 new, high-definition cameras, made available to Cal Fire and local fire officials, in high fire-threat areas by 2022, increasing coverage across high fire-threat areas to more than 90%;

Adding approximately 1,300 additional new weather stations by 2022, at a density of one station roughly every 20 circuit miles in high fire-threat areas;

Conducting enhanced safety inspections of electric infrastructure in high-fire threat areas, including approximately 735,000 electric towers and poles across approximately 5,700 transmission line miles and 25,200 distribution line miles;

Further enhancing vegetation management efforts across high and extreme fire-threat areas to address vegetation that poses higher potential for wildfire risk, such as removing or trimming trees from particular “at-risk” tree species that have exhibited a higher pattern of failing;

Continuing to disable automatic reclosing in high fire-threat areas during wildfire season and periods of high fire-risk and upgrading reclosers and circuit breakers in high fire-threat areas with remote control capabilities;

Expanding the Public Safety Power Shutoff Program (PSPS) to include all transmission and distribution lines in Tier 2 and Tier 3 High Fire Threat District (HFTD) areas;

Installing stronger and more resilient poles and covered power lines, including targeted undergrounding, starting in areas with the highest fire risk, ultimately upgrading and strengthening approximately 7,100 miles over the next 10 years; and

Partnering with additional communities in high fire-threat areas to create new resilience zones that can power central community resources during a Public Safety Power Shutoff.

On February 12, February 14, and April 25, 2019, the Utility filed amendments to the 2019 Wildfire Safety Plan with the CPUC to correct inadvertent errors in the cost table attached to the 2019 Wildfire Safety Plan; refine language in the 2019 Wildfire Safety Plan; and modify certain 2019 Wildfire Safety Plan targets in light of external conditions, enhance other targets based on early learnings, and clarify targets to minimize the potential for misinterpretation, respectively. On April 29, 2019, the ALJs issued two PDs applicable to the Utility: one PD addressing all wildfire mitigation plans filed by California electric utilities and one PD specific to the Utility. These two PDs ordered that, among other things, the Utility submit Advice Letters within 6 and 12 months of the effective date of PD describing concerns with the effectiveness of the Wildfire Safety Plan and submit an Advice Letter on July 30, 2019 proposing “metrics that assess whether the Wildfire Mitigation Plan is having or will have the desired result - a reduction in catastrophic wildfire”. The Utility specific PD refused to consider the Utility’s proposed April 25 amendments. As a condition of probation, the Utility must fully comply with the specific targets and metrics set forth in the wildfire safety plan ultimately approved by the CPUC. (see “U.S. District Court Matters and Probation” in Part II, Item 1. Legal Proceedings for more information).

The CPUC is expected to issue a decision in the second quarter of 2019. PG&E Corporation and the Utility are unable to predict the timing and outcome of this proceeding. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected if the Utility is unable to timely recover costs in connection with the 2019 Wildfire Safety Plan recorded in a memorandum account, which the Utility expects will be substantial.

OIR to Implement Public Utilities Code Section 451.2 Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a customer harm threshold, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service (the “Customer Harm Threshold”). SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code. In the OIR, the CPUC stated that “consistent with Section 451.2(a), the determination of what costs and expenses are just and reasonable must be made in the context of an application for the recovery of specific costs related to the 2017 wildfires.” Based on the CPUC’s interpretation of Section 451.2 as outlined in the OIR, PG&E Corporation and the Utility believe that any securitization of costs relating to the 2017 Northern California wildfires would not occur, if at all, until (a) the Utility has paid claims relating to the 2017 Northern California wildfires, (b) the Utility has filed an application for recovery of such costs, and (c) the CPUC makes a determination that such costs are just and reasonable or in excess of the Customer Harm Threshold. PG&E Corporation and the Utility therefore do not expect the CPUC to permit the Utility to securitize costs relating to the 2017 Northern California wildfires on an expedited or emergency basis. Based on the OIR, as well as prior experience and precedent, and unless the CPUC alters the position expressed in the OIR, PG&E Corporation and the Utility believe it likely would take several years to obtain authorization to securitize any amounts relating to the 2017 Northern California wildfires.

On February 11, 2019, the Utility filed opening comments in response to the OIR in which it argued, among other things, the CPUC should (1) promptly set a Customer Harm Threshold, or at least define the methodology for setting the Customer Harm Threshold with sufficient specificity to enable PG&E Corporation and the Utility and potential investors to anticipate that amount; (2) determine the Customer Harm Threshold based on the capital needed to resolve claims arising from both the 2018 Camp fire and 2017 Northern California wildfires to be provided for in a plan of reorganization; (3) define how the Customer Harm Threshold will be applied to any future wildfires; and (4) establish the Customer Harm Threshold based on the amount of debt the Utility can raise. Based on assumptions set forth in the comments, the Utility indicated that it could borrow up to approximately $3 billion to fund wildfire claims costs as part of a plan of reorganization.

On February 25, 2019, the Utility filed reply comments in response to the OIR and the opening comments of other parties, in which it urged the CPUC to clarify the regulatory construct pertaining to recovery of wildfire costs in order to mitigate the deepening crisis affecting utilities, their customers, their employees, and the State’s economy and clean energy goals. The Utility again asked the CPUC to adopt a predictable financial methodology applicable to costs arising from wildfires in 2017, 2018, and future years; and also asked the CPUC to refine prospective cost recovery standards to provide that a utility is deemed prudent if it substantially complies with its wildfire mitigation plan.

On March 29, 2019, the Assigned Commissioner issued a Scoping Memo, which stated that the CPUC in this proceeding will establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and will not determine a specific financial outcome in this proceeding.

On April 5, 2019, the Assigned Commissioner published a Staff Report, describing a proposed stress test to determine the Customer Harm Threshold based on: (1) the maximum additional debt that a utility can take on and maintain a minimum investment-grade credit rating; (2) excess cash available to the utility; and (3) a potential regulatory adjustment upward or downward by a maximum of 20%, to be determined by the CPUC. The Staff Report also proposed two “optional concepts” for ratepayer protection: (1) a de-escalation of the utility’s authorized return on equity based on the amount of customer costs in excess of the Customer Harm Threshold, capped at 300 basis points, and (2) equity warrants in favor of customers in the amount of 1% for every $500 million of securitized wildfire liability, capped at 15%. On April 10, 2019, a workshop addressing the Staff Report was held. On April 12, 2019, the Assigned Commissioner extended the time for parties to file comments on the Staff Report, to April 24, 2019 for opening comments and May 1, 2019 for reply comments.

Transportation Electrification

California ~~Law (SB 350)~~law SB 350 requires the CPUC, in consultation with the California Air Resources Board and the CEC, to direct electrical corporations to file applications for programs and investments to accelerate widespread TE. In September 2016, the CPUC directed the Utility and the other large IOUs to file TE applications that include both short-term projects (of up to $20 million in total) and ~~two- to five-year~~two-to-five year programs with a requested revenue requirement determined by the Utility.

On January 20, 2017, the Utility filed its TE application with the CPUC requesting program funding over five years (2018-2022) related to make-ready infrastructure for TE in medium to heavy-duty vehicle sectors, fast charging stations, and short-term projects that includes a series of TE demonstration projects and pilot programs.

~~On January 11, 2018, the CPUC approved, with modifications, four of the five short-term projects proposed by the Utility for a total of approximately $8 million.~~

On May 31, 2018, the CPUC issued a final decision approving the Utility’s ~~standard review~~two-to-five year program proposals for actual expenditures up to approximately $269 million (including $198 million of capital expenditures), to support utility-owned make-ready infrastructure supporting public fast charging and medium to heavy-duty fleets. In the ~~FleetReady~~EV Fleet program, the Utility has a goal of providing ~~utility-owned~~ make-ready infrastructure at 700 sites supporting 6,500 vehicles, conducting operation and maintenance of installed infrastructure, and educating customers on the benefits of electric vehicles. The final decision gives customers the option of self-funding, installing, owning, and maintaining the make-ready infrastructure installed beyond the customer meter in lieu of utility ownership, after which they would receive a utility rebate for a portion of those costs. The EV Fast Charge program has a goal to install utility-owned make-ready infrastructure at approximately 52 public charging sites amounting to roughly 234 DC fast chargers.

On December 19, 2018, the CPUC initiated a new Rulemaking for vehicle electrification matters (R.18-12-006). This new proceeding will include issues related to utility rate designs supporting transportation electrification and hydrogen fueling stations, a framework for IOUs’ transportation electrification investments, and vehicle-grid integration. A pre-hearing conference for this rulemaking was held on March 1, 2019, and a scoping memo will be issued following that conference.

Electric Distribution Resources Plan

As required by California law, on July 1, 2015, the Utility filed its proposed electric ~~distribution resources plan~~DRP for approval by the CPUC. The Utility’s ~~plan~~DRP identifies its approach for identifying optimal locations on its electric distribution system for deployment of DERs. The Utility’s ~~proposal~~DRP approach is designed to allow distributed energy technologies to be integrated into the larger grid while continuing to provide customers with safe, reliable, and affordable electric service.

~~The CPUC issued a decision~~As part of the Utility’s DRP approach, on ~~February 15,~~June 1, 2018, ~~requiring~~ the California IOUs to use the CEC’s DER forecast for the 2018-2019 distribution planning cycle. The decision also requires the IOUs to develop an alternative planning forecast scenario in 2018 to better inform DER sourcing policies by establishing a method for calculating costs and benefits for DER grid integration. Historically, the Utility has planned using the CEC forecast and will have the opportunity to adjust forecasts for EV, photovoltaic, and energy storage, if needed during the planning cycle.

The CPUC's decision also requires the Utility to develop and submit annually a grid needs assessment and distribution deferral opportunity report to identify proposed electric distribution investments that could be deferred by deploying DERs. The decision also extends the 4% pre-tax regulatory incentive mechanism, being piloted in the Integrated Distributed Energy Resources (IDER) proceeding, to all DER distribution deferral projects. The Utility filed its first annual distribution grid needs assessment report with the CPUC, and on ~~June 1,~~September 4, 2018, ~~and~~the Utility filed its first distribution deferral opportunity report. The distribution deferral report ~~on September 4, 2018.~~proposes cost effective electric distribution investments that can be deferred through deployment of dispatchable third-party-owned DERs, or non-wire alternative solutions, to operate during specific grid events. The Utility ~~has~~ convened a distribution planning advisory group comprised of CPUC staff, ratepayer and environmental advocates, and DER market participants, ~~and Utility staff,~~ to review and provide advisory input to the ~~Utility's grid needs assessment,~~Utility on its distribution deferral ~~opportunity report,~~identification process and ~~potential~~to identify distribution deferral ~~locations where DER solutions or non-wire alternatives can be considered~~opportunities. After incorporating the advisory group’s input, on November 28, 2018, the Utility filed a proposal with the CPUC for competitively procuring distribution services from third-party owned DERs to defer selected distribution projects. Following the CPUC’s approval of the Utility’s procurement plan on February 5, 2019, the Utility launched a competitive ~~solicitations.~~solicitation and is currently evaluating offers.

On March 26, 2018, the CPUC issued a final decision requiring the Utility to include a grid modernization plan for integrating DERs in the ~~Utility's GRC to address distribution system upgrades required to deploy DERs.~~Utility’s GRC. The grid modernization plan for DERs must include a narrative 10-year vision for investments needed to support DER growth, while ensuring safety and ~~reliability, and a status update of previously funded DER-related grid modernization GRC projects.~~service reliability. On June 25, 2018, the Utility hosted a public grid modernization workshop for integrating DERs to provide a high-level overview of its ~~grid integration platform~~vision and 10-year ~~plan. The~~plan and incorporate stakeholder input. On December 13, 2018, the Utility ~~is required to submit a grid modernization plan with each GRC application starting with~~filed its 2020 GRC ~~application.~~

~~LEGISLATIVE AND REGULATORY INITIATIVES~~

~~Senate Bill 901~~

~~On September 21, 2018, California's governor signed legislation to strengthen California's ability to prevent~~Application, which includes the Utility’s grid modernization vision and ~~recover from catastrophic wildfires, including SB 901. Some of the significant highlights of SB 901 include:~~

~~imposing more restrictive forest management practices and providing support and incentives to facilitate that work;~~

~~providing factors that the CPUC should consider when it conducts a review of the reasonableness of costs and expenses arising from a catastrophic wildfire occurring on or after January 1, 2019;~~

in applications for cost recovery in connection with the 2017 wildfires, directing the CPUC to consider the electric corporation's financial status and determine the maximum amount a utility can pay without harming customers or materially impacting its ability to provide adequate and safe service, and ensuring that the costs or expenses that are disallowed for recovery in rates assessed for the wildfires, in the aggregate, do not exceed that amount;

authorizing the CPUC to issue a financing order that permits recovery, through issuance of recovery bonds (securitization), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 wildfires, any amounts in excess of the maximum disallowance (see above). Securitization is available, for prudently incurred costs, for the 2017 wildfires and catastrophic wildfires occurring on or after January 1, 2019;

~~requiring electric corporations to prepare and submit to the CPUC a wildfire mitigation~~ plan. Among other things, the plan will include a description of the preventive strategies and programs of electric corporations that are designed to minimize the risk of their electrical lines and equipment causing catastrophic wildfires and protocols related to plan activities. Failure to substantially comply with such plan will result in penalties. The CPUC will consider whether the cost of implementing the plan is just and reasonable in each electric corporation's GRC;

establishing a Commission on Catastrophic Wildfire Cost and Recovery to evaluate wildfire reforms, including inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures; and

~~prohibiting an electric or gas corporation from recovering expenses for any annual salary, bonus, benefits, or other consideration of any value, paid to an officer of such utility from customers.~~

On October 25, 2018, the CPUC opened an OIR to implement the wildfire mitigation plan provisions in SB 901. This OIR will only focus on the wildfire mitigation plan of SB 901 implementation, and will not address utility cost recovery. Cost recovery associated with SB 901 wildfire mitigation plans will be addressed in utilities' GRCs.

~~Power Charge Indifference Adjustment~~

On October 11, 2018, the CPUC approved a decision to modify the PCIA methodology, which adjusts how customers that leave PG&E's bundled service for CCA or Direct Access service, pay for their share of the costs associated with long-term power purchase commitments made on their behalf. The decision better enables utilities to recover their above market costs from departing customers as compared to the current methodology, by:

~~adopting benchmark values used to set the PCIA rate that more closely resemble actual market prices for resource adequacy and renewable energy credits;~~

~~allowing legacy utility-owned generation costs to be recovered from CCA customers;~~

~~eliminating the 10-year limit on PCIA cost recovery for post-2002 utility owned generation and certain storage costs; and~~

adding an annual true-up to the PCIA rate based on market sales for brown power, with further discussion in phase 2 of the PCIA proceeding regarding true-up of resource adequacy, and renewable energy credits.

CCA and DA customers will pay a revised PCIA rate starting January 1, 2019. The CPUC also ordered a phase 2 of the PCIA proceeding to develop structures, processes, and rules to govern utility portfolio optimization and management in the future.

OIR to Consider Strategies and Guidance for Climate Change Adaptation

On April 26, 2018, the CPUC opened an OIR to consider strategies for integrating climate change adaptation matters into relevant CPUC proceedings. Phase one will focus on how to integrate climate change adaptation into the IOUs’ existing planning and operations to ensure utility safety and reliability.

The CPUC OIR will consider:

how to define climate change adaption for the IOUs;

the climate-driven risks facing the IOUs;

data, tools, resources, and guidance to instruct utilities on how to incorporate adaption in their existing planning and operational processes; and

strategies to address climate change in CPUC proceedings, including impacts on disadvantaged communities.

On October 10, 2018, the CPUC issued a scoping memo and established a procedural ~~schedule for IOUs.~~schedule. A final decision is expected ~~to be issued~~ in late 2019.

~~For information~~

LEGISLATIVE AND REGULATORY INITIATIVES

Senate Bill 901

SB 901, signed into law on September 21, 2018, requires the CPUC to establish a Customer Harm Threshold (as defined herein), directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the Customer Harm Threshold. SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs.

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code for cost recovery of 2017 wildfire costs. In the OIR, the CPUC stated that “consistent with Section 451.2(a), the determination of what costs and expenses are just and reasonable must be made in the context of an application for the recovery of specific costs related to the ~~Utility's~~2017 wildfires.” Based on the CPUC’s interpretation of Section 451.2 as outlined in the OIR, PG&E Corporation and the Utility believe that any securitization of costs relating to the 2017 Northern California wildfires would not occur, if at all, until (a) the Utility has paid claims relating to the 2017 Northern California wildfires, (b) the Utility has filed application for recovery of such costs, and (c) the CPUC makes a determination that such costs are just and reasonable or in excess of the Customer Harm Threshold. PG&E Corporation and the Utility therefore do not expect the CPUC to permit the Utility to securitize costs relating to the 2017 Northern California wildfires on an expedited or emergency basis. Based on the OIR, as well as prior experience and precedent, and unless the CPUC alters the position expressed in the OIR, PG&E Corporation and the Utility believe it likely would take several years to obtain authorization to securitize any amounts relating to the 2017 Northern California wildfires.

On February 11, 2019, and February 25, 2019, the Utility filed opening and reply comments, respectively, in response to the OIR. On March 29, 2019, the Assigned Commissioner issued a Scoping Memo, which stated that the CPUC in this proceeding will establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and will not determine a specific financial outcome at this time. (See “Regulatory Matters - OIR to Implement Public Utilities Code Section 451.2 Regarding Criteria and Methodology for Wildfire Cost Recovery Pursuant to Senate Bill 901” above.)

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC. The wildfire mitigation plan must include the components specified in SB 901, such as identification and prioritization of wildfire risks, and drivers for those risks; plans for vegetation management; actions to harden the system, prepare for, and respond to events; and protocols for disabling reclosers and deenergizing the system. The CPUC has three months to approve a utility’s plan, with the ability to extend the deadline. The CPUC will conduct an annual compliance review, which will be supported by an independent evaluator’s report. The CPUC will complete the compliance review within 18 months. SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan. Costs associated with the wildfire mitigation plan are tracked in a memorandum account, and the costs of implementing the plan will be assessed in each utility’s GRC proceeding, or other application proceedings. The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities.

Finally, SB 901 established a Commission on Catastrophic Wildfire Cost and Recovery to evaluate wildfire reforms, including inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures. The commission, which is composed of five members, is holding multiple meetings throughout the state to accept public and expert testimony and develop recommendations. SB 901 directs the commission, in consultation with the CPUC and California Insurance Commissioner, to prepare a report on or before July 1, 2019, that contains an assessment of issues surrounding catastrophic wildfire costs and damages and makes recommendations for changes to the law. The recommendations of the commission and the response by the Governor and legislature to those recommendations could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Power Charge Indifference Adjustment OIR

On October 11, 2018, the CPUC approved a decision to modify the PCIA methodology, which was developed after the 2001 California energy crisis, which adjusts how customers that leave the Utility’s bundled service for CCA or DA service, pay for their share of the costs associated with long-term power purchase commitments made on their behalf. The decision better enables utilities to recover their above market costs from departing customers as compared to the previous methodology, by:

adopting benchmark values used to set the PCIA rate that more closely resemble actual market prices for resource adequacy and renewable energy credits;

continuing to allow legacy utility-owned generation costs to be recovered from CCA customers;

eliminating the 10-year limit on PCIA cost recovery for post-2002 utility owned generation and certain storage costs; and

adding an annual true-up to the PCIA rate based on market sales.

The Utility anticipates the revised PCIA rate to go into effect as of July 1, 2019.

On December 19, 2018, a prehearing conference was held to initiate phase two of the PCIA proceeding, to further develop proposals for future consideration by the CPUC. On February 1, 2019, the assigned commissioner issued a phase two scoping memo and ruling, which sets forth the category, issues, need for hearing, schedule, and other matters. As indicated in the scoping memo and ruling, phase two of this proceeding will primarily rely upon a working group process to further develop a number of PCIA-related proposals for consideration by the CPUC, which include benchmark true-up for brown power resource adequacy and renewable energy credits, rate design mechanics, portfolio optimization and cost reduction, allocation and auctions, whether the CPUC should consider new or modified shareholder responsibility for future portfolio mismanagement, if any, and CCA and DA prepayment options. The schedule included in the scoping memo and ruling indicates that the CPUC is expected to issue decisions on several topics covered by this OIR starting in late 2019 and extending through 2020.

Strike Force Report

On February 12, 2019, California Governor Gavin Newsom created a “Strike Force” to coordinate the state’s efforts relating to the safety, reliability and affordability of energy and directed the Strike Force to develop a roadmap to address the issues of wildfire, climate change ~~resiliency strategies see Item 1~~and the state’s energy sector. On April 12, 2019, the Strike Force publicly issued a report setting out potential steps the state could take to reduce the incidence and severity of wildfires and outlining “actions to hold the state’s utilities accountable for their behavior and potential changes to stabilize California’s utilities to meet the energy needs of customers and the economy.” The Strike Force Report identified three potential concepts for addressing how to allocate the costs resulting from wildfires among stakeholders:

“A liquidity-only fundthat would provide liquidity for utilities to pay wildfire damage claims pending CPUC determination of cost recovery potentially coupled with modification of cost recovery standards.

“Adopting a fault-based standardthat would modify California’s strict liability standard to one based on fault to balance the need for public improvements with private harm to individuals.

“Creation of a catastrophic wildfire fundcoupled with a revised cost recovery standard to spread the cost of catastrophic wildfires more broadly among stakeholders.”

The Strike Force Report did not include a specific recommendation among the three identified concepts. Later on April 12, 2019, Governor Newsom stated that his goal would be to have legislation passed including at least some of the report’s recommendations before the legislative recess on July 12, 2019. The Strike Force Report also included a number of recommendations regarding PG&E Corporation and the Utility, including among others, that their investors should be required to “contribute to any solution adopted by the state to address wildfire liabilities in a way that benefits customers” and that the ~~2017 Form 10-K.~~Utility should be “fully remaking its corporate and safety culture.”

Due to uncertainty regarding the specific policy actions that may be taken as a result of the Strike Force Report, including the three concepts outlined above, the impact and timing of the report and any resulting policy actions on PG&E Corporation and the Utility cannot be determined at this time. However, the impact and timing of such actions on PG&E Corporation’s and the Utility’s future financial condition, results of operations, liquidity, and cash flows could be significant.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous wastes; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. (See Note 911 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q, as well as “Item 1A. Risk Factors” and Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.)

CONTRACTUAL COMMITMENTS

PG&E Corporation and the Utility enter into contractual commitments in connection with future obligations that relate to purchases of electricity and natural gas for customers, purchases of transportation capacity, purchases of renewable energy, and purchases of fuel and transportation to support the Utility’s generation activities. (See “Purchase Commitments” in Note 911 of the Notes to the Condensed Consolidated Financial Statements in Item 1). Contractual commitments that relate to financing arrangements include long-term debt, preferred stock, and certain forms of regulatory financing. For more in-depth discussion about PG&E Corporation’s and the Utility’s contractual commitments, see “Liquidity and Financial Resources” above and MD&A ~~"Contractual Commitments"~~“Contractual Commitments” in Item 7 of the ~~2017~~2018 Form 10-K.

Off-Balance Sheet Arrangements

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed in Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K (the Utility’s commodity purchase agreements).

RISK MANAGEMENT ACTIVITIES

PG&E Corporation, mainly through its ownership of the Utility, and the Utility are exposed to risks associated with adverse changes in commodity prices, interest rates, and counterparty credit.

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 risk mitigation purposes and not for speculative purposes. The Utility’s risk management activities include the use of physical and financial instruments such as forward contracts, futures, swaps, options, and other instruments and agreements, most of which are accounted for as derivative instruments. Some contracts are accounted for as leases. The Utility manages credit risk associated with its counterparties by assigning credit limits based on evaluations of their financial conditions, net worth, credit ratings, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored periodically. These activities are discussed in detail in the ~~2017~~2018 Form 10-K. There were no significant developments to the Utility’s and PG&E Corporation’s risk management activities during the ~~nine~~three months ended ~~September 30, 2018.~~March 31, 2019.

RECENT DEVELOPMENTS

New Chief Executive Officer and Board Members

On April 3, 2019, PG&E Corporation announced the appointment of 10 new directors to the Board of Directors of PG&E Corporation, with seven of the 10 then-incumbent directors stepping down, to be effective later that month. On April 22, 2019, Richard C. Kelly resigned from the Boards of PG&E Corporation and the Utility. Also, PG&E Corporation entered into a Settlement Agreement (the “Settlement Agreement”) with Blue Mountain Credit Alternatives Master Fund L.P. (together with its affiliates, “BlueMountain”), who had previously nominated candidates for election to PG&E Corporation’s Board of Directors. In connection with the execution and delivery of the Settlement Agreement, among other things, Frederick W. Buckman was appointed to the Boards of Directors of PG&E Corporation and the Utility and BlueMountain withdrew its nominations. The full text of the Settlement Agreement with BlueMountain is attached as an exhibit to PG&E Corporation’s Current Report on Form 8-K filed with the SEC on April 23, 2019. As of May 2, 2019, the Boards of Directors of PG&E Corporation and the Utility were each constituted with the following individuals: Richard R. Barrera, Jeffrey L. Bleich, Nora Mead Brownell, Frederick W. Buckman, Cheryl F. Campbell, Fred J. Fowler, William D. Johnson (Utility Board only), Michael J. Leffell, Kenneth Liang, Dominique Mielle, Meridee A. Moore, Eric D. Mullins, Kristine M. Schmidt and Alejandro D. Wolff.

In addition, William D. Johnson has joined PG&E Corporation as its new Chief Executive Officer and President, effective May 2, 2019. In connection with the Settlement Agreement, PG&E Corporation has agreed to engage Christopher A. Hart, a former chairman of the National Transportation Safety Board, to provide consulting services to Mr. Johnson regarding matters of safety.

PG&E Corporation and the Utility expect that these leadership changes will have a significant impact on their operations and financial performance in the future.

Proposed Wildfire Assistance Fund

On May 1, 2019, PG&E Corporation and the Utility filed a motion with the Bankruptcy Court seeking authorization to establish and fund a program (the “Wildfire Assistance Fund”) to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs. The Wildfire Assistance Fund is intended to aid certain wildfire claimants who are either uninsured or still in need of assistance for temporary housing expenses or other urgent needs. The Wildfire Assistance Fund would consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator, who will disburse and administer the funds. The administrator would be responsible for developing the specific eligibility requirements and application procedures for the distribution of the Wildfire Assistance Fund to eligible claimants. Up to $5 million of the Wildfire Assistance Fund could be used to pay administrative expenses. The filing of this motion is not an acknowledgment or admission by PG&E Corporation or the Utility of liability with respect of the 2018 Camp fire and 2017 Northern California wildfires. The motion is scheduled to be heard in the Bankruptcy Court on May 22, 2019.

CRITICAL ACCOUNTING POLICIES

The preparation of the Condensed Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the Condensed Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. In addition to those items listed below, PG&E Corporation and the Utility consider their accounting policies for regulatory assets and liabilities, loss contingencies associated with environmental remediation liabilities and legal and regulatory matters, AROs, and pension and other post-retirement benefits plans to be critical accounting policies. These policies are considered critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ materially from these estimates. These accounting policies and their key characteristics are discussed in detail in the ~~2017~~2018 Form 10-K.

Liabilities Subject to Compromise

As a result of the Chapter 11 Cases, the payment of pre-petition indebtedness is subject to compromise or other treatment under a plan of reorganization. The determination of how liabilities will ultimately be settled or treated cannot be made until the Bankruptcy Court confirms a Chapter 11 plan of reorganization and such plan becomes effective. Accordingly, the ultimate amount of such liabilities is not determinable at this time. ASC 852 requires pre-petition liabilities that are subject to compromise to be reported at the amounts expected to be allowed, even if they may be settled for lesser amounts. The amounts currently classified as liabilities subject to compromise are preliminary and may be subject to future adjustments depending on the Bankruptcy Court actions, further developments with respect to disputed claims, determinations of the secured status of certain claims, the values of any collateral securing such claims, rejection of executory contracts, continued reconciliation or other events.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See the discussion above in Note 23 of the Notes to the Condensed Consolidated Financial Statements in Item 1.

FORWARD-LOOKING STATEMENTS

This report contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions that are based on current estimates, expectations, and projections about future events and assumptions regarding these events and ~~management's~~management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated losses, including penalties and fines, associated with various investigations and proceedings; forecasts of pipeline-related expenses that the Utility will not recover through rates; forecasts of capital expenditures; estimates and assumptions used in critical accounting policies, including those relating to regulatory assets and liabilities, environmental remediation, litigation, third-party claims, and other liabilities; and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “plan,” “project,” “believe,” “estimate,” “predict,” “anticipate,” “may,” “should,” “would,” “could,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

the risks and uncertainties associated with the Chapter 11 Cases, including, but not limited to, the ability to develop, consummate, and implement a plan of reorganization with respect to PG&E Corporation and the Utility; the ability to develop and obtain applicable Bankruptcy Court, creditor or regulatory approvals; the effect of any alternative proposals, views or objections related to the plan of reorganization; potential complexities that may arise in connection with concurrent proceedings involving the Bankruptcy Court, the U.S. District Court, the CPUC, and the FERC; increased costs related to the Chapter 11 Cases; the ability to obtain sufficient financing sources for ongoing and future operations; disruptions to PG&E Corporation’s and the Utility’s business and operations and the potential impact on regulatory compliance;

restrictions on PG&E Corporation’s and the Utility’s ability to pursue strategic and operational initiatives for the duration of the Chapter 11 Cases;

increased employee attrition as a result of the filing of the Chapter 11 Cases;

PG&E Corporation’s and the Utility’s historical financial information not being indicative of future financial performance as a result of the Chapter 11 Cases;

the potential delay in emergence from bankruptcy if PG&E Corporation and the Utility are not able to develop and consummate a consensual plan of reorganization and are forced to engage in a contested proceeding;

the possibility that the DIP Credit Agreement is not sufficient to fund PG&E Corporation’s and the Utility’s cash requirements through their emergence from bankruptcy;

the possibility that PG&E Corporation and the Utility may not be able to obtain exit financing on favorable terms or at all;

the outcome of the U.S. District Court matters and probation;

the impact of the 2018 Camp fire and the 2017 Northern California wildfires, including whether the Utility will be able to timely recover costs incurred in connection with the ~~Northern California~~ wildfires in excess of the ~~Utility's~~Utility’s currently authorized revenue requirements; the timing and outcome of the remaining wildfire investigations and the extent to which the Utility will have liability associated with these fires; the timing and amount of insurance recoveries; and potential liabilities in connection with fines or penalties that could be imposed on the Utility if the CPUC or any other law enforcement agency were to bring an enforcement action and determined that the Utility failed to comply with applicable laws and regulations;

the timing and outcome of claims arising from the 2015 Butte fire, ~~litigation,~~including claims by the OES; the timing and outcome of any proceeding to recover related costs in excess of insurance through rates; ~~the effect, if~~and whether any ~~that the SED’s $8.3 million citations issued~~regulatory enforcement proceedings in connection with the ~~Butte fire may have on the Butte fire litigation; and whether additional investigations and proceedings in connection with the~~2015 Butte fire will be opened and any additional fines or penalties imposed on the Utility;

the timing and outcome of issuance of recovery bonds (“securitization”) of 2017 Northern California wildfires costs that the CPUC finds just and reasonable;

the timing and outcome of any policy actions resulting from Governor Newsom’s Strike Force Report;

whether PG&E Corporation and the Utility are able to successfully challenge the application of the doctrine of inverse condemnation to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire;

the timing and outcome of future regulatory and legislative developments in connection with SB 901, including the ~~customer harm threshold~~Customer Harm Threshold in connection with the 2017 Northern California wildfires, future wildfire reforms, ~~including~~ inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation ~~measures;~~measures or other reforms targeted at the Utility;

the outcome of the ~~Utility's community wildfire safety program~~Utility’s CWSP that the Utility has developed in coordination with first responders, civic and community leaders, and customers, to help reduce wildfire threats and improve safety as a result of climate-driven wildfires and extreme ~~weather;~~weather, including the Utility’s ability to comply with the targets and metrics set forth in the 2019 Wildfire Safety Plan; and the cost of the program, and the timing and outcome of any proceeding to recover such cost through rates;

whether the ~~amount~~Utility will be able to obtain full recovery of its significantly increased insurance premiums, and the timing of ~~additional common stock and debt issuances by PG&E Corporation, including the dilutive impact of common stock issuances to fund PG&E Corporation's equity contributions to~~any such recovery;

whether the Utility ascan obtain wildfire insurance at a reasonable cost in the ~~Utility incurs charges~~future, or at all, and ~~costs, including fines, that it cannot recover through rates;~~

the timing and outcome of CPUC decision(s) related to the Utility’s March 2018 submissions to the CPUC and May 2018 submission to the FERC in connection with the impact of the Tax Act on the Utility’s rate cases and its implementation plan;whether insurance coverage is adequate for future losses or claims;

the timing and outcomes of the 2019 GT&S rate case, 2020 GRC, FERC TO18, TO19, and TO20 rate cases, 2018 CEMA, future applications for WEMA, FHPMA and FRMMA, future cost of capital proceeding, and other ratemaking and regulatory proceedings;

the outcome of the probation and the monitorship imposed by the federal court after the Utility’s conviction in the federal criminal trial in 2017, the timing and outcomes of the debarment proceeding, potential reliability penalties or sanctions from the North American Electric Reliability Corporation, the SED’s unresolved enforcement matters relating to the Utility’s compliance with natural gas-related laws and regulations, and other investigations that have been or may be commenced relating to the Utility’s compliance with natural gas- and electric- related laws and regulations, ex parte communications, and the ultimate amount of fines, penalties, and remedial costs that the Utility may incur in connection with the outcomes;

the effects on PG&E ~~Corporation~~Corporation’s and the Utility’s reputations caused by the ~~CPUC's~~CPUC’s investigations of natural gas and electric incidents, the 2018 Camp fire and 2017 Northern California wildfires, locate and mark, improper communications between the CPUC and the Utility, and the Utility’s ongoing work to remove encroachments from transmission pipeline rights-of-way;

the ~~outcome~~implementation of the ~~safety culture~~Safety Culture OII ~~including~~decision approved on November 29, 2018, and the outcome of its phase two ~~PD issued on October 25, 2018,~~proceeding, and future legislative or regulatory actions that may be taken, such as requiring the Utility to separate its electric and natural gas businesses, or restructure into separate entities, or undertake some other corporate restructuring, or implement corporate governance changes;

whether the Utility can control its costs within the authorized levels of spending, and timely recover its costs through rates; whether the Utility can continue implementing a streamlined organizational structure and achieve project savings, the extent to which the Utility incurs unrecoverable costs that are higher than the forecasts of such costs; and changes in cost forecasts or the scope and timing of planned work resulting from changes in customer demand for electricity and natural gas or other reasons;

whether the Utility and its third-party vendors and contractors are able to protect the Utility’s operational networks and information technology systems from cyber- and physical attacks, or other internal or external hazards;

the timing and outcome of the October 1, 2018 request for rehearing of ~~FERC's~~FERC’s denial of the complaint filed by the CPUC and certain other parties that the Utility provide an open and transparent planning process for its capital transmission projects that do not go through the CAISO’s Transmission Planning Process to allow for greater participation and input from interested parties; and the timing and ultimate outcome of the Ninth Circuit Court of Appeals decision on January 8, 2018, to reverse FERC’s decision granting the Utility a 50 basis point ROE incentive adder for continued participation in the CAISO and remanding the case to FERC for further proceedings;

the outcome of current and future self-reports, investigations, or other enforcement proceedings that could be commenced or notices of violation that could be issued 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, electric grid reliability, inspection and maintenance practices, customer billing and privacy, physical and cybersecurity, environmental laws and regulations; and the outcome of existing and future SED notices of violations;

the timing and outcome of any CPUC action in connection with the Utility’s SmartMeter™ Upgrade cost-benefit analysis;

the impact of environmental remediation laws, regulations, and orders; the ultimate amount of costs incurred to discharge the Utility’s known and unknown remediation obligations; and the extent to which the Utility is able to recover environmental costs in rates or from other sources;

the impact of SB 100, which was signed into law on September 10, 2018, that increases the percentage from ~~50 percent~~50% to ~~60 percent~~60% of California’s electricity portfolio that must come from renewables by 2030; and ~~the requirement~~establishes state policy that ~~100 percent~~100% of all retail electricity sales must come from ~~RPS-eligible~~renewable portfolio standard-eligible or carbon-free resources by 2045;

how the CPUC and the California Air Resources Board implement state environmental laws relating to GHG, renewable energy targets, energy efficiency standards, DERs, EVs, and similar matters, including whether the Utility is able to continue recovering associated compliance costs, such as the cost of emission allowances and offsets under cap-and-trade regulations; and whether the Utility is able to timely recover its associated investment costs;

the impact of the California ~~governor's~~governor’s executive order issued on January 26, 2018, to implement a new target of five million zero-emission vehicles on the road in California by 2030;

the ultimate amount of unrecoverable environmental costs the Utility incurs associated with the Utility’s natural gas compressor station site located near Hinkley, California and the ~~Utility's~~Utility’s fossil fuel-fired generation sites;

the impact of new legislation or NRC regulations, recommendations, policies, decisions, or orders relating to the nuclear industry, including operations, seismic design, security, safety, relicensing, the storage of spent nuclear fuel, decommissioning, cooling water intake, or other issues; the impact of potential actions, such as legislation, taken by state agencies that may affect the Utility’s ability to continue operating Diablo Canyon until its planned retirement;

the impact of wildfires, droughts, floods, or other weather-related conditions or events, climate change, natural disasters, acts of terrorism, war, vandalism (including cyber-attacks), downed power lines, 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 the reparation and other costs that the Utility may incur in connection with such conditions or events; the impact of the adequacy of the Utility’s emergency preparedness; whether the Utility incurs liability to third parties for property damage or personal injury caused by such events; whether the Utility is subject to civil, criminal, or regulatory penalties in connection with such events; and whether the Utility’s insurance coverage is available for these types of claims and sufficient to cover the Utility’s liability;

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

the breakdown or failure of equipment that can cause damages, including fires, and unplanned outages; and whether the Utility will be subject to investigations, penalties, and other costs in connection with such events;

the impact that reductions in customer demand for electricity and natural gas have on the Utility’s ability to make and recover its investments through rates and earn its authorized return on equity, and whether the Utility is successful in addressing the impact of growing distributed and renewable generation resources, changing customer demand for natural gas and electric ~~services, and an increasing number of customers departing the Utility’s procurement service for CCAs;~~services;

the supply and price of electricity, natural gas, and nuclear fuel; the extent to which the Utility can manage and respond to the volatility of energy commodity prices; the ability of the Utility and its counterparties to post or return collateral in connection with price risk management activities; and whether the Utility is able to recover timely its electric generation and energy commodity costs through rates, including its renewable energy procurement costs;

the amount and timing of charges reflecting probable liabilities for third-party claims; the extent to which costs incurred in connection with third-party claims or litigation can be recovered through insurance, rates, or from other third parties; and whether the Utility can continue to obtain adequate insurance coverage for future losses or claims, especially following a major event that causes widespread third-party losses;

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 and on acceptable terms;

changes in credit ratings which could, among other things, result in cash collateral postings, higher borrowing costs and fewer financing options, especially if PG&E Corporation or the Utility were to lose their investment grade credit ratings;

the impact of 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 uncertainty in connection with the 2018 Camp fire and the 2017 Northern California wildfires, the ultimate outcomes of the CPUC’s pending investigations, and other enforcement matters will impact the Utility’s ability to make distributions to PG&E ~~Corporation, and whether they will continue impacting PG&E Corporation's and the Utility's ability to pay dividends;~~Corporation;

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;

changes in the regulatory and economic environment, including potential changes affecting renewable energy sources and associated tax credits, as a result of the current federal administration; 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.

~~Additional~~For more information about the significant risks that could affect the outcome of the forward-looking statements and ~~uncertainties, including more detail about~~PG&E Corporation’s and the ~~factors described in this report, is included throughout MD&A, in “Item~~Utility’s future financial condition, results of operations, liquidity, and cash flows, see Item 1A. Risk ~~Factors”~~Factors below and a detailed discussion of these matters contained elsewhere in ~~the 2017 Form 10-K, including the “Risk Factors” section. Forward-looking statements speak only as of the date they are made.~~MD&A. 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.

Additionally, PG&E Corporation and the Utility routinely provide links to the Utility’s principal regulatory proceedings before the CPUC and the FERC at http://investor.pgecorp.com, under the “Regulatory Filings” tab, so that such filings are available to investors upon filing with the relevant agency. PG&E Corporation and the Utility also routinely post or provide direct links to presentations, documents, and other information that may be of interest to investors at http://investor.pgecorp.com, under the “News & Events: Events & Presentations” tab and links to certain documents and information related to the 2018 Camp fire, the 2017 Northern California wildfires, ~~and~~ the 2015 Butte fire, and other updates which may be of interest to investors, at http://investor.pgecorp.com, under the “Wildfire Updates” tab, in order to publicly disseminate such information. It is possible that any of these filings or information included therein could be deemed to be material information. The information contained on this website is not part of this or any other report that PG&E Corporation or the Utility files with, or furnishes to, the SEC. PG&E Corporation and the Utility are providing the address to this website solely for the information of investors and do not intend the address to be an active link.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. (See the section above entitled “Risk Management Activities” in MD&A and in Note ~~7: Derivatives~~8 and Note ~~8: Fair Value Measurements~~9 of the Notes to the Condensed Consolidated Financial Statements in Item 1.)

ITEM 4. CONTROLS AND PROCEDURES

Based on an evaluation of PG&E Corporation’s and the Utility’s disclosure controls and procedures as of ~~September 30, 2018,~~March 31, 2019, 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 Securities Exchange Act of 1934, as amended, is (i) recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms, and (ii) accumulated and communicated to PG&E Corporation’s and the Utility’s management, including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended ~~September 30, 2018,~~March 31, 2019, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following 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 PG&E Corporation’s and the Utility’s contingencies, see ~~Note 9~~Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Item 1 and Part I, MD&A: “Enforcement and Litigation Matters.”

U.S. District Court Matters and Probation

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court issued a judgment of conviction against the Utility. The court sentenced the Utility to a five-year corporate probation period, oversight by the Monitor for a period of five years, with the ability to apply for early termination after three years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained the Monitor at the Utility’s expense. The goal of the Monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

On November 27, 2018, the court overseeing the Utility’s probation issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the Monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.” The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”). On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.” The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the Monitor were submitted on December 31, 2018.

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the Atlas fire. The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order. On January 4, 2019, the court issued another order requiring that the Utility provide “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition. The responses of the Utility were submitted on January 10, 2019.

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire. In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires;”

“document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions;” and

at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

The Utility was ordered to show cause by January 23, 2019 as to why the Utility’s conditions of probation should not be modified as proposed. The Utility’s response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019. On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. Also, on January 30, 2019, the court ordered the Utility to submit to the court on February 6, 2019 the 2019 Wildfire Safety Plan that the Utility was required to submit to the CPUC by February 6, 2019 in accordance with SB 901, and invited interested parties to comment on such plan by February 20, 2019. In addition, on February 14, 2019, the court ordered the Utility to provide additional information, including on its vegetation clearance requirements. The Utility submitted its response to the court on February 22, 2019. As of April 30, 2019, to the Utility’s knowledge, no parties have submitted comments to the court on the 2019 Wildfire Safety Plan.

On March 5, 2019, the court issued an order proposing to add new conditions of probation that would require the Utility, among other things, to:

“fully comply with all applicable laws concerning vegetation management and clearance requirements;”

“fully comply with the specific targets and metrics set forth in its wildfire mitigation plan, including with respect to enhanced vegetation management;”

submit to “regular, unannounced inspections” by the Monitor “of PG&E’s vegetation management efforts and equipment inspection, enhancement, and repair efforts” in connection with a requirement that the Monitor “assess PG&E’s wildfire mitigation and wildfire safety work;”

“maintain traceable, verifiable, accurate, and complete records of its vegetation management efforts” and report to the Monitor monthly on its vegetation management status and progress; and

“ensure that sufficient resources, financial and personnel, including contractors and employees, are allocated to achieve the foregoing” and to forego issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements as set forth above.”

The court ordered all parties to show cause by March 22, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The responses of the Utility, the USAO, Cal Fire, the CPUC, and non-party victims were filed on March 22, 2019. At a hearing on April 2, 2019, the court indicated it would impose the new conditions of probation proposed on March 5, 2019, on the Utility, and on April 3, 2019, the Court issued an order imposing the new terms though amended the second condition to clarify that “[f]or purposes of this condition, the operative wildfire mitigation plan will be the plan ultimately approved by the CPUC.” Also, on April 2, 2019, the court directed the parties to submit briefing by April 16, 2019, regarding whether the court can extend the term of probation beyond 5 years in light of the violation that has been adjudicated and whether the third-party Monitor reports should be made public. The responses of the Utility, the USAO, and the Monitor were filed on April 16, 2019. The Utility’s response contended that the term of probation may not be extended beyond five years and the USAO’s response contended that whether the term of probation could be extended beyond five years was an open legal issue.

Order Instituting an Investigation into PG&E ~~Corporation's~~Corporation’s and the Utility’s Safety Culture

On August 27, 2015, the CPUC began a formal investigation into whether the organizational culture and governance of PG&E Corporation and the Utility prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards. The CPUC directed the SED to evaluate the Utility’s and PG&E Corporation’s organizational culture, governance, policies, practices, and accountability metrics in relation to the Utility’s record of operations, including its record of safety incidents. The ~~CPUC authorized the~~ SED ~~to engage~~engaged a consultant to assist in the SED’s investigation and the preparation of a report containing the SED’s ~~assessment.~~assessment, and subsequently, to report on the implementation by the Utility of the consultant’s recommendations.

On May 8, 2017, the CPUC released the consultant’s report, accompanied by a scoping memo and ruling. The scoping memo ~~establishes~~established a second phase in ~~this~~the OII in which the CPUC ~~will evaluate~~evaluated the safety recommendations of the ~~consultant that may lead to the CPUC’s adoption of the recommendations in the report, in whole or in part. This phase~~consultant. Phase two of the proceeding ~~will~~ also ~~consider~~considered all necessary measures, including, but not limited to, a potential reduction of the Utility’s return on ~~equity until any recommendations adopted by the CPUC are implemented.~~

equity. On November 17, 2017, the CPUC issued a phase two scoping memo and procedural schedule. The scoping memo directed the Utility to file testimony addressing a number of issues including: adoption of the safety recommendations from the consultant, the Utility’s implementation process for the safety recommendations of the consultant, the Utility’s Board of Director’s actions and initiatives related to safety culture and the consultant’s recommendations, the Utility’s corrective action program, and the Utility’s response to certain specified safety incidents that occurred in 2013 through 2015.

The ~~CPUC retained the same consultant to prepare a second report on the Utility's safety culture and governance with respect~~Utility’s testimony was submitted to the ~~Utility's implementation plan in response to~~CPUC on January 8, 2018 and stated that the ~~consultant's recommendations. The consultant's report is expected to be completed~~Utility agrees with all the recommendations of the consultant and supports their adoption by the ~~end of November~~CPUC. Other parties’ responsive testimony was submitted on February 16, 2018, followed by the Utility’s rebuttal testimony on February 23, 2018.

On ~~October 25,~~November 29, 2018, the ~~assigned ALJ issued a~~CPUC approved the PD in connection with this proceeding. ~~If adopted,~~The decision directed the Utility ~~would be required~~ to implement the recommendations set forth in the May 2017 consultant report no later than July 1, 2019, and to submit quarterly reports on the Utility’s implementation status ~~of their implementation~~ beginning in the fourth quarter of 2018. ~~The PD, if adopted, would not result~~

On December 21, 2018, the CPUC issued a Scoping Memo and Ruling (the “Scoping Memo”) setting forth the scope to be addressed in the ~~adoption~~next phase of ~~safety performance metrics~~its ongoing investigation into whether the organizational culture and targets at this time, but they could be considered in the future. Additionally, the PD directs the assigned CPUC commissioner and the ALJ to develop a process for a remedial phase and to issue a scoping memo.

governance of PG&E Corporation and the Utility ~~are~~prioritize safety and adequately direct resources to promote accountability and achieve safety goals and standards (the “Safety Culture OII”). The Scoping Memo provides that the CPUC “will examine [PG&E’s] current corporate governance, structure, and operations to determine if the utility is positioned to provide safe electrical and gas service, and will review alternatives to the current management and operational structures of providing electric and gas service in Northern California.”

In the Scoping Memo, the CPUC alleges that the Utility has had “serious safety problems with both its gas and electric operations for many years” and that despite penalties and other remedial measures in connection with these problems, PG&E Corporation and the Utility have failed to develop “a comprehensive enterprise-wide approach to addressing safety.” The Scoping Memo outlines a number of proposals to address the CPUC’s concerns regarding PG&E Corporation’s and the Utility’s safety culture, including, but not limited to, (i) replacement of all or part of PG&E Corporation’s and the Utility’s existing boards of directors and corporate management, (ii) separating the Utility’s gas and electric distribution and transmission businesses into separate companies, (iii) reorganizing the Utility into regional subsidiaries based on regional distinctions, (iv) reconstituting the Utility as a publicly owned utility or utilities, (v) providing for entities other than the Utility to provide generation services, and (vi) conditioning the Utility’s return on equity on safety performance. The Scoping Memo does not propose penalties and states that this phase “is not a punitive phase.” The Utility submitted its background filing to the CPUC on January 16, 2019 and opening comments were filed on February 13, 2019. The Utility and other parties filed reply comments on February 28, 2019. Subsequently, the CPUC held workshops on some of the topics raised in the Scoping Memo on April 15, 2019 and April 26, 2019.

The Utility is unable to predict ~~whether additional fines, penalties, or other ratemaking tools such as a potential reduction~~the timing and outcome of ~~the Utility's return on equity will be adopted by the CPUC.~~

~~The earliest the CPUC could vote on~~ this ~~PD is November 29, 2018.~~proceeding.

Diablo Canyon ~~Nuclear~~ Power Plant

For more information regarding the status of the 2003 settlement agreement between the Central Coast Regional Water Quality Control Board, the Utility, and the California Attorney General’s Office, see Part I, Item 3. ~~"Legal~~“Legal Proceedings” in the ~~2017~~2018 Form 10-K.

ITEM 1A. RISK FACTORS

For information about the significant risks that could affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows, see the section of the ~~2017~~2018 Form 10-K entitled “Risk Factors,” as supplemented below, and the section of this quarterly report entitled “Forward-Looking Statements.”

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the Northern California wildfires. PG&E Corporation and the Utility also expect to be the subject of additional lawsuits and could be the subject of additional investigations, citations, fines or enforcement actions.

PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by potential losses resulting from the impact of the multiple wildfires that spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City, beginning on October 8, 2017 (the “Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the wildfires, there were 21 major wildfires in Northern California that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The wildfires resulted in 44 fatalities.

Cal Fire issued its determination on the causes of 17 of the Northern California wildfires, and alleged that each of these fires involved the Utility's equipment. The remaining wildfires remain under Cal Fire's investigation, including the possible role of the Utility's power lines and other facilities. Additionally, the Northern California wildfires are under investigation by the CPUC's SED.

In connection with the Northern California wildfires, if the doctrine of inverse condemnation applies, the Utility could be liable for property damage, interest, and attorneys’ fees without having been found negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. (See “The doctrine of inverse condemnation, if applied by courts in litigation to which PG&E Corporation or the Utility are subject, could significantly expand the potential liabilities from such litigation and materially negatively affect PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows” in PG&E Corporation and the Utility’s 2017 Form 10-K, Item 1A, Risk Factors.) In addition to such claims for property damage, interest, and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, and other damages under other theories of liability, including if the Utility were found to have been negligent, which liability, in the aggregate, could be substantial and have a material adverse effect on PG&E Corporation and the Utility. Further, the Utility could be subject to material fines or penalties if the CPUC or any other law enforcement agency brought an enforcement action, including as a result of the referral by Cal Fire of certain investigation reports to the appropriate county District Attorney's offices, and determined that the Utility failed to comply with applicable laws and regulations.

On September 6, 2018, the California Department of Insurance issued a news release announcing an update on property losses in connection with the October and December 2017 wildfires in California. As of that date, insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the Northern California wildfires. The balance relates to claims from the Southern California December 2017 wildfires. That news release reflected insured property losses only. Also, that amount did not account for uninsured losses, interest, attorneys’ fees, fire suppression and clean-up costs, personal injury and wrongful death damages or other costs. If PG&E Corporation and the Utility were to be found liable for certain or all of such other costs and expenses, including the potential liabilities outlined above, the amount of the liability could significantly exceed the approximately $10 billion in estimated insured property losses with respect to the Northern California wildfires. As a result, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows could be materially affected.

PG&E Corporation and the Utility also are the subject of a still increasing number of lawsuits that have been filed against PG&E Corporation and the Utility in Sonoma, Napa and San Francisco Counties’ Superior Courts, several of which seek to be certified as class actions, asserting damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees, and other damages. In addition, two insurance carriers who have made payments to their insureds for property damage arising out of the fires have filed 36 subrogation complaints in the San Francisco County Superior Court. Further, several derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court and two purported securities class actions were filed in the United States District Court for the Northern District of California. PG&E Corporation and the Utility expect to be the subject of additional lawsuits in connection with the Northern California wildfires. The wildfire litigation could take a number of years to be resolved because of the complexity of the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved.

PG&E Corporation and the Utility have liability insurance from various insurers, which provides coverage for third-party liability attributable to the Northern California wildfires in an aggregate amount of approximately $840 million, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. In addition, coverage limits within these wildfire insurance policies could result in further material self-insured costs in the event each fire were deemed to be a separate occurrence under the terms of the insurance policies. Further, the $2.5 billion charge recorded by PG&E Corporation and the Utility for the quarter ended June 30, 2018 exceeds the amount of their insurance coverage.

In addition, it could take a number of years before the Utility’s final liability is known and the Utility could apply for recovery of costs in excess of insurance. While the CPUC has authorized the Utility to track certain wildfire costs in its WEMA, the Utility will be required to submit a separate request with the CPUC in the future for recovery of those costs. The Utility may be unable to fully recover costs in excess of insurance through regulatory mechanisms and, even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

PG&E Corporation and the Utility have considered certain actions that might be taken to attempt to address liquidity needs of the business in such circumstances, but the inability to recover costs in excess of insurance through increases in rates and by collecting such rates in a timely manner, or any negative assessment by the Utility of the likelihood or timeliness of such recovery and collection, could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. (See “If the Utility is unable to recover all or a significant portion of its excess costs in connection with the Northern California wildfires and the Butte fire through ratemaking mechanisms, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected” below.)

Losses in connection with the wildfires would likely require PG&E Corporation and the Utility to seek financing, which may not be available on terms acceptable to PG&E Corporation or the Utility, or at all, when required. (See “Risks Related to Liquidity and Capital Requirements” in Item 1A Risk Factors in 2017 Form 10-K.)

Uncertainties relating to and market perception of these matters and the disclosure of findings regarding these matters over time, also could continue or increase volatility in the market for PG&E Corporation’s common stock and other securities, and for the securities of the Utility, and materially affect the price of such securities.

~~For more information about the Northern California wildfires, see Note 9 of the Notes to Condensed Consolidated Financial Statements in Item 1.~~

If the Utility is unable to recover all or a significant portion of its excess costs in connection with the Northern California wildfires and the Butte fire through ratemaking mechanisms, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

As of September 30, 2018, the Utility incurred substantial costs in connection with the Northern California wildfires and the Butte fire in excess of costs currently in rates, some of which currently are or are expected to be recorded in the future in its WEMA, 2018 CEMA and FHPMA accounts.

There can be no assurance that the Utility will be allowed to recover costs recorded in those accounts in the future. For example, while the CPUC previously approved WEMA tracking accounts for San Diego Gas & Electric Company in 2010, in December 2017, the CPUC denied recovery of costs that San Diego Gas & Electric Company stated it incurred as a result of the doctrine of inverse condemnation, holding that the inverse condemnation principles of strict liability are not relevant to the CPUC’s prudent manager standard. San Diego Gas & Electric, the Utility, and Southern California Edison filed requests for rehearing of that decision. On July 12, 2018, the CPUC voted out a decision denying the requests for rehearing.

~~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 and the Utility will continue to seek funds in the capital and credit markets to enable the Utility to make capital investments, and to pay fines that may be imposed in the future, as well as legal and regulatory costs. 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 primarily on PG&E Corporation’s and the Utility’s credit ratings and outlook. Their credit ratings and outlook can be affected by many factors, including pending or anticipated litigation, the pending Cal Fire and CPUC investigations and CPUC ratemaking proceedings, substantial legislative or judicial changes to the application of inverse condemnation, and by the December 20, 2017 decision of the Boards of Directors of PG&E Corporation and the Utility to suspend dividends, as well as the perceived impact of all such matters on PG&E Corporation’s and the Utility’s financial condition, whether or not such perception is accurate.

During 2018, PG&E Corporation's and the Utility's credit ratings were subject to multiple downgrades by Fitch Ratings, S&P Global Ratings, and Moody’s Investors Service, Inc. If PG&E Corporation’s or the Utility’s credit ratings were to be further downgraded, in particular 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, or lack of, access to the commercial paper market and 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, an increase in interest rates by the Federal Reserve Bank, and general economic and financial market conditions.

The reputations of PG&E Corporation and the Utility continue to suffer from the negative publicity about matters discussed under “Enforcement and Litigation Matters” in Part II, Item 1. Legal Proceedings and Note 9 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1. The negative publicity and the uncertainty about the outcomes of these matters may undermine confidence in management’s ability to execute its business strategy and restore a constructive regulatory environment, which could adversely impact PG&E Corporation’s stock price. Further, the market price of PG&E Corporation common stock could decline materially depending on the outcome of these matters. The amount and timing of future share issuances also could affect the stock price.

PG&E Corporation’s and the Utility’s financial results could be materially affected as a result of legislative and regulatory developments.

The Utility’s financial results could be materially affected as a result of SB 901 ~~recently~~ adopted in 2018 by the California legislature. In December 2018, the CPUC opened an OIR in connection with SB 901 that will adopt criteria and a methodology for use by the CPUC in future applications for cost recovery of wildfire costs. Following SB 901, in applications for cost recovery in connection with the 2017 Northern California wildfires, the CPUC is expected to consider the Utility’s financial status and determine the maximum amount the Utility can pay without harming customers or materially impacting its ability to provide adequate and safe service, and ensure that the costs or expenses that are disallowed for recovery in rates assessed for the wildfires, in the aggregate, do not exceed that amount. The Utility is unable to predict the timing or outcome of such future determination by the CPUC and its impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

In addition, SB 901 requires utilities to submit annual wildfire mitigation plans for approval by the CPUC on a schedule to be established by the CPUC. The wildfire mitigation plan must include the components specified in SB 901, such as identification and prioritization of wildfire risks, and drivers for those risks; plans for vegetation management; actions to harden the system, prepare for, and respond to events; and protocols for disabling reclosers and deenergizing the system. The CPUC has three months to approve a utility’s plan, with the ability to extend the deadline. The CPUC will conduct an annual compliance review, which will be supported by an independent evaluator’s report. The CPUC will complete the compliance review within 18 months. SB 901 establishes factors to be considered by the CPUC when setting penalties for failure to substantially comply with the plan. ~~Costs associated with the wildlife mitigation plan are tracked in a memorandum account, and the costs of implementing the plan will be assessed in each utility’s General Rate Case proceeding.~~ The Utility is unable to predict the timing or outcome of the CPUC’s review of the wildfire mitigation plan, the results of the CPUC compliance review of wildfire mitigation plan implementation, or the timing or extent of cost recovery for wildfire mitigation plan activities.

(See “Regulatory Matters - Other Regulatory Proceedings” in Item 2. MD&A.)

Finally, SB 901 established a Commission on Catastrophic Wildfire Cost and Recovery to evaluate wildfire reforms, including inverse condemnation reform, a potential state wildfire insurance fund, and other wildfire mitigation measures. The commission, which will be composed of members with demonstrated expertise in insurance, public and private utilities, or allocation of costs and reduction of damage associated with wildfires, will hold multiple meetings throughout the state to accept public and expert testimony and develop recommendations. The commission, in consultation with the CPUC and California Insurance Commissioner, will prepare a report on or before July 1, 2019, that contains an assessment of issues surrounding catastrophic wildfire costs and damages and makes recommendations for changes to the law. The recommendations of the ~~commission~~CPUC and the response by the Governor and legislature to those recommendations could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. (See “Regulatory Matters ~~-Legislative~~- Legislative and Regulatory Initiatives” in Item 7.2. MD&A.)

~~Severe weather conditions, extended drought and shifting climate patterns~~On April 12, 2019, California Governor Gavin Newsom’s “Strike Force” issued a report setting out potential steps the state could ~~materially affect PG&E Corporation’s and~~take to reduce the ~~Utility’s business, financial condition, results of operations, liquidity, and cash flows.~~

Extreme weather, extended drought and shifting climate patterns have intensified the challenges associated with wildfire management in California. The Utility's service territory encompasses some of the most densely forested areas in California and, as a consequence, is subject to higher risk from vegetation-related ignition events than other California IOUs. Further, environmental extremes, such as drought conditions followed by periods of wet weather, can drive additional vegetation growth (which can then fuel fires) and influence both the likelihoodincidence and severity of ~~extraordinary wildfire events. In California, over~~wildfires and outlining “actions to hold the ~~past five years, inconsistent~~state’s utilities accountable for their behavior and ~~extreme precipitation, coupled with more hot days, have increased~~potential changes to stabilize California’s utilities to meet the ~~wildfire risk~~energy needs of customers and ~~made wildfire outbreaks increasingly difficult~~the economy.” Due to ~~manage. In particular,~~uncertainty regarding the ~~risk posed by wildfires has increased in the Utility’s service area~~specific policy actions that may be taken as a result of ~~an extended period of drought, bark beetle infestations in~~ the ~~California forest~~Strike Force Report, the impact and wildfire fuel increases due to record rainfall following the drought, and strong wind events, among other environmental factors. Contributing factors other than environmental can include local land use policies and historical forestry management practices. The combined effects of extreme weather and climate change also impact this risk. For example, in 2017, there were nearly double the number of wildfires than the annual average, including fivetiming of the most devastating wildfires in California's history. On January 19, 2018, the CPUC approved a statewide fire-threat map that shows that most of the Utility's service territory is facing "elevated" or "extreme" fire danger. Approximately 25,000 circuit miles of the Utility's nearly 81,000 distribution overhead circuit milesreport and ~~approximately 5,500 miles of the nearly 18,000 transmission overhead circuit miles are in such high-fire threat areas, significantly more in total than other California IOUs.~~

Severe weather events and other natural disasters, including wildfires and other fires, storms, tornadoes, floods, heat waves, drought, earthquakes, tsunamis, rising sea levels, pandemics, solar events, electromagnetic events, or other natural disasters such as wildfires, could result in severe business disruptions, prolonged power outages, property damage, injuries or loss of life, significant decreases in revenues and earnings, and/or significant additional costs toany resulting policy actions on PG&E Corporation and the ~~Utility. Any~~Utility cannot be determined at this time. However, the impact and timing of such ~~event could have a material effect~~actions on PG&E Corporation’s and the Utility’s business, financial condition, results of operations, liquidity, and cash flows. Any of such events also could lead to significant claims against the Utility. Further, these events could result in regulatory penalties and disallowances, particularly if the Utility encounters difficulties in restoring power to its customers on a timely basis or if the related losses are found to be the result of the Utility’s practices and/or the failure of electric and other equipment of the Utility.

Further, the Utility has been studying the potential effects of climate change (increased temperatures, changing precipitation patterns, 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. As a result, the Utility’s hydroelectric generation could change and the Utility would need to consider managing or acquiring additional generation. If the Utility increases its 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, flooding caused by rising sea levels could damage the Utility’s facilities, including gas, generation, and electric transmission and distribution assets. The Utility could incur substantial costs to repair or replace facilities, restore service, or 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’sfuture financial condition, results of operations, liquidity, and cash flows could be ~~materially affected.~~significant. (See “Regulatory Matters - Strike Force Report” in Item 2. MD&A.)

In June 2018, the State of California enacted the California Consumer Privacy Act of 2018 (the “CCPA”), which will come into effect on January 1, 2020, with a 12-month look-back period requiring compliance by January 1, 2019. The ~~Utility’s electricity~~CCPA requires companies that process information on California residents to make new disclosures to consumers about their data collection, use and ~~natural gas operations are inherently hazardous~~sharing practices, allows consumers to opt out of certain data sharing with third parties and ~~involve significant risks which, if they materialize, can adversely affect PG&E Corporation’s and the Utility’s~~provides a new cause of action for data breaches. The CCPA provides for financial ~~condition, results of operations, liquidity, and cash flows.~~

~~The Utility owns and operates extensive electricity and natural gas facilities, including two nuclear generation units and an extensive~~hydroelectric generating system. (See “Electric Utility Operations” and “Natural Gas Utility Operations” in Item 1. Business of the Form 10-K.) 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, and the CPUC approved retirement of Diablo Canyon by 2024 and 2025.

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:

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;

an overpressure event occurring on natural gas facilities due to equipment failure, incorrect operating procedures or failure to follow correct operating procedures, or welding or fabrication-related defects, that resultspenalties in the ~~failure~~event of ~~downstream transmission pipelines or distribution assets~~non-compliance and ~~uncontained natural gas flow;~~

statutory damages in the ~~failure~~event of a data security breach. However, California legislators have stated that they intend to maintain adequate capacity to meet customer demand on the gas system that results in customer curtailments, controlled/uncontrolled gas outages, gas surges back into homes, serious personal injury or loss of life;

~~a prolonged statewide electrical black-out that results in damage~~propose amendments to the ~~Utility’s equipment~~CCPA, and it remains unclear what, if any, modifications will be made to the CCPA or ~~damage to property owned by customers or other third parties;~~

~~the failure to fully identify, evaluate, and control workplace hazards that result in serious injury or loss of life for employees or the public, environmental damage, or reputational damage;~~

~~the release of radioactive materials caused by a nuclear accident, seismic activity, natural disaster, or terrorist act;~~

~~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;~~

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);

~~inadequate emergency preparedness plans and the failure to respond effectively to a catastrophic event that can lead to public or employee harm or extended outages;~~

~~operator or other human error;~~

~~an ineffective records management program that results in the failure to construct, operate and maintain~~

~~a utility system safely and prudently;~~

construction performed by third parties that damages the Utility’s underground or overhead facilities, including, for example, ground excavations or “dig-ins” that damage the Utility’s underground pipelines;

the release of hazardous or toxic substances into the air, water, or soil, including, for example, gas leaks from natural gas storage facilities; releases of greenhouse gases; flaking lead-based paint from the Utility’s facilities, and leaking or spilled insulating fluid from electrical equipment; and

~~attacks by third parties, including cyber-attacks, acts of terrorism, vandalism, or war.~~

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, and to compensate third parties. Any of such incidents also could lead to significant claims against the Utility.

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 canhow it will be subject to penalties or other enforcement action if the contractor violates applicable laws, rules, regulations, or orders. The Utility may also be subject to liability, penalties or other enforcement action as a result of personal injury or death caused by third-party contractor actions.

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 condition, results of operations, liquidity, and cash flows. interpreted.

The Utility’s insurance coverage may not be sufficient to cover losses caused by an operating failure or catastrophic events, including severe weather events, or may not be available at a reasonable cost, or available at all.

The Utility has experienced increased costs and difficulties in obtaining insurance coverage for wildfires and other risks that could arise from the Utility’s ordinary operations. PG&E Corporation, the Utility or its contractors and customers could continue to experience coverage reductions and/or increased ~~wildfire~~ insurance costs in future years. No assurance can be given that future losses will not exceed the limits of the Utility’s insurance coverage. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss ~~which~~that is not fully insured or cannot be recovered in customer rates could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

As a result of the potential application to investor-owned utilities of a strict liability standard under the doctrine of inverse condemnation, recent losses recorded by insurance companies, the risk of ~~increase of~~increased wildfires including as a result of the ~~ongoing~~ drought, the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire, the Utility may not be able to obtain sufficient insurance coverage in the future at a reasonable cost, or at all. In addition, the Utility is unable to predict whether it would be allowed to recover in rates the increased costs of insurance or the costs of any uninsured losses.

If the amount of insurance is insufficient or otherwise unavailable, or if the Utility is unable to obtain insurance at a reasonable cost or recover in rates the costs of any uninsured losses, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected.

A cyber incident, cyber security breach, severe natural event or physical attack on the Utility’s operational networks and information technology systems could have a material effect on its business, financial condition, results of operations, liquidity, and cash flows.

The Utility’s electricity and natural gas systems rely on a complex, interconnected network of generation, transmission, distribution, control, and communication technologies, which can be damaged by natural events-such as severe weather or seismic events-and by malicious events, such as cyber and physical attacks. Private and public entities, such as the North American Electric Reliability Corporation, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, and the White House, have noted that cyber-attacks targeting utility systems are increasing in sophistication, magnitude, and frequency. The Utility’s operational networks also may face new cyber security risks due to modernizing and interconnecting the existing infrastructure with new technologies and control systems. Any failure or decrease in the functionality of the Utility’s operational networks could cause harm to the public or employees, significantly disrupt operations, negatively impact the Utility’s ability to safely generate, transport, deliver and store energy and gas or otherwise operate in the most safe and efficient manner or at all, and damage the Utility’s assets or operations or those of third parties.

The Utility also relies on complex information technology systems that allow it to create, collect, use, disclose, store and otherwise process sensitive information, including the Utility’s financial information, customer energy usage and billing information, and personal information regarding customers, employees and their dependents, contractors, and other individuals. In addition, the Utility often relies on third-party vendors to host, maintain, modify, and update its systems, and to provide other services to the Utility or the Utility’s customers. These third-party vendors could cease to exist, fail to establish adequate processes to protect the Utility’s systems and information, or experience security incidents or inadequate security measures. Any incidents or disruptions in the Utility’s information technology systems could impact the Utility’s ability to track or collect revenues and to maintain effective internal controls over financial reporting.

The Utility and its third-party vendors have been subject to, and will likely continue to be subject to breaches and attempts to gain unauthorized access to the Utility’s information technology systems or confidential data (including information about customers and employees), or to disrupt the Utility’s operations. None of these breaches or attempts has individually or in the aggregate resulted in a security incident with a material impact on PG&E Corporation’s and the Utility’s financial condition and results of operations. Despite implementation of security and control measures, there can be no assurance that the Utility will be able to prevent the unauthorized access to its operational networks, information technology systems or data, or the disruption of its operations. Such events could subject the Utility to significant expenses, claims by customers or third parties, government inquiries, penalties for violation of applicable privacy laws, investigations, and regulatory actions that could result in material fines and penalties, loss of customers and harm to PG&E Corporation’s and the Utility’s reputation, any of which could have a material adverse effect on PG&E Corporation’s and the Utility’s financial condition and results of operations.

The Utility maintains cyber liability insurance that covers certain damages caused by cyber incidents. However, there is no guarantee that adequate insurance will continue to be available at rates the Utility believes are reasonable or that the costs of responding to and recovering from a cyber incident will be covered by insurance or recoverable in rates.

The electric power industry is undergoing significant change driven by technological advancements and a decarbonized economy, which could materially impact the Utility’s operations, financial condition, and results of operations.

The electric power industry is undergoing transformative change driven by technological advancements enabling customer choice (for example, customer-owned generation and energy storage) and state climate policy supporting a decarbonized economy. The electric grid is a critical enabler of the adoption of new energy technologies that support California's climate change and GHG reduction objectives, which continue to be publicly supported by California policymakers. California's environmental policy objectives are accelerating the pace and scope of the industry change. For instance, Senate Bill 100, which was signed into law on September 10, 2018, increases from 50 percent to 60 percent, the percentage of California’s electricity portfolio that must come from renewables by 2030. SB 100 establishes a further goal to have an electric grid that is entirely powered by clean energy by 2045. California utilities also are experiencing increasing deployment by customers and third parties of DERs, such as on-site solar generation, energy storage, fuel cells, energy efficiency, and demand response technologies. These developments will require modernization of the electric distribution grid to, among other things, accommodate two-way flows of electricity, increase the grid's capacity, and interconnect DERs.

In order to enable the California clean energy economy, sustained investments are required in grid modernization, renewable integration projects, energy efficiency programs, energy storage options, EV infrastructure and state infrastructure modernization (e.g.. rail and water projects).

To this end, the CPUC is conducting proceedings to: evaluate changes to the planning and operation of the electric distribution grid in order to prepare for higher penetration of DERs and, consider future grid modernization and grid reinforcement investments; evaluate if traditional grid investments can be deferred by DERs, and if feasible, what, if any, compensation to utilities would be appropriate for enabling those investments; and clarify the role of the electric distribution grid operator. The CPUC also authorized development of two new, five-year programs aimed at accelerating widespread electric vehicle adoption and combating climate change. The new programs will increase fast charging options for consumers as well as electric charging infrastructure for non-light-duty fleet vehicles.

In addition, the CPUC has held discussions on potential changes to California’s electricity market. On May 19, 2017, California energy companies, along with other stakeholders, discussed customer choice and the future of the state’s electricity industry at a CPUC “en banc” meeting. Specifically, the goal of the “en banc” was to frame a discussion on the trends that are driving change within California’s electricity sector and overall clean-energy economy and to lay out elements of a path forward to ensure that California achieves its reliability, affordability, equity, and carbon reduction imperatives while recognizing the important role that technology and customer preferences will play in shaping this future. After the “en banc,” the CPUC formed the California Customer Choice Project to examine the issues and develop a report evaluating choice in California’s current market. On August 7, 2018, the California Customer Choice Project released its report which includes an expanded discussion of policy implementation, procurement, resource adequacy, and information on a central buyer. The CPUC intends to issue a gap analysis to examine the questions raised by the Choice Paper to identify critical issues requiring solutions. The gap analysis will be accompanied by a draft action plan. The CPUC held an additional "en banc" on October 29, 2018, to discuss gap analysis and the draft action plan. While the CPUC had indicated its intent to open a proceeding related to customer choice, the Utility is unable to predict whether that remains the CPUC’s intent or the timing of any such proceeding.

The industry change, costs associated with complying with new regulatory developments and initiatives and with technological advancements, or the Utility’s inability to successfully adapt to changes in the electric industry, could materially affect the Utility’s operations, financial condition, and results of operations.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PR~~OCEEDS~~PROCEEDS

During the quarter ended ~~September 30, 2018,~~March 31, 2019, PG&E Corporation did not make any equity contributions to the Utility. Also during the quarter ended March 31, 2019, PG&E Corporation did not make any sales of unregistered equity securities in reliance on an exemption from registration under the Securities Act of 1933, as amended.

Issuer Purchases of Equity Securities

During the quarter ended ~~September 30, 2018,~~March 31, 2019, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. PG&E Corporation does not have any preferred stock outstanding. During the quarter ended ~~September 30, 2018,~~March 31, 2019, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

ITEM 6. EXHIBITS

EXHIBIT INDEX




3.1	Bylaws of PG&E Corporation amended as of April 10, 2019

3.2	Bylaws of Pacific Gas and Electric Company amended as of ~~August 21, 2018~~

~~4.1~~	Indenture, dated as of August 6, 2018, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018)

~~4.2~~	First Supplemental Indenture, dated as of August 6, 2018, relating to the issuance by Pacific Gas and Electric Company of $500,000,000 aggregate principal amount of 4.25% Senior Notes due 2023 and $300,000,000 aggregate principal amount of 4.65% Senior Notes due 2028 (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018)

~~4.3~~	Registration Rights Agreement, dated as of August 6, 2018, among Pacific Gas and Electric Company, Goldman Sachs & Co. LLC, Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc., as representatives of the initial purchasers (incorporated by reference from PG&E Corporation and Pacific Gas and Electric Company’s Form 8-K dated August 6, 2018)April 5, 2019

10.1	~~Purchase~~Settlement Agreement, dated ~~as of August 2, 2018, among Pacific Gas~~April 22, 2019, by and ~~Electric Company, Goldman Sachs & Co.~~between PG&E Corporation and BlueMountain Capital Management, LLC ~~Mizuho Securities USA LLC, RBC Capital Markets, LLC and SMBC Nikko Securities America, Inc. as representatives of the initial purchasers listed on Schedules I-A and I-B thereto~~ (incorporated by reference ~~from~~to PG&E ~~Corporation and Pacific Gas and Electric Company’s~~Corporation’s Form 8-K dated ~~August 6, 2018)~~April 22, 2019 (File No. 1-12609), Exhibit 10.1)

*10.2	~~Non-Annual Restricted Stock Unit Award~~Senior Secured Superpriority Debtor-in-Possession Credit, Guaranty and Security Agreement, ~~between~~dated February 1, 2019, among Pacific Gas and Electric Company, PG&E Corporation, the financial institutions from time to time party thereto, as lenders and ~~Steven E. Malnight~~issuing lenders, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent (incorporated by reference to PG&E Corporation’s Form 8-K dated ~~September 4, 2018~~February 1, 2019 (File No. 1-12609), Exhibit 10.1)

*10.3	~~Non-Annual Restricted Stock Unit Award~~Separation Agreement between PG&E Corporation and ~~Kathleen B. Kay~~Geisha J. Williams dated ~~September 4,~~January 12, 2019 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2018 (File No. 1-12609), Exhibit 10.21)

*10.4	~~PG&E Corporation and~~Separation Agreement between Pacific Gas and Electric Company ~~Executive Incentive Compensation Recoupment Policy effective February 21,~~and Pat Hogan dated January 7, 2019 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2018 (File No. 1-2348), Exhibit 10.22)

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

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

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

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

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB	XBRL Taxonomy Extension Labels Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

*Management contract or compensatory agreement.

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

SIGNATURES

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

PG&E CORPORATION

/s/ JASON P. WELLS

Jason P. Wells

Senior Vice President and Chief Financial Officer

(duly authorized officer and principal financial officer)

PACIFIC GAS AND ELECTRIC COMPANY

/s/ DAVID S. THOMASON

David S. Thomason

Vice President, Chief Financial Officer and Controller
(duly authorized officer and principal financial officer)

Dated: ~~November 5, 2018~~May 2, 2019

89102



	UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C., 20549 FORM 10-Q
(Mark One)
[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended ~~September 30, 2018~~March 31, 2019 OR
[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________ to __________
Commission File Number		Exact Name of Registrant as Specified in its Charter	State or Other Jurisdiction of Incorporation		IRS Employer Identification Number
1-12609		PG&E Corporation	California		94-3234914
1-2348		Pacific Gas and Electric Company	California		94-0742640

PG&E Corporation 77 Beale Street P.O. Box 770000 San Francisco, California 94177			Pacific Gas and Electric Company 77 Beale Street P.O. Box 770000 San Francisco, California 94177
		Address of principal executive offices, including zip code

PG&E Corporation (415) 973-1000			Pacific Gas and Electric Company (415) 973-7000
		~~Registrant's~~Registrant’s telephone number, including area code

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.
PG&E Corporation:				[X] Yes [ ] No
Pacific Gas and Electric Company:				[X] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
PG&E Corporation:				[X] Yes [ ] No
Pacific Gas and Electric Company:				[X] Yes [ ] No



Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, oran emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
PG&E Corporation:	[X] Large accelerated filer	[ ] Accelerated filer
	[ ] Non-accelerated filer
	[ ] Smaller reporting company	[ ] Emerging growth company
Pacific Gas and Electric Company:	[ ] Large accelerated filer	[ ] Accelerated filer
	[X] Non-accelerated filer
	[ ] Smaller reporting company	[ ] Emerging growth company

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.
PG&E Corporation:		[ ]
PacificGas and Electric Company:		[ ]


Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
PG&E Corporation:		[ ] Yes [X] No
Pacific Gas and Electric Company:		[ ] Yes [X] No



Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, no par value	PCG	NYSE
First preferred stock, cumulative, par value $25 per share, 5% series A redeemable	PCG-PE	NYSE American
First preferred stock, cumulative, par value $25 per share, 5% redeemable	PCG-PD	NYSE American
First preferred stock, cumulative, par value $25 per share, 4.80% redeemable	PCG-PG	NYSE American
First preferred stock, cumulative, par value $25 per share, 4.50% redeemable	PCG-PH	NYSE American
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable	PCG-PI	NYSE American
First preferred stock, cumulative, par value $25 per share, 6% nonredeemable	PCG-PA	NYSE American
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable	PCG-PB	NYSE American
First preferred stock, cumulative, par value $25 per share, 5% nonredeemable	PCG-PC	NYSE American



Indicate the number of shares outstanding of each of the ~~issuer's~~issuer’s classes of common stock, as of the latest practicable date.
Common stock outstanding as of ~~October~~April 25, ~~2018:~~2019:
PG&E Corporation:								~~518,674,276~~529,210,278
Pacific Gas and Electric Company:								264,374,809



GLOSSARY
PART I. FINANCIAL INFORMATION
	ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
	PG&E CORPORATION
	CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	CONDENSED CONSOLIDATED BALANCE SHEETS
	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	PACIFIC GAS AND ELECTRIC COMPANY
	CONDENSED CONSOLIDATED STATEMENTS OF INCOME
	CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	CONDENSED CONSOLIDATED BALANCE SHEETS
	CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
	NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
	NOTE 2: BANKRUPTCY FILING
	NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
	NOTE 3:4: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS
	NOTE 4:5: DEBT
	NOTE 5:6: EQUITY
	NOTE 6:7: EARNINGS PER SHARE
	NOTE 7:8: DERIVATIVES
	NOTE 8:9: FAIR VALUE MEASUREMENTS
	NOTE 9:10: WILDFIRE-RELATED CONTINGENCIES
	NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	OVERVIEW
	RESULTS OF OPERATIONS
	LIQUIDITY AND FINANCIAL RESOURCES
	ENFORCEMENT AND LITIGATION MATTERS
	REGULATORY MATTERS
	LEGISLATIVE AND REGULATORY INITIATIVES
	ENVIRONMENTAL MATTERS
	CONTRACTUAL COMMITMENTS
	RISK MANAGEMENT ACTIVITIES
	RECENT DEVELOPMENTS
	CRITICAL ACCOUNTING POLICIES
	ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED
	FORWARD-LOOKING STATEMENTS
	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
	ITEM 1. LEGAL PROCEEDINGS
	ITEM 1A. RISK FACTORS
	ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
	ITEM 6. EXHIBITS
	SIGNATURES



~~2017~~2018 Form 10-K	PG&E Corporation and Pacific Gas and Electric ~~Company's~~Company’s combined Annual Report on Form 10-K for the year ended December 31, ~~2017~~2018
2019 Wildfire Safety Plan	the wildfire mitigation plan for 2019 submitted by the Utility to the CPUC pursuant to SB 901
ALJ	administrative law judge
ARO	asset retirement obligation
ASU	accounting standard update issued by the FASB (see below)
Bankruptcy Code	the United States Bankruptcy Code
Bankruptcy Court	the U.S. Bankruptcy Court for the Northern District of California
CAISO	California Independent System Operator
Cal Fire	California Department of Forestry and Fire Protection
Cal PA	Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)
CCA	Community Choice Aggregator
CEC	California Energy Resources Conservation and Development Commission
CEMA	Catastrophic Event Memorandum Account
Chapter 11	chapter 11 of title 11 of the U.S. Code
Chapter 11 Cases	the voluntary cases commenced by each of PG&E Corporation and the Utility under Chapter 11 on January 29, 2019
CPUC	California Public Utilities Commission
CRRs	congestion revenue rights
CWSP	Community Wildfire Safety Program
DA	Direct Access
DER	distributed energy resources
Diablo Canyon	Diablo Canyon nuclear power plant
DIP Credit Agreement	Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, and Citibank, N.A., as collateral agent
DOGGR	Division of Oil, Gas, and Geothermal Resources of the California Department of Conservation
DRP	Distribution Resource Plan
DTSC	Department of Toxic Substances Control
EPS	earnings per common share
EV	electric vehicle
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FHPMA	fire hazard prevention memorandum account
FRMMA	fire risk mitigation memorandum account
GAAP	U.S. Generally Accepted Accounting Principles
GHG	greenhouse gas
GRC	general rate case
GT&S	gas transmission and storage
HSM	hazardous substance memorandum account
IOU(s)	investor-owned utility(ies)
LIBOR	London Interbank Offered Rate
LSTC	liabilities subject to compromise



MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations set forth in Item 2 of this Form 10-Q
MGP(s)	manufactured gas plants
the Monitor	third-party monitor retained as part of its compliance with the sentencing terms of the Utility’s January 27, 2017 federal criminal conviction
NAV	net asset value
NDCTP	Nuclear Decommissioning Cost Triennial Proceedings
NEIL	Nuclear Electric Insurance Limited
NRC	Nuclear Regulatory Commission
OES	State of California Office of Emergency Services
OII	order instituting investigation
OIR	order instituting rulemaking
PAO	Public Advocates Office of the California Public Utilities Commission (formerly known as Office of Ratepayer Advocates or ORA)
PCIA	Power Charge Indifference Adjustment
PD	proposed decision
Petition Date	January 29, 2019
PFM	petition for modification
RAMP	Risk Assessment Mitigation Phase
ROE	return on equity
ROU asset	right-of-use asset
SB	Senate Bill



SEC	U.S. Securities and Exchange Commission
SED	Safety and Enforcement Division of the CPUC
Strike Force Report	California Governor Gavin Newsom’s “Strike Force” report in connection with the issues of wildfire, climate change and the state’s energy sector issued on April 12, 2019
Tax Act	Tax Cuts and Jobs Act of 2017
TE	transportation electrification
TO	transmission owner
TURN	The Utility Reform Network
USAO	United States Attorney’s Office for the Northern District of California
Utility	Pacific Gas and Electric Company
VIE(s)	variable interest entity(ies)
WEMA	Wildfire Expense Memorandum Account
Wildfire Assistance Fund	program to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs


	(Unaudited)												(Unaudited)
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
(in millions, except per share amounts)	2018			2017			2018			2017			2019			2018
Operating Revenues
Electric	$	3,466		$	3,648		$	9,729		$	10,036		$	2,792		$	2,951
Natural gas	915			869			2,942			2,999			1,219			1,105
Total operating revenues	4,381			4,517			12,671			13,035			4,011			4,056
Operating Expenses
Cost of electricity	1,256			1,466			3,038			3,436			599			819
Cost of natural gas	69			78			437			524			339			289
Operating and maintenance	1,611			1,324			5,001			4,453			2,087			1,604
Wildfire-related claims, net of insurance recoveries	(10		)	53			2,108			—			—			(7		)
Depreciation, amortization, and decommissioning	759			710			2,257			2,134			797			752
Total operating expenses	3,685			3,631			12,841			10,547			3,822			3,457
Operating Income (Loss)	696			886			(170		)	2,488
Operating Income													189			599
Interest income	14			9			35			22			22			9
Interest expense	(232		)	(220		)	(678		)	(663		)	(103		)	(220		)
Other income, net	104			38			318			98			71			108
Income (Loss) Before Income Taxes	582			713			(495		)	1,945
Reorganization items, net													(127		)	—
Income Before Income Taxes													52			496
Income tax provision (benefit)	15			160			(527		)	403			(84		)	51
Net Income	567			553			32			1,542			136			445
Preferred stock dividend requirement of subsidiary	3			3			10			10			—			3
Income Available for Common Shareholders	$	564		$	550		$	22		$	1,532		$	136		$	442
Weighted Average Common Shares Outstanding, Basic	517			513			516			511			526			515
Weighted Average Common Shares Outstanding, Diluted	517			516			517			514			527			516
Net Earnings Per Common Share, Basic	$	1.09		$	1.07		$	0.04		$	3.00		$	0.25		$	0.86
Net Earnings Per Common Share, Diluted	$	1.09		$	1.07		$	0.04		$	2.98		$	0.25		$	0.86

See accompanying Notes to the Condensed Consolidated Financial Statements.	See accompanying Notes to the Condensed Consolidated Financial Statements.												See accompanying Notes to the Condensed Consolidated Financial Statements.



	(Unaudited)
	Balance At
(in millions)	September 30, 2018			December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents	$	430		$	449
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates)	1,297			1,243
Accrued unbilled revenue	962			946
Regulatory balancing accounts	1,326			1,222
Other	902			861
Regulatory assets	229			615
Inventories:
Gas stored underground and fuel oil	116			115
Materials and supplies	389			366
Other	698			464
Total current assets	6,349			6,281
Property, Plant, and Equipment
Electric	56,860			55,133
Gas	20,798			19,641
Construction work in progress	2,855			2,471
Other	2			3
Total property, plant, and equipment	80,515			77,248
Accumulated depreciation	(24,310		)	(23,459		)
Net property, plant, and equipment	56,205			53,789
Other Noncurrent Assets
Regulatory assets	4,429			3,793
Nuclear decommissioning trusts	2,917			2,863
Income taxes receivable	67			65
Other	1,418			1,221
Total other noncurrent assets	8,831			7,942
TOTAL ASSETS	$	71,385		$	68,012

See accompanying Notes to the Condensed Consolidated Financial Statements.



	(Unaudited)
	Balance At
(in millions, except share amounts)	September 30, 2018			December 31, 2017
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	750		$	931
Long-term debt, classified as current	193			445
Accounts payable:
Trade creditors	1,699			1,646
Regulatory balancing accounts	1,230			1,120
Other	556			517
Disputed claims and customer refunds	217			243
Interest payable	151			217
Wildfire-related claims	2,794			561
Other	1,899			1,449
Total current liabilities	9,489			7,129
Noncurrent Liabilities
Long-term debt	18,407			17,753
Regulatory liabilities	8,607			8,679
Pension and other post-retirement benefits	2,014			2,128
Asset retirement obligations	4,999			4,899
Deferred income taxes	5,822			5,822
Other	2,351			2,130
Total noncurrent liabilities	42,200			41,411
Contingencies and Commitments (Note 9)
Equity
Shareholders' Equity
Common stock, no par value, authorized 800,000,000 shares; 517,102,983 and 514,755,845 shares outstanding at respective dates	12,833			12,632
Reinvested earnings	6,623			6,596
Accumulated other comprehensive loss	(12		)	(8		)
Total shareholders' equity	19,444			19,220
Noncontrolling Interest - Preferred Stock of Subsidiary	252			252
Total equity	19,696			19,472
TOTAL LIABILITIES AND EQUITY	$	71,385		$	68,012

See accompanying Notes to the Condensed Consolidated Financial Statements.


	(Unaudited)						(Unaudited)
	Nine Months Ended September 30,						Three Months Ended March 31,
(in millions)	2018			2017			2019			2018
Cash Flows from Operating Activities
Net income	$	32		$	1,542		$	136		$	445
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,257			2,134			797			752
Allowance for equity funds used during construction	(97		)	(63		)	(25		)	(32		)
Deferred income taxes and tax credits, net	10			848			4			178
Disallowed capital expenditures	(38		)	47
Reorganization items, net (Note 2)							19			—
Other	231			204			16			30
Effect of changes in operating assets and liabilities:
Accounts receivable	(201		)	(58		)	(31		)	120
Wildfire-related insurance receivable	64			(166		)	25			197
Inventories	(24		)	(35		)	18			28
Accounts payable	245			76			(180		)	24
Wildfire-related claims	2,233			12			(14		)	(118		)
Income taxes receivable/payable	—			135			23			—
Other current assets and liabilities	(154		)	23			150			(145		)
Regulatory assets, liabilities, and balancing accounts, net	(128		)	(30		)	343			114
Liabilities subject to compromise							833			—
Other noncurrent assets and liabilities	(194		)	68			130			(81		)
Net cash provided by operating activities	4,236			4,737			2,244			1,512
Cash Flows from Investing Activities
Capital expenditures	(4,592		)	(3,938		)	(1,224		)	(1,470		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,121			1,043			346			494
Purchases of nuclear decommissioning trust investments	(1,165		)	(1,071		)	(372		)	(505		)
Other	19			16			3			6
Net cash used in investing activities	(4,617		)	(3,950		)	(1,247		)	(1,475		)
Cash Flows from Financing Activities
Borrowings under revolving credit facilities	775			—
Repayments under revolving credit facilities	(775		)	—
Net issuances (repayments) of commercial paper, net of discount of $1 and $4 at respective dates	(182		)	(652		)
Proceeds from debtor-in-possession credit facility							350			—
Debtor-in-possession credit facility debt issuance costs							(111		)	—
Net issuances (repayments) of commercial paper, net of discount							—			36
Short-term debt financing	250			250			—			250
Short-term debt matured	(250		)	(250		)	—			(250		)
Proceeds from issuance of long-term debt, net of discount and issuance costs of $7 and $11 at respective dates	1,143			734
Long-term debt matured or repurchased	(750		)	(345		)	—			(400		)
Common stock issued	137			345			85			35
Common stock dividends paid	—			(754		)
Other	14			(101		)	(24		)	(13		)
Net cash provided by (used in) financing activities	362			(773		)	300			(342		)
Net change in cash and cash equivalents	(19		)	14
Cash and cash equivalents at January 1	449			177
Cash and cash equivalents at September 30	$	430		$	191
Net change in cash, cash equivalents, and restricted cash							1,297			(305		)
Cash, cash equivalents, and restricted cash at January 1							1,675			456
Cash, cash equivalents, and restricted cash at March 31							$	2,972		$	151
Less: Restricted cash and restricted cash equivalents included in other current assets							(8		)	$	(7	)
Cash and cash equivalents at March 31							$	2,964		$	144


Supplemental disclosures of cash flow information
Cash received (paid) for:
Interest, net of amounts capitalized	$	(650	)	$	(644	)	$	(10	)	$	(268	)
Income taxes, net	(49		)	158
Supplemental disclosures of noncash operating activities
Operating lease liabilities arising from obtaining ROU assets							$	2,816		$	—
Supplemental disclosures of noncash investing and financing activities
Common stock dividends declared but not yet paid	$	—		$	272
Capital expenditures financed through accounts payable	348			301			$	242		$	255
Noncash common stock issuances	—			16
Terminated capital leases	161			—

See accompanying Notes to the Condensed Consolidated Financial Statements.



(in millions)	PG&E Corporation⁽¹⁾		Utility		PG&E Corporation Consolidated
Financing debt⁽²⁾	$	650	$	21,811	$	22,461
Wildfire-related claims⁽³⁾	—		14,212		14,212
Trade creditors	1		1,850		1,851
Non-qualified benefit plan	122		17		139
2001 bankruptcy disputed claims	—		221		221
Customer deposits & advances	—		272		272
Other	2		164		166
Total Liabilities Subject to Compromise	$	775	$	38,547	$	39,322



	Post-Petition Period Through March 31, 2019
(in millions)	PG&E Corporation⁽¹⁾			Utility			PG&E Corporation Consolidated
Debtor-in-possession financing costs	17			97			114
Legal and other	$	1		$	23		$	24
Interest income	(2		)	(9		)	(11		)
Total reorganization items, net	$	16		$	111		$	127



	Pension Benefits						Other Benefits
	Three Months Ended September 30,
(in millions)	2018			2017			2018			2017
Service cost for benefits earned⁽¹⁾	$	128		$	118		$	16		$	14
Interest cost	171			178			17			20
Expected return on plan assets	(255		)	(193		)	(33		)	(24		)
Amortization of prior service cost	(1		)	(1		)	4			4
Amortization of net actuarial loss	1			6			(1		)	1
Net periodic benefit cost	44			108			3			15
Regulatory account transfer⁽²⁾	41			(23		)	—			—
Total	$	85		$	85		$	3		$	15



	Pension Benefits			Other Benefits			Total
(in millions, net of income tax)	Three Months Ended September 30, 2018
Beginning balance	$	(30	)	$	17		$	(13	)
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (net of taxes of $0 and $1, respectively)⁽¹⁾	(1		)	3			2
Amortization of net actuarial loss (net of taxes of $0 and $0, respectively)⁽¹⁾	1			(1		)	—
Regulatory account transfer (net of taxes of $0 and $1, respectively)⁽¹⁾	1			(2		)	(1		)
Net current period other comprehensive gain (loss)	1			—			1
Ending balance	$	(29	)	$	17		$	(12	)



(in millions)	Three Months Ended March 31, 2019
Operating lease fixed cost	$	122
Operating lease variable cost	309
Total operating lease costs	$	431



(in millions)	March 31, 2019
2019	$	686
2020	669
2021	616
2022	523
2023	195
Thereafter	672
Total lease payments	3,361
Less imputed interest	(633		)
Total	$	2,728



(in millions)	December 31, 2018
2019	$	684
2020	677
2021	621
2022	546
2023	252
Thereafter	581
Total lease commitments	$	3,361


	Asset Balance at				Asset Balance at
(in millions)	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Pension benefits(1)	$	1,837	$	1,954	$	1,938	$	1,947
Environmental compliance costs	851		837		932		1,013
Utility retained generation(2)	285		319		262		274
Price risk management	67		65		65		90
Unamortized loss, net of gain, on reacquired debt(3)	80		79		237		76
Catastrophic event memorandum account ⁽¹⁾⁽⁴⁾	760		274		865		790
Wildfire expense memorandum account ⁽²⁾⁽⁵⁾	77		—		111		94
Fire hazard prevention memorandum account ⁽³⁾⁽⁶⁾	65		1		329		263
Other	407		264		412		417
Total long-term regulatory assets	$	4,429	$	3,793	$	5,151	$	4,964


	Liability Balance at				Liability Balance at
(in millions)	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Cost of removal obligations(1)	$	5,888	$	5,547	$	6,134	$	5,981
Deferred income taxes(2)	437		1,021		142		283
Recoveries in excess of AROs(3)	489		624		471		356
Public purpose programs(4)	660		590		758		674
Retirement Plan⁽⁵⁾					422		421
Other	1,133		897		945		824
Total long-term regulatory liabilities	$	8,607	$	8,679	$	8,872	$	8,539


	Receivable Balance at				Receivable Balance at
(in millions)	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Electric distribution	$	31	$	—	$	449	$	160
Electric transmission	109		139		128		128
Utility generation					357		79
Gas distribution and transmission	624		486		70		462
Energy procurement	131		71		137		168
Public purpose programs	120		103		76		111
Other	311		423		280		327
Total regulatory balancing accounts receivable	$	1,326	$	1,222	$	1,497	$	1,435


	Payable Balance at				Payable Balance at
(in millions)	September 30, 2018		December 31, 2017		March 31, 2019		December 31, 2018
Electric distribution	$	—	$	72
Electric transmission	132		120		146		134
Utility generation	70		14
Gas distribution and transmission	9		—		51		9
Energy procurement	69		149		223		59
Public purpose programs	588		452		600		587
Other	362		313		325		287
Total regulatory balancing accounts payable	$	1,230	$	1,120	$	1,345	$	1,076



(in millions)	Termination Date		Limit			Letters of Credit Outstanding		Borrowings Against DIP Revolving Facility		Availability
DIP Facilities	December 2020	(1)	$	1,500	(2)	$	131	$	350	$	1,019


												Balance at,
(in millions)	Termination Date	Facility Limit			Letters of Credit Outstanding		Borrowings		Facility Availability		Contractual Interest Rates	March 31, 2019		December 31, 2018
Debt Subject to Compromise⁽¹⁾
PG&E Corporation	April 2022	$	300	⁽¹⁾	$	—	$	—	$	300
Borrowings under Pre-Petition Credit Facilities
PG&E Corporation Revolving Credit Facilities - Stated Maturity: 2022											variable rate⁽²⁾	$	300	$	300
Other borrowings:
Term Loan - Stated Maturity: 2020											variable rate⁽³⁾	350		350
Total PG&E Corporation Debt Subject to Compromise												650		650

Utility	April 2022	3,000		⁽²⁾	87		—		2,913
Total revolving credit facilities		$	3,300		$	87	$	—	$	3,213
Senior Notes - Stated Maturity:
2020											3.50%	800		800
2021											3.25% to 4.25%	550		550
2022											2.45%	400		400
2023											3.25% to 4.25%	1,175		1,175
2024 through 2046											2.95% to 6.35%	14,600		14,600
Unamortized discount, net or premium and debt issuance costs												—		(178		)
Total Senior notes, net of premium and debt issuance costs												17,525		17,347
Pollution Control Bonds - Stated Maturity:
Series 2008 F and 2010 E, due 2026⁽⁴⁾											1.75%	100		100
Series 2009 A-B, due 2026⁽⁵⁾											variable rate ⁽⁶⁾	149		149
Series 1996 C, E, F, 1997 B due 2026⁽⁵⁾											variable rate ⁽⁷⁾	614		614
Total pollution control bonds												863		863
Borrowings under Pre-Petition Credit Facilities
Utility Revolving Credit Facilities - Stated Maturity: 2022 ⁽⁸⁾											variable rate⁽⁹⁾	2,965		2,965
Other borrowings:
Term Loan - Stated Maturity: 2019											variable rate⁽¹⁰⁾	250		250
Total Borrowings under Pre-Petition Credit Facility Subject to Compromise												3,215		3,215
Total Utility Debt Subject to Compromise												21,603		21,425
Total PG&E Corporation Consolidated Debt Subject to Compromise												$	22,253	$	22,075



(in millions, except share amounts)	Common Stock Shares	Common Stock Amount		Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity		Non controlling Interest - Preferred Stock of Subsidiary		Total Equity
Balance at December 31, 2018	520,338,710	$	12,910	$	(250	)	$	(9	)	$	12,651	$	252	$	12,903
Net income (loss)	—	—		136			—			136		—		136
Other comprehensive loss	—	—		—			—			—		—		—
Common stock issued, net	8,871,568	85		—			—			85		—		85
Stock-based compensation amortization	—	5		—			—			5		—		5
Balance at March 31, 2019	529,210,278	$	13,000	$	(114	)	$	(9	)	$	12,877	$	252	$	13,129



(in millions)	Preferred Stock		Common Stock Amount		Additional Paid-in Capital		Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity
Balance at December 31, 2018	$	258	$	1,322	$	8,550	$	2,826	$	(1	)	$	12,955
Net income (loss)	—		—		—		133		—			133
Other comprehensive loss	—		—		—		—		—			—
Equity contribution	—		—		—		—		—			—
Preferred stock dividend	—		—		—		—		—			—
Balance at March 31, 2019	$	258	$	1,322	$	8,550	$	2,959	$	(1	)	$	13,088


		Contract Volume at			Contract Volume at
Underlying Product	Instruments	September 30, 2018	December 31, 2017	Instruments	March 31, 2019	December 31, 2018
Natural Gas ⁽¹⁾ (MMBtus ⁽²⁾)	Forwards, Futures and Swaps	250,021,802	228,768,745	Forwards, Futures and Swaps	138,016,980	177,750,349
	Options	29,534,224	60,736,806	Options	4,115,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,939,691	2,872,013	Forwards, Futures and Swaps	3,011,826	3,833,490
	Congestion Revenue Rights ⁽³⁾	316,451,690	312,272,177	Congestion Revenue Rights ⁽³⁾	335,556,726	340,783,089



	Commodity Risk
(in millions)	Gross Derivative Balance			Netting			Cash Collateral		Total Derivative Balance
Current assets – other	$	45		$	(2	)	$	38	$	81
Other noncurrent assets – other	165			1			—		166
Current liabilities – other	(37		)	17			3		(17		)
Noncurrent liabilities – other	(49		)	(16		)	—		(65		)
Total commodity risk	$	124		$	—		$	41	$	165


	Fair Value Measurements											Fair Value Measurements
	September 30, 2018											March 31, 2019
(in millions)	Level 1		Level 2		Level 3		Netting ⁽¹⁾			Total		Level 1		Level 2		Level 3		Netting ⁽¹⁾			Total
Assets:
Short-term investments	$	377	—		—		—			$	377	$	2,898	$	—	$	—	$	—		$	2,898
Nuclear decommissioning trusts
Short-term investments	14		—		—		—			14		18		—		—		—			18
Global equity securities	1,970		—		—		—			1,970		1,882		—		—		—			1,882
Fixed-income securities	738		631		—		—			1,369		790		692		—		—			1,482
Assets measured at NAV	—		—		—		—			19		—		—		—		—			18
Total nuclear decommissioning trusts ⁽²⁾	2,722		631		—		—			3,372		2,690		692		—		—			3,400
Price risk management instruments (Note 7)
Price risk management instruments (Note 8)
Electricity	1		5		110		2			118		—		1		209		15			225
Gas	—		6		—		1			7		—		—		—		22			22
Total price risk management instruments	1		11		110		3			125		—		1		209		37			247
Rabbi trusts
Fixed-income securities	—		75		—		—			75		—		96		—		—			96
Life insurance contracts	—		68		—		—			68		—		69		—		—			69
Total rabbi trusts	—		143		—		—			143		—		165		—		—			165
Long-term disability trust
Short-term investments	8		—		—		—			8		8		—		—		—			8
Assets measured at NAV	—		—		—		—			112		—		—		—		—			146
Total long-term disability trust	8		—		—		—			120		8		—		—		—			154
TOTAL ASSETS	$	3,108	$	785	$	110	$	3		$	4,137	$	5,596	$	858	$	209	$	37		$	6,864
Liabilities:
Price risk management instruments (Note 7)
Price risk management instruments (Note 8)
Electricity	$	5	$	12	$	86	$	(17	)	$	86	$	1	$	3	$	80	$	(4	)	$	80
Gas	—		3		—		(1		)	2		—		2		—		—			2
TOTAL LIABILITIES	$	5	$	15	$	86	$	(18	)	$	88	$	1	$	5	$	80	$	(4	)	$	82


	Fair Value at							Fair Value at
(in millions)	September 30, 2018							March 31, 2019
Fair Value Measurement	Assets		Liabilities		Valuation Technique	Unobservable Input	Range ⁽¹⁾	Assets		Liabilities		Valuation Technique	Unobservable Input	Range ⁽¹⁾
Congestion revenue rights	$	110	$	44	Market approach	CRR auction prices	$ (18.61) - 32.26	$	203	$	60	Market approach	CRR auction prices	$(36.87) - 23.04
Power purchase agreements	$	—	$	42	Discounted cash flow	Forward prices	$ 19.81 - 38.80	$	6	$	20	Discounted cash flow	Forward prices	$ 19.81 - 38.80



	Price Risk Management Instruments
(in millions)	2018			2017
Asset (liability) balance as of July 1	$	34		$	48
Net realized and unrealized gains:
Included in regulatory assets and liabilities or balancing accounts ⁽¹⁾	(10		)	—
Asset (liability) balance as of September 30	$	24		$	48


	At September 30, 2018				At December 31, 2017				At March 31, 2019		At December 31, 2018
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value		Carrying Amount	Level 2 Fair Value	Carrying Amount		Level 2 Fair Value
PG&E Corporation⁽¹⁾	$	350	$	350	$	350	$	350	—	—	$	350	$	350
Utility(2)	17,491		16,413		17,090		19,128		350	350	17,450		14,747


(in millions)
As of September 30, 2018	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
As of March 31, 2019										Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	14	$	—	$	—		$	14	$	18	$	—	$	—		$	18
Global equity securities	478		1,513		(2		)	1,989		481		1,422		(3		)	1,900
Fixed-income securities	1,369		28		(28		)	1,369		1,432		58		(8		)	1,482
Total⁽¹⁾	$	1,861	$	1,541	$	(30	)	$	3,372	$	1,931	$	1,480	$	(11	)	$	3,400
As of December 31, 2017
As of December 31, 2018
Nuclear decommissioning trusts
Short-term investments	$	23	$	—	$	—		$	23	$	29	$	—	$	—		$	29
Global equity securities	524		1,463		(2		)	1,985		568		1,246		(5		)	1,809
Fixed-income securities	1,252		51		(8		)	1,295		1,288		30		(18		)	1,300
Total⁽¹⁾	$	1,799	$	1,514	$	(10	)	$	3,303	$	1,885	$	1,276	$	(23	)	$	3,138