Non-service costs are reflected in Other income, net on the Condensed Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Condensed Consolidated Statements of Income.

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

On February 27, 2019, PG&E Corporation and the Utility received final approval from the Bankruptcy Court to maintain existing pension and other benefit plans, other than the non-qualified pension plan, during the pendency of the Chapter 11 Cases.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income(Loss)

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) are summarized below:

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in accounts receivable on the Condensed Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

~~Presentation of Net Periodic Pension and Post-Retirement Benefit Costs~~Recently Adopted Accounting Standards

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, the recognition of lease assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements. Under the new standard, all lessees must recognize ana ROU asset, reflecting the right to use the underlying asset for the lease term, and a lease liability, reflecting the obligation to make lease payments, on the balance sheet. Operating leases were previously not recognized on the balance sheet. ~~The ASU will be effective for~~ PG&E Corporation and the Utility adopted the ASU on January 1, ~~2019, with early adoption permitted.~~2019.

PG&E Corporation and the Utility ~~intend to elect~~elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. After adoption of the new standard, the Corporation and Utility elected to not separate lease and non-lease components. Additionally, PG&E Corporation and the Utility dohave elected not ~~intend~~ to restate comparative periods upon adoption.

PG&E Corporation and the Utility ~~plan to adopt this guidance in~~determine if an arrangement is a lease at inception. As most of the ~~first quarter of 2019. PG&E Corporation and~~leases do not provide implicit discount rates, the Utility ~~expect this standard~~uses an estimate of its incremental secured borrowing rates based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities include only fixed lease payments. Leases with an initial term of 12 months or less are not recorded on the balance sheet. Lease terms will only include options to ~~increase~~extend or terminate the lease when it is reasonably certain that the Utility will exercise such options. The Utility recognizes lease expense in conformity with ratemaking.

Operating leases are included in operating lease ROU assets and current and noncurrent operating lease liabilities on the Condensed Consolidated Balance ~~Sheets~~Sheets. Finance leases are included in property, plant, and ~~do not expect the guidance will have a material impact~~equipment, other current liabilities, and other noncurrent liabilities on the Condensed Consolidated ~~Statements of Income, Statements~~Balance Sheets. Financing leases were immaterial for the six months ended June 30, 2019.

The majority of the Utility’s ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins, for terms between 5 years and 20 years. PG&E Corporation and the Utility have also recorded ROU assets and lease liabilities related ~~disclosures.~~to property and land leases.

The following table shows the Utility’s future expected obligations for power purchase and other lease commitments:

Accounting Standards Issued But Not Yet Adopted

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Condensed Consolidated Financial Statements and related disclosures.

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and ~~Other-Internal-Use~~Other – Internal-Use Software (Subtopic 350-40): ~~Customer's~~Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact of the guidance ~~will have~~ on their Condensed Consolidated Financial Statements and related disclosures.

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326), which provides a model, known as the current expected credit loss model, to estimate the expected lifetime credit loss on financial assets, including trade and other receivables, rather than incurred losses over the remaining life of most financial assets measured at amortized cost. The guidance also requires use of an allowance to record estimated credit losses on available-for-sale debt securities. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020. PG&E Corporation and the Utility are currently evaluating the impact of the guidance on their Condensed Consolidated Financial Statements and related disclosures.

Current Regulatory Liabilities

Current regulatory liabilities are primarily comprised of the ~~Utility believes are probable~~current portion of ~~recovery. For more information, see Note 9 below.~~the tax reform adjustment recorded as a result of the Tax Act.

⁽³⁾~~Represents costs related to wildfire prevention vegetation management work that the Utility believes are probable of recovery.~~

Long-term regulatory liabilities are comprised of the following:

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.

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

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.

NOTE 4: 5: DEBT

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement, among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the “DIP Lenders”). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility,” together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein. The DIP Credit Agreement also provides for up to $4.0 billion of incremental facilities in the form of (i) one or more additional tranches of term loans or (ii) one or more increases in the aggregate amount of revolving commitments under the DIP Revolving Facility (together, the “Incremental Facilities”), subject to the terms and conditions set forth therein. The Incremental Facilities are uncommitted and would require approval from the Bankruptcy Court.

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to the Utility. On March 27, 2019, the Bankruptcy Court approved the DIP Facilities on a final basis, authorizing the Utility to borrow up to the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, in each case subject to the terms and conditions of the DIP Credit Agreement.

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case.

On February 1, 2019, the Utility borrowed $350 million under the DIP Revolving Facility. On April 3, 2019, following the Bankruptcy Court’s final approval of the DIP Facilities, the Utility borrowed $1.5 billion under the DIP Initial Term Loan Facility and repaid the $350 million outstanding under the DIP Revolving Facility.

The commencement of the Chapter 11 Cases constituted an event of default or termination event with respect to, and caused an automatic and immediate acceleration of the debt outstanding under or in respect of, certain instruments and agreements relating to direct financial obligations of PG&E Corporation and the Utility (the “Accelerated Direct Financial Obligations”). However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the Utility’s outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation’s term loan facility, as well as short-term borrowings under PG&E Corporation’s and the Utility’s revolving credit facilities and the Utility’s term loan facility. For more information, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

The following table summarizes the Utility’s outstanding borrowings and availability under the DIP Facilities at June 30, 2019:

As of June 30, 2019, PG&E Corporation and ~~Commercial Paper Program~~the Utility each had no commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

The following table summarizes PG&E Corporation’s and the Utility’s outstanding ~~borrowings under their revolving credit facilities and commercial paper programs at September 30, 2018:~~

There were no issuances under the PG&E Corporation February 2017 equity distribution agreement for the ~~nine~~six months ended ~~September~~June 30, ~~2018. As of September 30, 2018, the remaining amount available under this agreement was $246.3 million.~~2019.

PG&E Corporation issued common stock under the PG&E Corporation 401(k) plan and share-based compensation plans. During the ~~nine~~six months ended ~~September~~June 30, ~~2018, 3.6~~2019, 8.9 million shares were issued for cash proceeds of ~~$136.7~~$85 million under these plans. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E Corporation common stock to cash. Beginning in March 2019, at PG&E Corporation’s directive, the 401(k) plan trustee began purchasing new shares in the PG&E Corporation common stock fund on the open market rather than directly from PG&E Corporation.

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with the Northern California wildfires. See Wildfire-related contingencies in Note 10 below.

The ~~dividends declared per share on~~DIP Credit Agreement includes usual and customary covenants for debtor-in-possession loan agreements of this type, including covenants limiting PG&E ~~Corporation's common stock were $0~~Corporation’s and ~~$0.53, for~~ the ~~three months ended September 30, 2018~~Utility’s ability to, among other things, declare and ~~2017, respectively,~~pay any dividend or make any other distributions with respect to any of their capital stock. Also, on April 3, 2019, the court overseeing the Utility’s probation issued an order imposing new conditions of probation, including foregoing issuing “any dividends until [the Utility] is in compliance with all applicable vegetation management requirements under applicable law and ~~$0 and $1.55 for~~ the ~~nine months ended September 30, 2018 and 2017, respectively.~~Utility’s wildfire mitigation plan.” PG&E Corporation does not expect to pay any cash dividends during the Chapter 11 Cases.

At ~~September~~June 30, 2019, the Utility’s outstanding derivative balances were as follows:



	Commodity Risk
(in millions)	Gross Derivative Balance			Netting			Cash Collateral		Total Derivative Balance
Current assets – other	$	47		$	(4	)	$	48	$	91
Other noncurrent assets – other	161			—			—		161
Current liabilities – other	(25		)	4			3		(18		)
Noncurrent liabilities – other	(67		)	—			—		(67		)
Total commodity risk	$	116		$	—		$	51	$	167

At December 31, 2018, the Utility’s outstanding derivative balances were as follows:



	Commodity Risk
(in millions)	Gross Derivative Balance			Netting			Cash Collateral		Total Derivative Balance
Current assets – other	$	44		$	(1	)	$	89	$	132
Other noncurrent assets – other	165			—			—		165
Current liabilities – other	(29		)	1			7		(21		)
Noncurrent liabilities – other	(90		)	—			2		(88		)
Total commodity risk	$	90		$	—		$	98	$	188

Commodity Risk
(in millions)
Gross Derivative
Balance
Netting Cash Collateral
Total Derivative
Balance
Current assets – other $ 34
$ (2 ) $ 5
$ 37
Other noncurrent assets – other 88
—
—
88
Current liabilities – other (39 ) 2
12
(25 )
Noncurrent liabilities – other (67 ) —
4
(63 )
Total commodity risk $ 16
$ —
$ 21
$ 37

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Condensed Consolidated Statements of Cash Flows.

The majority of the Utility’s derivatives instruments, including ~~certain~~ power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. ~~The~~During the first quarter of 2019, multiple credit rating agencies downgraded the Utility’s credit ~~rating remains investment grade. If the Utility credit rating were to fall~~ratings below investment grade, which resulted in the Utility ~~would be required to post~~posting additional ~~cash immediately to fully collateralize some~~collateral. As of ~~its net liability derivative positions.~~

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above. There are no restrictions on the terms and conditions upon which the investments may be redeemed. Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period. There were no material transfers between any levels for the ~~nine~~three and six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~2018.

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks. Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities. U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets. A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads. The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Condensed Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

Price Risk Management Instruments

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

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

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

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market. Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

The Utility’s market and credit risk management function, which reports to PG&E Corporation’s Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives. The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative. Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively. All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments. (See Note 78 above.)

The following tables present the reconciliation for Level 3 price risk management instruments for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017:~~2018:

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts ~~receivable,~~receivable; short-term ~~borrowings,~~borrowings; accounts ~~payable,~~payable; and customer deposits ~~and the Utility’s variable rate pollution control bond loan agreements~~to approximate their carrying values at ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, as they are short-term in ~~nature or have interest rates that reset daily.~~nature.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s debt instruments were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

The following table provides a summary of equity securities and available-for-sale debt securities:

The fair value of fixed-income securities by contractual maturity is as follows:

The following table provides a summary of activity for fixed income and equity securities:

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to ~~enforcement and litigation matters and environmental remediation.~~wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E ~~Corporation's~~Corporation’s and the ~~Utility's~~Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

~~Enforcement and Litigation Matters~~

Wildfire-related claims on the Condensed Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

At ~~September~~June 30, ~~2018~~2019 and December 31, ~~2017,~~2018, the ~~Utility's~~Utility’s Condensed Consolidated Balance Sheets include estimated ~~losses~~liabilities in respect of total wildfire-related claims as follows:

In addition, during the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $19 million and $32 million, respectively, related to the 2018 Camp fire, with no corresponding costs in the same periods in 2018. During the three and six months ended June 30, 2019, the Utility incurred legal and other costs of $7 million and $41 million, respectively, related to the 2017 Northern California wildfires, as compared to $46 million and $68 million, respectively, in the same periods in 2018.

On November 8, 2018, a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire’s Camp Fire Incident Information Website as of July 9, 2019 (the “Cal Fire website”) indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 85 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. There have been no subsequent updates of this information on the Cal Fire website.

On May 15, 2019, Cal Fire issued a news release announcing the results of its investigation into the cause of the 2018 Camp fire. According to the news release:

Cal Fire indicated in its news release that its investigation report for the 2018 Camp fire has been forwarded to the Butte County District Attorney. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the 2018 Camp fire.) As of the date of this filing, this investigation report has not been released publicly.

PG&E Corporation and the Utility accept Cal Fire’s determination that the 2018 Camp fire ignited at the first ignition site. PG&E Corporation and the Utility have not been able to form a conclusion as to whether a second fire ignited as a result of vegetation contact with the Utility’s facilities.

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigation or to the investigation report prepared by Cal Fire.

Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in areas impacted by the 2018 Camp fire. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities may also be investigating the fire. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba ~~City.~~City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major ~~wildfires in Northern California~~fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

Cal Fire has issued 19 investigation reports and two supplementary investigation reports that include its determination onof the causes of 1721 of the 2017 Northern California wildfires, and alleged that ~~each~~all of these fires, with the exception of the Tubbs fire, involved the ~~Utility's~~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.

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news ~~releases,~~ releases:

Cal Fire ~~has not yet released~~stated in its ~~investigation reports related to~~news releases that the McCourtney, Lobo, ~~Honey,~~ Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas ~~fires~~fire investigations, and ~~stated in its news releases that these investigations~~the investigation related to the Honey fire, have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” ~~The Butte County~~(See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations by the District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain.Attorneys’ offices related to these fires.)

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire ~~"was~~“was started by sagging power lines coming into contact during heavy ~~winds"~~winds” and that ~~"the~~“the power line in question was owned by Pacific Gas and Electric Company." Also on October 9, 2018, the Office of the District Attorney of Yuba County issued a news release indicating that no criminal charges would be filed in relation to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire. (See “District Attorneys’ Offices’ Investigations” below for further information regarding the investigations of the Cascade fire by the Office of the District Attorney of Yuba County.)

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

During the second quarter of 2019, Cal Fire released its investigation reports related to the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. The Cal Fire investigation report for the Adobe fire included as Attachment 42.1 a “Supplementary Investigation Report” concerning the Pressley fire. The Cal Fire investigator concludes in the Supplementary Investigation Report that the Pressley fire was started by an ember cast from the Adobe fire.

On July 24, 2019, the CPUC released copies of Cal Fire’s investigation report related to the Point fire and supplementary investigation reports related to the Youngs fire, which Cal Fire had not previously released publicly, as attachments to the SED’s own investigative reports for those fires. (The Youngs fire is the fire that the Utility has previously referred to as the Maacama fire.) The Cal Fire investigation report for the Point fire alleges that the fire was caused by a tree limb that broke off in high winds and fell into a power line, causing the power line to contact the ground. The Cal Fire investigators in the Youngs supplementary reports conclude that the fire was caused by a tree that fell into a power line, severing the line.

Cal Fire has not ~~publicly~~yet released its investigation reports related to the McCourtney and Lobo fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential.

As described in Note 11, on June 27, 2019, the CPUC issued ~~any news releases or~~an OII disclosing the findings of a June 13, 2019 report by the SED, which, among other ~~determinations for~~things, alleges that the ~~Tubbs, Maacama, Pressley, and Point wildfires. The timing and outcome~~Utility committed 27 violations in connection with 12 of the 2017 Northern California wildfires (specifically, the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphur and Youngs fires). As described in the OII, the 27 alleged violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizing a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identified by the SED in connection with the Cherokee, La Porte and Tubbs fires. The 37 fire was determined by the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation ~~into~~reports related to these fires remains confidential. On a status conference call before the ~~remaining~~assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal charges in connection with the Lobo and McCourtney fires, ~~is uncertain.~~the SED may add alleged violations related to those fires and the 2018 Camp fire to the OII. As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violations set forth in the OII. The Utility also filed a Corrective Actions Report and an Application to Develop a Mobile Application and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019, the Utility submitted a report to respond to the information requests contained in the OII, relating to matters such as the Utility’s vegetation management procedures and practices, its use of recloser devices in high fire risk areas, its pro-active de-energization of powerlines during times of high fire danger and its recordkeeping and other practices.

Further, the SED is conducting investigations ~~to assess~~into certain of the ~~compliance of electric~~other 2017 Northern California wildfires, including the McCourtney and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response.Lobo fires. Various other entities ~~including fire departments,~~ may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, 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.~~negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts ~~could determine~~have determined that the doctrine of inverse condemnation ~~applies even in~~is applicable regardless of whether the ~~absence of an open~~ CPUC ~~proceeding for cost~~ultimately allows recovery ~~or before a potential cost recovery decision is issued~~ by the ~~CPUC. There is no guarantee that the~~utility for any such costs. The CPUC ~~would~~may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse ~~condemnation applies.~~ condemnation. (See “Loss Recoveries – Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.)

In addition to ~~such~~ claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive 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.~~ negligent.

Further, the Utility could be subject to material fines, penalties, or ~~penalties~~restitution orders if the CPUC or any law enforcement agency ~~brought~~were to bring an enforcement action, including a criminal proceeding, and it were determined that the Utility had failed to comply with applicable laws and regulations.

As of ~~October 30, 2018,~~January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility ~~are~~were aware of approximately ~~500~~100 complaints on behalf of at least ~~3,100~~4,200 plaintiffs related to the ~~Northern California wildfires, five~~2018 Camp fire, nine of which ~~seek~~sought to be certified as class actions. ~~These cases have been coordinated in the San Francisco Superior Court.~~ The ~~coordinated~~pending civil litigation ~~is in the early stages of discovery. The litigation pending~~ against PG&E Corporation and the Utility ~~includes~~related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs sought damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process.

As of January 28, 2019, before the automatic stay arising as a result of the filing of the Chapter 11 Cases, PG&E Corporation and the Utility were aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which sought to be certified as class actions. These cases were coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires, included claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance and negligence. ~~Plaintiffs~~This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally asserted that PG&E Corporation’s and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs sought damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. However, the TCC has submitted a motion to the Bankruptcy Court seeking relief from the automatic stay to enable certain plaintiffs to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires filed 52 subrogation complaints in the San Francisco County Superior Court and the Sonoma County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations were similar to the ones made by individual plaintiffs. As of January 28, 2019, insurance carriers have filed 39 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court and the Butte County Superior Court. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. However, certain holders of subrogation claims have submitted motions to the Bankruptcy Court seeking relief from the automatic stay in order to pursue their claims outside of the Chapter 11 process, as further described under the heading “Motions to Lift the Automatic Stay for Certain Tubbs Fire-Related Claims” below. PG&E Corporation and the Utility have opposed such motions.

Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also ~~seek punitive damages.~~asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages included, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations were similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility. As described below under the heading “Plan Support Agreements with Public Entities,” on June 18, 2019, PG&E Corporation and the Utility entered into agreements with certain government entities to potentially resolve their wildfire-related claims through the Chapter 11 process.

As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the bar date for which occurred on April 22, 2019. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2018 Camp fire and the 2017 Northern California wildfires through the Bar Date. On July 18, 2019, PG&E Corporation and the Utility filed a motion for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2018 Camp fire and the 2017 Northern California wildfires, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” below.

PG&E Corporation and the Utility ~~also~~ are continuing to review the ~~subject of investigations or other actions by~~evidence concerning the ~~county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket~~2018 Camp fire and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney's Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at this time against PG&E Corporation or the Utility pertaining to the Cascade fire. Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the2017 Northern California ~~wildfires that started in these counties for a period of six months, until April 8, 2019.~~wildfires. PG&E Corporation and the Utility ~~anticipate further discussions with~~have not yet had access to all of the ~~District Attorneys in these counties relating~~evidence collected by Cal Fire as part of its investigations or to the McCourtney and Lobo investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs have reached an agreement to transfer available evidence collected by Cal Fire for the fires for which its investigation reports have been released to a shared storage facility. The transfer of the evidence is not yet complete. (See “District Attorneys’ Offices’ Investigations” below for information regarding certain investigations related to the 2018 Camp fire and 2017 Northern California ~~wildfires and whether any criminal or civil charges should be brought.~~wildfires.)

Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E ~~Corporation~~Corporation’s and the Utility’s liability will be resolved through ~~litigation,~~the Chapter 11 process, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

PG&E Corporation and the Utility, as part of their efforts to emerge from bankruptcy, are ~~continuing~~engaged in discussions with holders of claims related to ~~review~~ the ~~evidence concerning the causes of the~~2017 Northern California ~~wildfires.~~wildfires and the 2018 Camp fire in an attempt to reach a global settlement of such claims. As discussed under the heading “Plan Support Agreements with Public Entities,” PG&E Corporation and the Utility have ~~not yet had access~~entered into agreements with certain government entity claimholders to ~~all of the evidence collected~~potentially resolve their wildfire-related claims. The most recent settlement offers made by ~~Cal Fire as part of its investigation or to the many investigation reports prepared by Cal Fire.~~ PG&E Corporation and the Utility to subrogated insurance claimholders and ~~plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set.~~

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial ~~court's~~court’s decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation’s and the Utility’s petition for review.

On July 2, 2019, the TCC submitted a motion, pursuant to section 362(d)(1) of the Bankruptcy Code, for entry of an order terminating the automatic stay to permit certain individual plaintiffs (the “Tubbs Preference Plaintiffs”) to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire, and to request the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires to order one or more of the cases of the Tubbs Preference Plaintiffs to trial with preference pursuant to California Code of Civil Procedure section 36. On July 9, 2019, the TCC submitted an amended motion to request relief from the stay with respect to additional individual plaintiffs to proceed to a jury trial on their claims against PG&E Corporation and the Utility arising from the Tubbs fire.

On July 3, 2019, the Ad Hoc Subrogation Group submitted a motion for relief from the automatic stay to permit certain of the Ad Hoc Subrogation Group’s members to pursue their claims against PG&E Corporation and the Utility regarding the issue of PG&E Corporation’s and the Utility’s liability for the Tubbs fire in the San Francisco Superior Court in the coordinated litigation for the 2017 Northern California wildfires.

On July 19, 2019, PG&E Corporation and the Utility filed an objection to the motions of the TCC and the Ad Hoc Subrogation Group, requesting that the motions be denied. Also on July 19, 2019, the UCC and the Shareholder Group filed objections to the motions of the TCC and the Ad Hoc Subrogation Group with the Bankruptcy Court, requesting that the motions be denied. The Shareholder Group also joined in PG&E Corporation’s and the Utility’s objection to the motions of the TCC and the Ad Hoc Subrogation Group.

On July 22, 2019, the Bankruptcy Court issued an order continuing the hearings on the TCC’s and the Ad Hoc Subrogation Group’s motions for relief from the automatic stay to August 14, 2019.

On July 18, 2019, PG&E Corporation and the Utility submitted a motion, pursuant to sections 105(a) and 502(c) of the Bankruptcy Code, for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for contingent and/or unliquidated claims arising out of the 2015 Butte fire, the 2017 Northern California wildfires and the 2018 Camp fire (which are collectively referred to in this paragraph as “wildfire claims”). In the motion, PG&E Corporation and the Utility proposed, among other things, the following general parameters of the estimation process:

The motion is expected to be heard by the Bankruptcy Court on August 14, 2019. On August 7, 2019, certain third parties filed joinders and statements in support with the Bankruptcy Court with respect to PG&E Corporation’s and the Utility’s motion, including the Ad Hoc Noteholder Committee, the UCC and the Shareholder Group. Also on August 7, 2019, certain third parties filed objections to PG&E Corporation’s and the Utility’s motion with the Bankruptcy Court, including the City and County of San Francisco, the Ad Hoc Subrogation Group and the TCC. The objection of the City and County of San Francisco is limited to PG&E Corporation’s and the Utility’s proposal for the Bankruptcy Court to address the legal issue of whether, under the doctrine of inverse condemnation, PG&E Corporation and the Utility may be held strictly liable for wildfire claims asserting property damages even where it was not negligent.

On June 18, 2019, PG&E Corporation and the Utility entered into PSAs with certain local public entities providing for an aggregate of $1.0 billion to be paid by PG&E Corporation and the Utility to such public entities pursuant to PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in order to settle such public entities’ claims against PG&E Corporation and the Utility relating to the 2018 Camp fire, 2017 Northern California wildfires and 2015 Butte fire (collectively, “Public Entity Wildfire Claims”). PG&E Corporation and the Utility’s Chapter 11 plan of reorganization currently is under development and has not yet been filed with the Bankruptcy Court. PG&E Corporation and the Utility have entered into a PSA with each of the following public entities or group of public entities, as applicable:

For purposes of each PSA, the local public entities that are party to such PSA are referred to herein as “Supporting Public Entities.”

Each PSA provides that PG&E Corporation and the Utility’s Chapter 11 plan of reorganization will include, among other things, the following elements:

The “Settlement Amount” set forth in each PSA is as follows:

Each PSA provides that, subject to certain terms and conditions, the Supporting Public Entities will support PG&E Corporation and the Utility’s Chapter 11 plan of reorganization with respect to its treatment of their respective Public Entity Wildfire Claims, including by voting to accept PG&E Corporation and the Utility’s Chapter 11 plan of reorganization in the Chapter 11 Cases.

Each PSA may be terminated by the applicable Supporting Public Entities under certain circumstances, including:

Each PSA may be terminated by PG&E Corporation and the Utility under certain circumstances, including if:

On May 8, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, indicating that “total claims over $12 billion as of April [2019]” in insured losses have been reported from the November 2018 fires, of which approximately $8.6 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that 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 2017 Northern California wildfires.

The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.6 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. ~~The wildfire litigation could take a number of years~~PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be ~~resolved because~~submitted to insurers, particularly with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.6 billion of insurance claims made as of the ~~complexity~~above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet (“future claims”), each of ~~the matters, including the ongoing investigation into the causes of the fires and the growing number of parties and claims involved.~~which could be significant.

Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, ~~weather-~~weather and ~~climate-related~~climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, ~~and~~ the amount of any penalties or fines that may be imposed by governmental ~~entities.~~entities, and the amount of any penalties, fines, or restitution orders that might result from any criminal charges brought.

There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, there is uncertainty at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims and other factors may have on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion, which amount does not include potential punitive damages, fines and penalties or damages related to claims that have not manifested yet. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount.

If PG&E Corporation and the Utility were to be found liable for any punitive damages, and such damages were allowed by the Bankruptcy Court, or if PG&E Corporation and the Utility were subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation’s and the Utility’s obligations with respect to such claims are expected to be determined through the Chapter 11 process. Regulatory proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses, and record a charge that is the amount within the range that is a better estimate than any other amount or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.

In light of the current state of the law ~~on inverse condemnation~~ and the information currently available to the Utility, ~~including, among other things, the Cal Fire determinations of cause as stated in Cal Fire's press releases and their released reports,~~ PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with ~~14 of~~ the Northern California wildfires referred to as the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires), and accordingly,2018 Camp fire. PG&E Corporation and the Utility recorded a charge in the amount of ~~$2.5~~$10.5 billion ~~during~~for the ~~quarter~~year ended December 31, 2018. Based on additional facts and circumstances available to the Utility as of the date of this filing, including the entry into the PSAs and the status of PG&E Corporation’s and the Utility’s efforts to reach a resolution with other holders of wildfire-related claims, PG&E Corporation and the Utility recorded an additional charge for claims in connection with the 2018 Camp fire in the amount of $1.9 billion for the three months ended June 30, ~~2018. This charge~~2019.

The aggregate liability of $12.4 billion for claims in connection with the 2018 Camp fire corresponds to the lower end of the range of PG&E ~~Corporation~~Corporation’s and the Utility’s reasonably estimated probable losses, and is subject to change based on additional information.

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the ~~Northern California wildfires~~2018 Camp fire may change, which could result in material increases to the loss accrued.

The ~~$2.5~~$12.4 billion ~~charge~~liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if ~~any. It~~any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount in respect of FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the ~~Atlas, 37, Tubbs, Cascade, Maacama, Pressley~~wildfire-related securities class action litigation described below.

In light of the current state of the law and ~~Point fires because at this time~~the information currently available to the Utility, PG&E Corporation and the Utility have ~~not concluded~~determined that it is probable they will incur a loss ~~arising from those fires is probable. However,~~for claims in connection with all 21 of the ~~future it is possible that facts could emerge that lead~~2017 Northern California wildfires identified above, the reasons for which are discussed in more detail in this section below. PG&E Corporation and the Utility ~~to believe that~~recorded a ~~loss is probable, resulting~~charge in ~~the accrual of a liability at that time,~~ the amount of ~~which could be significant.~~

The aggregate liability ~~could significantly exceed~~of $5.5 billion for claims in connection with the ~~approximately $10 billion~~2017 Northern California wildfires corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information.

In the case of the Tubbs and 37 fires, PG&E Corporation and the Utility continue to believe that if the claims related to these fires were litigated on the merits, it would not be probable that they would incur a loss for such claims. However, as a result of PG&E Corporation’s and the Utility’s most recent settlement offer to holders of claims related to the Tubbs and 37 fires as of the date of this filing, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in ~~estimated insured property losses~~connection with such fires. With respect to 17 of the other 19 of the 2017 Northern California ~~wildfires.~~wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires)), PG&E Corporation and the Utility previously determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits. With respect to 2 of the other 19 of the 2017 Northern California wildfires (the Youngs and Pressley fires), PG&E Corporation and the Utility have determined that it is probable they would incur a loss for claims in connection with such fires if such claims were litigated on the merits based on information that became available to PG&E Corporation and the Utility after the filing of their last Quarterly Report on Form 10-Q.

PG&E Corporation and the Utility ~~have liability insurance from various insurers, which provides coverage for third-party liability attributable~~currently believe that it is reasonably possible that the amount of the loss related to the 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2017 Northern California wildfires may change, which could result in material increases to the loss accrued.

The $5.5 billion liability does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant. In addition, the charge does not include any amount in respect of FEMA reimbursement claims, claims for property damages related to federal land and other property or claims by certain state and local public entities that are not party to the PSAs, which amounts could be substantial. The charge also does not include any amounts for potential losses in connection with the wildfire-related securities class action litigation described below.

The aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires is comprised of (i) $8.5 billion for subrogated insurance claimholders, (ii) $7.5 billion for individual claimholders (including those with uninsured and underinsured property losses, among other claims), (iii) $1.0 billion for the Supporting Public Entities with respect to their Public Entity Wildfire Claims pursuant to the PSAs and (iv) $900 million for clean-up and fire suppression costs. The aggregate liabilities of $8.5 billion for subrogated insurance claimholders and $7.5 billion for individual claimholders are based on PG&E Corporation’s and the Utility’s estimates of probable loss developed from data and other information available to PG&E Corporation and the Utility and PG&E Corporation’s and the Utility’s most recent settlement offers to representatives of such claimholders as of the date of this filing. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders. With respect to the $1.0 billion liability for claims held by the Supporting Public Entities, while PG&E Corporation and the Utility previously disclosed the existence of claims asserted by such entities, PG&E Corporation and the Utility had not previously taken a charge related to these claims as the amount of the liability could not be reasonably estimated. As described above, the aggregate liability of $17.9 billion for claims in connection with the 2018 Camp fire and the 2017 Northern California wildfires corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated probable losses and is subject to change based on additional information. (See “Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires” above.)

As of the date of this filing, PG&E Corporation and the Utility believe that the settlement discussions with representatives of subrogated insurance claimholders are in a particularly critical period of the negotiation. PG&E Corporation and the Utility believe that the potential exists for material developments in the negotiation in the near term. Accordingly, if PG&E Corporation, the Utility and such claimholders reach agreement, PG&E Corporation’s and the Utility’s probable loss contingency for the subrogated insurance claims may increase by a material amount, which would result in an ~~aggregate amount~~additional accrual above the $8.5 billion reflected in this filing. Any such increase could be substantial and could be taken in the third quarter of ~~approximately $840~~2019. In their motion submitted to the Bankruptcy Court on July 23, 2019, the Ad Hoc Subrogation Group stated that holders of subrogated insurance claims hold in excess of $20 billion of wildfire-related claims against PG&E Corporation and the Utility. In the “Restructuring Term Sheet” attached to such motion, the Ad Hoc Subrogation Group proposed terms for a plan of reorganization that would settle all such subrogated insurance claims for consideration valued at $15.8 billion. PG&E Corporation and the Utility cannot predict the outcome or timing of discussions with such claimholders.

PG&E Corporation and the Utility had insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

PG&E Corporation and the Utility had $842 million of insurance coverage for liabilities, including wildfire events, for the period from August 1, 2017 through July 31, 2018, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. ~~In addition,~~During the third quarter of 2018, PG&E Corporation and the Utility renewed their liability insurance coverage ~~limits within these~~for wildfire ~~insurance policies could result~~events in ~~further material~~an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured ~~costs in~~retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the ~~event each fire were deemed to be~~reinsurance market where a ~~separate occurrence under the terms of the insurance policies.~~catastrophe bond was utilized.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through ~~September~~June 30, ~~2018,~~2019, PG&E Corporation and the Utility recorded ~~$385~~$1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. ~~This amount reflects~~These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, ~~or if insurance is otherwise unavailable,~~ PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the ~~potential~~Utility expect their losses ~~arising out of~~in connection with the 2018 Camp fire and 2017 Northern California wildfires ~~could significantly~~will substantially exceed ~~the coverage limits of the~~their available insurance.

The following table presents changes in the insurance receivable for the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019. The balance for insurance receivable is included in Other accounts receivable in PG&E ~~Corporation's~~Corporation’s and the ~~Utility's~~Utility’s Condensed Consolidated Balance Sheets:



(in millions)	Insurance Receivable
2018 Camp fire
Balance at December 31, 2018	$	1,380
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	1,380

2017 Northern California wildfires
Balance at December 31, 2018	$	829
Accrued insurance recoveries	—
Reimbursements	—
Balance at June 30, 2019	$	829

~~In addition, it could take a number of years before the extent of the Utility’s liability is known and the Utility could apply for recovery of costs in excess of insurance.~~ On June 21, 2018, the CPUC issued a decision granting the ~~Utility's~~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. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at ~~all, and even~~all. Rate recovery is uncertain, therefore the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

~~As of~~In addition, SB 901, signed into law on September ~~30,~~21, 2018, requires the Condensed Consolidated Financial Statements include long-term regulatory assets of $77 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.

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 recovery of costs related to the 2017 Northern California wildfires.

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

On July 8, 2019, the CPUC issued a decision in the Customer Harm Threshold proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility ~~have considered actions that might be taken~~from access to ~~attempt to address liquidity needs~~relief under the Customer Harm Threshold during the pendency of the ~~business should~~Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be ~~unable~~determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to ~~recover~~ costs related to the ~~Northern California~~2018 Camp fire.

The decision otherwise adopts a methodology 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; (3) a potential maximum regulatory adjustment of either 20% of the Customer Harm Threshold or 5% of the total disallowed wildfire liabilities, whichever is greater; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the Customer Harm Threshold. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under Section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires ~~but the inability to recover costs in excess of insurance through increases in rates or to collect such rates in a timely manner~~ could have a material ~~adverse~~ effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominatedIn Re California North Bay Fire Derivative ~~Litigation.~~Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the ~~plaintiffs'~~plaintiffs’ access to discovery in other actions. ~~The parties submitted~~On January 28, 2019, the plaintiffs filed a ~~joint status report on October 24, 2018.~~request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire.

On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E ~~Corporation's~~Corporation’s and the ~~Utility's~~Utility’s 2017 proxy statement contained misrepresentations regarding the ~~companies'~~companies’ risk management and safety programs. On October 15, 2018, PG&E ~~Corporation's~~Corporation filed a motion to stay the ~~litigation was filed on October 15, 2018. Plaintiffs' opposition~~litigation. Prior to ~~that motion currently is due November 29, 2018, and defendants' reply brief in support of that motion currently is due December 24, 2018. The~~the scheduled hearing on this motion, this matter was automatically stayed by PG&E ~~Corporation's motion to stay currently is set for January 31, 2019.~~Corporation’s and the Utility’s commencement of bankruptcy proceedings, as discussed below.

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. Plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility ~~are unable~~as nominal defendants. This lawsuit includes allegations related to ~~predict~~ the ~~timing~~2017 Northern California wildfires and ~~outcome~~the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action.

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The court has scheduled a case management conference for December 13, 2019.

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants.

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al., was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these ~~proceedings.~~proceedings on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 5, 2019, the plaintiff in Bowlinger v. Chew, et al. filed a response to the notice asserting that the automatic stay did not apply to his claims. PG&E Corporation and the Utility accordingly filed a Motion to Enforce the Automatic Stay with the Bankruptcy Court as to the Bowlinger action, which was granted.

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al.and Jon Paul Moretti v. PG&E Corporation, et al., respectively. The complaints ~~allege~~alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints ~~assert~~asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and ~~seek~~sought unspecified monetary relief, interest, ~~attorneys'~~attorneys’ fees and other costs. Both complaints ~~identify~~identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In Rere PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. ~~Plaintiffs currently have until~~The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend their complaint to add allegations regarding the 2018 ~~to file an~~Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

On February 22, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint names as defendants certain current and former officers and directors, as well as the underwriters of four public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the federal Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

During the second quarter of 2018, Cal Fire issued news releases stating that it referred the investigations related to the McCourtney, Lobo, Honey, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” On March 12, 2019, the Sonoma, Napa, Humboldt and Lake County District Attorneys announced that they would not prosecute PG&E Corporation or the Utility for the fires in those counties, which include the Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires.

PG&E Corporation and the Utility were the subject of criminal investigations or other actions by the Nevada County District Attorney’s Office to whom Cal Fire had referred its investigations into the McCourtney and Lobo fires. On July 23, 2019, the Nevada County District Attorney informed PG&E Corporation and the Utility of his decision not to pursue criminal charges in connection with the McCourtney and Lobo fires.

The Honey fire was referred to the Butte County District Attorney’s Office, and in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have ~~until January 8, 2019~~been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to ~~move~~$1.5 million, not recoverable in rates.

On October 9, 2018, the Office of the District Attorney of Yuba County announced its decision not to ~~dismiss, answer~~pursue criminal charges at such time against PG&E Corporation or ~~otherwise~~the Utility pertaining to the Cascade fire. The District Attorney’s Office also indicated that it reserved the right “to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.”

In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. PG&E Corporation and the Utility have been informed by the Butte County District Attorney’s Office and the California Attorney General’s Office that a grand jury has been empaneled in Butte County, and the Utility was served with subpoenas in the grand jury investigation. The Utility has produced documents and continues to produce documents and respond to other requests for information in connection with the criminal investigation of the 2018 Camp fire, including, but not limited to, documents related to the operation and maintenance of equipment owned or operated by the Utility. The Utility has also cooperated with the Butte County District Attorney’s Office and the California Attorney General’s Office in the collection of physical evidence from equipment owned or operated by the Utility. PG&E Corporation and the Utility are unable to predict the outcome of the criminal investigation into the 2018 Camp fire. The Utility could be subject to material fines, penalties, or restitution if it is determined that ~~complaint.~~the Utility failed to comply with applicable laws and regulations, as well as non-monetary remedies such as oversight requirements. The criminal investigation is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases.

Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. The timing and outcome for resolution of the remaining referrals by Cal Fire to the appropriate county District Attorneys’ offices are uncertain.

On March 20, 2019, PG&E Corporation learned that the SEC’s San Francisco Regional Office is conducting an investigation related to PG&E Corporation’s and the Utility’s public disclosures and accounting for losses associated with the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire. PG&E Corporation and the Utility are unable to predict the timing and outcome of ~~these proceedings.~~the investigation.

The Utility incurred costs of ~~$308~~$655 million for clean-up and repair of the Utility’s facilities (including ~~$145~~$236 million in capital expenditures) through ~~September~~June 30, ~~2018,~~2019, in connection with the 2018 Camp fire. The Utility also incurred costs of $334 million for clean-up and repair of the Utility’s facilities (including $161 million in capital expenditures) through June 30, 2019, in connection with the 2017 Northern California wildfires. ~~While the~~The Utility ~~believes that such~~is authorized to track and seek recovery of clean-up and repair costs ~~are recoverable~~ through ~~CEMA, its CEMA~~CEMA. (CEMA requests are subject to CPUC approval. ~~The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected if the Utility is unable to recover such costs.~~

Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs ~~or any conclusion that such recovery is no longer probable,~~ could have a material ~~adverse~~ effect on PG&E ~~Corporation's~~Corporation’s and the ~~Utility's~~Utility’s financial condition, results of operations, liquidity, and cash flows.

On May 24, 2019, the Bankruptcy Court entered an order authorizing PG&E Corporation and the Utility 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 substitute or temporary housing (“Alternative Living Expenses”) 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 Alternative Living Expenses or have other urgent needs. The Wildfire Assistance Fund will consist of $105 million deposited into a segregated account to be controlled by an independent third-party administrator appointed by the Bankruptcy Court, who will disburse and administer the funds. The administrator will 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 may be used to pay the costs of administering the fund. The establishment of the Wildfire Assistance Fund is not an acknowledgment or admission by PG&E Corporation or the Utility of liability with respect to the 2018 Camp fire or 2017 Northern California wildfires.

The Utility fully funded $105 million into the Wildfire Assistance Fund on August 2, 2019.

In September 2015, a wildfire ~~(known as the “Butte~~(the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the ~~wildfire.~~2015 Butte fire. According to Cal Fire’s report, the 2015 Butte fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures. Cal Fire’s report concluded that the ~~wildfire~~2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree, and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento. Subrogation insurers also filed a separate master complaint on the same date. The California Judicial Council previously had authorized the coordination of all cases in Sacramento County. As of ~~October 30, 2018,~~January 28, 2019, 95 known complaints ~~have been~~were filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador. The complaints involve approximately ~~4,000~~3,900 individual plaintiffs representing approximately ~~2,100~~2,000 households and their insurance companies. These complaints ~~are~~were part of, or ~~are~~were in the process of being added to, the coordinated proceeding. Plaintiffs ~~seek~~sought to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability. Plaintiffs also ~~seek~~sought punitive damages. Several plaintiffs ~~have~~ dismissed the ~~Utility's~~Utility’s two vegetation management contractors from their complaints. The Utility does not expect the number of ~~individual complaints and plaintiffs~~claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. ~~The~~Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility ~~continues to mediate and settle cases.~~on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages. The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny ~~plaintiffs'~~plaintiffs’ claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of ~~Appeal's~~Appeal’s decision. Both requests were denied. Neither the trial nor appellate courts originally addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. ~~Based on~~However, the ~~July 2,~~trial court, in November 2018, ~~Court of Appeal's ruling,~~denied a motion filed by the Utility that would have confirmed that punitive damages under Public Utilities Code Section 2106 are unavailable. The Utility believes a loss related to punitive damages is ~~remote.~~unlikely, but possible.

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation ~~applies~~applied to the Utility with respect to the 2015 Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling iswas binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could ~~file lawsuits and~~ make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the ~~Utility's~~Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it iswas bound by earlier holdings of two appellate courts decisions, Barham and Pacific ~~Bell~~.Bell. Further, the court stated that the ~~Utility's~~Utility’s constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility ~~raises~~raised the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the ~~court's~~court’s decision. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. IfThe court granted the ~~court grants the~~Utility’s stipulated judgment motion on November 29, 2018 and the Utility ~~will have~~filed its appeal on December 11, 2018. As a result of the ~~right to an appellate court hearing on inverse condemnation.~~filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

In addition to the coordinated plaintiffs, Cal Fire, the ~~California Office of Emergency Services (OES),~~OES, the County of Calaveras, the Calaveras County Water District, and ~~five~~four smaller public entities (three fire districts ~~one water district~~ and the California Department of Veterans Affairs) ~~have~~ brought suit or indicated that they ~~intend~~intended to do so. ~~These five~~The Calaveras County Water District and the four smaller public entities filed their complaints in August 2018 and September 2018. They ~~are being~~were added to the coordinated proceedings. The Utility settled the claims of the three fire protection districts and the Calaveras County Water District.

On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims. On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the ~~Utility's~~Utility’s vegetation contractors. Cal Fire ~~has~~had requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of ~~Appeal's~~Appeal’s decision in ~~Dep't~~Dep’t of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion iswas set for January 31, ~~2019. The~~2019, but the hearing and Cal Fire’s case against the Utility are now stayed. Prior to the stay, the Utility and Cal Fire ~~are~~were also engaged in a mediation process.

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also ~~seeks~~sought punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras ~~currently are engaged~~settled the County’s claims in a mediation process. The County has also requested a trial to take place no later than summer 2019. Based on statements by the court, the Utility anticipates that trial would take place, if at all, after a trial of individual plaintiffs' claims and the separate trial of Cal Fire claims.November 2018 for $25.4 million.

Further, in May 2017, the OES indicated that it ~~intends~~intended to bring a claim against the Utility that it ~~estimates~~estimated to be approximately $190 million. This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the 2015 Butte fire. The Utility has not received any information or documentation from the OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that ~~extends their~~extended its deadline to file a claim to December 2020.

PG&E Corporation’s and the Utility’s obligations with respect to such outstanding claims are expected to be determined through the Chapter 11 process. As described in Note 2, on July 1, 2019, the Bankruptcy Court entered an order approving the Bar Date of October 21, 2019, at 5:00 p.m. (Pacific Time) for filing claims against PG&E Corporation and the Utility relating to the period prior to the Petition Date, including claims in connection with the 2015 Butte fire. The Bar Date is subject to certain exceptions, including for claims arising under section 503(b)(9) of the Bankruptcy Code, the bar date for which occurred on April 22, 2019. It is expected that numerous wildfire-related claims will be filed against PG&E Corporation and the Utility in connection with the 2015 Butte fire through the Bar Date. On July 18, 2019, PG&E Corporation and the Utility filed a motion for entry of an order establishing procedures and schedules for the estimation of PG&E Corporation’s and the Utility’s aggregate liability for certain claims arising out of the 2015 Butte fire, as further described under the heading “Motion for the Establishment of Wildfire Claims Estimation Procedures” above.

In connection with ~~this matter,~~the 2015 Butte fire, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent. While the Utility believes it was not negligent, there can be no assurance that a court ~~or jury~~ would agree with the Utility.

The Utility’s assessment of the estimated loss related to the 2015 Butte fire is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages.

The Utility has determined that it is probable that it will incur a loss of ~~at least~~ $1.1 billion in connection with the 2015 Butte fire. ~~The Utility estimates it is reasonably possible that it may incur an additional $200 million, for a total loss of $1.3 billion.~~ While ~~these amounts include~~this amount includes the ~~Utility's~~Utility’s assumptions about fire suppression costs (including its assessment of the Cal Fire loss), ~~and the County of Calaveras claim, they do~~it does not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

The process for estimating costs associated with claims relating to the 2015 Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors. As more information becomes known, including additional discovery from the plaintiffs, results from the ongoing mediation and settlement process, review of the potential claim from the OES, outcomes of future court or jury decisions, and information about damages, for which the Utility could be liable, management estimates and assumptions regarding the financial impact of the 2015 Butte fire may result in material increases to the loss accrued.

PG&E Corporation’s and the Utility’s Condensed Consolidated Balance ~~Sheets:~~

If the Utility records losses in connection with claims relating to the 2015 Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, orliquidity, and cash flows could be materially affected in the reporting periods during which additional charges are recorded.

The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the 2015 Butte fire in an aggregate amount of $922 million. The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range. Through ~~September~~June 30, ~~2018,~~2019, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 Butte fire. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries. In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management ~~contractors (excluded from the table below), including $7 million received in the nine months ended September 30, 2018.~~contractors. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

~~The following table presents changes in the insurance receivable since December 31, 2015.~~ The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance ~~Sheets:~~Sheets and was $85 million and $50 million as of December 31, 2018 and June 30, 2019, respectively, reflecting reimbursements of $35 million during the six months ended June 30, 2019.

PG&E Corporation and the Utility ~~received an additional $45 million~~have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

The Utility also has substantial financial commitments in ~~insurance reimbursements.~~connection with agreements entered into to support its operating activities.

~~Regulatory Citations~~PG&E Corporation’s and the Utility’s financial condition, results of operations, and cash flows may be materially affected by the outcome of the following matters.

On ~~April 25,~~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 ~~SED issued two citations to~~court imposed a sentence on the Utility in connection with the conviction. 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 ~~fire, totaling $8.3 million.~~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 ~~SED's investigation~~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 2017 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:

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 ~~neither~~ the Utility ~~nor~~had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. 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:

On June 27, 2019, the CPUC issued an OII (the “2017 Northern California Wildfires OII”) to determine whether the Utility “violated any provision(s) of the California Public Utilities Code (PU Code), Commission General Orders (GO) or decisions, or other applicable rules or requirements pertaining to the maintenance and operation of its electric facilities that were involved in igniting fires in its service territory in 2017.”

The 2017 Northern California Wildfires OII discloses the findings of a June 13, 2019 report by the SED, which, among other things, alleges that the Utility committed 27 violations in connection with 12 of the 2017 Northern California wildfires (specifically, the Adobe, Atlas, Cascade, Norrbom, Nuns, Oakmont/Pythian, Partrick, Pocket, Point, Potter/Redwood, Sulphur and Youngs fires). As described in the OII, the 27 alleged violations include failure to maintain vegetation clearances, failure to identify and abate hazardous trees, improper record keeping, incomplete patrol prior to re-energizing a circuit, failure to retain evidence, failure to report an incident, and failure to maintain clearances between lines. No violations were identified by the SED in connection with the Cherokee, La Porte and Tubbs fires. The 37 fire was determined by the SED to not be a reportable incident. The SED report does not address the Lobo and McCourtney fires because Cal Fire referred its investigations into these fires to local law enforcement and the information contained in its investigation reports related to these fires remains confidential. On a status conference call before the assigned ALJ on July 29, 2019, the SED informed the parties that because the Nevada County District Attorney had decided not to pursue criminal charges in connection with the Lobo and McCourtney fires, the SED may add alleged violations related to those ~~investigations.~~ fires and the 2018 Camp fire to the OII.

The ~~status~~2017 Northern California Wildfires OII requires the Utility to (i) show cause by July 29, 2019 why it should not be sanctioned for the 27 violations alleged in the SED report and (ii) submit a report by August 5, 2019, responding to information requests relating to “matters of ~~these investigations~~concern that […] warrant further investigation and possible charges for violations of law.” These latter matters include the following: (i) the Utility’s vegetation management procedures and practices, (ii) the Utility’s procedures and practices regarding use of “recloser” devices in fire risk areas and during fire season, (iii) the Utility’s lack of procedures or policies for proactive de-energization of power lines during times of extreme fire danger, and (iv) the Utility’s record-keeping and other practices. The Utility is ~~uncertain.~~also required to take certain corrective actions and provide information regarding the qualifications of vegetation management personnel within 30 days of the issuance of the 2017 Northern California Wildfires OII. The Utility must also file an application to develop an open source, publicly available asset management system/database and mobile app, the costs of development and continued operation of which would be at shareholder expense.

The OII also indicates that the assigned commissioner shall set a prehearing conference for 45 to 60 days after the initiation of the proceeding or as soon as practicable after the CPUC makes the assignment. The assigned commissioner will also issue a scoping memo setting forth the scope of the proceeding and establishing a procedural schedule.

As required by the OII, on July 29, 2019, the Utility filed its initial response to the OII. In the initial response, the Utility indicated that it intends to fully cooperate with the CPUC but also stated that it disagreed with certain of the alleged violations set forth in the OII. The Utility also filed a Corrective Actions Report and an Application to Develop a Mobile Application and Supporting Systems, both as required by the OII. Also as required by the OII, on August 5, 2019, the Utility submitted a report to respond to the information requests contained in the OII, as explained above.

Order Instituting an Investigation and Order to Show Cause into the Utility’s Locate and Mark practices

On December 14, 2018, the CPUC issued an order instituting investigation and order to show cause (the “OII”) to assess the Utility’s practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the CPUC should not find violations in this matter, and why the CPUC should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.

The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided an analysis, based on the available data, of tickets that should be properly categorized as late, and identification of associated dig-ins. As a result, the OII will determine whether the Utility violated any provision of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locate and mark policies, practices, and related issues, and the extent to which the Utility’s practices with regard to locate and mark may have diminished system safety.

~~Regulatory Proceedings~~

The CPUC indicates that it has not concluded that the Utility has violated the law in any instance pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found, the CPUC will consider what monetary fines and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines.

On March 14, 2019, as directed by the CPUC, the Utility submitted a report that addressed the SED report and responded to the order to show cause. A prehearing conference was held on April 4, 2019, to establish scope and a procedural schedule. The assigned Commissioner and ALJ encouraged the SED and the Utility to reach a partial stipulation in order to streamline the proceeding. On April 24, 2019, the Utility provided notice of a settlement conference and the parties have continued settlement discussions. On May 7, 2019, the assigned Commissioner issued a scoping memo and ruling that included within the proceedings, in addition to the issues identified in the OII relating to the Utility’s locate and mark procedures, issues relating to the Utility’s use of “qualified electrical workers” for locating and marking underground infrastructure. On July 24, 2019, the SED submitted its opening testimony to the CPUC. A status conference with the ALJ was held on July 30, 2019. The parties continue settlement discussions. In accordance with the current procedural schedule issued by the ALJ on June 27, 2019, intervenor testimony is due August 16, 2019, and the Utility’s reply testimony is due September 18, 2019. The SED’s rebuttal testimony is due October 4, 2019. Evidentiary hearings are scheduled for October 21 to 25, 2019.

Based on the information available to PG&E Corporation and the Utility as of the date of this filing, PG&E Corporation and the Utility believe it is probable that the Utility will incur penalties, including fines or other remedies. Accordingly, PG&E Corporation and the Utility recorded a charge during the quarter ended June 30, 2019 for an amount that is not material, which corresponds to the lower end of the range of PG&E Corporation's and the Utility's reasonably estimated losses and is subject to change based on additional information. PG&E Corporation and the Utility are unable to determine a better estimate within such range given the CPUC’s wide discretion and the number of factors that can be considered in determining penalties. The Utility is 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 were required to pay a material amount of penalties or if the Utility were required to incur a material amount of costs that it cannot recover through rates.

This proceeding is not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of this proceeding are stayed.

For more information about this proceeding, see Note 14 of the Notes to the Consolidated Financial Statements in Item 8 of the 2018 Form 10-K.

On April 26, 2018, the CPUC approved the revised ~~proposed decision~~PD issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the ~~"settlement agreement"~~“settlement agreement”) by the Utility, the Cities of San Bruno and San Carlos, ~~Cal PA~~PAO (formerly known as the Office of Ratepayer Advocates or ORA), the SED, and TURN.

The decision ~~results~~resulted in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund, (2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

As a result of the CPUC’s April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At June 30, 2019, PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets include an $16 million accrual for a portion of the 2019 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On ~~May 22, 2018,~~June 28, 2019, the ~~assigned ALJ issued a ruling requiring~~Cities of San Bruno and San Carlos, PAO, the ~~parties to meet~~SED, TURN, and ~~confer to determine if an agreement can be reached on~~ the ~~issues identified by the ALJ. On September 17, 2018, the parties submitted~~Utility filed a joint ~~status report indicating a settlement in principle could not be reached. The ALJ will hold a prehearing conference~~motion with the ~~parties to determine if evidentiary hearings are required. The Utility is unable to predict the timing and outcome~~CPUC seeking approval of a comprehensive settlement agreement that addresses all issues in the second phase inof this proceeding.

At June 30, 2019, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $4 million accrual for the amounts payable to the California General Fund and the Cities of San Bruno and San Carlos. The Utility is unable to predict whether the CPUC will approve the settlement.

For more information about ~~the~~this proceeding, see Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 went into effect on May 1, 2019.

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ~~ALJ's~~ALJ’s recommendations. The Utility expects the FERC to issue a ~~final~~ decision in the TO18 rate case by ~~mid-2019.~~ late-2019, however, that decision will likely be the subject of requests for rehearing and appeal.

On September 21, 2018, the Utility filed an all-party settlement with FERC, which was approved by FERC on December 20, 2018, 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 upon issuance of a final unappealable decision in TO18.

On November 30, 2018, the ~~TO18 final decision.~~ FERC issued an order accepting the Utility’s October 2018 filing of its TO20 formula rate case, 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 ~~outcomes~~timing or outcome of FERC’s decisions in ~~these proceedings.~~the TO18 and TO19 proceedings or the timing or outcome of the TO20 proceeding.

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

PG&E Corporation and the Utility are subject to various claims, lawsuits, and regulatory proceedings that separately are not considered material. Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed above under “Enforcement and Litigation Matters”) totaled ~~$94 million at September 30, 2018, and $86~~$98 million at December 31, ~~2017.~~2018. These amounts ~~are~~were included in Other current liabilities in the Condensed Consolidated Balance Sheets. On the Petition Date, these amounts were moved to LSTC. PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the Environmental Protection Agency under the ~~federal~~Federal Resource Conservation and Recovery Act ~~and/or~~in addition to other ~~federal and~~ state hazardous waste laws. The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements. The Utility assesses and monitors the environmental requirements on an ongoing basis, and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

The Utility’s environmental remediation liability at ~~September~~June 30, ~~2018,~~2019, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the ~~Utility's~~Utility’s time frame for remediation. The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material impact on results of operations, financial condition, and cash flows during the period in which they are recorded. At ~~September~~June 30, ~~2018,~~2019, the Utility expected to recover ~~$797~~$960 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

For more information, see remediation site descriptions below and see Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.

~~During the third quarter of~~In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general wildfire liability in policies covering wildfire and non-wildfire events (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for wildfire property damages only, which ~~property damage coverage includes an aggregate amount of~~included approximately $200 million of coverage through the ~~reinsurance market where~~use of a catastrophe ~~bond was utilized.~~bond. For the period from August 1, 2019 through July 31, 2020, PG&E Corporation and the Utility have secured approximately $430 million for general wildfire liability(subject to an initial self-insured retention of $10 million per occurrence). PG&E Corporation and the Utility continue to pursue additional insurance coverage for the period from August 1, 2019 through July 30, 2020. Various coverage limitations applicable to different insurance layers could result in ~~substantial~~ uninsured costs in the future depending on the amount and type of ~~damages.~~damages resulting from covered events.

PG&E Corporation’s and the Utility’s cost of obtaining the wildfire and non-wildfire insurance coverage ~~has increased to $360~~in place for the period of August 1, 2019 through July 31, 2020 (consisting of the $430 million general wildfire liability coverage described above and $520 million for non-wildfire general liability) is approximately $190 million, compared to the ~~adopted~~ approximately $50 million that the Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs paid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on December 31, 2019.

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through June 30, 2019, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.

The Utility maintains multiple insurance policies through NEIL and European Mutual Association for Nuclear Insurance, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment. If NEIL were to exercise this assessment, as of ~~September 30, 2018,~~ the ~~current~~policy renewal on April 1, 2020, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately ~~$47~~$41 million. If European Mutual Association for Nuclear Insurance losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3$5 million, as of ~~September 30, 2018.~~the policy renewal on April 1, 2020. For more information about the Utility’s nuclear insurance coverage, see Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of audits. As of ~~September~~June 30, ~~2018,~~2019, it is reasonably possible that unrecognized tax benefits will decrease by approximately $10 million within the next 12 months. PG&E Corporation and the Utility believe that the majority of the decrease will not impact net income.

In the ordinary course of business, the Utility enters into various agreements to purchase power and electric capacity; natural gas supply, transportation, and storage; nuclear fuel supply and services; and various other commitments. At December 31, ~~2017,~~2018, the Utility had undiscounted future expected obligations of approximately ~~$44~~$40 billion. (See Note 1314 of the Notes to the Consolidated Financial Statements in Item 8 of the ~~2017~~2018 Form 10-K.) The Utility has not entered into any new material commitments during the ~~nine~~six months ended ~~September~~June 30, ~~2018.~~2019.

On July 12, 2019, the California Governor signed into law AB 1054, a bill which provides for the establishment of a statewide fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. Eligible claims are claims for third party damages resulting from any such wildfires, limited to the portion of such claims that exceeds the greater of (i) $1.0 billion in the aggregate in any calendar year and (ii) the amount of insurance coverage required to be in place for the electric utility company pursuant to Section 3293 of the Public Utilities Code, added by AB 1054.

Each of California’s large investor-owned electric utility companies that are not currently subject to Chapter 11 (Southern California Edison and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

The Wildfire Fund to be established under AB 1054 will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund.

The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

In order to participate in the Wildfire Fund, within 60 days of the effective date of AB 1054, the Utility must obtain the Bankruptcy Court’s approval of the Utility’s election to pay the initial and annual Wildfire Fund contributions upon emergence from Chapter 11. The Utility would then be required to pay its share of the initial contribution to the Wildfire Fund upon emergence from Chapter 11, and meet certain eligibility requirements listed below, in order to participate in the Wildfire Fund. In such event (assuming the Utility satisfies the eligibility and other requirements set forth in AB 1054), the Wildfire Fund will be available to the Utility to pay for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11, subject to a limit of 40% of the amount of such claims. The balance of any such claims would need to be addressed through the Chapter 11 Cases. There are several additional eligibility requirements for the Utility, including that by June 30, 2020, the following conditions are satisfied:

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

If the Utility satisfies the requirements to participate in the Wildfire Fund, the Utility will be required to fund its initial contribution upon its emergence from Chapter 11. The Utility’s required contributions to the Wildfire Fund will be substantial. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions. The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases. The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, consummate or implement any such plan, which will ultimately require Bankruptcy Court, creditor and regulatory approval. Further, there can be no assurance that the expected benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs.

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers.

The Utility is regulated primarily by the CPUC and the FERC. The CPUC has jurisdiction over the rates, terms, and conditions of service for the Utility’s electricity and natural gas distribution operations, electric generation, and natural gas transportation and storage. The FERC has jurisdiction over the rates and terms and conditions of service governing the Utility’s electric transmission operations and interstate natural gas transportation contracts. The NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities. The Utility is also subject to the jurisdiction of other federal, state, and local governmental agencies.

This is a combined quarterly report of PG&E Corporation and the Utility and should be read in conjunction with each company’s separate Condensed Consolidated Financial Statements and the Notes to the Condensed Consolidated Financial Statements included in this quarterly report. It also should be read in conjunction with the ~~2017~~2018 Form 10-K.

~~Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada,~~On the Petition Date, PG&E Corporation and ~~Yuba Counties, as well as~~the Utility filed voluntary petitions for relief under Chapter 11 in the ~~area surrounding Yuba City (the “Northern California wildfires”)~~Bankruptcy Court. PG&E Corporation’s and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM). ~~According~~For additional information regarding the Chapter 11 Cases, refer to the ~~Cal Fire California Statewide Fire Summary dated October 30, 2017,~~website maintained by Prime Clerk, LLC, PG&E Corporation’s and the Utility’s claims and noticing agent, 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.http://restructuring.primeclerk.com/pge.

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. For more information about the Chapter 11 Cases, see ~~Note 9~~“Item 1A. Risk Factors – Risks Related to Chapter 11 Proceedings and Liquidity” and “Item 7. MD&A – Chapter 11 Proceedings” in the 2018 Form 10-K and Notes 2 and 5 of the Notes to the Condensed Consolidated Financial Statements in Item 1.1 of this Form 10-Q.

The accompanying Condensed Consolidated Financial Statements to this Form 10-Q have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the ~~Utility’s financial condition, results~~satisfaction of ~~operations, liquidity and cash flows could be materially affected by additional potential losses resulting from the impact of the Northern California wildfires. See “Item 1A. Risk Factors”~~liabilities in the ~~2017 Form 10-K and in Part II below under “Item 1A. Risk Factors.”~~

Management has concluded that uncertainty regarding these matters raises substantial doubt about PG&E Corporation’s and the Utility’s ability to continue as going concerns, and their independent registered public accountants included an explanatory paragraph in their auditors’ reports relating to the ~~federal tax rate.~~consolidated balance sheets of PG&E Corporation and the Utility recorded reasonable estimates to reflect the impacts of the Tax Act and recorded provisional amounts, in accordance with rules issued by the SEC staff in Staff Accounting Bulletin No. 118, for the re-measurement of deferred tax balances as of December 31, ~~2017. As a result of updated amounts used in PG&E Corporation~~2018 and 2017, and the ~~Utility's 2017 tax returns, during~~related consolidated statements of income, comprehensive income, equity, and cash flows, for each of the ~~nine months~~three years in the period ended ~~September 30, 2018, the Utility recorded a $12 million tax benefit to adjust provisional tax expense recorded at~~ December 31, ~~2017, for~~2018, included in the ~~Tax Act. For~~2018 Form 10-K, which stated certain conditions exist which raise substantial doubt about PG&E Corporation’s and the ~~nine months ended September 30, 2018, the Utility recorded an $80 million reduction~~Utility’s ability to continue as going concerns in relation to the ~~regulatory liability recorded at December 31, 2017 for~~foregoing. The Condensed Consolidated Financial Statements do not include any adjustments that might result from the ~~Tax Act.~~

~~The tables below include a summary reconciliation of~~ PG&E Corporation’s ~~consolidated income available for common shareholders~~net loss was $2,553 million and ~~EPS~~$2,420 million in the three and six months ended June 30, 2019, respectively, compared to ~~earnings from operations~~net losses of $984 million and ~~EPS based on earnings from operations~~$542 million in the same periods in 2018. PG&E Corporation recognized charges of $1.9 billion and $2.0 billion, net of probable insurance recoveries, associated with the 2018 Camp fire and the 2017 Northern California wildfires, respectively, for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018 as~~2019, compared to charges of $2.1 billion, net of probable insurance recoveries, associated with the 2017 Northern California wildfires during the same periods in 2017 and a summary reconciliation of the key drivers of PG&E Corporation’s earnings from operations and EPS based on earnings from operations for the three and nine months ended September 30, 2018 as compared to the same period in 2017. “Earnings from operations” is a non-GAAP financial measure and is calculated as income available for common shareholders less items impacting comparability. “Items impacting comparability” represent items that management does not consider part of the normal course of operations and affect comparability of financial results between periods. PG&E Corporation uses earnings from operations to understand and compare operating results across reporting periods for various purposes including internal budgeting and forecasting, short and long-term operating planning, and employee incentive compensation. PG&E Corporation believes that non-GAAP earnings from operations provide additional insight into the underlying trends of the business allowing for a better comparison against historical results and expectations for future performance. Non-GAAP earnings from operations are not a substitute or alternative for GAAP measures such as income available for common shareholders and may not be comparable to similarly titled measures used by other companies.2018.

The ~~tables~~table below ~~show~~shows certain items from the Utility’s Condensed Consolidated Statements of Income for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017.~~2018. The ~~tables~~table separately ~~identify~~identifies the revenues and costs that impacted earnings from those that did not impact earnings. In general, expenses the Utility is authorized to pass through directly to customers (such as costs to purchase electricity and natural gas, as well as costs to fund public purpose programs), and the corresponding amount of revenues collected to recover those pass-through costs, do not impact earnings. In addition, expenses that have been specifically authorized (such as the payment of pension costs) and the corresponding revenues the Utility is authorized to collect to recover such costs do not impact earnings.

Revenues that impact earnings are primarily those that have been authorized by the CPUC and the FERC to recover the Utility’s costs to own and operate its assets and to provide the Utility an opportunity to earn its authorized rate of return on rate base. Expenses that impact earnings are primarily those that the Utility incurs to own and operate its assets.

The following discussion presents the Utility’s operating results for the three and ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 and ~~2017,~~2018, focusing on revenues and expenses that impacted earnings for these periods.

The Utility’s electric and natural gas operating revenues that impacted earnings ~~increased~~decreased by ~~$50~~$67 million, or 2%, and $33 million, or 1% in the three and six months ended ~~September~~June 30, ~~2018,~~2019, respectively, compared to the same ~~period~~periods in ~~2017,~~2018, primarily due to ~~increased base revenues authorized in~~ the ~~2017 GRC.~~regulatory treatment of interest on pre-petition debt and other impacts of the Chapter 11 Cases.

The Utility’s operating and maintenance expenses that impacted earnings increased by ~~$120~~$318 million, or ~~11%~~26%, in the three months ended ~~September~~June 30, ~~2018,~~2019, compared to the same period in ~~2017,~~2018, primarily due to ~~Northern California wildfire-related legal~~$275 million related to enhanced and ~~other~~accelerated inspections and repairs of transmission and distribution assets and $71 million for clean-up and repair costs ~~of $53 million in~~relating to the ~~three months ended September 30,~~ 2018 Camp fire, with no similar charges in the same period in 2017. Additionally, the Utility incurred approximately $50 million in costs related to higher premiums for liability insurance (net of the portion deferred as a regulatory asset for amounts that are probable of recovery), during the three months ended September 30, 2018, as compared to the same period in 2017. These increases were partially offset by a $38 million reduction to the estimated disallowance for gas-related capital costs that were expected to exceed authorized amounts in the three months ended September 30, 2018, with no corresponding activity during the same period in 2017.2018.

The Utility’s operating and maintenance expenses that impacted earnings increased by ~~$148~~$762 million, or 4%31%, in the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, compared to the same period in ~~2017,~~2018, primarily due to ~~Northern California wildfire-related legal~~$485 million related to enhanced and ~~other costs~~accelerated inspections and repairs of ~~$120~~transmission and distribution assets and $250 million ~~and~~for clean-up and repair costs of $40 million, and an increase in environmental remediation expenses at the San Francisco Potrero Power Plant of approximately $40 million in the nine months ended September 30, 2018, with no corresponding charges during the same period in 2017. Additionally, the Utility incurred approximately $50 million in costs related to higher premiums for liability insurance (net of the portion deferred as a regulatory asset for amounts that are probable of recovery), during the nine months ended September 30, 2018, as comparedrelating to the same period in 2017. These increases were partially offset by a $38 million reduction to the estimated disallowance for gas-related capital costs that were expected to exceed authorized amounts in the nine months ended September 30, 2018. Additionally, the Utility recorded a $47 million disallowance related to the Diablo Canyon settlement in the nine months ended September 30, 2017,2018 Camp fire, with no similar charges in the same period in 2018. Additionally, the Utility recorded $40 million in clean-up and repair costs relating to the 2017 Northern California wildfires in the six months ended June 30, 2018, with no similar charges in the same period in 2019.

Wildfire-related claims, net of insurance recoveries

Costs related to wildfires that impacted earnings decreased by $63 million in the three months ended September 30, 2018, compared to the same period in 2017. In 2017, the Utility recognized a $350 million charge, offset by probable insurance recoveries of $297 million related to the Butte fire, compared to $10 million of probable insurance recoveries associated with the Northern California wildfires recorded in 2018.

The Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected by additional potential losses resulting from the impact of the Northern California wildfires and any additional charges associated with costs related to the Butte fire. (See(See “Item 1A. Risk Factors” in the ~~2017~~2018 Form 10-K and ~~in Part II below under “Item 1A. Risk Factors,” as well as~~ Note 910 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

The Utility’s depreciation, amortization, and decommissioning expenses that impacted earnings increased by ~~$49~~$50 million, or 7%, and ~~$123~~$95 million, or 6%, in the three and ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, respectively, compared to the same periods in ~~2017,~~2018, primarily due to capital additions.

There ~~were~~was no material ~~changes~~change to interest income ~~and interest expense~~ that impacted earnings for the periods presented.

Interest expense that impacted earnings decreased by $162 million, or 73%, and $278 million, or 63% in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018, primarily due to the cessation of interest accruals on outstanding pre-petition debt beginning January 29, 2019 in connection with the Chapter 11 Cases.

There were no material changes to other income, net, that impacted earnings for the periods presented.

Reorganization items, net increased by $57 million and $168 million in the three and six months ended June 30, 2019, respectively, compared to the same periods in 2018, due to $75 million and $195 million, respectively, of expenses directly associated with the Utility’s Chapter 11 filing in the three and six months ended June 30, 2019, partially offset by interest income of $18 million and $27 million, respectively.

(See “Item 1A. Risk Factors” in the 2018 Form 10-K and Note 2 of the Notes to the Condensed Consolidated Financial Statements in Item 1 of this Form 10-Q.)

~~The income~~Income tax ~~provision decreased~~benefits increased by ~~$124~~$527 million and $661 million in the three and six months ended ~~September~~June 30, ~~2018,~~2019, respectively, as compared to the same periods in 2018. The increases in income tax benefits were primarily the result of higher pretax losses in the three and six months ended June 30, 2019, compared to the same period in 2017. The effective tax rates for the three months ended September 30, 2018 and 2017 were 2.5% and 21.2%, respectively. The decrease in the income tax provisions and in the effective tax rates were primarily the result of a decrease in the corporate income tax rate from 35% to 21% as a result of the Tax Act.2018.

Fluctuations in revenues that did not impact earnings are primarily driven by electricity and natural gas procurement costs. See below for more information.

The Utility’s cost of electricity includes the cost of power purchased from third parties (including renewable energy resources), transmission, fuel used in its own generation facilities, fuel supplied to other facilities under power purchase agreements, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. The costs also include net sales (Utility owned generation and third parties) in the CAISO electricity markets. (See Note 78 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s total purchased power is driven by customer demand, net CAISO electricity market activities (purchases or sales), the availability of the Utility’s own generation facilities (including Diablo Canyon and its hydroelectric plants), and the cost-effectiveness of each source of electricity.

The Utility’s cost of natural gas includes the costs of procurement, storage and transportation of natural gas, costs to comply with California’s cap-and-trade program, and realized gains and losses on price risk management activities. (See Note 78 of the Notes to the Condensed Consolidated Financial Statements in Item 1.) The Utility’s cost of natural gas is impacted by the market price of natural gas, changes in the cost of storage and transportation, and changes in customer demand.

The Utility’s operating expenses that did not impact earnings include certain costs that the Utility is authorized to recover as incurred such as pension contributions and public purpose programs costs. If the Utility were to spend more than authorized amounts, these expenses could have an impact to earnings.

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of operating expenses, other than expenses such as depreciation that do not require the use of cash. During the ~~nine~~six months ended ~~September~~June 30, ~~2018,~~2019, net cash provided by operating activities ~~decreased~~increased by ~~$508~~$54 million compared to the same period in ~~2017.~~2018. This ~~decrease~~increase was due to ~~fluctuations~~a reduction in ~~activities within the normal course~~interest paid of ~~business such as the timing~~$368 million, offset by an increase in amounts paid for reorganization items, and ~~amount~~enhanced and accelerated inspections and repairs of ~~customer billings~~transmission and ~~collections and vendor billings and payments.~~distribution assets in 2019, with no similar payments in 2018.

The Utility will continue to operate its business as a debtor in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. Future cash flow from operating activities will be affected by various ~~factors,~~ongoing activities, including:

The Utility had material obligations outstanding as of the Petition Date, including claims related to the 2018 Camp fire and

Net cash used in investing activities ~~increased~~decreased by ~~$667~~$461 million during the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to the same period in ~~2017 primarily due to an increase in capital expenditures.~~2018. The Utility’s investing activities primarily consist of the construction of new and replacement facilities necessary to provide safe and reliable electricity and natural gas services to its customers. Cash used in investing activities also includes the proceeds from sales of nuclear decommissioning trust investments which are largely offset by the amount of cash used to purchase new nuclear decommissioning trust investments. The funds in the decommissioning trusts, along with accumulated earnings, are used exclusively for decommissioning and dismantling the Utility’s nuclear generation facilities.

The Utility’s capital expenditures were approximately ~~$5.7~~$6.5 billion in ~~2017.~~2018. Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility estimates that it will incur approximately ~~$6.5~~$7.1 billion in capital expenditures in ~~2018,~~2019, and ~~$6.4~~$7 billion in ~~2019.~~2020.

Net cash provided by financing activities increased by ~~$1.1~~$1.2 billion during the ~~nine~~six months ended ~~September~~June 30, ~~2018~~2019 as compared to the same period in ~~2017.~~2018. This increase was primarily due to $1.5 billion of borrowings under the ~~suspension of dividend payments (see “Dividends” section above) and a reduction~~DIP Initial Term Loan Facility in ~~net repayments of commercial paper of approximately $600 million.~~2019.

Cash provided by or used in financing activities is driven by the Utility’s financing needs, which depend on the level of cash provided by or used in operating activities, the level of cash provided by or used in investing activities, the conditions in the capital markets, and the maturity date of existing debt instruments. The Utility generally utilizes long-term debt issuances and equity contributions from PG&E Corporation to maintain its CPUC-authorized capital structure, and relies on short-term debt to fund temporary financing needs.

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.”

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.

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. On April 30, 2019, the CPUC held a prehearing conference, and on May 29, 2019, the CPUC issued a scoping memo and ruling on issues for briefing. On July 15, 2019, the ALJ approved briefing dates in August and September of 2019. No evidentiary hearings are scheduled. The Utility is unable to predict the timing and outcome of its waiver application.

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 reflected, among other things, the wildfire-related challenges that the Utility was facing. The Utility also 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 challenges that investor-owned utilities face in California in connection with the extreme wildfire risk.

AB 1054, enacted on July 12, 2019, provides for the establishment of the Wildfire Fund that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment, subject to the terms and conditions of AB 1054. On July 23, 2019, the Utility notified the CPUC of its election to participate in the Wildfire Fund. The Utility’s participation in the Wildfire Fund is subject to the conditions and limitations set forth in AB 1054 and approval by the Bankruptcy Court.

As a result of the expected effects of AB 1054 on the Utility’s wildfire-related risk profile, on August 1, 2019, in a supplemental cost of capital testimony, the Utility proposed to revise its rate of return on equity to 12%.

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, as updated by the Utility’s August 1, 2019 testimony to reflect a revised rate of return on equity:

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 supplemental cost of capital testimony that AB 1054 does not directly impact the Utility’s test year 2020 cost of debt. However, the cost of debt will be impacted by the Utility’s exit financing as part of its future chapter 11 plan of reorganization. The supplemental cost of capital testimony did not address the Utility’s currently-effective formula rate for electric transmission rates, including the requested return on equity, which is pending at the FERC. The parties in the FERC proceeding are currently involved in settlement negotiations.

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

For 2020, the Utility expects that the proposed cost of capital, if adopted, would result in revenue requirement increases of approximately $271 million for electric generation and distribution and $74 million gas distribution operations, assuming 2017 authorized rate base amounts. The revenues for the gas transmission and storage operations would increase by approximately $51 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, as updated to reflect a revised rate of return on equity submitted to the CPUC on August 1, 2019:

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.

On July 2, 2019, the assigned Commissioner issued a scoping memo and ruling that, among other things, consolidated the Utility’s proceeding with the 2020 cost of capital applications submitted to the CPUC by Southern California Edison Company, San Diego Gas & Electric Company, and Southern California Gas Company. The scoping memo also identified the issues to be addressed within the proceeding and its schedule. On July 15, 2019, the assigned ALJ also issued a ruling directing the Utility and the other Applicants to submit supplemental testimony regarding AB 1054’s impact on financial risks and other issues within the scope of this proceeding by August 1, 2019. According to the current schedule, rebuttal testimony is due August 16, 2019, and additional rebuttal on testimony regarding the passage of AB 1054 is due August 21, 2019. A proposed decision would be issued on November 15, 2019. A final decision would be issued no sooner than 30 days after the proposed decision. The Utility is unable to predict the timing and outcome of this proceeding.

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. On July 12, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements. There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter period of time developed in collaboration with the Energy Division. The earliest the CPUC can consider this matter is on August 15, 2019. The Utility cannot predict the timing and outcome of this ~~PFM.~~matter.

~~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,~~July 11, 2019, the CPUC further extended the statutory deadline for the 2017 GRC to February 9, ~~2019,~~2020, in order to allow for comments and CPUC action on ~~any~~a 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.~~study.

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

On ~~November 30, 2017,~~December 13, 2018, the Utility filed its ~~first RAMP report~~2020 GRC application with the ~~CPUC in advance of its~~CPUC. In the 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~~Utility has requested that the CPUC determine the annual amount of base revenues (or “revenue requirements”) that the Utility 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 ~~risk assessment procedures, and proposed mitigations of those risks for 2020-2022.~~

For 2020, ~~GRC. A workshop on~~ the ~~report was held on April 17, 2018, and~~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 ~~parties submitted opening and reply comments on May 10, 2018, and May 24, 2018, respectively.~~2019 authorized rate base of $27.3 billion. The ~~RAMP results will be incorporated in~~Utility also requested that the CPUC establish a ratemaking mechanism that would increase the Utility’s ~~2020 GRC.~~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.

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:

This GRC proposal did not request funding for potential lawsuits or claims resulting from the 2018 Camp fire and 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 ~~General Rate Case~~GRC period. The Utility also may seek or may be required to update the scope of work for the 2019 Wildfire Safety Plan that was approved by the CPUC on June 4, 2019.

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. The ruling indicates a proposed decision will be issued in the first quarter of 2020.

On June ~~4, 2018, the Utility~~28, 2019, PAO submitted ~~a letter to~~testimony recommending that the CPUC ~~requesting an extension of up to four months, from September 1, 2018, to January 1, 2019, to file its~~authorize a 2020 GRC ~~application. The Utility requested this extension due to extraordinary uncertainties related to~~revenue requirement of $503 million, or 5.91%, higher than the ~~2017 Northern California wildfires that could significantly impact~~2019 authorized level. PAO also recommended establishing a one-way balancing account for the ~~content of~~Utility’s revenue requirement during the rate case ~~application. On June 29, 2018, the CPUC granted the Utility’s extension request~~term (2020 to file its 2020 GRC application no later than January 1, 2019. On October 15, 2018, the Utility notified the CPUC that the Utility anticipates submitting its 2020 GRC to the CPUC between December 10, 2018 and December 20, 2018.2022).

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). On July 15, 2019, a proposed decision on the PFM was issued requesting that the Utility make additional reductions to the revenue requirements. There were two primary changes: first, to include the cost of removal component of book depreciation when calculating the amortization of protected excess deferred income taxes using the average rate assumption method (ARAM); and second, to amortize unprotected excess deferred taxes over a shorter period of time developed in collaboration with the Energy Division. The earliest a final decision could be voted is on August 15, 2019. The Utility cannot predict the timing and outcome of this ~~PFM.~~matter.

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

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.

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.

In this case, the CPUC will authorize the revenue requirement that the Utility will collect through rates to recover its anticipated costs of providing natural gas transmission and storage services from 2019 through 2021, or 2022, in the event the CPUC adopts an additional year.

On July 16, 2019, the assigned ALJ issued a PD in the Utility’s 2019 GT&S rate case pending at the CPUC. The PD proposes a 2019 revenue requirement of $1.327 billion compared to the Utility’s (revised) request of $1.485 billion. This corresponds to an increase of $27 million over the Utility’s 2018 authorized revenue requirement of $1.301 billion, compared to the $184 million increase requested by the Utility. The PD also proposes revenue requirements of $1.427 billion for 2020, and $1.511 billion for 2021, compared to the Utility’s request of $1.595 billion for 2020, and $1.693 million for 2021. The PD also proposes a revenue requirement of $1.575 billion for 2022, compared to the Utility’s request of $1.679 billion for 2022. The proposed revenue requirement for 2022 allows for the possible combination of the Utility’s 2023 GRC and GT&S rate cases.

The revenue requirement amounts requested by the Utility and the revenue requirement amounts in the PD are set forth in the following table:

The PD proposes to remove from rate base of $304 million of pipeline replacement capital expenditures for the 2016-2018 period due to cost overruns. Incorporating this reduction, the PD proposes a rate base for 2019 of $4.46 billion, which corresponds to an increase of $0.75 billion over the 2018 adopted rate base of $3.71 billion. This is compared to the Utility’s rate base request of $4.75 billion for 2019.

The PD proposes a rate base of $4.98 billion for 2020, $5.37 billion for 2021, and $5.71 billion for 2021. The rate base amounts also 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 pursuant to the 2015 GT&S rate case decision. The Utility is unable to predict whether the $576 million, or a portion thereof, will ultimately be approved by the CPUC and included in the Utility’s future rate base.

The PD proposes the adoption of the Utility’s proposed Natural Gas Storage Strategy, with minor modifications related to the decommissioning or sale of the Utility’s Los Medanos and Pleasant Creek storage fields, and adopts a two-way balancing account for storage costs, which will be subject to a reasonableness review in the next GT&S rate case. The PD proposes to retain the one-way balancing account for transmission integrity management, and to adopt a number of new, one-way balancing accounts covering other operational areas.

If adopted, the PD also would resolve the second phase of the proceeding, which addressed the removal of officer compensation costs from the revenue requirement, which is required by SB 901. The PD proposes adoption of the joint stipulation offered by the Utility, PAO and TURN that reduces the Utility’s requested 2019 GT&S operating expenses by $1.428 million and capital expenditures by $0.455 million.

Opening comments on the PD were filed on August 5, 2019. The CPUC may vote on the PD, at the earliest, on August 15, 2019. The Utility is unable to predict the timing and outcome of this proceeding.

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

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~~were remanded to FERC for further proceedings consistent with the Court of Appeals’ opinion. If FERC ~~concludes~~concluded 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~~concluded 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~~On July 18, 2019, FERC issued its Order on Remand reaffirming its prior grant of the ~~timing and outcome of FERC’s decision.~~Utility’s request for the 50 basis point ROE adder.

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.

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 late-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.

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,

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 parties conducted a settlement conference on March 14 to 15, 2019 and on June 13 to 14, 2019. The next settlement conference is scheduled for August 13 to 14, 2019.

On May 9, 2019, the Utility filed an application with the FERC requesting revisions to its TO20 rate case formula rate model to remove the impact of this non-cash charge on the ratio of common equity to total capital. The Utility ~~requested~~indicates in its application that, because of the recording of the non-cash wildfire-related charges in connection with the 2017 Northern California wildfires and the 2018 Camp fire, the Utility’s financial statements reflected a ratio of common equity to total capital of approximately 41% as of December 31, 2018. The Utility indicates that the proposed revisions adjust the equity ratio to accurately reflect how the Utility financed the capital projects that are included in rate base. The Utility’s current rate base was financed with an equity ratio of approximately 52%, rather than the 41% equity ratio. In addition, on May 9, 2019, the Utility submitted a request to the FERC ~~accept~~to exclude the Wildfire Charge from the Utility’s capital structure for the purpose of calculating its Allowance for Funds Used During Construction (AFUDC) effective January 1, 2019.

On July 10, 2019, the FERC accepted the Utility’s revisions to the formula rate ~~filing~~ to become effective on December ~~1, 2018,~~9, 2019, subject to refund, 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, 2019. FERC may decide to suspend the TO20 rates 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 of 2019.established hearing and settlement judge procedures.

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 December 2019, for rates and charges to become effective January 1 of the following year, consistent with the formula rate.

~~Diablo Canyon Nuclear Power Plant~~For more information on the TO rate cases, see the 2018 Form 10-K.

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~~Utility submitted a Diablo Canyon site-specific decommissioning cost estimate of $4.8 billion which represents a total cost estimate to decommission the Diablo Canyon facilities.

On February 14, 2019, the CPUC issued a scoping memo authorizing addressing the scope of the NDCTP ~~forecast includes employee severance program~~Proceeding to include reasonableness reviews of the Diablo Canyon decommissioning cost estimates, ~~it does not include estimated~~ratemaking proposals, proposed Diablo Canyon milestone framework, plans to address host community needs, reasonableness of Humboldt Bay Power Plant decommissioning costs, ~~related~~and reasonableness of preforming Diablo Canyon 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 ~~employee retention~~combine A.18-07-013, which seeks authorization for the Utility to establish the Diablo Canyon Decommissioning Memorandum Account to track funding for Diablo Canyon pre-shutdown decommissioning planning activities with the NDCTP 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 ~~retraining~~approval of the CPUC which will be discussed in this year’s NDCTP Proceeding. The CPUC will hold a public participation hearing for residents and ~~development programs,~~organizations in and ~~the~~near San Luis Obispo ~~County community mitigation program, which were approved in the CPUC’s final decision~~to give their perspective and in SB 1090. The employee retraining program costs will be included in the 2018 NDCTP forecast. The Utility intends to conduct a site-specific decommissioning study to update the 2015 NDCTP forecast and to submit the study, along with the NDCTP application,input to the CPUC byabout the ~~end~~Utility’s request to track costs of ~~December 2018.~~Diablo Canyon Decommissioning Planning Activities. The public participation hearing is scheduled for August 7 to 8, 2019.

On July 15, 2019, intervenors in this proceeding submitted their testimonies. Rebuttal Testimony is due August 15, 2019.

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 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 2-year period 2023 to 2024; by an annual expense only balancing account. The Utility is also defending the reasonableness and prudence of the ~~Notes~~$398.4 million spent for Humboldt Bay Power Plant decommissioning project costs completed to ~~the Consolidated Financial Statements in Item 8 of the 2017 Form 10-K.~~date.

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 June 30, 2019, the Condensed Consolidated Financial Statements include long-term regulatory assets of $127 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.

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.

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. However, on April 25, 2019, the CPUC adopted a decision denying cost recovery on a forecast basis for the 2018 and 2019 costs requested.

On ~~October 12,~~November 2, 2018, the assigned ALJ denied the 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 ~~notified~~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 ~~and other parties that $180~~authorized the Utility’s request for interim rate relief, allowing for recovery of $373 million of costs (63% of the ~~forecasted~~total costs incurred in 2016 and 2017). Costs included in the interim rate relief are subject to audit and refund. On July 1, 2019, the Utility filed a motion requesting approval to: (i) revise the 2018 CEMA testimony and ~~2019~~workpapers to exclude forecast costs, (ii) include 2018 recorded tree mortality and fire risk ~~mitigation~~reduction costs, ~~would be removed from~~

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.

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

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.

On March 12, 2019, the CPUC approved the Utility’s FRMMA to track costs incurred beginning January 1, 2019, for fire risk mitigation activities that are not otherwise covered in revenue requirements. The FRMMA was authorized by SB 901 to capture mitigation costs incurred in advance of the CPUC’s approval of the Utility’s Wildfire Mitigation Plan. The Utility has proposed that the FRMMA continue after the approval of its 2019 Wildfire Mitigation Plan to record costs of wildfire mitigation activities that were beyond the initial identified scope of work.

While the Utility intends to seek recovery of the FRMMA balance in a future application, rate recovery requires CPUC reasonableness review and authorization in a separate proceeding or through a GRC. ~~(See Note 3~~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 the FRMMA, which the Utility expects will be substantial.

On June 5, 2019, the Utility submitted an advice letter to establish the WPMA effective May 30, 2019. The purpose of the ~~Notes~~WPMA is to track costs incurred to implement the Utility’s Wildfire Mitigation Plan, as required by SB 901. The WPMA is required to be established upon approval of a utility’s wildfire mitigation plan to track costs incurred to implement the plan. Upon approval of the memorandum account, the Utility will record any costs incurred in implementing an approved Wildfire Mitigation Pan.

The Utility anticipates that the recovery of the costs recorded to the ~~Condensed Consolidated Financial Statements~~WPMA would occur through a general rate case or future application at which time the CPUC would review the costs for reasonableness as required by SB 901. 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 ~~Item 1.)~~connection with the 2019 Wildfire Safety Plan recorded in the WPMA, which the Utility expects will be substantial.

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 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 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:

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 May 30, 2019, the CPUC approved two decisions related to the Utility’s 2019 Wildfire Safety Plan. The first decision was specific to the Utility’s plan and generally approved the plan, subject to certain reporting, data gathering, and other requirements set forth in the decision. The Utility-specific decision did not approve the amendment filed by the Utility on April 25, 2019. The second decision was a guidance decision for all of the utilities that submitted wildfire mitigation plans. This guidance decision included additional reporting, data gathering, and other requirements and provided that the Utility’s April 25^th amendment will be examined in Phase 2 of this proceeding. On June 14, 2019, the Assigned Commissioner and ALJ issued a decision implementing Phase 2 of the OIR, announcing Phase 2 workshops to develop metrics and templates to evaluate the Utility’s 2019 Wildfire Safety Plan and report data consistently and a process for submission of the 2020 plans. The decision also announced that the CPUC would evaluate the Utility’s April 25^th amendment in Phase 2, as well as the process for independent evaluation of the Utility’s compliance with its 2019 plan. 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 the FRMMA and WPMA, which the Utility expects will be substantial.

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 for recovery of costs related to the 2017 Northern California wildfires.

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

On July 8, 2019, the CPUC issued a decision in the Customer Harm Threshold proceeding. The CPUC decision provides that “[a]n electrical corporation that has filed for relief under chapter 11 of the Bankruptcy Code may not access the Stress Test to recover costs in an application under Section 451.2(b), because the Commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs, and liabilities, as required by Section 451.2(b).” This determination effectively bars PG&E Corporation and the Utility from access to relief under the Customer Harm Threshold during the pendency of the Chapter 11 Cases. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

The decision otherwise adopts a methodology 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; (3) a potential maximum regulatory adjustment of either 20% of the Customer Harm Threshold or 5% of the total disallowed wildfire liabilities, whichever is greater; and (4) an adjustment to preserve for ratepayers any tax benefits associated with the Customer Harm Threshold. The decision also requires a utility to include proposed ratepayer protection measures to mitigate harm to ratepayers as part of an application under section 451.2(b).

Failure to obtain a substantial or full recovery of costs related to wildfires could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows.

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 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 prehearing conference for this rulemaking was held on March 1, 2019. On May 2, 2019, the Assigned Commissioner issued a scoping memo and ruling for the proceeding, which sets forth the category, issues to be addressed, and schedule of the proceeding.

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.

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.~~

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:

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

On December 13, 2018, the CPUC opened an OIR to examine the notification, mitigation, and reporting requirements on electric utilities when de-energizing power lines in case of dangerous conditions that threaten life or property in California. This proceeding has focused on the following issues:

On May 30, 2019, the CPUC approved a decision for phase one of this proceeding, which adopted de-energization communication and notification guidelines for the electric IOUs along with updates to requirements established in Resolution ESRB-8. The CPUC also provided clarity on phase two issues; however, a final determination of phase two issues will be conveyed in the phase two scoping memo. Phase 2 will take a more comprehensive look at de-energization practices, including mitigation, additional coordination across agencies, further refinements to findings in phase 1, re-energization practices, and other matters.

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 recovery of costs related to the 2017 Northern California wildfires. On March 29, 2019, the Assigned Commissioner issued a scoping memo, which confirmed that the CPUC in this proceeding would establish a Customer Harm Threshold methodology applicable only to 2017 fires, to be invoked in connection with a future application for cost recovery, and would not determine a specific financial outcome in this proceeding. On July 8, 2019, the CPUC issued a decision in the OIR, which establishes a methodology to establish the Customer Harm Threshold in future applications under Section 451.2(a), but determines that a utility that has filed for relief under Chapter 11 cannot access the Customer Harm Threshold. On August 7, 2019, the Utility submitted to the CPUC an application for rehearing of the decision. The Utility indicated in its application, among other things, that the CPUC’s decision “is contrary to law because it bars a utility that has filed for Chapter 11 from accessing the CHT [Customer Harm Threshold], requires a utility to file a cost recovery application before the CHT [Customer Harm Threshold] will be determined, and erects ratepayer protection mechanisms as an extra-statutory hurdle for accessing the CHT [Customer Harm Threshold].” The Utility also argued that the CPUC should apply the Customer Harm Threshold methodology to costs related to the 2018 Camp fire.

(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.

Each of California’s large investor-owned electric utility companies that are not currently subject to Chapter 11 (Southern California Edison and San Diego Gas & Electric Company) has elected to participate in the Wildfire Fund to be established under AB 1054. On July 23, 2019, the Utility notified the CPUC of its intent to participate in the Wildfire Fund (which participation is subject to the conditions set forth in AB 1054, including those conditions outlined below).

The Wildfire Fund to be established under AB 1054 will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment. Electric utility companies that draw from the fund will only be required to repay amounts that are determined by the CPUC in an application for cost recovery not to be just and reasonable, subject to a rolling three-year disallowance cap equal to 20% of the electric utility company’s transmission and distribution equity rate base. For the Utility, this disallowance cap is expected to be approximately $2.3 billion for the three-year period starting in 2019, subject to adjustment based on changes in the Utility’s total transmission and distribution equity rate base. The disallowance cap is inapplicable in certain circumstances, including if the Wildfire Fund administrator determines that the electric utility company’s actions or inactions that resulted in the applicable wildfire constituted “conscious or willful disregard for the rights and safety of others,” or the electric utility company fails to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable will not need to be repaid to the fund, resulting in a draw-down of the fund. The Wildfire Fund and disallowance cap will be terminated when the amounts therein are exhausted. The Wildfire Fund is expected to be capitalized with (i) $10.5 billion of proceeds of bonds supported by a 15-year extension of the Department of Water Resources charge to ratepayers, (ii) $7.5 billion in initial contributions from California’s three investor-owned electric utility companies and (iii) $300 million in annual contributions paid by California’s three investor-owned electric utility companies. The contributions from the investor-owned electric utility companies will be effectively borne by their respective shareholders, as they will not be permitted to recover these costs from ratepayers. The costs of the initial and annual contributions are allocated among the three investor-owned electric utility companies pursuant to a “Wildfire Fund allocation metric” set forth in AB 1054 based on land area in the applicable utility’s service territory classified as high fire threat districts and adjusted to account for risk mitigation efforts. The Utility’s initial Wildfire Fund allocation metric is expected to be 64.2% (representing an initial contribution of approximately $4.8 billion and annual contributions of approximately $193 million). In addition, all initial and annual contributions will be excluded from the measurement of the Utility’s authorized capital structure.

AB 1054 provides that the Wildfire Fund will be established when Southern California Edison and San Diego Gas & Electric Company provide their initial contributions.

On August 7, 2019, PG&E Corporation and the Utility submitted a motion with the Bankruptcy Court for the entry of an order authorizing PG&E Corporation and the Utility to participate in the Wildfire Fund and to make any initial and annual contributions to the Wildfire Fund upon emergence from Chapter 11. The motion is expected to be heard on August 28, 2019, and objections and other responses are due August 21, 2019.

If the Utility satisfies the requirements to participate in the Wildfire Fund, the Utility will be required to fund its initial contribution upon its emergence from Chapter 11. The Utility’s required contributions to the Wildfire Fund will be substantial. Participation in the Wildfire Fund is expected to have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity and cash flows. The Utility is currently evaluating the accounting and tax treatment of the required initial and annual contributions. The timing and amount of any potential charges associated with shareholder contributions would also depend on various factors, including the final determination of an allocation of contributions among the Utility and California’s other large electric utility companies (San Diego Gas & Electric Company and Southern California Edison Company) and the timing of resolution of the Chapter 11 Cases. The Utility is currently developing a Chapter 11 plan of reorganization that would provide for the financing of such required contributions, but there can be no assurance that PG&E Corporation and the Utility will successfully develop, consummate or implement any such plan, which will ultimately require Bankruptcy Court, creditor and regulatory approval. Further, there can be no assurance that the expected benefits of participating in the Wildfire Fund ultimately outweigh its substantial costs.

In response to directives in AB 1054, on July 26, 2019, the CPUC opened a new rulemaking to consider the authorization of a non-bypassable charge to support the Wildfire Fund. Comments on issues (e.g., the just and reasonableness of such a charge) are expected to be due in late August, 2019. A final decision in the proceeding is expected in October 2019.

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:

The Utility implemented a revised PCIA in rates 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 stakeholder working group process to further develop a number of PCIA-related proposals for consideration by the CPUC. Working Group One, which is co-facilitated by the Utility and the California Community Choice Association, focuses on developing benchmarks and a true-up mechanism that reflect the current market value of brown power, resource adequacy, and renewable energy credits (Issues 1 to 7); and load forecasting, rate design mechanics, and customer bill presentation (Issues 8 to 12). Working Group Two focuses on CCA and DA prepayment options; and Working Group Three focuses on portfolio optimization and cost reduction, allocation and auctions, and whether the CPUC should consider new or modified shareholder responsibility for future portfolio mismanagement. The schedule included in the scoping memo and ruling indicates that the CPUC is expected to issue two decisions impactful to 2020 rates in late 2019 concerning benchmark true-ups and PCIA rate design mechanics. Proposed decisions addressing matters relevant to the prepayment working group and the portfolio optimization and cost reduction, and allocation and auction working group are anticipated in 2020.

On May 31, 2019, the Working Group One co-leads filed the Final Report on Issues 1 to 7. On July 1, 2019, the Working Group One co-leads filed the Final Report on Issues 8 to 12. On July 9, 2019, the assigned ALJ modified the procedural schedule allowing parties to file comments on the July 1 Final Report, and updated the date for parties to request evidentiary hearings on the Final Report of Working Group One on Issues 8 to 12. Opening comments on issues 8 to 12 were filed on July 19, 2019, reply comments were filed on July 26, 2019, and motions for evidentiary hearings were due August 2, 2019. In accordance with the current schedule, a proposed decision on Working Group One issues 1 to 7 would be issued in ~~late 2019.~~September 2019, a proposed decision on Working Group One issues 8 to 12 would be issued in Fall 2019, and final decisions on each of those matters would be voted 30 days after those proposed decisions.



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	The New York Stock Exchange
First preferred stock, cumulative, par value $25 per share, 5% series A redeemable	PCG-PE	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% redeemable	PCG-PD	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.80% redeemable	PCG-PG	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.50% redeemable	PCG-PH	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 4.36% series A redeemable	PCG-PI	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 6% nonredeemable	PCG-PA	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5.50% nonredeemable	PCG-PB	NYSE American LLC
First preferred stock, cumulative, par value $25 per share, 5% nonredeemable	PCG-PC	NYSE American LLC



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



Indicate the numberof 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 25, 2018:~~August 2, 2019:
PG&E Corporation:								~~518,674,276~~529,223,793
PacificGas 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 EQUITY
	~~CONDENSED CONSOLIDATED STATEMENTS OF INCOME~~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
	CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY
	NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
	NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION
	NOTE 2: ~~SIGNIFICANT ACCOUNTING POLICIES~~BANKRUPTCY FILING
	NOTE 3: SIGNIFICANT ACCOUNTING POLICIES
	NOTE 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 ~~AND COMMITMENTS~~
	NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS
	NOTE 12: SUBSEQUENT EVENTS
	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
	~~CRITICAL ACCOUNTING POLICIES~~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



~~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
AB	Assembly Bill
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
CCPA	California Consumer Privacy Act of 2018
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~~PSA	~~Risk Assessment Mitigation Phase~~plan support agreement
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
Tax Act	Tax Cuts and Jobs Act of 2017
TCC	Official Committee of Tort Claimants
TE	transportation electrification
TO	transmission owner
TURN	The Utility Reform Network
UCC	Official Committee of Unsecured Creditors
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 designed to assist those displaced by the 2018 Camp fire and 2017 Northern California wildfires with the costs of temporary housing and other urgent needs
Wildfire Fund	statewide fund established by AB 1054 that will be available for eligible electric utility companies to pay eligible claims for liabilities arising from wildfires occurring after July 12, 2019 that are caused by the applicable electric utility company’s equipment
WPMA	wildfire plan memorandum account


	(Unaudited)												(Unaudited)
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended June 30,						Six Months Ended June 30,
(in millions, except per share amounts)	2018			2017			2018			2017			2019			2018			2019			2018
Operating Revenues
Electric	$	3,466		$	3,648		$	9,729		$	10,036		$	2,946		$	3,312		$	5,738		$	6,263
Natural gas	915			869			2,942			2,999			997			922			2,216			2,027
Total operating revenues	4,381			4,517			12,671			13,035			3,943			4,234			7,954			8,290
Operating Expenses
Cost of electricity	1,256			1,466			3,038			3,436			837			963			1,436			1,782
Cost of natural gas	69			78			437			524			108			79			447			368
Operating and maintenance	1,611			1,324			5,001			4,453			1,942			1,786			4,029			3,390
Wildfire-related claims, net of insurance recoveries	(10		)	53			2,108			—			3,900			2,125			3,900			2,118
Depreciation, amortization, and decommissioning	759			710			2,257			2,134			796			746			1,593			1,498
Total operating expenses	3,685			3,631			12,841			10,547			7,583			5,699			11,405			9,156
Operating Income (Loss)	696			886			(170		)	2,488
Operating Loss													(3,640		)	(1,465		)	(3,451		)	(866		)
Interest income	14			9			35			22			22			12			44			21
Interest expense	(232		)	(220		)	(678		)	(663		)	(60		)	(226		)	(163		)	(446		)
Other income, net	104			38			318			98			66			106			137			214
Income (Loss) Before Income Taxes	582			713			(495		)	1,945
Income tax provision (benefit)	15			160			(527		)	403
Net Income	567			553			32			1,542
Reorganization items, net													(56		)	—			(183		)	—
Loss Before Income Taxes													(3,668		)	(1,573		)	(3,616		)	(1,077		)
Income tax benefit													(1,119		)	(593		)	(1,203		)	(542		)
Net Loss													(2,549		)	(980		)	(2,413		)	(535		)
Preferred stock dividend requirement of subsidiary	3			3			10			10			4			4			7			7
Income Available for Common Shareholders	$	564		$	550		$	22		$	1,532
Loss Attributable to Common Shareholders													$	(2,553	)	$	(984	)	$	(2,420	)	$	(542	)
Weighted Average Common Shares Outstanding, Basic	517			513			516			511			529			516			528			516
Weighted Average Common Shares Outstanding, Diluted	517			516			517			514			529			516			528			517
Net Earnings Per Common Share, Basic	$	1.09		$	1.07		$	0.04		$	3.00
Net Earnings Per Common Share, Diluted	$	1.09		$	1.07		$	0.04		$	2.98
Net Loss Per Common Share, Basic													$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)
Net Loss Per Common Share, Diluted													$	(4.83	)	$	(1.91	)	$	(4.58	)	$	(1.05	)

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)						(Unaudited)
	Balance At						Balance At
(in millions)	September 30, 2018			December 31, 2017			June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	430		$	449		$	3,459		$	1,668
Accounts receivable:
Customers (net of allowance for doubtful accounts of $58 and $64 at respective dates)	1,297			1,243
Customers (net of allowance for doubtful accounts of $39 and $56 at respective dates)							1,260			1,148
Accrued unbilled revenue	962			946			991			1,000
Regulatory balancing accounts	1,326			1,222			1,884			1,435
Other	902			861			2,610			2,686
Regulatory assets	229			615			212			233
Inventories:
Gas stored underground and fuel oil	116			115			99			111
Materials and supplies	389			366			509			443
Income taxes receivable							18			23
Other	698			464			535			448
Total current assets	6,349			6,281			11,577			9,195
Property, Plant, and Equipment
Electric	56,860			55,133			60,967			59,150
Gas	20,798			19,641			22,428			21,556
Construction work in progress	2,855			2,471			2,563			2,564
Other	2			3			20			2
Total property, plant, and equipment	80,515			77,248			85,978			83,272
Accumulated depreciation	(24,310		)	(23,459		)	(25,727		)	(24,715		)
Net property, plant, and equipment	56,205			53,789			60,251			58,557
Other Noncurrent Assets
Regulatory assets	4,429			3,793			5,349			4,964
Nuclear decommissioning trusts	2,917			2,863			3,016			2,730
Operating lease right of use asset							2,662			—
Income taxes receivable	67			65			67			69
Other	1,418			1,221			1,465			1,480
Total other noncurrent assets	8,831			7,942			12,559			9,243
TOTAL ASSETS	$	71,385		$	68,012		$	84,387		$	76,995

See accompanying Notes to the Condensed Consolidated Financial Statements.


	(Unaudited)						(Unaudited)
	Nine Months Ended September 30,						Six Months Ended June 30,
(in millions)	2018			2017			2019			2018
Cash Flows from Operating Activities
Net income	$	32		$	1,542
Net loss							$	(2,413	)	$	(535	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	2,257			2,134			1,593			1,498
Allowance for equity funds used during construction	(97		)	(63		)	(45		)	(63		)
Deferred income taxes and tax credits, net	10			848			(915		)	(145		)
Disallowed capital expenditures	(38		)	47
Reorganization items, net (Note 2)							90			—
Other	231			204			53			104
Effect of changes in operating assets and liabilities:
Accounts receivable	(201		)	(58		)	(54		)	(11		)
Wildfire-related insurance receivable	64			(166		)	35			(144		)
Inventories	(24		)	(35		)	(41		)	(6		)
Accounts payable	245			76			159			39
Wildfire-related claims	2,233			12			(14		)	2,299
Income taxes receivable/payable	—			135			5			—
Other current assets and liabilities	(154		)	23			(15		)	(103		)
Regulatory assets, liabilities, and balancing accounts, net	(128		)	(30		)	(34		)	(12		)
Liabilities subject to compromise							4,221			—
Other noncurrent assets and liabilities	(194		)	68			132			(168		)
Net cash provided by operating activities	4,236			4,737			2,757			2,753
Cash Flows from Investing Activities
Capital expenditures	(4,592		)	(3,938		)	(2,410		)	(2,897		)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,121			1,043			517			802
Purchases of nuclear decommissioning trust investments	(1,165		)	(1,071		)	(547		)	(815		)
Other	19			16			6			15
Net cash used in investing activities	(4,617		)	(3,950		)	(2,434		)	(2,895		)
Cash Flows from Financing Activities
Proceeds from debtor-in-possession credit facility							1,850			—
Repayments of debtor-in-possession credit facility							(350		)	—
Debtor-in-possession credit facility debt issuance costs							(111		)	—
Borrowings under revolving credit facilities	775			—			—			700
Repayments under revolving credit facilities	(775		)	—
Net issuances (repayments) of commercial paper, net of discount of $1 and $4 at respective dates	(182		)	(652		)
Net repayments of commercial paper, net of discount of $1							—			(182		)
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
Proceeds from issuance of long-term debt, net of discount and issuance costs							—			350
Long-term debt matured or repurchased	(750		)	(345		)	—			(750		)
Common stock issued	137			345			85			82
Common stock dividends paid	—			(754		)
Other	14			(101		)	(6		)	10
Net cash provided by (used in) financing activities	362			(773		)
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 cash provided by financing activities							1,468			210
Net change in cash, cash equivalents, and restricted cash							1,791			68
Cash, cash equivalents, and restricted cash at January 1							1,675			456
Cash, cash equivalents, and restricted cash at June 30							$	3,466		$	524
Less: Restricted cash and restricted cash equivalents included in other current assets							(7		)	$	(7	)
Cash and cash equivalents at June 30							$	3,459		$	517


Supplemental disclosures of cash flow information
Cash received (paid) for:
Cash paid for:
Interest, net of amounts capitalized	$	(650	)	$	(644	)	$	(21	)	$	(394	)
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			$	836		$	317
Noncash common stock issuances	—			16
Terminated capital leases	161			—

See accompanying Notes to the Condensed Consolidated Financial Statements.



(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	—	—		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
Net loss	—	—		(2,549		)	—			(2,549		)	—		(2,549		)
Other comprehensive loss	—	—		—			—			—			—		—
Common stock issued, net	13,515	—		—			—			—			—		—
Stock-based compensation amortization	—	14		—			—			14			—		14
Balance at June 30, 2019	529,223,793	$	13,014	$	(2,663	)	$	(9	)	$	10,342		$	252	$	10,594



(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	—		—		—		133			—			133
Other comprehensive loss	—		—		—		—			—			—
Equity contribution	—		—		—		—			—			—
Balance at March 31, 2019	$	258	$	1,322	$	8,550	$	2,959		$	(1	)	$	13,088
Net loss	—		—		—		(2,550		)	—			(2,550		)
Other comprehensive loss	—		—		—		—			—			—
Equity contribution	—		—		—		—			—			—
Balance at June 30, 2019	$	258	$	1,322	$	8,550	$	409		$	(1	)	$	10,538



(in millions)	Utility		PG&E Corporation⁽¹⁾		PG&E Corporation Consolidated
Financing debt⁽²⁾	$	21,811	$	650	$	22,461
Wildfire-related claims⁽³⁾	18,012		—		18,012
Trade creditors	1,325		4		1,329
Non-qualified benefit plan	18		125		143
2001 bankruptcy disputed claims	221		—		221
Customer deposits & advances	278		—		278
Other	164		2		166
Total Liabilities Subject to Compromise	$	41,829	$	781	$	42,610



	Three Months Ended June 30, 2019
(in millions)	Utility			PG&E Corporation⁽¹⁾			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	—		$	—		$	—
Legal and other	75			1			76
Interest income	(18		)	(3		)	(21		)
Adjustments to LSTC	—			—			—
Trustee fees⁽²⁾	—			1			1
Total reorganization items, net	$	57		$	(1	)	$	56



	Petition Date Through June 30, 2019
(in millions)	Utility			PG&E Corporation⁽¹⁾			PG&E Corporation Consolidated
Debtor-in-possession financing costs	$	97		$	17		$	114
Legal and other	98			2			100
Interest income	(27		)	(5		)	(32		)
Adjustments to LSTC	—			—			—
Trustee fees⁽²⁾	—			1			1
Total reorganization items, net	$	168		$	15		$	183


	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
	Three Months Ended September 30,												Three Months Ended June 30,
(in millions)	2018			2017			2018			2017			2019			2018			2019			2018
Service cost for benefits earned⁽¹⁾	$	128		$	118		$	16		$	14		$	111		$	129		$	14		$	17
Interest cost	171			178			17			20			190			172			19			18
Expected return on plan assets	(255		)	(193		)	(33		)	(24		)	(226		)	(256		)	(30		)	(32		)
Amortization of prior service cost	(1		)	(1		)	4			4			(2		)	(2		)	3			3
Amortization of net actuarial loss	1			6			(1		)	1			—			2			(1		)	(2		)
Net periodic benefit cost	44			108			3			15			73			45			5			4
Regulatory account transfer⁽²⁾	41			(23		)	—			—			10			39			—			—
Total	$	85		$	85		$	3		$	15		$	83		$	84		$	5		$	4


	Pension Benefits			Other Benefits			Total			Pension Benefits			Other Benefits			Total
(in millions, net of income tax)	Three Months Ended September 30, 2018									Three Months Ended June 30, 2019
Beginning balance	$	(30	)	$	17		$	(13	)	$	(21	)	$	17		$	(4	)
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		)
Amortization of prior service cost (net of taxes of $1 and $1, respectively)⁽¹⁾										(1		)	2			1
Amortization of net actuarial loss (net of taxes of $0 and $1, respectively)⁽¹⁾										—			—			—
Regulatory account transfer (net of taxes of $1 and $0, respectively)⁽¹⁾										1			(2		)	(1		)
Net current period other comprehensive gain (loss)	1			—			1			—			—			—
Ending balance	$	(29	)	$	17		$	(12	)	$	(21	)	$	17		$	(4	)



(in millions)	Three Months Ended June 30, 2019		Six Months Ended June 30, 2019
Operating lease fixed cost	$	114	$	236
Operating lease variable cost	490		799
Total operating lease costs	$	604	$	1,035



(in millions)	June 30, 2019
2019⁽¹⁾	$	450
2020	679
2021	623
2022	548
2023	255
Thereafter	692
Total lease payments	3,247
Less imputed interest	(594		)
Total	$	2,653



(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		June 30, 2019		December 31, 2018
Pension benefits(1)	$	1,837	$	1,954	$	1,928	$	1,947
Environmental compliance costs	851		837		997		1,013
Utility retained generation(2)	285		319		251		274
Price risk management	67		65		67		90
Unamortized loss, net of gain, on reacquired debt(3)	80		79		230		76
Catastrophic event memorandum account ⁽¹⁾⁽⁴⁾	760		274		918		790
Wildfire expense memorandum account ⁽²⁾⁽⁵⁾	77		—		127		94
Fire hazard prevention memorandum account ⁽³⁾⁽⁶⁾	65		1		291		263
Fire risk mitigation memorandum account⁽⁷⁾					154		—
Other	407		264		386		417
Total long-term regulatory assets	$	4,429	$	3,793	$	5,349	$	4,964



	Liability Balance at
(in millions)	June 30, 2019		December 31, 2018
Cost of removal obligations⁽¹⁾	$	6,233	$	5,981
Deferred income taxes⁽²⁾	4		283
Recoveries in excess of AROs⁽³⁾	472		356
Public purpose programs⁽⁴⁾	785		674
Employee benefit plans⁽⁵⁾	423		421
Other	1,121		824
Total long-term regulatory liabilities	$	9,038	$	8,539



	Receivable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric distribution	$	465	$	160
Electric transmission	91		128
Utility generation	92		79
Gas distribution and transmission	173		462
Energy procurement	654		168
Public purpose programs	97		111
Other	312		327
Total regulatory balancing accounts receivable	$	1,884	$	1,435



	Payable Balance at
(in millions)	June 30, 2019		December 31, 2018
Electric transmission	135		134
Gas distribution and transmission	6		9
Energy procurement	308		59
Public purpose programs	610		587
Other	311		287
Total regulatory balancing accounts payable	$	1,370	$	1,076



(in millions)	Termination Date		Aggregate Limit		Term Loan Borrowings		Revolver Borrowings		Letters of Credit Outstanding		Aggregate Availability
DIP Facilities	December 2020	(1)	$	5,500	$	1,500	$	—	$	521	$	3,479


												Balance at,
(in millions)	Termination Date	Facility Limit			Letters of Credit Outstanding		Borrowings		Facility Availability		Contractual Interest Rates	June 30, 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 2047											2.95% to 6.35%	14,600		14,600
Unamortized discount, net of 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


		Contract Volume at			Contract Volume at
Underlying Product	Instruments	September 30, 2018	December 31, 2017	Instruments	June 30, 2019	December 31, 2018
Natural Gas ⁽¹⁾ (MMBtus ⁽²⁾)	Forwards, Futures and Swaps	250,021,802	228,768,745	Forwards, Futures and Swaps	174,575,917	177,750,349
	Options	29,534,224	60,736,806	Options	16,455,000	13,735,405
Electricity (Megawatt-hours)	Forwards, Futures and Swaps	3,939,691	2,872,013	Forwards, Futures and Swaps	2,999,616	3,833,490
	Congestion Revenue Rights ⁽³⁾	316,451,690	312,272,177	Options	912,033	—
				Congestion Revenue Rights ⁽³⁾	329,571,344	340,783,089


•	Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.


•	Level 2 – Other inputs that are directly or indirectly observable in the marketplace.


•	Level 3 – Unobservable inputs which are supported by little or no market activities.


	Fair Value Measurements											Fair Value Measurements
	September 30, 2018											June 30, 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	$	3,402	$	—	$	—	$	—		$	3,402
Nuclear decommissioning trusts
Short-term investments	14		—		—		—			14		16		—		—		—			16
Global equity securities	1,970		—		—		—			1,970		1,959		—		—		—			1,959
Fixed-income securities	738		631		—		—			1,369		815		698		—		—			1,513
Assets measured at NAV	—		—		—		—			19		—		—		—		—			19
Total nuclear decommissioning trusts ⁽²⁾	2,722		631		—		—			3,372		2,790		698		—		—			3,507
Price risk management instruments (Note 7)
Price risk management instruments (Note 8)
Electricity	1		5		110		2			118		—		13		192		20			225
Gas	—		6		—		1			7		—		3		—		24			27
Total price risk management instruments	1		11		110		3			125		—		16		192		44			252
Rabbi trusts
Fixed-income securities	—		75		—		—			75		—		98		—		—			98
Life insurance contracts	—		68		—		—			68		—		71		—		—			71
Total rabbi trusts	—		143		—		—			143		—		169		—		—			169
Long-term disability trust
Short-term investments	8		—		—		—			8		5		—		—		—			5
Assets measured at NAV	—		—		—		—			112		—		—		—		—			142
Total long-term disability trust	8		—		—		—			120		5		—		—		—			147
TOTAL ASSETS	$	3,108	$	785	$	110	$	3		$	4,137	$	6,197	$	883	$	192	$	44		$	7,477
Liabilities:
Price risk management instruments (Note 7)
Price risk management instruments (Note 8)
Electricity	$	5	$	12	$	86	$	(17	)	$	86	$	—	$	4	$	83	$	(4	)	$	83
Gas	—		3		—		(1		)	2		2		3		—		(3		)	2
TOTAL LIABILITIES	$	5	$	15	$	86	$	(18	)	$	88	$	2	$	7	$	83	$	(7	)	$	85


	Fair Value at							Fair Value at
(in millions)	September 30, 2018							June 30, 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	$	191	$	64	Market approach	CRR auction prices	$(13.11) - 22.76
Power purchase agreements	$	—	$	42	Discounted cash flow	Forward prices	$ 19.81 - 38.80	$	1	$	19	Discounted cash flow	Forward prices	$ 19.68 - 38.80


	At September 30, 2018				At December 31, 2017				At June 30, 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		1,500		1,500		17,450		14,747


(in millions)
As of September 30, 2018	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
As of June 30, 2019										Amortized Cost		Total Unrealized Gains		Total Unrealized Losses			Total Fair Value
Nuclear decommissioning trusts
Short-term investments	$	14	$	—	$	—		$	14	$	16	$	—	$	—		$	16
Global equity securities	478		1,513		(2		)	1,989		496		1,486		(4		)	1,978
Fixed-income securities	1,369		28		(28		)	1,369		1,431		84		(2		)	1,513
Total⁽¹⁾	$	1,861	$	1,541	$	(30	)	$	3,372	$	1,943	$	1,570	$	(6	)	$	3,507
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