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美国证券交易委员会
华盛顿特区，20549

表格

10-Q

（勾选一项）

☒

根据1934年《证券交易法》第13或15(d)条提交的
季度报告

截至以下日期的季度期间

2026年9月30日

或

☐

根据1934年《证券交易法》第13或15(d)条提交的过渡期报告

过渡期自 ___________ 至 __________

委员会
档案
编号

注册人章程中
规定的
完整名称

注册成立所在州或
其他司法管辖区

美国国税局雇主
识别
号码

1-12609

PG&E Corporation

加利福尼亚州

94-3234914

1-2348

Pacific Gas and Electric Company

加利福尼亚州

94-0742640

PG&E Corporation

Pacific Gas and Electric Company

300 Lakeside Drive

奥克兰，

加利福尼亚州

94612

奥克兰，

加利福尼亚州

94612

包括邮政编码在内的主要行政办公地址

PG&E Corporation

Pacific Gas and Electric Company

415

973-1000

415

973-7000

注册人电话号码（包括区号）


根据该法第12(b)条注册的证券：

各类证券名称	交易代码	注册所在交易所名称
普通股，无面值	PCG	纽约证券交易所
第一优先股，累积型，每股面值$25，6%不可赎回	PCG-PA	NYSE American LLC
第一优先股，累积型，每股面值$25，5.50%不可赎回	PCG-PB	NYSE American LLC
第一优先股，累积型，每股面值$25，5%不可赎回	PCG-PC	NYSE American LLC
第一优先股，累积型，每股面值$25，5%可赎回	PCG-PD	NYSE American LLC
第一优先股，累积型，每股面值$25，5% A系列可赎回	PCG-PE	NYSE American LLC
第一优先股，累积型，每股面值$25，4.80%可赎回	PCG-PG	NYSE American LLC
第一优先股，累积型，每股面值$25，4.50%可赎回	PCG-PH	NYSE American LLC
第一优先股，累积型，每股面值$25，4.36%可赎回	PCG-PI	NYSE American LLC
6.000% A系列强制可转换优先股，无面值	PCG-PrX	纽约证券交易所

请勾选说明注册人 (1) 是否已在过去12个月内（或注册人须提交此类报告的较短期间内）提交《1934年证券交易法》第13或15(d)条要求提交的所有报告，以及 (2) 在过去90天内是否一直受此类申报要求约束。

PG&E Corporation：

☒

是

☐

否

Pacific Gas and Electric Company：

☒

是

☐

否

请勾选说明注册人是否已在过去 12 个月内（或注册人须提交此类文件的较短期间内），以电子方式提交根据 S-T 条例第 405 条（本章 § 232.405）要求提交的所有交互式数据文件。

PG&E Corporation：

☒

是

☐

否

Pacific Gas and Electric Company：

☒

是

☐

否

请勾选说明注册人属于大型加速申报公司、加速申报公司、非加速申报公司、较小申报公司还是新兴成长公司。有关“大型加速申报公司”“加速申报公司”“较小申报公司”和“新兴成长公司”的定义，请参见《交易法》规则 12b-2。

PG&E Corporation：

☒

大型加速申报公司

☐

加速申报公司

☐

非加速申报公司

☐

较小申报公司

☐

新兴成长公司

Pacific Gas and Electric Company：

☐

大型加速申报公司

☐

加速申报公司

☒

非加速申报公司

☐

较小申报公司

☐

新兴成长公司

如果属于新兴成长公司，请勾选说明注册人是否选择不使用《交易法》第 13(a) 条规定的、遵守任何新颁布或修订财务会计准则的延长过渡期。

PG&E Corporation：

☐

Pacific Gas and Electric Company：

☐

请勾选说明注册人是否为空壳公司（定义见《交易法》规则 12b-2）。

PG&E Corporation：

☐

是

☒

否

Pacific Gas and Electric Company：

☐

是

☒

否

请勾选说明注册人是否已在法院确认的计划下证券分配后，提交《1934 年证券交易法》第 12、13 或 15(d) 条要求提交的所有文件和报告。

PG&E Corporation：

☒

是

☐

否

Pacific Gas and Electric Company：

☒

是

☐

否

注明截至最近可行日期发行人各类普通股的流通股数。

截至 2026 年 10 月 14 日的普通股流通股数：

PG&E Corporation：

2,680,173,293*

Pacific Gas and Electric Company：

264,374,809

*包括由 Pacific Gas and Electric Company 持有的 477,743,590 股普通股。

PG&E CORPORATION 及

PACIFIC GAS AND ELECTRIC COMPANY

10-Q 表

截至 2026 年 9 月 30 日的季度期间


		SEC 10-Q 表参考编号

术语表
前瞻性陈述
风险因素	第二部分，第 1A 项
管理层对财务状况和经营成果的讨论与分析	第一部分，第 2 项
	概述
	经营成果
	流动性和财务资源
	监管事项
	立法举措
	诉讼及其他事项
	环境事项
	风险管理活动
	关键会计估计
	已发布但尚未采用的会计准则
简明合并财务报表	第一部分，第1项
	PG&E CORPORATION
	简明合并利润表
	简明合并综合收益表
	简明合并资产负债表
	简明合并现金流量表
	简明合并权益表
	PACIFIC GAS AND ELECTRIC COMPANY
	简明合并利润表
	简明合并综合收益表
	简明合并资产负债表
	简明合并现金流量表
	简明合并股东权益表
	简明合并财务报表附注（未经审计）
	附注1：组织架构和列报基础
	附注2：重要会计政策概要
	附注3：监管资产、负债及平衡账户
	附注4：债务
	附注5：SB 901证券化和客户信用信托
	附注6：权益
	附注7：每股收益
	附注8：衍生工具
	附注9：公允价值计量
	附注10：野火相关或有事项
	附注11：其他或有事项和承诺
有关市场风险的定量和定性披露	第一部分，第3项
控制和程序	第一部分，第4项
法律诉讼	第二部分，第1项
未注册的股权证券销售及所得款项用途	第二部分，第2项


其他信息	第二部分，第5项
附件	第二部分，第6项
签名

术语表

本报告正文中出现的下列术语和缩写，其含义如下。


AB	议会法案
ASU	财务会计准则委员会发布的会计准则更新
破产法院	美国加利福尼亚州北区破产法院
CAISO	加州独立系统运营商公司
Cal Fire	加利福尼亚州林业与消防保护局
CEMA	灾难事件备忘账户
第11章	《美国法典》第11编第11章
第11章案件	PG&E Corporation 和 Utility 各自于 2019 年 1 月 29 日根据第11章自愿提起的案件
延续账户	SB 254 在全州设立的账户，用于扩大现有的野火基金
CPUC	加利福尼亚州公用事业委员会
CRR	拥塞收入权
DCPP	迪亚布洛峡谷核电站
地区法院	美国加利福尼亚北区联邦地区法院
DOE	美国能源部
DOE 贷款担保协议	Utility 与 DOE 于 2025 年 1 月 17 日签订的贷款担保协议
DWR	加利福尼亚州水资源部
EMANI	欧洲核保险互助协会
生效日期	2020 年 7 月 1 日，即第11章案件中重组计划的生效日期
EPS	普通股每股收益
《交易法》	经修订的《1934年证券交易法》
FASB	财务会计准则委员会
FERC	联邦能源监管委员会
第一抵押债券	根据 Utility 与 The Bank of New York Mellon Trust Company, N.A. 于 2020 年 6 月 19 日签订并经修订和补充的《抵押契约》发行的债券
10-K 表格	PG&E Corporation 和 Utility 的联合 10-K 表格年度报告
10-Q 表格	PG&E Corporation 和 Utility 的联合 10-Q 表格季度报告
GAAP	美国公认会计原则
GRC	一般费率案
HSMA	危险物质备忘账户
IOUs	投资者所有的公用事业公司
MD&A	本 10-Q 表格第一部分第2项所载的管理层对财务状况和经营成果的讨论与分析
MGP	人造煤气厂
MWh	连续一小时提供一兆瓦电力
NAV	资产净值
NEIL	Nuclear Electric Insurance Limited，一家由拥有核设施的公用事业公司持有的互助保险机构
NRC	核管理委员会
OEIS	能源基础设施安全办公室（CPUC 野火安全部门的继任机构）
重组计划	PG&E Corporation 和 Utility、Knighthead Capital Management, LLC 及 Abrams Capital Management, LP 于 2020 年 6 月 19 日签订的联合第11章重组计划
PD	拟议决定
应收账款证券化计划	Utility 于 2020 年 10 月 5 日订立的应收账款证券化计划；根据该计划，Utility 将部分应收账款及某些其他相关权利出售给 SPV，而 SPV 随后从金融机构取得以这些应收款项作担保的贷款
ROE	股东权益回报率
使用权资产	使用权资产


RUBA	住宅欠费平衡账户
SB	参议院法案
SCE	Edison International 和 Southern California Edison Company
SEC	美国证券交易委员会
SFGO	该公用事业公司原旧金山总办公室总部综合设施
SPV	PG&E AR Facility, LLC
TO	输电所有者
USFS	美国林务局
公用事业公司	Pacific Gas and Electric Company
VIE(s)	可变利益实体
WEMA	野火支出备忘账户
WGSC	野火与天然气安全成本
野火基金	由 AB 1054 设立的全州性基金，可供符合条件的电力公用事业公司用于支付因适用电力公用事业公司的设备所引发、发生于 2019 年 7 月 12 日之后的野火所产生的符合条件的索赔责任
WMCE	野火缓解与灾害事件
WMP	野火缓解计划

前瞻性陈述

本报告包含前瞻性陈述，这些陈述必然面临各种风险和不确定性。这些陈述反映了管理层的判断和意见，其依据是对未来事件的当前估计、预期和预测，以及管理层基于截至本报告日期所掌握事实对这些事件作出的假设。这些前瞻性陈述涉及（除其他事项外）此前宣布的战略审查；估计负债；费率制定和监管程序；资本支出；成本节约；负荷增长；客户费率；关键会计估计中使用的估算和假设，包括与保险应收款、监管资产和负债、环境修复、诉讼、第三方索赔、野火基金及其他负债相关的估算和假设；以及未来股权或债务发行和股息的水平。这些陈述还可通过“假设”“预期”“意图”“预测”“计划”“预计”“相信”“估计”“预测”“预料”“承诺”“目标”“指标”“将”“可能”“应当”“会”“能够”“潜在”“按计划推进”等词语及类似表达加以识别。PG&E Corporation 和公用事业公司无法预测可能影响未来业绩的所有因素。可能导致未来业绩与前瞻性陈述所表达或暗示的结果，或与历史业绩存在重大差异的部分因素包括但不限于：

•战略审查的时间安排和结果，包括是否会确定任何战略替代方案并获得 PG&E Corporation 董事会批准，以及战略审查及相关不确定性可能对 PG&E Corporation 或公用事业公司的业务造成的任何干扰或导致的成本；

•无法达成任何战略替代方案的风险，包括无法获得某些战略替代方案所需的任何适用政府实体的必要监管批准（或此类批准附带的任何条件、限制或约束）的可能性，或法律、监管或其他约束可能限制 PG&E Corporation 追求某些战略替代方案的能力，而 PG&E Corporation 董事会或管理层认为这些方案原本符合 PG&E Corporation 和 Utility 的最佳利益；

•即使达成战略替代方案，也可能无法实现该方案的部分或全部预期或计划收益；

•Utility 正在进行及未来费率制定和监管程序的时间安排与结果，包括 PG&E Corporation 和 Utility 能否通过费率收回记入备忘录账户或平衡账户的成本，或以其他方式申请收回的成本；以及 Utility 资产所有权转移给市政机构或其他公共实体的情况，包括因旧金山市县的估值申请而导致的转移；

•Wildfire Fund、Continuation Account 以及 AB 1054 修订后的审慎性标准在多大程度上能有效降低因灾难性野火造成损害的责任风险，包括 Utility 是否维持经批准的 WMP 和有效的安全认证，以及 Wildfire Fund 或 Continuation Account 是否有足够的剩余资金（随着加利福尼亚州其他参与的电力公司提出索赔，资金将会减少）；

•与 Utility 服务区域内已经发生或可能发生的野火相关的风险和不确定性，包括 2021 年 7 月 13 日在加利福尼亚州普卢马斯县 Feather River Canyon 的 Cresta Dam 附近发生的野火（“2021 年 Dixie 野火”）、2022 年 9 月 6 日在加利福尼亚州普莱瑟县 Oxbow Reservoir 附近发生的野火（“2022 年 Mosquito 野火”），以及任何其他起因尚未确定的野火；此类野火造成的损害；Utility 对此类野火承担责任的程度（包括 Utility 可能被判定承担损害赔偿责任而不论是否存在过错的风险）；对这类野火的调查，包括 CPUC 正在进行的调查；如果 CPUC 或任何其他执法机构就此类火灾采取执法行动，Utility 可能面临的罚款或处罚责任；以及 Utility 无法从 Wildfire Fund、Continuation Account 或其他第三方处，或通过费率收回成本的风险；

•与 PG&E Corporation 和 Utility 其他正在进行或未来的诉讼相关的风险和不确定性，包括相关成本能否通过保险、费率或从其他第三方处收回；

•Utility 的野火缓解举措在多大程度上有效，包括 Utility 能否遵守其 WMP 中规定的目标和指标，以及其系统加固（包括地下化）的有效性；

•公用事业公司安全、可靠且高效地建设、维护、运营、保护和退役其设施，并安全、可靠地提供电力和天然气服务的能力；

•电力和天然气行业的重大变化，包括技术进步、电气化以及向脱碳经济转型；公用事业公司天然气客户需求减少的影响；客户需求低于公用事业公司预测值的影响，以及公用事业公司能否成功应对分布式发电和可再生能源发电资源的增长、数据中心以及交通、建筑和经济其他领域电气化导致的电力需求增加所带来的影响，以及客户对其天然气和电力服务需求因此发生的变化；

•针对公用事业公司或其第三方供应商、承包商或客户（或其他与其共享数据的对象）的网络或实体攻击、恐怖主义行为、战争和破坏行为，可能导致运营中断；机密或专有资产、信息或数据（包括客户、员工、财务或运营系统信息）或知识产权被盗用或丢失；数据损坏；或可能产生补救、合规及其他成本、收入损失、诉讼、调查或声誉损害；

•恶劣天气事件及其他自然灾害的影响，包括野火和其他火灾、风暴、龙卷风、洪水、极端高温事件、干旱、地震、闪电、海啸、海平面上升、泥石流、疫情、太阳事件、电磁事件、风力事件或其他天气相关状况、气候变化或自然灾害，以及其他可能导致非计划停电、降低发电量、扰乱公用事业公司向客户提供服务，或损坏或扰乱公用事业公司、其客户或其所依赖第三方拥有的设施、运营或信息技术及系统的事件；公用事业公司预防、减轻或应对此类状况或事件的措施是否有效；公用事业公司可能因此类状况或事件承担的修复及其他成本；公用事业公司应急准备是否充分；公用事业公司是否因此类事件造成的财产损失或人身伤害而对第三方承担责任；公用事业公司能否采购替代电力；以及公用事业公司是否因此类事件受到民事、刑事或监管处罚；

•现行及未来的监管规定以及联邦、州或地方立法，其实施和解释；遵守此类监管规定和立法的成本；以及公用事业公司收回相关合规和投资成本的程度，以及此类成本由 PG&E Corporation 承担的程度，包括涉及以下方面的规定和立法：

◦野火，包括逆向征收改革、野火自保、野火基金、延续账户，以及针对公用事业公司或其行业的额外野火缓解措施或其他改革；

◦环境，包括履行公用事业公司的补救义务所产生的成本，或遵守温室气体（“GHG”）排放、可再生能源目标、能源效率标准、分布式能源资源和电动汽车相关标准的成本；

◦核能行业，包括运营、抗震设计、安保、安全、重新许可、乏核燃料储存、退役和冷却水取水；DCPP运营是否延长至2030年之后；以及公用事业公司能否持续运营DCPP直至计划退役；

◦公用事业公司及其关联公司的监管，包括适用于作为公用事业公司控股公司的PG&E Corporation的条件；

◦隐私和网络安全；以及

◦税项和税务审计；

•因当前和未来的自行报告、调查或其他执法行动、机构合规报告或违规通知而产生的罚款、处罚、补救或其他义务的金额；这些事项可能涉及公用事业公司遵守法律、规则、法规或命令的情况；

•公用事业公司能否将运营成本控制在获准支出水平内；公用事业公司能否继续实施精益运营体系并实现预计节省；公用事业公司发生的不可回收成本超过此类成本预测的程度；与通胀（包括原材料方面）、进口关税和贸易战相关的风险和不确定性；以及因客户对电力和天然气的需求变化或其他原因而导致的成本预测或计划工作范围及时间安排的变化；

•与PG&E Corporation和公用事业公司的巨额债务以及债务相关文件对其运营灵活性所施加的限制有关的风险和不确定性，包括公用事业公司提取DOE贷款额度的程度；

•公用事业公司在加利福尼亚州欣克利附近的天然气压缩站场址及公用事业公司的化石燃料发电场址所产生的不可回收环境成本的最终金额；

•电力、天然气和核燃料的供应及价格；公用事业公司管理和应对能源商品价格波动的程度；公用事业公司及其交易对手在价格风险管理活动中提供或返还抵押品的能力；以及公用事业公司能否及时通过费率收回其发电和能源商品采购成本；

•PG&E Corporation和公用事业公司能否及时以可接受的条件进入资本市场及其他债务和股权融资来源；此类资本市场的波动；以及利率变化；

•与公用事业公司客户费率较高相关的风险和不确定性，包括客户需求减少，以及公用事业公司费率制定或成本回收程序中获批的金额；

•信用评级机构下调PG&E Corporation或公用事业公司信用评级的行动；以及

•GAAP、准则、规则或政策（包括与监管会计相关的规定）发生变化，以及对其解释或应用发生变化所产生的影响。

有关可能影响前瞻性声明结果以及 PG&E Corporation 和 Utility 未来财务状况、经营业绩、流动性和现金流的重大风险的更多信息，请参阅 2025 年 Form 10-K 中的第 1A 项“风险因素”，以及 2025 年 Form 10-K 第 7 项“管理层对财务状况和经营业绩的讨论与分析”及本 Form 10-Q 第一部分第 2 项中对这些事项的详细讨论。PG&E Corporation 和 Utility 不承担因新信息、未来事件或其他原因而更新前瞻性声明的任何义务。

PG&E Corporation 和 Utility 的 Form 10-K 年度报告、Form 10-Q 季度报告、Form 8-K 当前报告及代理声明，均可在向 SEC 提交或提供后尽可能及时地从 PG&E Corporation 网站 www.pgecorp.com 免费获取。SEC 还设有网站 http://www.sec.gov，其中包含以电子方式向 SEC 提交文件的发行人的报告、代理和信息声明及其他信息。此外，PG&E Corporation 和 Utility 通常会在 http://investor.pgecorp.com 的“Regulatory Filings”标签下提供 Utility 向 CPUC 和 FERC 提交的主要监管程序文件链接，以便投资者在相关机构收到文件后即可查阅。PG&E Corporation 和 Utility 还通常在 http://investor.pgecorp.com 的“Wildfire and Safety”及“News & Events: Events & Presentations”页面发布或提供演示文稿、文件及其他可能令投资者感兴趣的信息的直接链接，以公开传播此类信息。这些文件或其中所含信息均可能被视为重大信息。PG&E Corporation 网站所含信息不属于 PG&E Corporation 或 Utility 向 SEC 提交或提供的本报告或任何其他报告的一部分。PG&E Corporation 和 Utility 提供该网站地址仅供投资者参考，并无意将该地址设为活动链接。

第 1A 项：风险因素

有关可能影响 PG&E Corporation 和 Utility 财务状况、经营业绩、流动性及现金流的重大风险，请参阅 2025 年 Form 10-K 第 1A 项“风险因素”，以及本 Form 10-Q“前瞻性声明”一节中的补充内容。

第一部分：财务信息

第 2 项：管理层对财务状况和经营业绩的讨论与分析

概览

本文件是 PG&E Corporation 和 Utility 的合并 Form 10-Q，其中分别包含这两个实体的简明合并财务报表。本合并 MD&A 应与第一部分第 1 项所载的简明合并财务报表及其附注一并阅读，也应与 2025 Form 10-K 一并阅读。

通常，PG&E Corporation 和 Utility 的收入会因费率制定程序的结果以及发生的转付成本金额而有所变化。关于 Utility 收入的确定方式，请参阅 2025 Form 10-K 第一部分第 1 项“业务”中的“费率制定机制”。导致成本变化的因素包括外购电力和燃料成本；天然气采购、储存和运输成本；天气；与野火相关的刑事、民事和监管费用；费率制定程序的结果；以及因新增债务发行或利率变化而导致的利息费用增加。

截至 2025 年 9 月 30 日止三个月和九个月的经营业绩及流动性讨论，与 2024 年同期相比的相关内容，通过引用纳入 PG&E Corporation 和 Utility 截至 2025 年 9 月 30 日止三个月和九个月的合并 Form 10-Q 第一部分第 2 项“管理层对财务状况和经营业绩的讨论与分析”；该文件已于 2025 年 10 月向 SEC 提交。

影响财务业绩的关键因素

PG&E Corporation 和 Utility 认为，以下因素可能对其财务状况、经营业绩、流动性和现金流产生重大影响：

•与野火、野火防范及相关成本回收有关的不确定性。 PG&E Corporation 和 Utility 的财务状况、经营业绩、流动性和现金流可能受到以下因素的重大影响：Utility 野火防范举措的成本及成效；加利福尼亚州的野火责任框架；实际发生野火造成的损失程度；野火的财务影响；以及 PG&E Corporation 和 Utility 通过保险、自保、Wildfire Fund、Continuation Account 和监管成本回收减轻这些财务影响的能力。

尽管采取了广泛的野火缓解措施，但公用事业公司仍面临重大野火风险，而气候变化、极端天气事件、基础设施老化和植被生长加剧了这一风险。一旦发生起火，公用事业公司可能无法控制损失范围，损失主要取决于环境和植被状况、第三方的灭火行动以及野火发生地点。公用事业公司可能须对这些损失和灭火行动的费用承担责任；其自有资产也可能受损或被毁，且其部分野火缓解成本须接受合理性审查。公用事业公司能否通过电价收回这些成本尚不确定。对于超出可用保险保障范围的野火相关索赔及法律费用，公用事业公司只有在适用情况下由 CPUC 或 FERC 认定其符合适用的审慎性标准后，才能通过电价收回。此外，如果公用事业公司在野火缓解工作方面未能合规，还可能面临罚款、处罚、执法行动或其他不利的法律或监管后果。

过去野火造成的财务影响重大。PG&E Corporation 和公用事业公司或可通过 Wildfire Fund、Continuation Account 或电价成本回收，缓解超出保险保障或自我保险范围的野火财务影响。每种缓解方式均存在不确定性，且负债可能超过可收回金额。例如，公用事业公司能否收回某一承保年度中超过 $1.0 billion 的野火成本，取决于 Wildfire Fund 或 Continuation Account 是否仍有足够资金；此外，由于加利福尼亚州其他参与计划的电力公司提出索赔，Continuation Account 也可能比预期更快耗尽。公用事业公司是否必须向 Wildfire Fund 或 Continuation Account 偿还款项，取决于其能否向 CPUC 证明已支付的野火相关成本合理且公允。对于 Continuation Account，其他不确定因素还包括：Wildfire Fund 管理方是否认定 Continuation Account 有必要、CPUC 是否批准延长不可规避收费、管理方是否认定需要追加缴款，以及如需追加缴款，其或有缴款的时间安排。

关于 Wildfire Fund，PG&E Corporation 和公用事业公司预计将根据有关 2025 年 1 月 7 日在加利福尼亚州洛杉矶县 Eaton Canyon 起始的野火（“Eaton 火灾”）的可靠公开信息，重新评估目前估计的 20 年使用寿命是否合理，并确认加速摊销。SCE 已披露，Eaton 火灾造成的可能损失为 $1.6 billion，并确认 Wildfire Fund 应收款 $645 million，该金额代表可能损失区间的低端；其余可能损失无法合理估算。因此，PG&E Corporation 和公用事业公司可能将估计使用寿命缩短至零，并产生最高达 $3.7 billion 的加速摊销。

更多信息请参见“第一部分第1项”所载简明合并财务报表附注中的附注2（涉及野火基金资产）、附注3（涉及为减轻野火风险而发生的支出）、附注10中的“2021年 Dixie 火灾”和“2022年 Mosquito 火灾”（涉及野火负债）、附注10中的“损失追回”（涉及追回款项），以及下文“监管事项”中的“根据 AB 1054 程序申请审查和追回与2019年 Kincade 火灾及2021年 Dixie 火灾相关的成本”。

•费率制定程序、其他程序及立法的时间安排和结果。监管费率制定程序是公用事业公司的业务关键方面。公用事业公司的收入需求主要包括为使其能够收回合理运营费用（例如维护费用、管理及一般费用）和资本成本（例如折旧及融资费用）而设定的基本金额。尽管公用事业公司通常力求及时收回已记录的成本，但备忘录账户和差额账户余额增加会提高其融资成本。可能影响公用事业公司业务状况及财务业绩的其他程序，包括市政当局及其他公共实体采取行动，收购公用事业公司在其各自辖区内的电力资产。监管程序的结果可能受多种因素影响，包括介入方的证词、潜在费率影响、监管和政治环境及其他因素。请参见“第一部分第1项”所载简明合并财务报表附注3和11，以及下文“监管事项”。

近年来，加州州立法活动以及围绕野火、能源可负担性及相关议题的政治讨论有所增加。与这些事项有关的任何立法或其他行政、监管措施的实质内容和时间安排（如实施此类措施，或未能采取野火相关措施），都可能对 PG&E Corporation 和公用事业公司的业务、现金流、经营业绩及财务状况造成重大影响。加州立法机关结束了2025-2026立法会议，未通过修改该州野火责任框架的其他立法。因此，PG&E Corporation 和公用事业公司可能面临持续的财务限制和较高风险，包括难以按可接受的条件获得融资、借款成本和抵押品提供要求上升，或融资需求增加；进而可能对其财务业绩和客户可负担性产生不利影响。

•战略审查与修订后的资本计划。PG&E Corporation 和 Utility 于 2026 年 9 月 2 日宣布正在进行战略审查，将 2027 年计划资本支出从 134 亿美元下调至 114 亿美元，并撤回此前披露的 2028 年至 2030 年资本支出预测。战略审查正在评估合理可行的各类监管、财务、运营和战略替代方案，包括与 PG&E Corporation 和 Utility 的组织及融资方式相关的各种方案，以更好地服务客户和加利福尼亚州。实现财务稳健并取得投资级信用评级是本次审查的基础目标。

•PG&E Corporation 和 Utility 控制运营及融资成本的能力。根据成本服务监管定价，公用事业公司的收益取决于其能否将成本控制在费率制定程序中获准回收的金额范围内。Utility 制定了一项目标：增加资本投资以实现安全和气候目标，同时节省运营成本。Utility 计划通过提高业务规划和执行效率来实现此类节省，包括通过精益运营体系消除浪费。PG&E Corporation 和 Utility 也致力于通过识别并执行高效融资业务的机会来降低融资成本，而这些机会取决于资本市场状况。资本市场波动加剧以及利率持续处于高位，可能影响 PG&E Corporation 和 Utility 以可接受条件获得融资的能力，或推高融资成本，进而可能对其财务业绩造成不利影响。

有关可能对 PG&E Corporation 和 Utility 的财务状况、经营业绩、流动性及现金流产生重大影响，或可能导致未来业绩与历史业绩存在重大差异的风险的更多信息，请参见上文第 1A 项：“风险因素”和“前瞻性陈述”。

税务事项

如果某些股东持有的 PG&E Corporation 股票超过法定门槛，PG&E Corporation 使用其美国联邦和加利福尼亚州净经营亏损结转额及某些其他税务属性的能力可能会受到重大限制。为降低发生此类限制的可能性，PG&E Corporation 和 Utility 于 2020 年 6 月 22 日分别提交的经修订及重述公司章程，以及 PG&E Corporation 于 2022 年 5 月 24 日提交的公司章程修正证书（统称“经修订章程”），对直接或间接收购或累积 PG&E Corporation 股票作出了限制。这些限制规定，任何个人或实体（包括某些人员群体）在限制解除日（定义见经修订章程）之前，未经 PG&E Corporation 董事会批准，不得收购或累积超过一定门槛的 PG&E Corporation 股票，包括普通股和强制可转换优先股；该门槛根据此类股票的数量和相对价值确定。适用门槛的计算较为复杂，且可能随日期而变化；截至 2026 年 10 月 14 日，PG&E Corporation 普通股与强制可转换优先股的合计价值门槛约为 3.92%。有关影响 PG&E Corporation 股票所有权的这些限制的更多信息，请参阅 2025 年 Form 10-K 第二部分第 7 项“管理层对财务状况和经营成果的讨论与分析”中的“税务事项”。

经营成果

以下讨论介绍 PG&E Corporation 和 Utility 截至 2026 年和 2025 年 9 月 30 日的三个月和九个月经营成果。有关可能影响未来经营成果的因素，请参阅上文“影响财务业绩的关键因素”中的进一步讨论。

PG&E Corporation

合并经营成果主要由 Utility 相关成果构成，详见下文“Utility”部分。下表汇总了截至 2026 年和 2025 年 9 月 30 日的三个月和九个月归属于普通股股东的收益（亏损）：


	截至 9 月 30 日的三个月		净变动		变动百分比		截至 9 月 30 日的九个月	净变动		变动百分比
（百万美元）	2026		2025				2026	2025
合并总计	$	749			$	823		$	(74)		(9)	%	$	2,340		$	1,951			$	389	20	%
PG&E Corporation	(68)			(87)			19		(22)	%	(255)		(259)		4			(2)	%
Utility	$	817			$	910		$	(93)		(10)	%	$	2,595		$	2,210			$	385	17	%

PG&E Corporation 的净亏损主要包括长期债务利息支出。

Utility

下表列示了 Utility 截至 2026 年和 2025 年 9 月 30 日的三个月和九个月简明合并损益表中的若干项目。总体而言，Utility 获准直接向客户转嫁的费用（例如购电和购天然气成本，以及用于资助公共事业项目的成本）及为收回这些可转嫁成本而收取的相应收入，不会影响净利润。


	截至 9 月 30 日的三个月		净变动		变动百分比		截至 9 月 30 日的九个月	净变动		变动百分比
（百万美元）	2026		2025				2026	2025
电力	$	4,660			$	4,755		$	(95)		(2)	%	$	14,015		$	13,304			$	711	5	%
天然气	1,528			1,495			33		2	%	4,956		4,827		129			3	%
营业总收入	6,188			6,250			(62)		(1)	%	18,971		18,131		840			5	%
电力成本	904			1,015			(111)		(11)	%	2,265		2,013		252			13	%
天然气成本	109			131			(22)		(17)	%	694		738		(44)			(6)	%
运营与维护	2,541			2,636			(95)		(4)	%	8,182		8,128		54			1	%
SB 901 证券化费用，净额	36			35			1		3	%	36		35		1			3	%
野火相关索赔，扣除回收额	—			1			(1)		(100)	%	—		100		(100)			(100)	%
野火基金费用	141			86			55		64	%	369		271		98			36	%
折旧、摊销及退役费用	1,206			1,132			74		7	%	3,434		3,302		132			4	%
营业总费用	4,937			5,036			(99)		(2)	%	14,980		14,587		393			3	%
营业收入	1,251			1,214			37		3	%	3,991		3,544		447			13	%
利息收入	97			91			6		7	%	320		384		(64)			(17)	%
利息费用	(729)			(691)			(38)		5	%	(2,145)		(2,059)		(86)			4	%
其他收入，净额	116			97			19		20	%	334		251		83			33	%
税前收入	735			711			24		3	%	2,500		2,120		380			18	%
所得税收益	(85)			(202)			117		(58)	%	(105)		(100)		(5)			5	%
净收入	820			913			(93)		(10)	%	2,605		2,220		385			17	%
优先股股息要求	3			3			—		—	%	10		10		—			—	%
普通股可得收入	$	817			$	910		$	(93)		(10)	%	$	2,595		$	2,210			$	385	17	%

营业收入

截至2026年9月30日的三个月内，该公用事业公司的电力和天然气营业收入较2025年同期减少了$62 million，即1%。这一减少主要是由于：

•截至2026年9月30日的三个月内，2023年WMCE程序授权的临时费率补偿（见下文“2023年WMCE申请”）较2025年同期减少约$140 million；以及

•截至2026年9月30日的三个月内，用于收回电力成本的收入较2025年同期减少$111 million。这些成本会转嫁给客户，不会影响净收入。

部分被以下因素抵消：

•截至2025年9月30日的三个月内，与2022年WMCE程序相关的收入减少约$60 million，而2026年同期没有类似减少。

截至2026年9月30日的九个月内，该公用事业公司的电力和天然气营业收入较2025年同期增加了$840 million，即5%。这一增加主要是由于：

•截至2026年9月30日的九个月内，2023年WMCE最终决定授权的收入（见下文“2023年WMCE申请”）约为$650 million，而2025年同期没有类似收入。确认的收入是此前确认的临时费率补偿之外的增量收入；

•截至2026年9月30日的九个月内，用于收回电力成本的收入较2025年同期增加$252 million；

•截至2026年9月30日的九个月内，2023年GRC授权的收入较2025年同期增加约$140 million；以及

•截至2025年9月30日的九个月内，与2022年WMCE程序相关的收入减少约$60 million，而2026年同期没有类似减少。

部分被以下因素抵消：

•截至2026年9月30日的九个月内，2023年WMCE程序授权的临时费率补偿（见下文“2023年WMCE申请”）较2025年同期减少约$380 million。

电力成本

公用事业公司的电力成本包括从第三方（包括可再生能源资源）购买电力的成本、自有发电设施所用燃料及相关输电成本、根据购电协议向其他设施供电所用燃料及相关输电成本、遵守加州限额与投资计划的成本，以及价格风险管理活动的已实现收益和损失。电力成本还包括在 CAISO 电力市场以及直接从第三方进行的净能源销售（公用事业公司自有发电及第三方发电）。这些成本转嫁给客户，不影响净收入。请参阅第一部分第 1 项简明合并财务报表附注中的附注 8。

截至 2026 年 9 月 30 日的三个月和九个月期间，电力成本与 2025 年同期相比没有重大变化。

天然气成本

公用事业公司的天然气成本包括天然气采购、储存和运输成本、遵守加州限额与投资计划的成本，以及价格风险管理活动的已实现收益和损失。这些成本转嫁给客户，不影响净收入。请参阅第一部分第 1 项简明合并财务报表附注中的附注 8。

截至 2026 年 9 月 30 日的三个月和九个月期间，天然气成本与 2025 年同期相比没有重大变化。

运营与维护

公用事业公司截至 2026 年 9 月 30 日的三个月运营与维护费用较 2025 年同期减少 9500 万美元，即 4%。此次减少主要是由于：

•截至 2026 年 9 月 30 日的三个月，2023 年 WMCE 申请（见下文“2023 年 WMCE 申请”）通过临时费率救济获准的先前递延费用减少约 1.4 亿美元，较 2025 年同期有所下降。

部分被以下因素抵消：

•DCPP 延长运营相关成本增加约 7000 万美元，这是截至 2026 年 9 月 30 日的三个月与 2025 年同期相比的情况。

公用事业公司截至 2026 年 9 月 30 日的九个月运营与维护费用较 2025 年同期增加 5400 万美元，即 1%。此次增加主要是由于：

•增加约 4 亿美元的成本，源于确认 2023 年 WMCE 最终裁定中获准的先前递延费用（见下文“2023 年 WMCE 申请”）；截至 2026 年 9 月 30 日的九个月发生了这些费用，而 2025 年同期没有可比费用。这些费用是在 2023 年 WMCE 申请中作为临时费率救济而先前确认的费用之外的增量；以及

截至 2026 年 9 月 30 日的九个月，DCPP 延长运营相关成本增加约 3000 万美元，较 2025 年同期有所增加。

部分被以下因素抵消：

•截至2026年9月30日的九个月期间，较2025年同期，针对2023年WMCE申请（见下文“2023年WMCE申请”）通过临时费率救济获准确认的此前递延费用减少了约3.8亿美元。

野火相关索赔，扣除追回款项后

截至2026年9月30日的三个月和九个月期间，该公用事业公司的野火相关索赔（扣除追回款项后）较2025年同期分别减少100万美元（降幅100%）和1亿美元（降幅100%）。该公用事业公司在截至2025年9月30日的九个月期间确认了与2019年金凯德山火相关的1亿美元税前费用，而2026年同期没有可比费用。

野火基金费用

截至2026年9月30日的三个月和九个月期间，该公用事业公司的野火基金费用较2025年同期分别增加5500万美元（增幅64%）和9800万美元（增幅36%）。这些增幅主要是由于SCE披露了与伊顿山火相关的野火基金应收款，从而加速摊销；2025年同期没有可比费用。

折旧、摊销和退役

截至2026年9月30日的三个月和九个月期间，该公用事业公司的折旧、摊销和退役费用较2025年同期分别增加7400万美元（增幅7%）和1.32亿美元（增幅4%）。这些增幅主要是由于资本增加带来的电厂资产余额增长，部分被等待监管决定的成本所对应的递延折旧费用增加所抵消。

利息收入

截至2026年9月30日的三个月期间，利息收入较2025年同期没有重大变化。

The Utility’s Interest income decreased by $64 million, or 17%, in the nine months ended September 30, 2026, compared to the same period in 2025. This decrease was primarily due to lower dividend income and lower interest-bearing account balances, partially offset by higher interest-bearing self-insurance related balances.

Interest Expense

The Utility’s Interest expense increased by $38 million, or 5%, and $86 million, or 4%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to the issuance of additional long-term debt and higher borrowings under its revolving credit facility, partially offset by lower balancing account interest.

Other Income, Net

The Utility’s Other Income, Net increased by $19 million, or 20%, and $83 million, or 33%, in the three and nine months ended September 30, 2026, compared to the same periods in 2025. These increases were primarily due to a higher return from the trust assets for the qualified pension plan in the three and nine months ended September 30, 2026, compared to the same periods in 2025.

Income Tax Provision

The Utility’s Income tax provision increased by $117 million, or 58%, in the three months ended September 30, 2026, compared to the same period in 2025. This increase was primarily due to decreased deductions for certain costs attributable to electric generation.

The Utility’s Income tax provision decreased by $5 million, or 5%, in the nine months ended September 30, 2026, compared to the same period in 2025. The income tax provision was comparable to the prior-year period.

The effective tax rates were (11.7)% and (4.2)%, and (28.3)% and (4.7)% for the three and nine months ended September 30, 2026 and 2025, respectively. While the effective tax rate for the nine months ended September 30, 2026 was generally consistent compared to the same period in 2025, the change in the effective tax rate for the three months ended September 30, 2026 compared to the same period in 2025 was primarily due to decreased deductions for certain costs attributable to electric generation. The Utility’s effective tax rate is below the federal statutory rate of 21% for 2026 and 2025, primarily due to the effect of the flow-through ratemaking treatment for certain property-related costs. For these temporary tax differences, the Utility recognizes the deferred tax impact in the current period and records offsetting regulatory assets and liabilities. Therefore, the Utility’s effective tax rate is impacted as these differences arise and reverse. The Utility recognizes such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.

LIQUIDITY AND FINANCIAL RESOURCES

Overview

PG&E Corporation and the Utility expect to be able to generate and obtain adequate cash to meet their cash requirements in the short term and in the long term.

PG&E Corporation and the Utility rely on access to debt and equity markets and credit facilities to finance their capital requirements and support their liquidity needs. The CPUC authorizes the Utility’s capital structure, the aggregate amount of long-term and short-term debt that the Utility may issue, and the revenue requirements the Utility is able to collect to recover its cost of service. The Utility generally utilizes retained earnings, equity contributions from PG&E Corporation and long-term debt issuances to maintain its CPUC-authorized long-term capital structure consisting of 52% common equity, 47.5% long-term debt, and 0.5% preferred equity and relies on short-term debt, including its revolving credit facilities, to fund temporary financing needs.

PG&E Corporation’s ability to fund operations, make scheduled principal and interest payments, fund equity contributions to the Utility, and pay dividends depends on the level of cash on hand, cash received from the Utility, and PG&E Corporation’s access to the capital and credit markets. Generally, PG&E Corporation and the Utility expect that capital expenditures, debt maturities, and PG&E Corporation capital stock dividends will exceed operating cash flows. As a result, they expect to finance future cash needs in excess of operating cash flows primarily through the capital and credit markets.

PG&E Corporation and the Utility have various contractual commitments which impact cash requirements. These commitments are discussed in “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

As of September 30, 2026, PG&E Corporation and the Utility had access to approximately $5.8 billion of total liquidity comprised of $339 million of the Utility’s Cash and cash equivalents, $563 million of PG&E Corporation’s (on a standalone basis) Cash and cash equivalents and $4.9 billion of availability under PG&E Corporation’s and the Utility’s revolving credit facilities.

Credit Ratings

Credit ratings impact the cost and availability of short-term borrowings, including credit facilities, and long-term debt costs. In addition, some of the Utility’s commodity contracts contain collateral posting provisions tied to the Utility’s unsecured credit rating from each of the major credit rating agencies. Contracts which may require collateral postings include the Utility's power and natural gas commodity, transportation, services, and environmental products agreements. Because the Utility’s unsecured credit rating remains below investment grade with one of the major credit rating agencies, the Utility generally does not receive unsecured credit from its energy procurement counterparties, and it may be required to increase its collateral postings if its credit rating is downgraded.

Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. PG&E Corporation and the Utility maintain separate bank accounts and primarily invest their cash in money market funds. In addition to Cash and cash equivalents, the Utility holds Restricted cash and restricted cash equivalents that primarily consist of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds. The Utility also holds restricted cash related to the DOE’s Civil Nuclear Credit Program. As of September 30, 2026, PG&E Corporation (on a standalone basis) and the Utility had Cash and cash equivalents of $563 million and $339 million, respectively.

Financial Resources

Equity Financings

PG&E Corporation does not expect to undertake any equity issuances through 2030. Factors that could affect this plan include liquidity and cash flow needs, capital expenditures, interest rates, credit ratings, PG&E Corporation’s common share price, its earnings, the timing and outcome of legislative and ratemaking proceedings, and the timing and terms of other financings.

Debt Financings and Credit Facilities

The Utility generally issues first mortgage bonds and secured debt to meet its long-term funding requirements.

For more information, see “Credit Facilities” and “Long-Term Debt Issuances and Redemptions” in Note 4 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

DOE Loan Guarantee Agreement

As of the date of this report, the Utility has not borrowed any advances under the facility. While the Utility has continued to work with the DOE, the Utility is not able to predict the timing or amount of any funds it may receive from the facility in the future.

For more information about the DOE Loan Guarantee Agreement, see “Liquidity and Financial Resources” in Item 7: “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the 2024 Form 10-K.

Other Financings

Citizens Energy Corporation

On January 29, 2025, the Utility entered into an amended and restated agreement with Citizens Energy Corporation (“Citizens”) pursuant to which the Utility may lease to Citizens entitlements to certain transmission assets. A portion of the costs associated with each project that is expected to be subject to such a lease will be excluded from the Utility’s FERC transmission rates for the duration of the applicable lease. The Utility may offer Citizens up to five lease options over the term of the agreement, for a total investment by Citizens of up to $1.0 billion. If Citizens exercises and the parties close on a lease option, the Utility will receive an upfront payment as prepaid rent for that lease, which is expected to average approximately $200 million per lease, and the rate base associated with the leased entitlements will go into Citizens’ rate base, rather than the Utility’s, for 30 years.

On May 7, 2026, the CPUC issued a final decision authorizing the Utility to file an advice letter seeking approval for each entitlements lease. The transactions contemplated by the agreement remain subject to further FERC and CPUC approvals.

Dividends

PG&E Corporation has announced guidance entailing consistent dividend increases targeting a dividend payout ratio of approximately 20% of core earnings by 2028. No dividend is payable unless and until declared by the applicable Board of Directors. The Board of Directors of PG&E Corporation retains authority to change the common stock dividend target and dividend payout ratio at any time. Future dividend decisions made by the applicable Board of Directors may be impacted by results of operations, financial condition, cash requirements, contractual restrictions, the strategic review, and other factors.

For information on dividend declarations and payments, see Note 6 to the Condensed Consolidated Financial Statements in Part I, Item 1.

Utility Cash Flows

PG&E Corporation’s consolidated cash flows consist primarily of cash flows related to the Utility. The following discussion presents the Utility’s cash flows for the nine months ended September 30, 2026 and 2025.

The Utility’s cash flows were as follows:


	Nine Months Ended September 30,
(in millions)	2026		2025
Net cash provided by operating activities	$	6,262			$	7,019
Net cash used in investing activities	(9,296)			(9,250)
Net cash provided by financing activities	3,166			1,874
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	$	132			$	(357)

Operating Activities

The Utility’s cash flows from operating activities primarily consist of receipts from customers less payments of cash operating expenses. Net cash provided by operating activities decreased by $757 million, or 11%, during the nine months ended September 30, 2026 as compared to the same period in 2025. This decrease was primarily due to:

•an increase in electric procurement costs driven by lower sales of renewable portfolio standard compliance instruments into the market and lower CAISO-related revenues; and

•a decrease in collections driven by recoveries related to 2020 to 2023 WMCE rate cases.

Partially offset by:

•a decrease in wildfire-related payments, net of recoveries.

Future cash flow from operating activities will be affected by various factors, including:

•the timing and amount of costs in connection with the 2019 Kincade fire, the 2021 Dixie fire, and the 2022 Mosquito fire and the timing and amount of any potential related insurance, Wildfire Fund, and regulatory recoveries;

•the timing and amount of costs in connection with future wildfires and the timing and amount of any potential related insurance, including funds available from self-insurance and the Wildfire Fund (see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1);

•the timing and amount of costs in connection with the portion of the 2023-2025 WMP that are being recovered through rates and the portion of the costs previously incurred in connection with the 2021-2022 WMP that are not currently being recovered through rates (see “Regulatory Matters” below for more information);

•the timing and outcomes of the Utility’s pending and future ratemaking and regulatory proceedings, including the extent to which PG&E Corporation and the Utility are able to recover their costs through regulated rates as recorded in memorandum accounts or balancing accounts, or as otherwise requested; and

•the timing and amount of electric and natural gas commodity price volatility and differences between commodity costs and revenue collections.

PG&E Corporation and the Utility do not have any off-balance sheet arrangements that have had, or are reasonably likely to have, a current or future material effect on their financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures, or capital resources, other than those discussed under “Purchase Commitments” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

Investing Activities

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, customer credit trust, and self-insurance investments which are partially offset by the amount of cash used to purchase new nuclear decommissioning trust, customer credit trust, and self-insurance investments.

The following table summarizes changes in key components of the Utility’s investing cash flows for the nine months ended September 30, 2026, compared to September 30, 2025.


(in millions)	Nine Months Ended September 30,
Cash used in investing activities - 2025	$	(9,250)
Capital expenditures	(990)
Net purchases related to customer credit trust investments	821
Net purchases related to self-insurance investment and other investing activities	123

Net decrease in cash used in investing activities	(46)
Cash used in investing activities - 2026	$	(9,296)

Net cash used in investing activities increased by $46 million, or 0.5%, during the nine months ended September 30, 2026 as compared to the same period in 2025. The increase was primarily due to a $990 million increase in capital expenditures, mainly driven by increased investments in electric transmission and distribution hardening, capacity, reliability, and interconnection work. The increase was partially offset by a $821 million decrease in net purchases related to customer credit trust investments, and by a $123 million decrease in net purchases related to self‑insurance investments.

Future cash flows used in investing activities are largely dependent on the timing and amount of capital expenditures. The Utility forecasts that it will invest $12.4 billion in capital expenditures in 2026 and $11.4 billion in 2027. The strategic review may result in further changes in planned capital expenditures.

Financing Activities

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 or prepayment date of existing debt instruments. Additionally, the Utility’s future cash flows from financing activities will be affected by the timing and outcome of the strategic review, the Utility’s financings, dividend payments, and equity contributions from PG&E Corporation.

The following table summarizes changes in key components of the Utility’s financing cash flows for the nine months ended September 30, 2026, compared to September 30, 2025.


(in millions)	Nine Months Ended September 30,
Cash provided by financing activities - 2025	$	1,874
Net borrowings under credit facilities	(1,540)
Net repayments under term loan	(180)
Proceeds from issuances of long-term debt, net of repayments	2,746


Dividend payments	(149)

Equity contributions from PG&E Corporation	527
Other financing activities	(112)
Net increase in cash provided by financing activities	1,292
Cash provided by financing activities - 2026	$	3,166

Net cash provided by financing activities increased by $1.3 billion, or 69%, during the nine months ended September 30, 2026 as compared to the same period in 2025. The increase was primarily due to:

•$2.7 billion increase in proceeds from issuances of long-term debt, net of repayments; and

•$527 million increase in equity contributions received from PG&E Corporation.

Partially offset by:

•$1.5 billion decrease in net borrowings under credit facilities;

•$180 million increase in net repayments under term loan; and

•$149 million increase in dividend payments.

REGULATORY MATTERS

The Utility is subject to substantial regulation by the CPUC, the FERC, the OEIS, the NRC, and other federal and state regulatory agencies. The resolutions of the proceedings described below and other proceedings may materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. Except as otherwise noted, PG&E Corporation and the Utility are unable to predict the timing or outcome of the following proceedings.

Key updates to the Utility’s regulatory matters include the following:

•On August 13, 2026, the CPUC adopted an administrative consent order approving a settlement with the CPUC’s enforcement division for the 2022 Mosquito fire.

•On September 18, 2026, the CPUC issued a PD in Track 1 of the WGSC proceeding that would authorize recovery of approximately $1.8 billion of recorded wildfire mitigation costs for the 2020 to 2022 period and disallow approximately $477 million of requested costs.

•On September 23, 2026, the CPUC issued a PD in the Utility’s 2027 GRC proceeding that would authorize the Utility to recover $456 million in interim rate recovery effective January 1, 2027.

•On September 30, 2026, the Utility filed a ten-year Electrical Undergrounding Plan (“EUP”) for the years 2028 through 2037 with the OEIS.

Cost Recovery Proceedings

Periodically, costs arise that could not have been anticipated by the Utility during CPUC GRC proceedings or that have been deliberately excluded from such proceedings. For instance, these costs may result from catastrophic events, changes in regulation, or extraordinary changes in operating practices. The Utility may seek authority to track incremental costs in a memorandum account and the CPUC may later authorize recovery of costs tracked in memorandum accounts if the costs are deemed incremental and prudently incurred. The CPUC may also authorize memorandum and balancing accounts with limitations or caps on cost recovery. While the Utility generally expects such unanticipated costs to be recoverable, the CPUC may authorize the Utility to recover less than the full amount of its costs.

In recent years, the Utility has recorded significant amounts to these accounts. Because rate recovery may require CPUC review and authorization of the costs in these accounts, there can be a delay between when the Utility incurs costs and when it may recover those costs.

If the amount of the costs recorded in these accounts increases, or the delay between incurring and recovering costs lengthens, PG&E Corporation and the Utility may incur additional financing costs. If the Utility does not recover the full amount of its recorded costs, the difference between the recorded and recovered amounts would be written off as a non-cash disallowance. Such disallowances could materially affect PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

For more information, see Note 3 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1, and “Wildfire Mitigation and Catastrophic Events Cost Recovery Applications” and “Wildfire and Gas Safety Costs Recovery Application” below.

Statuses of the Utility’s cost recovery proceedings are summarized in the following table:

Proceeding

Request

Status

2023 WMCE

$2.18 billion of cost recovery

Final decision authorizing $1.9 billion of costs issued February 2026. Application for rehearing filed March 2026 and denied in August 2026. Appealed in September 2026.

2024 WMCE

$596 million of cost recovery

Application filed November 2024. A PD is expected by February 2027.

2023 WGSC

$2.5 billion of cost recovery

Application filed June 2023. Decision authorizing $516 million of interim rate relief adopted March 2024. Track 1 PD authorizing recovery of approximately $1.8 billion of wildfire mitigation costs issued September 2026. A final decision is expected by March 2027.

Kincade and Dixie AB 1054

Review of 2019 Kincade fire and 2021 Dixie fire costs, including recovery of approximately $1.9 billion

Application filed November 2025. A PD is expected by November 2026.

Wildfire Mitigation and Catastrophic Events Cost Recovery Applications

2023 WMCE Application

As previously disclosed, on February 5, 2026, the CPUC voted out a final decision in the 2023 WMCE proceeding. On March 16, 2026, the Utility filed an application for rehearing of the final decision with the CPUC, which the CPUC denied on August 14, 2026. On September 14, 2026, the Utility filed a petition for a writ of review with the California Court of Appeal.

2024 WMCE Application

On November 21, 2024, the Utility filed an application with the CPUC requesting cost recovery of approximately $596 million of recorded expenditures in the CEMA and other accounts, resulting in a revenue requirement of approximately $435 million (the “2024 WMCE application”). The costs addressed in the 2024 WMCE application include those incurred in connection with rebuild and restoration activities, certain catastrophic wildfire and weather events, and other programs supporting gas, customer, and climate initiatives. These costs were incurred primarily in 2023.

The recorded expenditures consist of $80 million in expense and $516 million in capital expenditures. Of these amounts, approximately $50 million of expense and $396 million of capital expenditures relate to community rebuild and restoration activities and other catastrophic events included in the CEMA. Opening and reply briefs were filed on May 8 and June 3, 2026, respectively.

On June 22, 2026, the CPUC extended the statutory deadline in the proceeding from May 21, 2026 to February 19, 2027.

Wildfire and Gas Safety Costs Recovery Application

On June 15, 2023, the Utility filed a WGSC application with the CPUC requesting cost recovery of approximately $2.5 billion of recorded expenditures related to wildfire mitigation costs and gas safety and electric modernization costs.

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization efforts consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility recorded these costs to the memorandum and balancing accounts as set forth in the following table:


(in millions)	Recorded Costs
Wildfire mitigation plan memorandum account	$	2,095
Fire risk mitigation memorandum account	165
Gas storage balancing account	101
In line inspection memorandum account	92
Other	45
Total	$	2,498

In connection with the WGSC application, the Utility also requested interim rate relief of $583 million. The remaining $105 million would be recovered after the CPUC issues a final decision. On March 7, 2024, the CPUC approved a final decision authorizing the Utility to recover $516 million in interim rates to be recovered over at least 12 months starting April 1, 2024.

On September 17, 2026, the CPUC extended the statutory deadline in the proceeding to March 31, 2027.

On September 18, 2026, the CPUC issued a PD that would authorize recovery of approximately $1.8 billion of the $2.3 billion of Track 1 costs requested by the Utility, consisting primarily of Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account balances. The PD does not address recovery of amounts recorded in the Gas Storage Balancing Account, In-Line Inspection Memorandum Account, and other memorandum and balancing accounts that are being considered separately in Track 2 of the proceeding. The PD would also disallow approximately $477 million of requested costs, including approximately $291 million of capital expenditures that would be permanently excluded from rate base.

Review and Recovery of Costs Associated with the 2019 Kincade Fire and 2021 Dixie Fire Under AB 1054 Proceeding Application

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire. The application seeks (1) recovery of $1.59 billion of costs recorded to the WEMA and not covered through the Wildfire Fund or insurance, (2) review of the costs recorded to the WEMA and drawn from the Wildfire Fund, and (3) recovery of $314 million of costs recorded to the CEMA.

The Utility had drawn approximately $674 million from the Wildfire Fund at the time of the application. This amount will increase as a result of payments by the Utility to resolve claims and draws from the Wildfire Fund. The CPUC may require the Utility to reimburse the Wildfire Fund to the extent that amounts drawn from the Wildfire Fund are determined not to be just and reasonable. See Note 10 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

The scoping memo indicates that a PD will be issued by November 2026. That deadline could be extended by six months.

Forward-Looking Rate Cases

The Utility routinely participates in forward-looking rate case applications before the CPUC and the FERC. Those applications include GRCs, where the revenue required for general operations (“base revenue”) of the Utility is assessed and reset. In addition, the Utility is periodically involved in “cost of capital” proceedings to adjust its regulated return on rate base. The Utility’s future earnings will depend on the revenue requirements authorized in such rate cases.

Decisions in GRC proceedings have historically been expected prior to the commencement of the period to which the rates would apply. In recent decades, decisions in GRC proceedings have been delayed. Delayed decisions may cause the Utility to develop its budgets based on possible outcomes, rather than authorized amounts. When decisions are delayed, the CPUC typically provides rate relief to the Utility effective as of the commencement of the rate case period (not effective as of the date of the delayed decision). Nonetheless, the Utility’s spending during the period of the delay may exceed the authorized amount, without an ability for the Utility to seek cost recovery of such excess. If the Utility’s spending during the period of the delay is less than the authorized amount, the Utility could be exposed to operational and financial risks associated with the lower level of work achieved compared to that funded by the CPUC.

Statuses of the Utility’s forward-looking rate cases are summarized in the following table:

Rate Case

Request

Status

2027 GRC

Revenue requirement of $16.64 billion for 2027

Filed May 2025. A PD is expected by March 2027 and a final decision by May 2027. A PD on interim rate relief was issued in September 2026.

2027 General Rate Case

On May 7, 2026, the Utility requested interim rate recovery effective January 1, 2027, of 55%, 75%, or 85% of its requested 2027 revenue requirement (approximately $654 million, $891 million, and $1.01 billion, respectively), which has been opposed by some intervenors. On September 23, 2026, the CPUC issued a PD that would authorize the Utility to recover $456 million in interim rate recovery effective January 1, 2027. The CPUC could vote on this PD as early as October 29, 2026.

Opening briefs were filed on July 2, 2026, and reply briefs were filed on July 23, 2026.

For more information regarding the 2027 GRC, see the 2025 Form 10-K.

Transmission Owner Rate Case for 2024

On October 13, 2023, the Utility filed its TO21 rate case with the FERC. On August 5, 2025, the FERC issued a decision approving the settlement that resolved all issues in the proceeding. The decision set a base ROE of 10.38%, a fixed capital structure with common equity weighted at 50.0%, preferred equity at 0.3%, and long-term debt at 49.7%. For 2026, the Utility’s annual update includes a revenue requirement of $2.6 billion.

On December 29, 2023, the FERC issued an order denying a 0.5% ROE adder. On January 29, 2024, the Utility filed a request for rehearing of the FERC’s denial of the 0.5% ROE adder for participation in the CAISO, which the FERC denied on June 12, 2024. On June 18, 2024, the Utility and other California IOUs filed an appeal, which the Ninth Circuit Court of Appeals denied on July 11, 2025. After the Ninth Circuit denied a request from the utilities for en banc review on October 7, 2025, they filed a petition for certiorari with the U.S. Supreme Court. On February 23, 2026, the U.S. Supreme Court denied the petition for certiorari.

Other Regulatory Proceedings

Extension of Diablo Canyon Operations

On November 7, 2023, the Utility submitted an application for license renewal with the NRC. On April 2, 2026, the NRC approved the Utility’s 20-year license renewal application for extended operations of DCPP. Continued operation of DCPP beyond October 31, 2029 and October 31, 2030, for Unit 1 and Unit 2, respectively, also requires action by the California Legislature.

SB 884 10-Year Distribution Undergrounding Program

On March 7, 2024, the CPUC approved a resolution that establishes an expedited utility distribution infrastructure undergrounding program pursuant to Public Utilities Code Section 8388.5. The resolution addressed the process and requirements for the CPUC’s review of any large electrical corporation’s 10-year distribution infrastructure undergrounding plan and conditional approval of its related costs. On December 4, 2025, the CPUC approved a resolution that updated and refined the prior resolution and instructed the Utility to file a joint application with SCE and San Diego Gas & Electric Company requesting approval of a proposal to resolve several cost recovery issues, including the benefit-cost ratio and audit methodologies, not addressed in the resolution. On February 9, 2026, the utilities submitted that filing. On October 16, 2026, the CPUC issued a PD in response to the joint application that did not adopt most of the proposals submitted by the Utility, SCE and San Diego Gas & Electric Company. The Utility is currently evaluating the PD.

On February 20, 2025, the OEIS adopted final program guidelines. The OEIS has indicated that it will issue separate compliance guidelines.

On September 30, 2026, the Utility filed a ten-year Electrical Undergrounding Plan (“EUP”) for the years 2028 through 2037 with the OEIS.

Under the proposed plan, the Utility would install 5,000 miles of electrical distribution conduit underground to mitigate wildfire risk and increase electric reliability by reducing the need to de-energize electric distribution lines during periods of increased wildfire risk. The Utility estimates the cost of the proposed EUP, if fully approved, as $16.6 billion in capital expenditures over the ten-year period.

Pursuant to Public Utilities Code Section 8388.5, the OEIS has nine months to review and approve or deny the plan. Before approving the plan, the OEIS may require the Utility to modify the plan or to modify and resubmit the plan. If OEIS approves the plan, the Utility will file an application within 60 days to recover associated costs from the CPUC, which will have nine months to review and approve or deny the application.

LEGISLATIVE INITIATIVES

SB 254

On April 7, 2026, the Wildfire Fund administrator issued its study report pursuant to SB 254. The report sets out policy options for California’s Governor and Legislature to consider. The California Legislature concluded its 2025-2026 legislative session without enacting additional legislation to modify the state's wildfire liability framework. For more information regarding SB 254, see the 2025 Form 10-K.

LITIGATION AND OTHER MATTERS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to matters described in Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and in “Regulatory Matters” above that are incorporated by reference herein. 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, liquidity, and cash flows.

ENVIRONMENTAL MATTERS

The Utility’s operations are subject to extensive federal, state, and local laws and permits relating to the protection of the environment and the safety and health of the Utility’s personnel and the public. These laws and requirements relate to a broad range of the Utility’s activities, including the remediation of hazardous substances; the reporting and reduction of carbon dioxide and other GHG emissions; the discharge of pollutants into the air, water, and soil; the reporting of safety and reliability measures for natural gas storage facilities; and the transportation, handling, storage, and disposal of spent nuclear fuel. See “Environmental Remediation Contingencies” in Note 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q, as well as Item 1A: “Risk Factors” and Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

RISK MANAGEMENT ACTIVITIES

There have been no material changes to the Utility’s or PG&E Corporation’s risk management activities as previously disclosed in Item 7 of the 2025 Form 10-K.

CRITICAL ACCOUNTING ESTIMATES

There have been no material changes to the Utility’s or PG&E Corporation’s critical accounting estimates as previously disclosed in Item 7 of the 2025 Form 10-K.

ACCOUNTING STANDARDS ISSUED BUT NOT YET ADOPTED

See Note 2 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions, except per share amounts)


	(Unaudited)
	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
Operating Revenues
Electric	$	4,660			$	4,755		$	14,015	$	13,304
Natural gas	1,528			1,495			4,956		4,827
Total operating revenues	6,188			6,250			18,971		18,131
Operating Expenses
Cost of electricity	904			1,015			2,265		2,013
Cost of natural gas	109			131			694		738
Operating and maintenance	2,543			2,641			8,191		8,147
SB 901 securitization inception charge	36			35			36		35
Wildfire-related claims, net of recoveries	—			1			—		100
Wildfire Fund expense	141			86			369		271
Depreciation, amortization, and decommissioning	1,206			1,132			3,434		3,302
Total operating expenses	4,939			5,041			14,989		14,606
Operating Income	1,249			1,209			3,982		3,525
Interest income	104			94			336		392
Interest expense	(825)			(770)			(2,424)		(2,296)
Other income, net	153			97			366		251
Income Before Income Taxes	681			630			2,260		1,872
Income tax benefit	(95)			(220)			(162)		(161)
Net Income	776			850			2,422		2,033
Preferred stock dividend requirement	27			27			82		82
Income Available for Common Shareholders	$	749			$	823		$	2,340	$	1,951
Weighted Average Common Shares Outstanding, Basic	2,202			2,198			2,201		2,197
Weighted Average Common Shares Outstanding, Diluted	2,285			2,281			2,284		2,202
Net Income Per Common Share, Basic	$	0.34			$	0.37		$	1.06	$	0.89
Net Income Per Common Share, Diluted	$	0.34			$	0.37		$	1.06	$	0.89

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	(Unaudited)
	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
Net Income	$	776			$	850		$	2,422	$	2,033
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $1, and $0 respectively)	—			—			1		1
Net unrealized gain (loss) on available-for-sale securities (net of taxes of $3, $1, $7, and $4 respectively)	(2)			(4)			(12)		10
Total other comprehensive income (loss)	(2)			(4)			(11)		11
Comprehensive Income	774			846			2,411		2,044
Preferred stock dividend requirement	27			27			82		82
Comprehensive Income Available for Common Shareholders	$	747			$	819		$	2,329	$	1,962

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	(Unaudited)
	Balance at
	September 30, 2026		December 31, 2025
ASSETS
Current Assets
Cash and cash equivalents	$	902			$	713
Restricted cash and restricted cash equivalents (includes $370 million and $225 million related to VIEs at respective dates)	404			259
Accounts receivable
Customers (net of allowance for doubtful accounts of $391 million and $408 million at respective dates) (includes $1.8 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $391 million and $408 million at respective dates)	2,205			2,267
Accrued unbilled revenue (includes $1.4 billion and $1.3 billion related to VIEs at respective dates)	1,613			1,463
Regulatory balancing accounts	4,846			6,300
Other (net of allowance for doubtful accounts of $28 million and $69 million at respective dates)	1,633			1,719
Regulatory assets	159			305
Inventories
Gas stored underground and fuel oil	68			75
Materials and supplies	789			745
Wildfire Fund asset	286			297
Wildfire self-insurance asset	1,008			1,043
Other	834			644
Total current assets	14,747			15,830
Property, Plant, and Equipment
Property, Plant, and Equipment	136,221			128,989
Construction work in progress	5,115			4,627
Financing lease ROU asset and other	—			2
Total property, plant, and equipment	141,336			133,618
Accumulated depreciation	(38,781)			(37,270)
Net property, plant, and equipment	102,555			96,348
Other Noncurrent Assets
Regulatory assets	16,531			15,981
Customer credit trust	408			804
Nuclear decommissioning trusts	4,432			4,230
Operating lease ROU asset	452			450
Wildfire Fund asset	3,373			3,728
Other (includes noncurrent accounts receivable of $76 million and $67 million related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $15 million and $272 million and $0 of noncurrent restricted cash related to the DOE’s Civil Nuclear Credit Program at respective dates)	4,797			4,240
Total other noncurrent assets	29,993			29,433
TOTAL ASSETS	$	147,295			$	141,611

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


	(Unaudited)
	Balance at
	September 30, 2026		December 31, 2025
LIABILITIES AND EQUITY
Current Liabilities
Short-term borrowings	$	2,205			$	2,675
Long-term debt, classified as current (includes $227 million and $221 million related to VIEs at respective dates)	1,474			821
Accounts payable
Trade creditors	3,052			3,353
Regulatory balancing accounts	2,406			3,119
Other	815			929
Operating lease liabilities	94			90
Interest payable (includes $154 million and $72 million related to VIEs at respective dates)	773			764
Wildfire-related claims	173			524
Other	3,331			4,025
Total current liabilities	14,323			16,300
Noncurrent Liabilities
Long-term debt (includes $11.5 billion and $11.7 billion related to VIEs at respective dates)	61,347			57,387
Regulatory liabilities	20,369			20,188
Pension and other postretirement benefits	496			549
Asset retirement obligations	5,654			5,439
Deferred income taxes	5,020			4,135
Operating lease liabilities	358			360
Financing lease liabilities	—			2
Other	4,903			4,459
Total noncurrent liabilities	98,147			92,519
Equity
Shareholders’ Equity
Mandatory convertible preferred stock	1,579			1,579
Common stock, no par value, authorized 3,600,000,000 and 3,600,000,000 shares at respective dates; 2,202,416,553 and 2,193,573,536 shares outstanding at respective dates	31,672			31,636
Reinvested earnings	1,357			(650)
Accumulated other comprehensive loss	(35)			(25)
Total shareholders’ equity	34,573			32,540
Noncontrolling Interest - Preferred Stock of Subsidiary	252			252
Total equity	34,825			32,792
TOTAL LIABILITIES AND EQUITY	$	147,295			$	141,611

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	(Unaudited)
	Nine Months Ended September 30,
	2026		2025
Cash Flows from Operating Activities
Net income	$	2,422			$	2,033
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,434			3,302
Bad debt expense	185			331
Allowance for equity funds used during construction	(161)			(164)
Deferred income taxes and tax credits, net	888			700
Wildfire Fund expense	369			271
Other	34			(84)
Effect of changes in operating assets and liabilities:
Accounts receivable	(143)			(454)
Wildfire-related insurance receivable	158			(106)
Inventories	(37)			57
Accounts payable	(232)			25
Wildfire-related claims	(351)			(424)
Other current assets and liabilities	(368)			377
Regulatory assets, liabilities, and balancing accounts, net	(86)			1,324
Other noncurrent assets and liabilities	(272)			(432)
Net cash provided by operating activities	5,840			6,756
Cash Flows from Investing Activities
Capital expenditures	(9,621)			(8,631)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,967			1,365
Purchases of nuclear decommissioning trust investments	(2,029)			(1,421)
Proceeds from sales and maturities of customer credit trust investments	440			310
Purchases of customer credit trust investments	(38)			(729)
Proceeds from sales and maturities of self-insurance investments	930			669
Purchases of self-insurance investments	(962)			(828)
Other	17			15
Net cash used in investing activities	(9,296)			(9,250)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,353			3,080
Repayments under credit facilities	(6,143)			(1,330)
Borrowings under term loan	180			500
Repayments under term loan	(860)			(1,000)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $47 and $27 at respective dates	7,053			2,973
Repayments of long-term debt	(2,269)			(1,925)
Repayment of AB 1054 recovery bonds	(65)			(72)
Repayment of SB 901 recovery bonds	(69)			(67)
Common stock dividends paid	(330)			(166)
Mandatory convertible preferred stock dividends paid	(72)			(72)
Other	12			132


Net cash provided by financing activities	3,790		2,053
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	334		(441)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	972		1,213
Cash, cash equivalents, restricted cash, and restricted cash equivalents at September 30	$	1,306		$	772
Less: Restricted cash and restricted cash equivalents	(404)		(368)
Cash and cash equivalents at September 30	$	902		$	404


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(2,226)		$	(2,079)
Income taxes, net	(165)		—
Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,609		$	1,416
Operating lease liabilities arising from ROU assets	68		—



DWR loan forgiveness and performance-based disbursements	28		95
Common stock dividends declared but not yet paid	111		55
Mandatory convertible preferred stock dividends declared but not yet paid	24		24
Capital expenditures financed through current assets and noncurrent liabilities	—		592

See accompanying Notes to the Condensed Consolidated Financial Statements.

PG&E CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share amounts)


	Preferred Stock		Common Stock				Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)	Total Shareholders' Equity	Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
		Shares		Amount
Balance at December 31, 2025	$	1,579			2,197,942,874			$	31,636					$	(650)		$	(25)			$	32,540		$	252	$	32,792
Net income	—			—			—					885			—		885			—			885
Other comprehensive loss	—			—			—					—			(6)		(6)			—			(6)
Common stock issued, net	—			4,281,854			—					—			—		—			—			—
Stock-based compensation amortization	—			—			(31)					—			—		(31)			—			(31)
Common stock dividends declared	—			—			—					(111)			—		(111)			—			(111)
Preferred stock dividend requirement	—			—			—					(27)			—		(27)			—			(27)
Balance at March 31, 2026	$	1,579			2,202,224,728			$	31,605					$	97		$	(31)			$	33,250		$	252	$	33,502
Net income	—			—			—					761			—		761			—			761
Other comprehensive loss	—			—			—					—			(2)		(2)			—			(2)
Common stock issued, net	—			141,998			—					—			—		—			—			—
Stock-based compensation amortization	—			—			31					—			—		31			—			31
Common stock dividends declared	—			—			—					(111)			—		(111)			—			(111)
Preferred stock dividend requirement	—			—			—					(28)			—		(28)			—			(28)
Balance at June 30, 2026	$	1,579			2,202,366,726			$	31,636					$	719		$	(33)			$	33,901		$	252	$	34,153
Net income			—			—					776			—		776			—			776
Other comprehensive loss			—			—					—			(2)		(2)			—			(2)
Common stock issued, net			49,827			—					—			—		—			—			—
Stock-based compensation amortization			—			36					—			—		36			—			36
Common stock dividends declared										(111)				(111)		—			(111)
Preferred stock dividend requirement										(27)				(27)		—			(27)
Balance at September 30, 2026	$	1,579			2,202,416,553			$	31,672					$	1,357		$	(35)			$	34,573		$	252	$	34,825


	Preferred Stock		Common Stock			Reinvested Earnings		Accumulated Other Comprehensive Income (Loss)	Total Shareholders' Equity	Non- controlling Interest - Preferred Stock of Subsidiary		Total Equity
		Shares		Amount
Balance at December 31, 2024	$	1,579			2,193,573,536		$	31,555					$	(2,966)	$	(19)		$	30,149		$	252	$	30,401
Net income	—			—		—					634			—	634		—			634
Other comprehensive income	—			—		—					—			7	7		—			7
Common stock issued, net	—			4,111,477		(1)					—			—	(1)		—			(1)
Stock-based compensation amortization	—			—		(22)					—			—	(22)		—			(22)
Common stock dividends declared	—			—		—					(55)			—	(55)		—			(55)
Preferred stock dividend requirement	—			—		—					(27)			—	(27)		—			(27)
Balance at March 31, 2025	$	1,579			2,197,685,013		$	31,532					$	(2,414)	$	(12)		$	30,685		$	252	$	30,937
Net income	—			—		—					549			—	549		—			549
Other comprehensive income	—			—		—					—			8	8		—			8
Common stock issued, net	—			152,389		—					—			—	—		—			—
Stock-based compensation amortization	—			—		28					—			—	28		—			28
Common stock dividends declared	—			—		—					(56)			—	(56)		—			(56)
Preferred stock dividend requirement	—			—		—					(28)			—	(28)		—			(28)
Balance at June 30, 2025	$	1,579			2,197,837,402		$	31,560					$	(1,949)	$	(4)		$	31,186		$	252	$	31,438
Net income	—			—		—					850			—	850		—			850
Other comprehensive loss	—			—		—					—			(4)	(4)		—			(4)
Common stock issued, net	—			70,001		—					—			—	—		—			—
Stock-based compensation amortization	—			—		28					—			—	28		—			28
Common stock dividends declared	—			—		—					(55)			—	(55)		—			(55)
Preferred stock dividend requirement	—			—		—					(27)			—	(27)		—			(27)
Balance at September 30, 2025	$	1,579			2,197,907,403		$	31,588					$	(1,181)	$	(8)		$	31,978		$	252	$	32,230

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(in millions)


	(Unaudited)
	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
Operating Revenues
Electric	$	4,660			$	4,755		$	14,015	$	13,304
Natural gas	1,528			1,495			4,956		4,827
Total operating revenues	6,188			6,250			18,971		18,131
Operating Expenses
Cost of electricity	904			1,015			2,265		2,013
Cost of natural gas	109			131			694		738
Operating and maintenance	2,541			2,636			8,182		8,128
SB 901 securitization charges, net	36			35			36		35
Wildfire-related claims, net of recoveries	—			1			—		100
Wildfire Fund expense	141			86			369		271
Depreciation, amortization, and decommissioning	1,206			1,132			3,434		3,302
Total operating expenses	4,937			5,036			14,980		14,587
Operating Income	1,251			1,214			3,991		3,544
Interest income	97			91			320		384
Interest expense	(729)			(691)			(2,145)		(2,059)
Other income, net	116			97			334		251
Income Before Income Taxes	735			711			2,500		2,120
Income tax benefit	(85)			(202)			(105)		(100)
Net Income	820			913			2,605		2,220
Preferred stock dividend requirement	3			3			10		10
Income Available for Common Stock	$	817			$	910		$	2,595	$	2,210

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in millions)


	(Unaudited)
	Three Months Ended September 30,		Nine Months Ended September 30,
	2026		2025		2026		2025
Net Income	$	820			$	913		$	2,605	$	2,220
Other Comprehensive Income
Pension and other postretirement benefit plans obligations (net of taxes of $0, $0, $1, and $0 respectively)	1			—			1		2
Net unrealized gain (loss) on available-for-sale securities (net of taxes of $3, $1, $7, and $4 respectively)	(3)			(4)			(12)		10
Total other comprehensive income (loss)	(2)			(4)			(11)		12
Comprehensive Income	$	818			$	909		$	2,594	$	2,232

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions)


	(Unaudited)
	Balance at
	September 30, 2026		December 31, 2025
ASSETS
Current Assets
Cash and cash equivalents	$	339			$	353
Restricted cash and restricted cash equivalents (includes $370 million and $225 million related to VIEs at respective dates)	404			258
Accounts receivable
Customers (net of allowance for doubtful accounts of $391 million and $408 million at respective dates) (includes $1.8 billion and $1.9 billion related to VIEs, net of allowance for doubtful accounts of $391 million and $408 million at respective dates)	2,205			2,267
Accrued unbilled revenue (includes $1.4 billion and $1.3 billion related to VIEs at respective dates)	1,613			1,463
Regulatory balancing accounts	4,846			6,300
Other (net of allowance for doubtful accounts of $28 million and $69 million at respective dates)	1,635			1,725
Regulatory assets	159			305
Inventories
Gas stored underground and fuel oil	68			75
Materials and supplies	789			745
Wildfire Fund asset	286			297
Wildfire self-insurance asset	1,008			1,043
Other	865			643
Total current assets	14,217			15,474
Property, Plant, and Equipment
Property, Plant, and Equipment	136,222			128,989
Construction work in progress	5,114			4,626
Financing lease ROU asset and other	—			2
Total property, plant, and equipment	141,336			133,617
Accumulated depreciation	(38,781)			(37,269)
Net property, plant, and equipment	102,555			96,348
Other Noncurrent Assets
Regulatory assets	16,531			15,981
Customer credit trust	408			804
Nuclear decommissioning trusts	4,432			4,230
Operating lease ROU asset	448			445
Wildfire Fund asset	3,373			3,728
Other (includes noncurrent accounts receivable of $76 million and $67 million related to VIEs, net of noncurrent allowance for doubtful accounts of $17 million and $15 million and $272 million and $0 of noncurrent restricted cash related to the DOE’s Civil Nuclear Credit Program at respective dates)	4,599			4,073
Total other noncurrent assets	29,791			29,261
TOTAL ASSETS	$	146,563			$	141,083

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(in millions, except share amounts)


	(Unaudited)
	Balance at
	September 30, 2026		December 31, 2025
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Short-term borrowings	$	2,205			$	2,675
Long-term debt, classified as current (includes $227 million and $221 million related to VIEs at respective dates)	1,474			821
Accounts payable
Trade creditors	3,051			3,352
Regulatory balancing accounts	2,406			3,119
Other	781			844
Operating lease liabilities	94			90
Interest payable (includes $154 million and $72 million related to VIEs at respective dates)	709			673
Wildfire-related claims	173			524
Other	3,174			3,710
Total current liabilities	14,067			15,808
Noncurrent Liabilities
Long-term debt (includes $11.5 billion and $11.7 billion related to VIEs at respective dates)	54,729			51,766
Regulatory liabilities	20,369			20,188
Pension and other postretirement benefits	430			482
Asset retirement obligations	5,654			5,439
Deferred income taxes	5,678			4,732
Operating lease liabilities	354			355
Financing lease liabilities	—			2
Other	4,914			4,474
Total noncurrent liabilities	92,128			87,438
Shareholders’ Equity
Preferred stock	258			258
Common stock, $5 par value, authorized 800,000,000 shares; 264,374,809 shares outstanding at respective dates	1,322			1,322
Additional paid-in capital	39,327			37,505
Reinvested earnings	(505)			(1,225)
Accumulated other comprehensive loss	(34)			(23)
Total shareholders’ equity	40,368			37,837
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	146,563			$	141,083

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)


	(Unaudited)
	Nine Months Ended September 30,
	2026		2025
Cash Flows from Operating Activities
Net income	$	2,605			$	2,220
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization, and decommissioning	3,434			3,302
Bad debt expense	185			331
Allowance for equity funds used during construction	(161)			(164)
Deferred income taxes and tax credits, net	948			738
Wildfire Fund expense	369			271
Other	(13)			(121)
Effect of changes in operating assets and liabilities:
Accounts receivable	(139)			(456)
Wildfire-related insurance receivable	158			(106)
Inventories	(37)			57
Accounts payable	(179)			27
Wildfire-related claims	(351)			(424)
Other current assets and liabilities	(228)			449
Regulatory assets, liabilities, and balancing accounts, net	(86)			1,324
Other noncurrent assets and liabilities	(243)			(429)
Net cash provided by operating activities	6,262			7,019
Cash Flows from Investing Activities
Capital expenditures	(9,621)			(8,631)
Proceeds from sales and maturities of nuclear decommissioning trust investments	1,967			1,365
Purchases of nuclear decommissioning trust investments	(2,029)			(1,421)
Proceeds from sales and maturities of customer credit trust investments	440			310
Purchases of customer credit trust investments	(38)			(729)
Proceeds from sales and maturities of self-insurance investments	930			669
Purchases of self-insurance investments	(962)			(828)
Other	17			15
Net cash used in investing activities	(9,296)			(9,250)
Cash Flows from Financing Activities
Borrowings under credit facilities	6,353			3,080
Repayments under credit facilities	(6,143)			(1,330)
Borrowings under term loan	180			500
Repayments under term loan	(860)			(1,000)
Proceeds from issuance of long-term debt, net of premium, discount and issuance costs of $37 and $27 at respective dates	6,063			2,973
Repayments of long-term debt	(2,269)			(1,925)
Repayment of AB 1054 recovery bonds	(65)			(72)
Repayment of SB 901 recovery bonds	(69)			(67)
Preferred stock dividends paid	(10)			(11)
Common stock dividends paid	(1,875)			(1,725)


Equity contribution from PG&E Corporation	1,822		1,295
Other	39		156
Net cash provided by financing activities	3,166		1,874
Net change in cash, cash equivalents, restricted cash, and restricted cash equivalents	132		(357)
Cash, cash equivalents, restricted cash, and restricted cash equivalents at January 1	611		977
Cash, cash equivalents, restricted cash, and restricted cash equivalents at September 30	$	743		$	620
Less: Restricted cash and restricted cash equivalents	(404)		(367)
Cash and cash equivalents at September 30	$	339		$	253


Supplemental disclosures of cash flow information
Cash paid for:
Interest, net of amounts capitalized	$	(1,928)		$	(1,819)
Income taxes, net	(230)		—

Supplemental disclosures of noncash investing and financing activities
Capital expenditures financed through accounts payable	$	1,609		$	1,416
Operating lease liabilities arising from obtaining ROU assets	68		—


DWR loan forgiveness and performance-based disbursements	28		95
Capital expenditures financed through current assets and noncurrent liabilities	—		592

See accompanying Notes to the Condensed Consolidated Financial Statements.

PACIFIC GAS AND ELECTRIC COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in millions)


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2025	$	258			$	1,322		$	37,505		$	(1,225)		$	(23)	$	37,837
Net income	—			—			—		954		—		954
Other comprehensive loss	—			—			—		—		(6)		(6)
Equity contribution	—			—			977		—		—		977
Common stock dividend	—			—			—		(625)		—		(625)
Preferred stock dividend requirement	—			—			—		(3)		—		(3)
Balance at March 31, 2026	$	258			$	1,322		$	38,482		$	(899)		$	(29)	$	39,134
Net income	—			—			—		831		—		831
Other comprehensive loss	—			—			—		—		(3)		(3)
Equity contribution	—			—			320		—		—		320
Common stock dividend	—			—			—		(625)		—		(625)
Preferred stock dividend requirement	—			—			—		(4)		—		(4)
Balance at June 30, 2026	$	258			$	1,322		$	38,802		$	(697)		$	(32)	$	39,653
Net income	—			—			—		820		—		820
Other comprehensive loss	—			—			—		—		(2)		(2)
Equity contribution	—			—			525		—		—		525
Common stock dividend	—			—			—		(625)		—		(625)
Preferred stock dividend requirement	—			—			—		(3)		—		(3)
Balance at September 30, 2026	$	258			$	1,322		$	39,327		$	(505)		$	(34)	$	40,368


	Preferred Stock		Common Stock		Additional Paid-in Capital		Reinvested Earnings	Accumulated Other Comprehensive Income (Loss)		Total Shareholders' Equity
Balance at December 31, 2024	$	258			$	1,322		$	35,930		$	(1,940)		$	(20)	$	35,550
Net income	—			—			—		695		—		695
Other comprehensive income	—			—			—		—		7		7
Equity contribution	—			—			450		—		—		450
Common stock dividend	—			—			—		(575)		—		(575)
Preferred stock dividend requirement	—			—			—		(3)		—		(3)
Balance at March 31, 2025	$	258			$	1,322		$	36,380		$	(1,823)		$	(13)	$	36,124
Net income	—			—			—		612		—		612
Other comprehensive income	—			—			—		—		8		8
Equity contribution	—			—			325		—		—		325
Common stock dividend	—			—			—		(575)		—		(575)
Preferred stock dividend requirement	—			—			—		(4)		—		(4)
Balance at June 30, 2025	$	258			$	1,322		$	36,705		$	(1,790)		$	(5)	$	36,490
Net income	—			—			—		913		—		913
Other comprehensive loss	—			—			—		—		(4)		(4)
Equity contribution	—			—			521		—		—		521
Common stock dividend	—			—			—		(575)		—		(575)
Preferred stock dividend requirement	—			—			—		(3)		—		(3)
Balance at September 30, 2025	$	258			$	1,322		$	37,226		$	(1,455)		$	(9)	$	37,342

See accompanying Notes to the Condensed Consolidated Financial Statements.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

Organization and Basis of Presentation

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility 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 primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

This Form 10-Q is a combined report of PG&E Corporation and the Utility. PG&E Corporation’s Condensed Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Condensed Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Condensed Consolidated Financial Statements apply to both PG&E Corporation and the Utility.

The accompanying Condensed Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the interim period reporting requirements of Form 10-Q and reflect all adjustments which are, in the opinion of the management, of a normal recurring nature and necessary to a fair statement of the results for the interim periods presented. The information as of December 31, 2025 in the Condensed Consolidated Balance Sheets included in this Form 10-Q was derived from the audited Consolidated Balance Sheets in Item 8 of the 2025 Form 10-K. This Form 10-Q should be read in conjunction with the 2025 Form 10-K.

The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s regulatory assets and liabilities, wildfire-related liabilities, legal and regulatory contingencies, the Wildfire Fund, environmental remediation liabilities, asset retirement obligations, wildfire-related receivables, and pension and other post-retirement benefit plan obligations. Management believes that its estimates and assumptions reflected in the Condensed Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that would have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Segment Reporting

PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis and operate as one reportable segment. PG&E Corporation’s and the Utility’s chief operating decision maker (“CODM”) is the Chief Executive Officer of PG&E Corporation.

Net income (loss) is the measure that the CODM uses to assess performance and decide how to allocate resources and that is most consistent with GAAP principles. Net income is reported on PG&E Corporation’s Condensed Consolidated Statements of Income. Because PG&E Corporation and the Utility are a single reportable segment, all segment financial information can be found in PG&E Corporation’s Condensed Consolidated Financial Statements.

PG&E Corporation and the Utility do not have any significant segment expenses because the CODM is not regularly provided with information that is considered to be significant under Accounting Standards Codification (“ASC”) 280, Segment Reporting. Except for publicly available information, the information regularly provided to the CODM consists of financial reports with metrics that combine year-to-date actual results with forecasts of the remainder of the year in order to provide a comprehensive view of the entire year. These metrics do not separate expenses already incurred from forecast information.

Revenue Recognition

Revenue from Contracts with Customers

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.

Regulatory Balancing Account Revenue

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass through to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

The following table presents the Utility’s revenues disaggregated by type of customer:


	Three Months Ended September 30,		Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Electric
Revenue from contracts with customers
Residential	$	1,980			$	2,306		$	5,571	$	5,561
Commercial	2,365			2,249			5,693		5,368
Industrial	695			655			1,587		1,455
Agricultural	766			807			1,461		1,484
Public street and highway lighting	28			27			81		80
Other, net (1)	(352)			(196)			479		558
Total revenue from contracts with customers - electric	5,482			5,848			14,872		14,506
Regulatory balancing accounts (2)	(822)			(1,093)			(857)		(1,202)
Total electric operating revenue	$	4,660			$	4,755		$	14,015	$	13,304

Natural gas
Revenue from contracts with customers
Residential	$	468			$	490		$	2,303	$	2,629
Commercial	167			173			716		794
Transportation service only	385			436			1,249		1,438
Other, net (1)	45			(1)			(319)		(268)
Total revenue from contracts with customers - gas	1,065			1,098			3,949		4,593
Regulatory balancing accounts (2)	463			397			1,007		234
Total natural gas operating revenue	1,528			1,495			4,956		4,827
Total operating revenues	$	6,188			$	6,250		$	18,971	$	18,131

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent alternative revenues authorized to be billed or refunded to customers.

Financial Assets Measured at Amortized Cost – Credit Losses

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of September 30, 2026, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade Receivables

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

Expected credit losses of $66 million and $185 million were recorded in Operating and maintenance expense on the Condensed Consolidated Statements of Income for credit losses associated with trade and other receivables during the three and nine months ended September 30, 2026, respectively. For the three and nine months ended September 30, 2025, expected credit losses were $89 million and $331 million, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA and a FERC regulatory asset account. As of September 30, 2026, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $162 million and $84 million, respectively. As of December 31, 2025, the RUBA current balancing accounts and FERC noncurrent regulatory asset balances were $278 million and $92 million, respectively. The RUBA current balancing account balance decreased from December 31, 2025 to September 30, 2026 primarily due to the annual electric and gas rate true-up, which allows the Utility to recover approximately $278 million in undercollections from residential customers in 2026.

Other Receivables and Available-For-Sale Debt Securities

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion. For more information, see Note 10 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. For certain investments held by PG&E Corporation and the Utility, the companies are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

As of September 30, 2026, expected credit losses for insurance receivables, Wildfire Fund receivables, and available-for-sale debt securities were immaterial.

Government Assistance

The Utility participated in various government assistance programs during the three and nine months ended September 30, 2026 and 2025. The Utility accounts for government grants in accordance with ASU 2025-10, Government Grants (Topic 832).

DWR Loan Agreement

On October 18, 2022, the DWR and the Utility entered into a $1.4 billion loan agreement to support the extension of DCPP, with up to $1.1 billion potentially repaid by DOE funds. Under the agreement, the Utility received monthly performance-based disbursements of $7 per MWh generated, capped at $300 million. The final loan proceeds were received in 2024, and no further disbursements will be made.

The Utility initially accounted for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When the Utility has reasonable assurance that the DWR will forgive loan disbursements (such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs), the Utility recognizes those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.

The following table summarizes where DWR loan activity is presented in PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements:


	Three Months Ended September 30,		Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Long-term debt:
Beginning Balance - DWR loan outstanding	$	709			$	808		$	738	$	886



Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	—			(2)			—		(20)
Operating and maintenance expense - Loan forgiveness and other adjustments	(24)			(17)			(28)		(75)

Other current liabilities:
Change in performance-based disbursements deferred	—			2			—		—

Other noncurrent assets:
Loan forgiveness and other adjustments	—			—			(25)		—

Long-term debt:
Ending Balance - DWR loan outstanding	$	685			$	791		$	685	$	791

U.S. DOE’s Civil Nuclear Credit Program

On January 11, 2024, the Utility and the DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to DCPP as part of the DOE’s Civil Nuclear Credit Program. The Utility uses these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts are determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the DCPP operations. The Utility deposits cash received from the DOE’s Civil Nuclear Credit Program into a Utility held escrow account. Cash held in the escrow account will be released and paid to DWR after completion of the DOE’s final annual review process.

When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility recognizes such funding as income and records a receivable related to government grants. During the three and nine months ended September 30, 2026, the Condensed Consolidated Statements of Income reflected $6 million and $37 million respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three and nine months ended September 30, 2025, the Condensed Consolidated Statements of Income reflected $34 million and $134 million, respectively, as a deduction to Operating and maintenance expense, for income related to government grants for incurred eligible costs to support the extension of DCPP. During the three and nine months ended September 30, 2026, the amount recorded as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP was immaterial. During the nine months ended September 30, 2025, the Condensed Consolidated Statements of Income reflected $57 million as a deduction to Cost of electricity for income related to government grants for incurred fuel costs to support the extension of DCPP.

On August 24, 2026, the Utility received $272 million from the DOE’s Civil Nuclear Credit Program related to partial payment of award years 2023 and 2024. As of September 30, 2026, the Condensed Consolidated Balance Sheets reflected $272 million of cash as restricted cash within Other noncurrent assets - Other.

Variable Interest Entities

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

Consolidated VIEs

Receivables Securitization Program

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions. The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Condensed Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the nine months ended September 30, 2026 or is expected to be provided in the future that was not previously contractually required. As of September 30, 2026 and December 31, 2025, the SPV had net accounts receivable of $3.2 billion and outstanding borrowings of $1.8 billion under the Receivables Securitization Program. For more information, see Note 4 below.

AB 1054 Securitization

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the AB 1054 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued three separate series of recovery bonds secured by separate Recovery Property.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the nine months ended September 30, 2026 or is expected to be provided in the future that was not previously contractually required. Between 2021 and 2024, PG&E Recovery Funding LLC issued an aggregate of $3.26 billion of senior secured recovery bonds. As of September 30, 2026 and December 31, 2025, PG&E Recovery Funding LLC had outstanding borrowings of $3.0 billion and $3.1 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets.

SB 901 Securitization

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the nine months ended September 30, 2026 or is expected to be provided in the future that was not previously contractually required. In 2022, PG&E Wildfire Recovery Funding LLC issued an aggregate of $7.5 billion of senior secured recovery bonds. As of September 30, 2026 and December 31, 2025, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.0 billion and $7.1 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Condensed Consolidated Balance Sheets. For more information, see Note 5 below.

Non-Consolidated VIEs

Power Purchase Agreements

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of September 30, 2026, the Utility assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of September 30, 2026, it did not consolidate any of them.

Contributions to the Wildfire Fund and the Continuation Account

AB 1054 did not specify a period of coverage for the Wildfire Fund, and so the accounting treatment is subject to significant judgments and estimates. PG&E Corporation and the Utility account for shareholder contributions to the Wildfire Fund by recognizing an asset, amortizing the asset ratably over the life of the fund based on an estimated period of coverage, and accelerating amortization of the asset when it is determined probable and estimable that the Wildfire Fund longevity has declined, as further described below.

In estimating the life of the fund, PG&E Corporation and the Utility use a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. PG&E Corporation’s and the Utility’s initial estimated life of the fund was 15 years. In 2024, a re-evaluation resulted in the estimated life increasing from 15 to 20 years.

The number of years of historic fire-loss data, the estimated costs to settle wildfire claims for participating electric utilities (including the Utility), the estimated amount of Wildfire Fund claim payments, and the effectiveness of wildfire mitigation efforts by the California electric utility companies are significant assumptions used to estimate the life of the fund. Other assumptions include the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. The estimated life of the fund has a high degree of uncertainty for many of these assumptions, and so subsequent changes could materially impact the remaining estimated life of the fund.

PG&E Corporation and the Utility have an established process to re-evaluate the estimated life of the fund whenever they obtain new significant fire-loss data. PG&E Corporation and the Utility consider significant fire-loss data to include Cal Fire’s annual release of the prior year’s fire-loss data, internally developed data about wildfires and wildfire conditions in their own service area, and other participating electric utilities’ public disclosures of probable and estimable wildfire-related losses in their service area. PG&E Corporation and the Utility are not able to independently verify other utilities’ estimates. During each re-evaluation, PG&E Corporation and the Utility update their assumptions and the dataset of historical fire-losses for wildfires caused by electrical equipment, as applicable. Based upon the outcome of the newly run Monte Carlo simulations, PG&E Corporation and the Utility may determine to increase or decrease, as applicable, the estimated life of the fund. PG&E Corporation and the Utility apply adjustments to the estimated life of the fund on a prospective basis.

In addition to estimating the life of the fund, PG&E Corporation and the Utility also assess the Wildfire Fund asset for accelerated amortization when they record or increase a Wildfire Fund receivable or when reliable information becomes publicly available, including when another participating electric utility discloses a Wildfire Fund receivable. SCE has disclosed that it has entered into settlements with insurance claimants and claimants under its Wildfire Recovery Compensation Program related to the Eaton fire. As of June 30, 2026, SCE had recorded $1.6 billion in losses related to these settlements. SCE also recorded expected recoveries from the Wildfire Fund of $645 million. As a result, PG&E Corporation and the Utility accelerated the amortization of the Wildfire Fund asset during the three and nine months ended September 30, 2026 as described below.

As of September 30, 2026, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $380 million in Other noncurrent liabilities, $286 million in Current assets - Wildfire Fund asset, and $3.4 billion in Noncurrent assets - Wildfire Fund asset in the Condensed Consolidated Balance Sheets. During the three months ended September 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $141 million and $86 million, respectively. During the nine months ended September 30, 2026 and 2025, the Utility recorded amortization and accretion expense of $369 million and $271 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset are reflected in Wildfire Fund expense in the Condensed Consolidated Statements of Income.

PG&E Corporation and the Utility expect to begin accounting for the Continuation Account if the Wildfire Fund administrator determines that the Continuation Account is necessary and the CPUC approves the extension of non-bypassable charges to customers.

For more information, see “Wildfire Fund Recoveries under AB 1054 and SB 254” in Note 10 below.

Pension and Other Post-Retirement Benefits

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan. Both plans are included in “Pension Benefits” below. Post-retirement medical and life insurance plans are included in “Other Benefits” below.

The net periodic benefit costs reflected in PG&E Corporation’s Condensed Consolidated Financial Statements for the three and nine months ended September 30, 2026 and 2025 were as follows:


	Pension Benefits		Other Benefits
	Three Months Ended September 30,
(in millions)	2026		2025		2026		2025
Service cost for benefits earned (1)	$	115			$	106		$	11	$	9
Interest cost	256			252			20		18
Expected return on plan assets	(307)			(263)			(39)		(37)
Amortization of prior service cost (credit)	(1)			(1)			1		1
Amortization of net actuarial loss (gain)	1			—			(4)		(6)
Net periodic benefit cost	64			94			(11)		(15)
Regulatory account transfer (2)	20			(10)			—		—
Total	$	84			$	84		$	(11)	$	(15)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.


	Pension Benefits		Other Benefits
	Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Service cost for benefits earned (1)	$	345			$	318		$	33	$	28
Interest cost	768			756			59		55
Expected return on plan assets	(921)			(790)			(117)		(112)
Amortization of prior service cost (credit)	(2)			(2)			2		2
Amortization of net actuarial loss (gain)	2			1			(11)		(17)
Net periodic benefit cost	192			283			(34)		(44)
Regulatory account transfer (2)	61			(30)			—		—
Total	$	253			$	253		$	(34)	$	(44)

(1) A portion of service costs is capitalized pursuant to GAAP.

(2) The Utility recorded these amounts to a regulatory account since they are probable of recovery from, or refund to, customers in future rates.

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.

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) consisted of the following:


	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
(in millions, net of income tax)	Three Months Ended September 30, 2026
Beginning balance	$	(46)			$	19		$	(1)	$	(28)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0 and $3, respectively)	—			—			(3)		(3)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $0, $0 and $1, respectively)	—			1			—		1
Amortization of net actuarial gain (net of taxes of $1, $1, and $1, respectively)	—			(3)			—		(3)
Regulatory account transfer (net of taxes of $0, $1, and $1, respectively)	—			3			—		3
Net current period other comprehensive gain (loss)	—			1			(3)		(2)
Ending balance	$	(46)			$	20		$	(4)	$	(30)

(1) These components are included in the computation of net periodic pension and other post-retirement benefit costs. See the “Pension and Other Post-Retirement Benefits” table above for additional details.

(2) Includes amounts related to the customer credit trust and self-insurance.


	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
(in millions, net of income tax)	Three Months Ended September 30, 2025
Beginning balance	$	(34)			$	18		$	17	$	1
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0, and $1 respectively)	—			—			(4)		(4)
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $1, and $0, respectively)	—			—			—		—
Amortization of net actuarial gain (net of taxes of $0, $2, and $0, respectively)	—			(4)			—		(4)
Regulatory account transfer (net of taxes of $0, $1, and $0, respectively)	—			4			—		4
Net current period other comprehensive loss	—			—			(4)		(4)
Ending balance	$	(34)			$	18		$	13	$	(3)

(2) Includes amounts related to the customer credit trust and self-insurance.


	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2026
Beginning balance	$	(47)			$	19		$	8	$	(20)
Other comprehensive income before reclassification
Loss on investments (net of taxes of $0, $0, and $7, respectively)	—			—			(12)		(12)
Unrecognized net actuarial gain (net of taxes of $0, $0 and $0, respectively)	1			—			—		1
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (gain) (net of taxes of $0, $1, and $0, respectively)	(1)			2			—		1
Amortization of net actuarial loss (gain) (net of taxes of $1, $3, and $0, respectively)	1			(8)			—		(7)
Regulatory account transfer (net of taxes of $0,$3, and $0, respectively)	—			7			—		7
Net current period other comprehensive gain (loss)	1			1			(12)		(10)
Ending balance	$	(46)			$	20		$	(4)	$	(30)

(2) Includes amounts related to the customer credit trust and self-insurance.


	Pension Benefits		Other Benefits		Available-for-Sale Securities(2)		Total
(in millions, net of income tax)	Nine Months Ended September 30, 2025
Beginning balance	$	(35)			$	18		$	3	$	(14)
Other comprehensive income before reclassification
Gain on investments (net of taxes of $0, $0, and $4, respectively)	—			—			10		10
Amounts reclassified from other comprehensive income: (1)
Amortization of prior service cost (net of taxes of $1, $1, and $0, respectively)	(1)			1			—		—
Amortization of net actuarial loss (gain) (net of taxes of $0, $5, and $0, respectively)	1			(12)			—		(11)
Regulatory account transfer (net of taxes of $0, $4, and $0, respectively)	1			11			—		12
Net current period other comprehensive gain	1			—			10		11
Ending balance	$	(34)			$	18		$	13	$	(3)

(2) Includes amounts related to the customer credit trust and self-insurance.

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

Recently Adopted Accounting Standards

Induced Conversions of Convertible Debt Instruments

In November 2024, the FASB issued ASU No. 2024-04, Debt—Debt with Conversion and Other Options (Subtopic 470-20): Induced Conversions of Convertible Debt Instruments, which amended the existing guidance by clarifying the requirements for determining whether certain settlements of convertible debt instruments should be accounted for as induced conversions. Under this ASU, to account for a settlement of a convertible debt instrument as an induced conversion, an inducement offer is required to provide the debt holder with, at a minimum, the consideration (in form and amount) issuable under the conversion privileges provided in the terms of the instrument. An entity should assess whether this criterion is satisfied as of the date the inducement offer is accepted by the holder. This ASU became effective for PG&E Corporation and the Utility on January 1, 2026. The adoption of this ASU did not have an immediate impact and is not expected to have a significant impact in future periods on PG&E Corporation’s and the Utility’s Condensed Consolidated Financial Statements and related disclosures.

Accounting Standards Issued But Not Yet Adopted

Disaggregation of Income Statement Expenses

In November 2024, the FASB issued ASU No. 2024-03, Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, which amended the existing guidance to require disclosure, in the notes to the financial statements, of specified information about certain costs and expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their financial statements and related disclosures.

Intangibles – Goodwill and Other – Internal-Use Software

In September 2025, the FASB issued ASU No. 2025-06, Intangibles—Goodwill and Other— Internal-Use Software (Subtopic 350-40), which amended the existing guidance to modernize the accounting for software costs that are accounted for under Subtopic 350-40, Intangibles—Goodwill and Other—Internal-Use Software. The amendments in this ASU remove all references to prescriptive and sequential software development stages throughout Subtopic 350-40. Therefore, an entity is required to start capitalizing software costs when both of the following occur: (1) management has authorized and committed to funding the software project, and (2) it is probable that the project will be completed, and the software will be used to perform the function. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their financial statements and related disclosures.

Environmental Credits and Environmental Credit Obligations

In May 2026, the FASB issued ASU No. 2026-02, Environmental Credits and Environmental Credit Obligations (Topic 818), which establishes guidance on the recognition, measurement, presentation, and disclosure requirements for all entities that generate, purchase, or receive environmental credits or have a regulatory compliance obligation that may be settled with environmental credits. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2027, and interim reporting periods within those annual reporting periods, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their financial statements and related disclosures.

NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

Regulatory Assets

Noncurrent regulatory assets are comprised of the following:


	Balance at
(in millions)	September 30, 2026		December 31, 2025
Pension benefits	$	341			$	400
Environmental compliance costs	1,145			1,158
Price risk management	90			100
Catastrophic event memorandum account	526			666
Wildfire-related accounts	1,458			1,626
Deferred income taxes	7,211			6,157
Financing costs	192			202
SB 901 securitization	4,960			5,089
Other	608			583
Total noncurrent regulatory assets	$	16,531			$	15,981

Regulatory Liabilities

Noncurrent regulatory liabilities are comprised of the following:


	Balance at
(in millions)	September 30, 2026		December 31, 2025
Cost of removal obligations	$	10,070			$	9,488
Public purpose programs	1,158			1,169
Employee benefit plans	1,061			1,043
Transmission tower wireless licenses	246			257
SB 901 securitization	5,676			6,010
Wildfire self-insurance	1,024			1,035
Other	1,134			1,186
Total noncurrent regulatory liabilities	$	20,369			$	20,188

Regulatory Balancing Accounts

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


	Balance at
(in millions)	September 30, 2026		December 31, 2025
Electric distribution	$	1,416			$	1,465
Electric transmission	147			122
Gas distribution and transmission	743			142
Energy procurement	1,496			2,711
Public purpose programs	135			151
Wildfire-related accounts	91			84
Residential uncollectibles balancing accounts	162			278
Catastrophic event memorandum account	27			181
Other	629			1,166
Total regulatory balancing accounts receivable	$	4,846			$	6,300


	Balance at
(in millions)	September 30, 2026		December 31, 2025
Electric transmission	$	—			$	37
Gas distribution and transmission	2			78
Energy procurement	572			1,502
Public purpose programs	603			472
SFGO sale	60			83
Wildfire-related accounts	521			338
Nuclear decommissioning adjustment mechanism	—			1
Other	648			608
Total regulatory balancing accounts payable	$	2,406			$	3,119

For more information, see Note 3 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

NOTE 4: DEBT

Credit Facilities

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their credit facilities as of September 30, 2026:


(in millions)	Termination Date	Maximum Facility Limit		Loans Outstanding		Letters of Credit Outstanding		Facility Availability
Utility revolving credit facility	June 2031	$	6,250		(1)	$	(1,785)		$	(213)		$	4,252
Utility Receivables Securitization Program (2)	June 2028	1,750		(3)	(1,750)			—		—	(3)
PG&E Corporation revolving credit facility	June 2029	650			—			—		650
Total credit facilities		$	8,650			$	(3,535)		$	(213)		$	4,902

(1) Includes a $2.0 billion letter of credit sublimit.

(2) For more information on the Receivables Securitization Program, see “Variable Interest Entities” in Note 2 above.

(3) The amount the Utility may borrow under the Receivables Securitization Program is limited to the lesser of the facility limit and the facility availability. Further, the facility availability may vary based on the amount of accounts receivable that the Utility owns that are eligible for sale to the SPV and the portion of those accounts receivable that are sold to the SPV that are eligible for advances by the lenders under the Receivables Securitization Program.

Utility

On June 22, 2026, the Utility amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 20, 2031, (ii) increase the aggregate commitments from $5.4 billion to $6.25 billion and (iii) modify both the interest rate pricing grid and commitment fee pricing grid.

On June 26, 2026, the Utility and the SPV amended the existing $1.75 billion Receivables Securitization Program to extend the scheduled termination date from June 25, 2027 to June 26, 2028.

On September 23, 2026, the Utility amended its existing term loan credit agreement with Wells Fargo Bank, National Association to, among other things, (i) extend the maturity date to September 22, 2027 and (ii) increase the aggregate amount of outstanding term loans from $70 million to $250 million.

PG&E Corporation

On June 22, 2026, PG&E Corporation amended its existing revolving credit agreement to, among other things, (i) extend the maturity date of such agreement to June 22, 2029, (ii) modify both the interest rate pricing grid and commitment fee pricing grid and (iii) add collateral release terms.

Long-Term Debt Issuances and Redemptions

Utility

On February 20, 2026, the Utility completed the sale of (i) $400 million aggregate principal amount of 6.100% first mortgage bonds due 2029, (ii) $1.0 billion aggregate principal amount of 5.200% first mortgage bonds due 2036 and (iii) $800 million aggregate principal amount of 6.000% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of $600 million aggregate principal amount of 2.95% first mortgage bonds due March 1, 2026. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On June 3, 2026, the Utility completed the sale of (i) $800 million aggregate principal amount of 5.050% first mortgage bonds due 2031, (ii) $800 million aggregate principal amount of 5.600% first mortgage bonds due 2036 and (iii) $600 million aggregate principal amount of 6.300% first mortgage bonds due 2056. The Utility used the net proceeds of such issuances for repayment of short-term debt, including borrowings outstanding under its revolving credit facility. The Utility used the remaining net proceeds from the offerings for general corporate purposes.

On August 4, 2026, the Utility completed the sale of (i) $700 million aggregate principal amount of 5.250% first mortgage bonds due 2032 and (ii) $1.0 billion aggregate principal amount of 5.850% first mortgage bonds due 2036. The Utility used the net proceeds to purchase through a cash tender offer approximately $1.1 billion aggregate principal amount of the Utility’s 3.30% senior notes due December 1, 2027, approximately $152 million aggregate principal amount of the Utility’s 2.10% first mortgage bonds due August 1, 2027, and to redeem $450 million aggregate principal amount of the Utility’s 5.450% first mortgage bonds due June 15, 2027. The Utility used the remaining net proceeds for general corporate purposes, including to repay indebtedness.

PG&E Corporation

On February 19, 2026, PG&E Corporation completed the sale of $1.0 billion aggregate principal amount of 6.850% Fixed-to-Fixed Reset Rate Junior Subordinated Notes due 2056. These notes initially bear interest at the rate of 6.850% per annum, and beginning September 15, 2031 and every five-year anniversary thereafter, the interest rate will be reset to an amount that is equal to the five-year U.S. Treasury rate plus 3.225% (but not below 6.850%). PG&E Corporation used the net proceeds for general corporate purposes, including repayment of indebtedness.

Convertible Notes

On December 4, 2023, PG&E Corporation completed the sale of $2.15 billion aggregate principal amount of 4.25% Convertible Senior Secured Notes due December 1, 2027 (the “Convertible Notes”).

As of both September 30, 2026 and December 31, 2025, the Condensed Consolidated Financial Statements reflected the net carrying amount of the Convertible Notes of $2.14 billion, with unamortized debt issuance costs of $8 million and $13 million, respectively, included in Long-term debt. For both the three and nine months ended September 30, 2026 and 2025, the Condensed Consolidated Statements of Income reflected total interest expense of approximately $23 million and $69 million, respectively.

For more information about the Convertible Notes, see Note 4 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K. As of September 30, 2026, none of the conditions allowing holders of the Convertible Notes to convert had been met.

NOTE 5: SB 901 SECURITIZATION AND CUSTOMER CREDIT TRUST

Pursuant to the financing order for the SB 901 securitization transactions, the Utility sold its right to receive revenues from the SB 901 Recovery Property to PG&E Wildfire Recovery Funding LLC, which, in turn, issued the recovery bonds secured by separate fixed recovery charges and separate SB 901 Recovery Property. The fixed recovery charges are designed to recover the full scheduled principal amount of the applicable series of recovery bonds along with any associated interest and financing costs. The customer credit trust (see Note 9 below) funds a customer credit to ratepayers, designed to equal the recovery bond principal, interest, and financing costs over the life of the recovery bonds to offset the fixed recovery charge. The fixed recovery charges and customer credits are presented on a net basis in Operating revenues in the Condensed Consolidated Statements of Income and had no net impact on Operating revenues for the nine months ended September 30, 2026 and 2025.

Upon issuance of senior secured recovery bonds in May 2022 (“inception”), the Utility recorded a $5.5 billion SB 901 securitization regulatory asset reflecting PG&E Wildfire Recovery Funding LLC’s right to recover $7.5 billion in wildfire claims costs associated with the 2017 Northern California wildfires, partially offset by the $2.0 billion in required upfront shareholder contributions to the customer credit trust. As of December 31, 2025, the Utility had made all required upfront contributions. The Utility also recorded a $5.54 billion SB 901 securitization regulatory liability at inception, which represents certain shareholder tax benefits the Utility had previously recognized that will be returned to customers. As tax benefits are monetized, contributions will be made to the customer credit trust, up to $7.59 billion. The Utility expects to amortize the SB 901 securitization regulatory asset and liability over the life of the recovery bonds, with such amortization reflected in Operating and maintenance expense in the Condensed Consolidated Statements of Income. During the three and nine months ended September 30, 2026, the Utility recorded $46 million and $209 million for amortization of the regulatory asset and liability, respectively, in the Condensed Consolidated Statements of Income. During the three and nine months ended September 30, 2025, the Utility recorded $87 million and $226 million for amortization of the regulatory asset and liability, respectively, in the Condensed Consolidated Statements of Income.

The following tables illustrate the changes in the SB 901 securitization’s impact on the Utility’s regulatory assets and liabilities:


	SB 901 securitization regulatory asset
(in millions)	2026		2025
Balance at January 1	$	5,089			$	5,194
Amortization	(129)			(77)
Balance at September 30	$	4,960			$	5,117


	SB 901 securitization regulatory liability
(in millions)	2026		2025
Balance at January 1	$	(6,010)			$	(6,295)
Amortization	338		303
Additions(1)	(4)			(111)
Balance at September 30	$	(5,676)			$	(6,103)

(1) Includes $1 million and $76 million of returns on investments in the customer credit trust expected to be credited to customers for each of the nine months ended September 30, 2026 and 2025, respectively.

NOTE 6: EQUITY

Dividends

Subject to the dividend restrictions as described in Notes 6 and 7 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K, any decision to declare and pay dividends in the future will be made at the discretion of PG&E Corporation’s and the Utility’s Boards of Directors and will depend on, among other things, results of operations, financial condition, cash requirements, contractual restrictions and other factors that the Boards of Directors may deem relevant.

The following table summarizes the dividends paid or declared by PG&E Corporation and the Utility in 2026:

Security

Amount per Share

Aggregate amount (in millions)

Date of Declaration

Record Date

Payment Date

PG&E Corporation common stock

0.05

110

December 11, 2025

December 31, 2025

January 15, 2026

0.05

111

February 19, 2026

March 31, 2026

April 15, 2026

0.05

111

May 21, 2026

June 30, 2026

July 15, 2026

0.05

111

September 17, 2026

September 30, 2026

October 15, 2026

Utility common stock

(1)

625

February 19, 2026

(1)

March 30, 2026

(1)

625

May 21, 2026

(1)

June 30, 2026

(1)

625

September 17, 2026

(1)

September 30, 2026

PG&E Corporation mandatory convertible preferred stock

0.75

December 11, 2025

February 13, 2026

March 1, 2026

0.75

February 19, 2026

May 15, 2026

June 1, 2026

0.75

May 21, 2026

August 14, 2026

September 1, 2026

0.75

September 17, 2026

November 13, 2026

December 1, 2026

Utility preferred stock

varies by series

3.5

December 11, 2025

January 30, 2026

February 15, 2026

varies by series

3.5

February 19, 2026

April 30, 2026

May 15, 2026

varies by series

3.5

May 21, 2026

July 31, 2026

August 15, 2026

varies by series

3.5

September 17, 2026

October 30, 2026

November 15, 2026

(1) PG&E Corporation owns all of the outstanding shares of the Utility’s common stock.

NOTE 7: EARNINGS PER SHARE

PG&E Corporation’s basic EPS is calculated by dividing the Income available for common shareholders, basic, by the weighted average number of common shares outstanding, basic. PG&E Corporation’s diluted EPS is calculated by dividing the income available for common shareholders, diluted, by the weighted average number of common shares outstanding, diluted. PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS. The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS:


	Three Months Ended September 30,		Nine Months Ended September 30,
(in millions, except per share amounts)	2026		2025		2026		2025
Numerator
Income available for common shareholders, basic	$	749			$	823		$	2,340	$	1,951
Plus: Mandatory Convertible Preferred Stock dividends	24			24			72		—
Income available for common shareholders, diluted	$	773			$	847		$	2,412	$	1,951

Denominator
Weighted average common shares outstanding, basic(1)	2,202			2,198			2,201		2,197
Dilutive effect of Employee stock-based compensation	5			5			5		5
Dilutive effect of Mandatory Convertible Preferred Stock	78			78			78		—
Weighted average common shares outstanding, diluted	2,285			2,281			2,284		2,202

Total income per common share:
Basic	$	0.34			$	0.37		$	1.06	$	0.89
Diluted	$	0.34			$	0.37		$	1.06	$	0.89

(1) Excludes 477,743,590 shares of PG&E Corporation common stock held by the Utility.

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

NOTE 8: DERIVATIVES

Use of Derivative Instruments

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

Derivatives are presented in the Utility’s Condensed Consolidated Balance Sheets and recorded at fair value and on a net basis in accordance with master netting arrangements for each counterparty. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

Price risk management activities that meet the definition of derivatives are recorded at fair value on the Condensed Consolidated Balance Sheets. These instruments are not held for speculative purposes and are subject to certain regulatory requirements. The Utility expects to fully recover through rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives. Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Condensed Consolidated Balance Sheets. Net realized gains or losses on commodity derivatives are recorded in the Cost of electricity or the Cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

The Utility elects the normal purchase and sale exception for eligible derivatives. Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business and do not contain pricing provisions unrelated to the commodity delivered. These items are not reflected in the Condensed Consolidated Balance Sheets at fair value.

Volume of Derivative Activity

The volumes of the Utility’s outstanding derivatives were as follows:


		Contract Volume at
Underlying Product	Instruments	September 30, 2026	December 31, 2025
Natural Gas (1) (MMBtus (2))	Forwards, futures, and swaps	196,386,942		232,825,834
	Options	62,440,000		48,215,000
Electricity (MWh)	Forwards, futures, and swaps	5,588,429		7,196,942
	Options	2,206,000		1,650,800
	Congestion Revenue Rights (3)	67,268,155		93,712,644

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

Presentation of Derivative Instruments in the Financial Statements

As of September 30, 2026, 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	$	131			$	(11)		$	—	$	120
Noncurrent assets – other	139			(1)			—		138
Current liabilities – other	(76)			11			14		(51)
Noncurrent liabilities – other	(91)			1			—		(90)
Total commodity risk	$	103			$	—		$	14	$	117

As of December 31, 2025, 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	$	165			$	(46)		$	—	$	119
Noncurrent assets – other	170			(6)			—		164
Current liabilities – other	(169)			46			—		(123)
Noncurrent liabilities – other	(106)			6			—		(100)
Total commodity risk	$	60			$	—		$	—	$	60

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

Some of the Utility’s derivative instruments, including 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. One major credit rating agency continues to rate the Utility below investment grade, which results in the Utility posting additional collateral. As of September 30, 2026, the Utility satisfied or has otherwise addressed its obligations related to the credit-risk-related contingency features.

NOTE 9: FAIR VALUE MEASUREMENTS

PG&E Corporation and the Utility measure their cash equivalents, self-insurance assets, trust assets, and price risk management instruments at fair value. A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

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

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

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

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below. Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.


	Fair Value Measurements
	At September 30, 2026
(in millions)	Level 1		Level 2		Level 3		Netting (1)	Total
Assets:
Short-term investments	$	764			$	—		$	—	$	—	$	764
Self-insurance investments
Short-term investments	1,243			—			—		—	1,243
Total Self-insurance investments (2)	1,243			—			—		—	1,243
Nuclear decommissioning trusts
Short-term investments	28			—			—		—	28
Global equity securities	2,528			—			—		—	2,528
Fixed-income securities	1,507			1,164			—		—	2,671
Assets measured at NAV	—			—			—		—	30
Total nuclear decommissioning trusts (3)	4,063			1,164			—		—	5,257
Customer credit trust
Short-term investments	20			—			—		—	20
Global equity securities	—			—			—		—	—
Fixed-income securities	118			270			—		—	388
Total customer credit trust	138			270			—		—	408
Price risk management instruments (Note 8)
Electricity	—			40			223		(7)	256
Gas	—			7			—		(5)	2
Total price risk management instruments	—			47			223		(12)	258
Rabbi trusts
Short-term investments	119			—			—		—	119
Global equity securities	3			—			—		—	3
Life insurance contracts	—			65			—		—	65
Total rabbi trusts	122			65			—		—	187
Long-term disability trust
Short-term investments	7			—			—		—	7
Assets measured at NAV	—			—			—		—	105
Total long-term disability trust	7			—			—		—	112
TOTAL ASSETS	$	6,337			$	1,546		$	223	$	(12)	$	8,229
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—			$	16		$	143	$	(20)	$	139
Gas	—			8			—		(6)	2
TOTAL LIABILITIES	$	—			$	24		$	143	$	(26)	$	141

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.

(2) Includes approximately $1 billion and $167 million held in the entities for wildfire and non-wildfire self-insurance, respectively.

(3) Represents amount before deducting $825 million primarily related to deferred taxes on appreciation of investment value.


	Fair Value Measurements
	At December 31, 2025
(in millions)	Level 1		Level 2		Level 3		Netting (1)	Total
Assets:
Short-term investments	$	634			$	—		$	—		$	—	$	634
Self-insurance investments
Short-term investments	1,120			—			—		—		1,120
Total Self-insurance investments(2)	1,120			—			—		—		1,120
Nuclear decommissioning trusts
Short-term investments	94			—			—		—		94
Global equity securities	2,433			—			—		—		2,433
Fixed-income securities	1,445			1,113			—		—		2,558
Assets measured at NAV	—			—			—		—		26
Total nuclear decommissioning trusts (3)	3,972			1,113			—		—		5,111
Customer credit trust
Short-term investments	111			—			—		—		111
Global equity securities			—			—		—		—
Fixed-income securities	367			326			—		—		693
Total customer credit trust	478			326			—		—		804
Price risk management instruments (Note 8)
Electricity	—			19			283		(6)		296
Gas	—			33			—		(46)		(13)
Total price risk management instruments	—			52			283		(52)		283
Rabbi trusts
Short-term investments	115			—			—		—		115
Global equity securities	5			—			—		—		5
Life insurance contracts	—			65			—		—		65
Total rabbi trusts	120			65			—		—		185
Long-term disability trust
Short-term investments	10			—			—		—		10
Assets measured at NAV	—			—			—		—		127
Total long-term disability trust	10			—			—		—		137
TOTAL ASSETS	$	6,334			$	1,556		$	283		$	(52)	$	8,274
Liabilities:
Price risk management instruments (Note 8)
Electricity	$	—			$	80		$	130		$	(6)	$	204
Gas	—			65			—		(46)		19
TOTAL LIABILITIES	$	—			$	145		$	130		$	(52)	$	223

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements.

(2) Includes approximately $1 billion and $77 million held in the entities for wildfire and non-wildfire self-insurance, respectively.

(3) Represents amount before deducting $881 million primarily related to deferred taxes on appreciation of investment value.

Valuation Techniques

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. There were no material transfers between any levels for the nine months ended September 30, 2026 or 2025.

Trust Assets

Assets Measured at Fair Value

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, customer credit 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 classified as 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.

Assets Measured at NAV Using Practical Expedient

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, credit securities, and asset-backed securities.

Self-insurance investments

Investments held in Pacific Energy Risk Solutions, LLC and Pacific Casualty Insurance Company, LLC primarily include short-term investments that are U.S. government securities classified as Level 1.

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. The Utility 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.

Level 3 Measurements and Uncertainty Analysis

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 rates; therefore, there is no impact on net income resulting from changes in the fair value of these instruments. See Note 8 above.

Fair Value
(in millions)

At September 30, 2026

Valuation
Technique

Unobservable
Input

Fair Value Measurement

Assets

Liabilities

Range (1)/Weighted-Average Price (2)

Congestion revenue rights

190

Market approach

CRR auction prices

$ (74) - 74 / 2

Power purchase agreements

Discounted cash flow

Forward prices

$ 13 - 96 / 47

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Fair Value
(in millions)

At December 31, 2025

Valuation
Technique

Unobservable
Input

Fair Value Measurement

Assets

Liabilities

Range (1)/Weighted-Average Price (2)

Congestion revenue rights

252

Market approach

CRR auction prices

$ (74) - 74 / 2

Power purchase agreements

Discounted cash flow

Forward prices

$ 11 - 106 / 53

(1) Represents price per MWh.

(2) Unobservable inputs were weighted by the relative fair value of the instruments.

Level 3 Reconciliation

The following table presents the reconciliation for Level 3 price risk management instruments for the three and nine months ended September 30, 2026 and 2025:


	Price Risk Management Instruments
(in millions)	2026		2025
Asset balance as of July 1	$	78			$	136
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	2			—
Asset balance as of September 30	$	80			$	136

(1) The costs related to price risk management activities are recovered through rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets, and net income is not impacted.


	Price Risk Management Instruments
(in millions)	2026		2025
Asset balance as of January 1	$	153			$	199
Net realized and unrealized gains (losses):
Included in regulatory assets and liabilities or balancing accounts (1)	(73)			(63)
Asset balance as of September 30	$	80			$	136

Financial Instruments

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, and customer deposits approximate their carrying values as of September 30, 2026 and December 31, 2025, as they are short-term in nature.

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


	At September 30, 2026		At December 31, 2025
(in millions)	Carrying Amount		Level 2 Fair Value		Carrying Amount		Level 2 Fair Value
Debt (Note 4)
PG&E Corporation (1)	$	6,324			$	6,437		$	5,360	$	5,697
Utility	43,195			37,836			38,145		35,565

(1) As of September 30, 2026, the net carrying amount and the estimated fair value (Level 2) of the Convertible Notes were $2.14 billion and $2.1 billion, respectively.

Nuclear Decommissioning Trust Investments

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


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of September 30, 2026
Nuclear decommissioning trusts
Short-term investments	$	6			$	22		$	—	$	28
Global equity securities	269			2,295			(6)		2,558
Fixed-income securities	2,798			3			(130)		2,671
Total (1)	$	3,073			$	2,320		$	(136)	$	5,257
As of December 31, 2025
Nuclear decommissioning trusts
Short-term investments	$	94			$	—		$	—	$	94
Global equity securities	324			2,140			(5)		2,459
Fixed-income securities	2,557			48			(47)		2,558
Total (1)	$	2,975			$	2,188		$	(52)	$	5,111

(1) Represents amounts before deducting $825 million and $881 million as of September 30, 2026 and December 31, 2025, respectively, primarily related to deferred taxes on appreciation of investment value.

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


	As of
(in millions)	September 30, 2026
Less than 1 year	$	75
1–5 years	876
5–10 years	612
More than 10 years	1,108
Total maturities of fixed-income securities	$	2,671

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


	Three Months Ended September 30,		Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Proceeds from sales and maturities of nuclear decommissioning trust investments	$	803			$	586		$	1,967	$	1,365
Gross realized gains on securities	54			124			138		130
Gross realized losses on securities	(28)			(4)			(42)		(21)

Customer Credit Trust

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


(in millions)	Amortized Cost		Total Unrealized Gains		Total Unrealized Losses		Total Fair Value
As of September 30, 2026
Customer credit trust
Short-term investments	$	20			$	—		$	—	$	20
Global equity securities	—			—			—		—
Fixed-income securities	396			—			(8)		388
Total	$	416			$	—		$	(8)	$	408
As of December 31, 2025
Customer credit trust
Short-term investments	$	111			$	—		$	—	$	111
Global equity securities	—			—			—		—
Fixed-income securities	689			5			(1)		693
Total	$	800			$	5		$	(1)	$	804

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


	As of
(in millions)	September 30, 2026
Less than 1 year	$	26
1–5 years	222
5–10 years	38
More than 10 years	102
Total maturities of fixed-income securities	$	388

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


	Three Months Ended September 30,		Nine Months Ended September 30,
(in millions)	2026		2025		2026		2025
Proceeds from sales and maturities of customer credit trust investments	$	157			$	114		$	440	$	310
Gross realized gains on securities	—			7			5	12
Gross realized losses on securities	(1)			(3)			(4)		(14)

NOTE 10: WILDFIRE-RELATED CONTINGENCIES

Liability Overview

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. PG&E Corporation and the Utility record a provision for a loss contingency when they determine that it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility record a wildfire-related liability when they determine that a loss is probable, and they can reasonably estimate the loss or a range of losses. The provision is based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.

Assessing whether a loss is probable or reasonably possible, whether the loss or a range of losses is estimable, and the amount of the accrual often requires management to exercise significant judgment about future events. Management makes these assessments based on a number of assumptions and subjective factors, including negotiations (including those during mediations with claimants), discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter, and estimates based on currently available information and prior experience with wildfires. Unless expressly noted otherwise, the estimated liabilities in this Note reflect the lower end of the range of the reasonably estimable range of losses. PG&E Corporation and the Utility believe that it is reasonably possible that the amount of loss could be greater than the accrued estimated amounts but are unable to reasonably estimate the additional loss or the upper end of the range because, as described below, 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.

Loss contingencies are reviewed quarterly, and estimates are adjusted to reflect the impact of all known information. As more information becomes available, including from potential claimants as litigation or resolution efforts progress, management estimates and assumptions regarding the potential financial impacts of wildfire events may change. For instance, PG&E Corporation and the Utility receive additional information with respect to damages claimed as the claims mediation and trial processes progress. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated outside counsel costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Potential liabilities related to wildfires depend on various factors, including the cause of the fire, contributing causes of the fire (including alternative potential origins, weather- and climate-related issues, and forest management and fire suppression practices), 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 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, fines, or restitution that may be imposed by courts or other governmental entities.

The complaints include claims based on multiple theories of liability, including inverse condemnation, negligence, violations of the Public Utilities Code, violations of the Health & Safety Code, premises liability, trespass, public nuisance, and private nuisance. The plaintiffs in each action principally assert that PG&E Corporation’s and the Utility’s alleged failure to properly maintain, inspect, and de-energize their power lines and equipment was the cause of the relevant wildfire. The timing and outcome for resolution of any such claims or investigations are uncertain. The Utility believes it will continue to receive additional information from potential claimants in connection with these wildfire events as litigation or resolution efforts progress. Although PG&E Corporation and the Utility may receive further complaints, the applicable statutes of limitations have expired, except for the statutes of limitations applicable to federal fire suppression claims for the 2021 Dixie fire and the 2022 Mosquito fire, which expire in 2027 and 2028, respectively. Any such additional information may potentially allow PG&E Corporation and the Utility to refine the estimates of their accrued losses and may result in changes to the accrual depending on the information received. PG&E Corporation and the Utility intend to vigorously defend themselves against both criminal charges and civil complaints.

If the Utility’s facilities, such as its electric distribution and transmission lines, are judicially determined to be the substantial cause of the following matters, 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. 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 through rates. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC 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. In addition to claims for property damage, business interruption, interest, and attorneys’ fees under inverse condemnation, PG&E Corporation and 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 in connection with the following wildfire events, including if PG&E Corporation or the Utility were found to have been negligent.

The Utility has made claims to the Wildfire Fund for claims paid in excess of $1.0 billion. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in the possession of Cal Fire, USFS, or the relevant district attorney’s office, 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 damages and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

The following table presents the cumulative amounts PG&E Corporation and the Utility have paid through September 30, 2026.


Payments (in millions)


2021 Dixie Fire	$	2,199
2022 Mosquito Fire	355
Total at September 30, 2026	$	2,554

2021 Dixie Fire

According to the Cal Fire Investigation Report on the 2021 Dixie fire (the “Cal Fire Investigation Report”), on July 13, 2021, at approximately 5:07 p.m. Pacific Time, a wildfire began in the Feather River Canyon near Cresta Dam (the “2021 Dixie fire”), located in the service area of the Utility. According to the Cal Fire Investigation Report, the 2021 Dixie fire consumed 963,309 acres and resulted in 1,311 structures destroyed and 94 structures damaged (including 763 residential homes, 12 multi-family homes, 8 commercial residential homes, 148 nonresidential commercial structures, and 466 detached structures), and four first-responder injuries. The Cal Fire Investigation Report does not attribute a fatality that was previously published in an October 25, 2021 Cal Fire incident report to the 2021 Dixie fire.

On January 4, 2022, Cal Fire issued a press release with its determination that the 2021 Dixie fire was caused by a tree contacting electrical distribution lines owned and operated by the Utility. On June 7, 2022, the Utility received a copy of the Cal Fire Investigation Report, which states that the fire ignited when a tree fell and contacted electrical distribution lines owned and operated by the Utility, and the Cal Fire Investigation Report has been made publicly available. The Cal Fire Investigation Report alleges that the Utility acted negligently in its response to the initial outage and fault that caused the 2021 Dixie fire. The Cal Fire Investigation Report also alleges that the subject tree had visible outward signs of damage and decay which would have been noticeable at the ground level, and that a brief visual inspection should have discovered the decay. Based on the information currently available to the Utility, through its ongoing investigation, including its inspection records, operating and inspection protocols and procedures, implementation of those protocols and procedures, and day-of-event response, the Utility believes its personnel acted reasonably (within the meaning of the applicable prudency standard discussed under “Regulatory Recovery” below) given the information available at the time and followed applicable policies and protocols both before ignition and in the day-of-event response. While an intervenor in the Utility’s proceeding for review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire under AB 1054 or a future cost recovery proceeding may argue there is serious doubt with respect to the reasonableness of the Utility’s conduct, PG&E Corporation and the Utility do not believe there are sufficient facts to shift the burden of proof applicable in a proceeding for cost recovery to the Utility. (See “Regulatory Recovery” and “Wildfire Fund Recoveries under AB 1054 and SB 254” below.) PG&E Corporation and the Utility disagree with many allegations in the Cal Fire Investigation Report and plan to vigorously contest them. However, if the CPUC were to reach conclusions similar to those of the Cal Fire Investigation Report, it may determine that the Utility had been imprudent, in which case some or all of its costs recorded to the WEMA would not be recoverable or the Utility would be required to reimburse the Wildfire Fund for the costs and expenses that are allocated to it.

As of October 14, 2026, PG&E Corporation and the Utility are aware of approximately 190 complaints on behalf of at least 9,061 individual plaintiffs related to the 2021 Dixie fire. The plaintiffs seek damages that include wrongful death, property damage, economic loss, medical monitoring, punitive damages, exemplary damages, attorneys’ fees and other damages. A substantial majority of these claims have been resolved. The court has scheduled and vacated numerous trial dates, including the previously scheduled bellwether trial date of June 23, 2025 and a previously scheduled individual trial date of December 2, 2026. Pursuant to an agreed-upon alternative dispute resolution protocol, a voluntary process for plaintiffs to mediate their cases, when a mediation does not resolve a plaintiff’s case, the plaintiff can opt to pursue a “damages-only” trial. No bellwether or damages-only trial is set.

Cal Fire filed a complaint against the Utility to recover suppression and investigation costs on June 30, 2023. In the second quarter of 2026, the Utility and Cal Fire reached a settlement in principle. In August 2026, the Utility entered into a settlement agreement with Cal Fire resolving Cal Fire’s claims.

In February 2023, the Utility entered into a tolling agreement with the California Governor’s Office of Emergency Services (“Cal OES”), extending the agency’s time to file a complaint. That tolling agreement remains in effect.

There is a separate putative class complaint that primarily seeks relief in the form of medical monitoring. On January 28, 2026, plaintiffs filed their fifth amended complaint in that case. On December 12, 2025, plaintiffs filed their motion for class certification, which the court denied on July 20, 2026.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including Cal Fire’s determination of the cause and the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2021 Dixie fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $2.15 billion as of December 31, 2025 (before available recoveries). During the second quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $100 million for an aggregate liability of $2.25 billion (before available recoveries). The aggregate liability remained unchanged as of September 30, 2026.

PG&E Corporation’s and the Utility’s accrued estimated losses of $2.25 billion do not include potential claims for fire suppression costs, other than Cal Fire, or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2021 Dixie fire. PG&E Corporation and the Utility believe, however, that such losses could be significant with respect to fire suppression costs due to the size and duration of the 2021 Dixie fire and corresponding magnitude of fire suppression resources dedicated to fighting the 2021 Dixie fire and with respect to claims for damage to land and vegetation in national parks or national forests due to the very large number of acres of national parks and national forests that were affected by the 2021 Dixie fire. According to the Cal Fire Investigation Report, over $650 million of costs had been incurred in suppressing the 2021 Dixie fire. The Utility estimates that the fire burned approximately 70,000 acres of national parks and approximately 685,000 acres of national forests.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2021 Dixie fire since December 31, 2025.


Loss Accrual (in millions)
Balance at December 31, 2025	$	243
Accrued Losses	100
Payments	(291)
Balance at September 30, 2026	$	52

The Utility has liability insurance coverage for third-party liability attributable to the 2021 Dixie fire in an aggregate amount of $521 million, all of which was collected as of September 30, 2026.

The Utility recorded an aggregate Wildfire Fund receivable of $1.25 billion for probable recoveries in connection with the 2021 Dixie fire, of which it had received $1.05 billion as of September 30, 2026. AB 1054 provides that the CPUC may allocate costs and expenses in the application for cost recovery in full or in part taking into account factors both within and beyond the utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds. PG&E Corporation and the Utility believe that, even if it found that the Utility acted unreasonably, the CPUC would nevertheless authorize recovery in part. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of September 30, 2026, the Utility also recorded a $98 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $544 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

2022 Mosquito Fire

On September 6, 2022, at approximately 6:17 p.m. Pacific Time, the Utility was notified that a wildfire had ignited near Oxbow Reservoir in Placer County, California (the “2022 Mosquito fire”), located in the service area of the Utility. The National Wildfire Coordinating Group’s InciWeb incident overview dated November 4, 2022 at 6:30 p.m. Pacific Time indicated that the 2022 Mosquito fire had consumed approximately 76,788 acres at that time. It also indicated no fatalities, no injuries, 78 structures destroyed, and 13 structures damaged (including 44 residential homes and 40 detached structures) and that the fire was 100% contained.

The USFS has indicated to the Utility an initial assessment that the fire started in the area of the Utility’s power line on National Forest System lands and that the USFS is conducting a criminal investigation into the 2022 Mosquito fire. On September 24, 2022, the USFS removed and took possession of one of the Utility’s transmission poles and attached equipment. The USFS has not issued a determination as to the cause.

The cause of the 2022 Mosquito fire remains under investigation by the USFS and the United States Department of Justice. PG&E Corporation and the Utility are cooperating with the investigations. It is uncertain when any such investigations will be complete. PG&E Corporation and the Utility are also conducting their own investigation into the cause of the 2022 Mosquito fire. This investigation is ongoing.

As of October 14, 2026, PG&E Corporation and the Utility are aware of approximately 24 complaints on behalf of at least 2,651 individual plaintiffs related to the 2022 Mosquito fire. Placer County Water Agency (“PCWA”), Middle Fork Project Finance Authority, and the Regents of the University of California have each filed a complaint. The plaintiffs seek damages that include property damage, economic loss, punitive damages, exemplary damages, attorneys’ fees, and other damages. In January 2026, PG&E Corporation and the Utility entered into a settlement agreement with five public entities, and their complaint was dismissed on February 4, 2026. In April 2026, PG&E Corporation and the Utility entered into a settlement agreement with PCWA and Middle Fork Project Finance Authority, and their complaints and the Utility’s cross-complaints have been dismissed. The court vacated the previously scheduled individual claimant bellwether trial dates for April 13, 2026 and November 30, 2026.

The Utility has entered into a tolling agreement with Cal OES, extending the agency’s time to file a complaint. That tolling agreement remains in effect.

On August 21, 2025, Cal Fire filed a complaint against the Utility for fire suppression and investigation costs. In August 2026, the Utility entered into a settlement agreement with Cal Fire.

On August 13, 2026, the CPUC adopted an administrative consent order and agreement between the Utility and the Safety and Enforcement Division of the CPUC (“SED”, and such agreement, the “Mosquito SED Settlement”). The Mosquito SED Settlement provides for the Utility to pay $22 million and resolves the SED’s investigation into the 2022 Mosquito Fire.

Based on the current state of the law concerning inverse condemnation in California and the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including the information gathered as part of PG&E Corporation’s and the Utility’s investigation, PG&E Corporation and the Utility believe it is probable that they will incur a loss in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility recorded a liability in the aggregate amount of $350 million as of December 31, 2025 (before available recoveries). In the first quarter of 2026, PG&E Corporation and the Utility recorded additional charges of $50 million. Based on the facts and circumstances available to PG&E Corporation and the Utility as of the date of this filing, including their experience with settlements, PG&E Corporation and the Utility recorded additional charges during the third quarter of 2026 of $75 million for an aggregate liability of $475 million (before available recoveries).

PG&E Corporation’s and the Utility’s accrued estimated losses do not include, among other things: (i) any amounts for potential penalties or fines that may be imposed by courts or other governmental entities on PG&E Corporation or the Utility, (ii) any punitive damages, (iii) amounts in respect of compensation claims by federal agencies for federal fire suppression costs and damages related to federal land, other than claims by PCWA or (iv) any other amounts that are not reasonably estimable.

As noted above, the aggregate estimated liability for claims in connection with the 2022 Mosquito fire does not include potential claims for fire suppression costs from federal agencies or damage to land and vegetation in national parks or national forests. As to these damages, PG&E Corporation and the Utility have not concluded that a loss is probable. PG&E Corporation and the Utility are unable to reasonably estimate the range of possible losses for any such claims due to, among other factors, incomplete information as to facts pertinent to potential claims and defenses, as well as facts that would bear on the amount, type, and valuation of vegetation loss, potential reforestation, habitat loss, and other resources damaged or destroyed by the 2022 Mosquito fire.

The following table presents changes in PG&E Corporation’s and the Utility’s reasonably estimable losses, net of payments, for claims arising from the 2022 Mosquito fire since December 31, 2025.


Loss Accrual (in millions)
Balance at December 31, 2025	$	243
Accrued Losses	125
Payments	(248)
Balance at September 30, 2026	$	120

As of September 30, 2026, the Utility recorded an insurance receivable of $496 million for probable insurance recoveries in connection with the 2022 Mosquito fire, including claims and legal fees, of which $369 million had been received. As of September 30, 2026, the Utility also recorded a $6 million reduction to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate and a $54 million regulatory asset for costs that were determined to be probable of recovery through the WEMA. See “Regulatory Recovery” below.

Loss Recoveries

PG&E Corporation and the Utility have recovery mechanisms available for wildfire liabilities including from insurance, through rates, and from the Wildfire Fund. PG&E Corporation and the Utility record a receivable for a recovery when it is deemed probable that recovery of a recorded loss will occur, and the Utility can reasonably estimate the amount or its range. While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such recoveries. For more information on the applicable facts and circumstances of the corresponding wildfires, see “2021 Dixie Fire” and “2022 Mosquito Fire.”

Total probable recoveries for the 2021 Dixie fire and the 2022 Mosquito fire as of September 30, 2026 are:


Potential Recovery Source (in millions)	2021 Dixie fire		2022 Mosquito fire
Insurance	$	521			$	496
FERC TO rates	98			6
WEMA	544			54
Wildfire Fund	1,250			—
Probable recoveries at September 30, 2026 (1)	$	2,413			$	556

(1) Includes legal costs of $158 million and $81 million related to the 2021 Dixie fire and 2022 Mosquito fire, respectively, as of September 30, 2026.

The Utility could be subject to significant liability in connection with these wildfire events. If such liability is not recoverable from insurance or the other mechanisms described in this section, it could have a material impact on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

Insurance

Self-Insurance

Since August 2023, the Utility’s wildfire liability insurance for amounts up to $1.0 billion has been entirely based on self-insurance and will remain as such through at least 2026. The self-insurance program includes a 5% deductible, capped at a maximum of $50 million, on claims that are incurred each year.

Insurance Receivable

As of September 30, 2026, PG&E Corporation and the Utility have recorded total probable insurance recoveries of $496 million in connection with the 2022 Mosquito fire. PG&E Corporation and the Utility intend to seek full recovery for all insured losses.

The balances for insurance receivables with respect to wildfires are included in Other accounts receivable in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets. The following table presents changes in accrued insurance recoveries, net of reimbursements received, for the 2022 Mosquito fire since December 31, 2025:


Insurance Receivable (in millions)	2022 Mosquito fire
Balance at December 31, 2025	$	281
Accrued insurance recoveries	133
Reimbursements	(287)
Balance at September 30, 2026	$	127

Regulatory Recovery

Section 451.1 of the Public Utilities Code provides that when determining an application to recover costs and expenses arising from a covered wildfire, the CPUC shall allow cost recovery if the costs and expenses are just and reasonable (i.e., the “prudency standard”). AB 1054 states that a utility with a valid safety certification for the time period in which a covered wildfire ignited “shall be deemed to have been reasonable” unless “a party to the proceeding creates a serious doubt as to the reasonableness of the electrical corporation’s conduct,” in which case the burden shifts to the utility to prove its conduct was reasonable. The Utility had a valid safety certification at the time of the 2021 Dixie fire and the 2022 Mosquito fire, so any analysis of cost recovery starts with this reasonableness presumption. AB 1054 also allows the CPUC to allocate costs and expenses “in full or in part taking into account factors both within and beyond the Utility’s control that may have exacerbated the costs and expenses, including humidity, temperature, and winds.”

The Utility’s recorded receivables under the WEMA and with respect to the Wildfire Fund take into account this revised prudency standard and the presumption of reasonableness of the Utility’s conduct, based on the Utility’s interpretation of AB 1054 and the information currently available to the Utility. Although the concept of “serious doubt” has been applied in other regulatory proceedings, such as FERC proceedings, the revised prudency standard under AB 1054 has not been interpreted or applied by the CPUC and it is possible that the CPUC could interpret or apply the standard differently, in which case the Utility may not be able to recover all or a portion of expenses that it has recorded as a receivable.

On November 14, 2025, the Utility filed an application with the CPUC seeking review and recovery of costs associated with the 2019 Kincade fire and 2021 Dixie fire.

FERC TO Rates

The Utility recognizes income subject to potential refunds through future FERC TO formula rates for a portion of the third-party wildfire-related claims in excess of insurance coverage. The FERC presumes that a utility’s expenditures are prudent and permits cost recovery unless a party raises a serious doubt regarding the prudency of such costs. The allocation to FERC transmission customers was based on a FERC-approved allocation factor as determined in the formula rate. Based on an order from the FERC approving an all-party settlement in the TO21 rate case, as of September 30, 2026, the Utility recorded reductions of $98 million and $6 million regarding the 2021 Dixie fire and the 2022 Mosquito fire, respectively, to its regulatory liability for wildfire-related claims costs that were determined to be probable of recovery through the FERC TO formula rate.

WEMA

The WEMA provides for tracking of incremental wildfire claims, outside legal costs, and insurance premiums above those authorized in rates. With respect to wildfire claims and outside legal costs, the Utility expects that the same prudency standard as applies to the Wildfire Fund would also be applied in any CPUC review of an application filed by the Utility seeking recovery of such costs recorded to the WEMA. See “Wildfire Fund Recoveries under AB 1054 and SB 254” below. As of September 30, 2026, based on information currently available to the Utility, incremental wildfire claims-related costs for the 2021 Dixie fire and the 2022 Mosquito fire were determined to be probable of recovery, and the Utility recorded $544 million and $54 million, respectively, as regulatory assets in the WEMA.

Wildfire Fund Recoveries under AB 1054 and SB 254

AB 1054 became law on July 12, 2019, and SB 254 became law on September 19, 2025. AB 1054 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. SB 254 provides for a Continuation Account which is designed to provide additional liquidity to reimburse catastrophic wildfire-related claims that occur after September 19, 2025, subject to the terms and conditions of SB 254. Each of California’s large electric IOUs has elected to participate in the Wildfire Fund and the Continuation Account. 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 arising from wildfires in any coverage 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. The accrued Wildfire Fund receivable as of September 30, 2026 reflects an expectation that the coverage year will be based on the calendar year.

Utilities that draw from the Wildfire Fund or the Continuation Account will only be required to reimburse amounts that are determined by the CPUC in a proceeding for cost recovery not to be just and reasonable, applying the prudency standard in AB 1054 and after allocating costs and expenses for cost recovery based on relevant factors both within and outside of a utility’s control that may have exacerbated the costs and expenses. As amended by SB 254, the reimbursement requirement is subject to a maximum disallowance equal to 20% of the equity portion of the utility’s electric transmission and distribution rate base in the year of the ignition. A utility would not be required to reimburse the Wildfire Fund or the Continuation Account for disallowances that exceed the maximum disallowance in the aggregate in a three calendar-year period. For the Continuation Account, the amount of reimbursement would also be reduced by the amount of contributions for which the utility has not claimed a reduction. For the Utility, the maximum disallowance would be approximately $5.1 billion for 2026. This maximum disallowance is based on the equity portion of the Utility’s forecasted weighted-average 2026 electric transmission and distribution rate base, which is subject to adjustment based on changes in the Utility’s electric transmission and distribution rate base. The maximum disallowance 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 failed to maintain a valid safety certification. Costs that the CPUC determines to be just and reasonable in accordance with the prudency standard in AB 1054 will not be reimbursed to the Wildfire Fund or the Continuation Account, resulting in a draw-down of the Wildfire Fund or Continuation Account, as applicable.

Before the expiration of any current safety certification, the Utility must request a new safety certification from the OEIS, which the Utility expects to be issued within 90 days if the Utility has provided documentation that it has satisfied the requirements for the safety certification pursuant to Section 8389(e) of the Public Utilities Code, added by AB 1054. An issued safety certification is valid for 12 months or until a timely request for a new safety certification is acted upon, whichever occurs later. The safety certification is separate from the CPUC’s enforcement authority and does not preclude the CPUC from pursuing remedies for safety or other applicable violations. On March 2, 2026, the OEIS approved the Utility’s 2025 application and issued the Utility’s 2025 safety certification.

The Wildfire Fund is expected to be capitalized with at least $21 billion through (i) a 15-year non-bypassable charge to customers, (ii) $7.5 billion in initial contributions from California’s three large electric IOUs and (iii) $300 million in annual contributions paid by the participating utilities for a 10-year period. If the administrator determines that additional annual contributions are necessary, the Continuation Account would be capitalized with up to $18 billion, of which $9 billion would be contributed through a non-bypassable charge from customers, $5.1 billion would be contributed by the utilities, and an additional $3.9 billion would be contributed by the utilities if the administrator determines that additional contributions are needed.

The Wildfire Fund and Continuation Account will only be available for payment of eligible claims so long as they have sufficient funds remaining. Such funds could be depleted more quickly than PG&E Corporation’s and the Utility’s 20-year estimate for the life of the Wildfire Fund, including as a result of claims made by California’s other participating utilities. The Wildfire Fund is available to pay for the Utility’s eligible claims arising between July 12, 2019, the effective date of AB 1054, and September 19, 2025, the effective date of SB 254. Payments for eligible claims arising between the effective date of AB 1054 and the Utility’s emergence from Chapter 11 are subject to a limit of 40% of the allowed amount of such claims. The 40% limit does not apply to eligible claims that arise after the Utility’s emergence from Chapter 11.

AB 1054 authorizes the payment of funds to a participating utility where that utility has demonstrated that it exercised reasonable business judgment in the valuation and payment of third-party claims.

PG&E Corporation’s and the Utility’s Wildfire Fund recoveries are reflected in Wildfire-related claims, net of recoveries in the Condensed Consolidated Statements of Income to the extent PG&E Corporation and the Utility determine that it is probable the CPUC will conclude that the Utility’s conduct was just and reasonable or when the Utility is not otherwise required to reimburse the Wildfire Fund.

The following table presents changes in accrued Wildfire Fund recoveries, net of claim payments received from the Wildfire Fund, for the 2021 Dixie fire since December 31, 2025:


Wildfire Fund Receivable (in millions)	2021 Dixie fire
Balance at December 31, 2025	$	299
Accrued Wildfire Fund recoveries	100
Claims paid by Wildfire Fund	(195)
Balance at September 30, 2026	$	204

As of September 30, 2026, the Utility had received $129 million from the Wildfire Fund related to the 2019 Kincade fire. The Utility has recorded a deferred gain for this amount, which is included in Other noncurrent liabilities in PG&E Corporation’s and the Utility’s Condensed Consolidated Balance Sheets.

For more information, see Note 2 above.

Wildfire-Related Securities Litigation

As further described under the headings “Wildfire-Related Securities Claims in District Court” and “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process,” PG&E Corporation and the Utility faced certain wildfire-related securities claims related to the 2017 Northern California wildfires and other claims related to the 2018 Camp fire and the Public Safety Power Shutoff program in the Chapter 11 Cases (i.e., the Subordinated Claims (as defined below)), and certain former directors, former officers, and underwriters of certain note offerings face wildfire-related securities claims in the District Court action. The claims described under the heading “Wildfire-Related Securities Claims in District Court” are referred to as the “Wildfire-Related Non-Bankruptcy Securities Claims” and collectively with the claims described under the heading “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” are referred to in this section as the “Wildfire-Related Securities Claims.”

PG&E Corporation initially recorded a liability in the aggregate amount of $300 million, which represented its best estimate of probable losses for the Wildfire-Related Securities Claims. On August 25, 2026, the District Court granted final approval of the $100 million class settlement with the Public Employee Retirement Association of New Mexico (“PERA”), which resolved substantially all the Wildfire-Related Securities Claims. As a result, PG&E Corporation has recorded a reduction of the aggregate accrued liability from $300 million to $260 million in the third quarter of 2026.

Wildfire-Related Securities Claims in District Court

In June 2018, two purported securities class actions were filed in the District Court, naming PG&E Corporation and certain of its former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al. The complaints alleged material misrepresentations and omissions in various PG&E Corporation public disclosures related to, among other things, vegetation management and other issues connected to the 2017 Northern California wildfires. The complaints asserted claims under Section 10(b) and Section 20(a) of the Exchange Act and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys’ fees and other costs. Both complaints 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 was denominated In re PG&E Corporation Securities Litigation, U.S. District Court for the Northern District of California, Case No. 18-03509. The court also appointed PERA as lead plaintiff.

On February 22, 2019, a third purported securities class action was filed in the District Court, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. (the “York County Action”). The complaint named as defendants certain 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 was named as a defendant. The complaint asserted claims under Section 11 of the Securities Act of 1933, as amended, based on alleged 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. On May 7, 2019, the York County Action was consolidated with In re PG&E Corporation Securities Litigation.

On January 10, 2026, PERA filed a motion for preliminary approval of a $100 million proposed class settlement among PERA, the defendants, PG&E Corporation, and the Utility, to resolve the consolidated securities actions. On February 26, 2026, the District Court entered an order preliminarily approving the settlement and scheduled the settlement approval hearing for August 25, 2026. On July 6, 2026, the deadline for putative class members to object to the proposed settlement passed with no objections filed. On August 25, 2026, the District Court approved the class settlement with PERA. On September 24, 2026, the deadline to appeal the District Court’s final approval of the class settlement passed without appeal.

Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process

As a result of the District Court’s approval of the class settlement described above, PG&E Corporation and the Utility have resolved all securities claims filed in the bankruptcy consistent with the Plan. These claims consisted of pre-petition claims against PG&E Corporation or the Utility under the federal securities laws related to, among other things, allegedly misleading statements or omissions with respect to vegetation management and wildfire safety disclosures, and were classified into separate categories under the Plan, each of which was subject to subordination under the United States Bankruptcy Code. The first category of claims consisted of pre-petition claims arising from or related to the trading of common stock of PG&E Corporation, and the second category of pre-petition claims, which comprised two separate classes under the Plan, consisted of claims arising from the trading of debt securities issued by PG&E Corporation and the Utility (together, the “Subordinated Claims”).

NOTE 11: OTHER CONTINGENCIES AND COMMITMENTS

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation. A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated. PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount. The assessments of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involve 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, penalties related to regulatory compliance, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation and the Utility exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities. See “Purchase Commitments” below. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

Wildfire and Gas Safety Costs Interim Rate Relief Subject to Refund

The recorded expenditures for wildfire mitigation consist of $726 million in expenses and $1.5 billion in capital expenditures and cover activities during the years 2020 to 2022. The recorded expenditures for gas safety and electric modernization consist of $120 million in expenses and $118 million in capital expenditures and cover activities during the years 2017 to 2022. If approved, the requested cost recovery would result in an aggregate revenue requirement of $688 million. The costs addressed in the WGSC application are incremental to those previously authorized in the Utility’s 2020 GRC and other proceedings.

The Utility has recovered $516 million in interim rates, which the CPUC approved in a decision on March 7, 2024. The remaining $172 million will be recovered to the extent it is approved after the CPUC issues a final decision. On September 18, 2026, the CPUC issued a PD that would authorize recovery of approximately $1.8 billion of the $2.3 billion of Track 1 costs requested by the Utility, consisting primarily of Wildfire Mitigation Plan Memorandum Account and Fire Risk Mitigation Memorandum Account balances. The PD does not address recovery of amounts recorded in the Gas Storage Balancing Account, In-Line Inspection Memorandum Account, and certain other memorandum and balancing accounts that are being considered separately in Track 2 of the proceeding. The PD would also disallow approximately $477 million of requested costs, including approximately $291 million of capital expenditures that would be permanently excluded from rate base. The PD remains subject to CPUC review and modification prior to a final decision. Cost recovery requested in this application is subject to the CPUC’s reasonableness review, which could result in some or all of the $516 million in interim rate relief being subject to refund.

Tax Matters

PG&E Corporation’s tax returns have been accepted through 2015 for federal income tax purposes. The Internal Revenue Service (“IRS”) is auditing PG&E Corporation’s tax returns for 2015 through 2018. The most significant unresolved matter relates to the deductibility of approximately $850 million in costs for San Bruno related safety spend, which the CPUC did not allow the Utility to recover through rates, and $400 million in customer bill credits. PG&E Corporation records an income tax benefit related to a deduction for an uncertain tax position when it determines it is more likely than not that the uncertain tax position will ultimately be sustained. In 2024, PG&E Corporation decreased its Income tax benefit by $70 million after the Office of Chief Counsel of the IRS issued a technical advice memorandum taking the position that the costs the Utility incurred for San Bruno related to safety spend and customer bill credits are nondeductible fines or penalties. PG&E Corporation intends to defend itself vigorously as to all costs in this matter.

Other Matters

PG&E Corporation and the Utility are subject to various claims and lawsuits that separately are not considered material. Estimated liabilities for contingencies related to such matters totaled $49 million and $106 million as of September 30, 2026 and 2025, respectively. These amounts were included in Other current liabilities on the Condensed Consolidated Financial Statements. Included among these claims and lawsuits are the proofs of claim filed in the Chapter 11 Cases, except for proofs of claim discussed under “Wildfire-Related Securities Claims—Claims in the Bankruptcy Court Process” in Note 10 above. PG&E Corporation and the Utility have resolved a significant majority of the proofs of claim. PG&E Corporation and the Utility continue their review and analysis of certain remaining claims. 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.

Environmental Remediation Contingencies

Environmental remediation contingencies are contingent liabilities that arise from federal, state, or local regulations requiring the remediation of contamination in soil, sediment, groundwater, and surface water. Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable, and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include the extent and types of hazardous substances at a potential site, the range of technologies that can be used for remediation, the determination of the Utility’s liability in proportion to other responsible parties, and the extent to which such costs are recoverable from third parties. Where possible, the Utility estimates costs using site-specific information but also considers historical experience for costs incurred at similar sites depending on the level of information available. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in Noncurrent liabilities on the Condensed Consolidated Balance Sheets and is comprised of the following:


	Balance at
(in millions)	September 30, 2026		December 31, 2025
Topock natural gas compressor station	$	283			$	315
Hinkley natural gas compressor station	99			99
Former MGP sites owned by the Utility or third parties (1)	785			715
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (2)	56			71
Fossil fuel-fired generation facilities and sites (3)	16			17
Total environmental remediation liability	$	1,239			$	1,217

(1) Primarily driven by the following sites: San Francisco Beach Street, San Francisco Outside East Harbor, San Francisco East Harbor, San Francisco North Beach and San Francisco Fillmore Street.

(2) Primarily driven by Geothermal Landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

The Utility’s gas compressor stations, former MGP 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 United States Environmental Protection Agency under the Federal Resource Conservation and Recovery Act in addition to other state laws relating to hazardous substances. The Utility has a comprehensive program to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.

The Utility’s environmental remediation liability as of September 30, 2026, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations, but the Utility’s actual costs could materially exceed its estimates. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans, the Utility’s time frame for remediation, and unanticipated claims filed against the Utility. As of September 30, 2026, the Utility expected to recover $1.0 billion of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

The table below presents the high end of the range for the Utility's potential losses and whether HSMA recovery is available.


	Balance at September 30, 2026
(in millions)	Low end of the range		High end of the range		HSMA Recovery (1)
Topock natural gas compressor station (2)	$	283			$	476		Available
Hinkley natural gas compressor station (2)	99			221			Unavailable
Former MGP sites owned by the Utility or third parties (3)	785			1,338			Available
Utility-owned generation facilities (other than fossil fuel-fired), other facilities, and third-party disposal sites (4)	56			126			Available
Fossil fuel-fired generation facilities and sites (5)	16			31			Unavailable

(1) For sites where HSMA recovery is available, the Utility expects to recover 90% of the costs associated with environmental remediation through rates.

(2) The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment. At the Topock site, the Utility completed the initial phase of construction on an in-situ groundwater treatment system in 2021, and additional construction will continue for several years.

(3) Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed.

(4) Utility-owned generation facilities and third-party disposal sites often involve long-term remediation.

(5) The Utility sold its fossil-fueled generation power plants in 1998 but retains the environmental remediation liability associated with each site.

Nuclear Insurance

The Utility maintains multiple insurance policies through NEIL and EMANI, covering nuclear or non-nuclear events at the Utility’s two nuclear generating units at DCPP and the Humboldt Bay independent spent fuel storage installation.

NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at the Utility’s two nuclear generating units at DCPP. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.5 billion per non-nuclear incident for DCPP. For the Humboldt Bay independent spent fuel storage installation, NEIL provides up to $50 million of coverage for nuclear and non-nuclear property damages. NEIL also provides coverage for damages caused by acts of terrorism and cyberattacks at nuclear power plants. Through NEIL, there is up to $3.2 billion available to the membership to cover this exposure. These coverage amounts are shared by all NEIL members and all nuclear and non-nuclear property insurance policies issued by NEIL. EMANI shares losses with NEIL, as part of the first $400 million of coverage within the current nuclear insurance program. EMANI also provides an additional $200 million in excess insurance for property damage and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at DCPP. 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, the maximum aggregate annual retrospective premium obligation for the Utility would be approximately $44 million. For more information about the Utility’s nuclear insurance coverage, see Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

Purchase Commitments

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. As of December 31, 2025, the Utility had undiscounted future expected obligations of approximately $33 billion. See Note 15 of the Notes to the Consolidated Financial Statements in Item 8 of the 2025 Form 10-K.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

PG&E Corporation’s and the Utility’s primary market risk results from changes in energy commodity prices. PG&E Corporation and the Utility engage in price risk management activities for non-trading purposes only. Both PG&E Corporation and the Utility may engage in these price risk management activities using forward contracts, futures, options, and swaps to hedge the impact of market fluctuations on energy commodity prices and interest rates. See the section above entitled “Risk Management Activities” in Part I, Item 2 and Notes 8 and 9 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1.

ITEM 4. CONTROLS AND PROCEDURES

As required by Rules 13a-15(b) or 15d-15(b) under the Exchange Act, management of PG&E Corporation and the Utility carried out an evaluation, under the supervision and with the participation of their respective principal executive officers and principal financial officers, of the effectiveness of the design and operation of their disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. No matter how well designed and operated, disclosure controls and procedures can provide only reasonable, rather than absolute, assurance of achieving the desired control objectives. Based on the foregoing, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers concluded that such controls and procedures were effective as of the end of the period covered by this Form 10-Q.

There were no changes in internal control over financial reporting that occurred during the three months ended September 30, 2026, that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

In addition to the following proceedings, PG&E Corporation and the Utility are parties to various lawsuits and regulatory proceedings in the ordinary course of their business. For more information regarding material lawsuits and proceedings, including updates to information reported under Item 3: “Legal Proceedings” of the 2025 Form 10-K, see Notes 10 and 11 of the Notes to the Condensed Consolidated Financial Statements in Part I, Item 1 and Part I, Item 2: “Litigation and Other Matters.”

Each of PG&E Corporation and the Utility has elected to disclose environmental proceedings described in Item 103(c)(3)(iii) of Regulation S-K unless it reasonably believes that such proceeding will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than $1 million.

CZU Lightning Complex Fire Notices of Violation

Between November 2020 and January 2021, several governmental entities raised concerns regarding the Utility’s emergency response to the 2020 CZU Lightning Complex fire, including Cal Fire, the California Coastal Commission, the Central Coast Regional Water Quality Control Board, and the Santa Cruz County Board of Supervisors alleging environmental, vegetation management, and unpermitted work violations. The Utility continues to work with the California Coastal Commission and the Central Coast Regional Water Quality Control Board to resolve any outstanding issues. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred. Accordingly, PG&E Corporation and the Utility have recorded charges for amounts that are not material. PG&E Corporation and the Utility do not believe that the resolution of these matters will have a material impact on their financial condition, results of operations, or cash flows.

Butte Canal Breach

On August 9, 2023, a canal in Butte County owned by the Utility breached. The Central Valley Regional Water Quality Control Board has alleged environmental violations in connection with the breach. Violations can result in penalties, remediation, and other relief.

Based on the information available, PG&E Corporation and the Utility believe it is probable that a liability has been incurred, but the amount of the liability is not reasonably estimable. PG&E Corporation and the Utility do not believe that the resolution of this matter will have a material impact on their financial condition, results of operations, or cash flows.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 5. OTHER INFORMATION

Certain officers have made elections to participate in, and are participating in, the PG&E Corporation Retirement Savings Plan, which includes a PG&E Corporation Common Stock Fund investment option, and non-qualified deferred compensation plans, which may have a similar option and are described in PG&E Corporation’s and the Utility’s joint proxy statement. Also, certain officers have made, and may from time to time make, elections to have shares withheld to cover withholding taxes upon the vesting of restricted stock units or performance share units, or to pay the exercise price and withholding taxes for stock options, which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute “non-Rule 10b5-1 trading arrangements” (as defined in Item 408(c) of Regulation S-K). During the three months ended September 30, 2026, no director or officer of PG&E Corporation or the Utility adopted or terminated a “Rule 10b5-1 trading arrangement” (as defined in Item 408(a) of Regulation S-K).

ITEM 6. EXHIBITS

EXHIBIT INDEX


3.1		Conformed Version of Amended and Restated Articles of Incorporation of PG&E Corporation, filed June 22, 2020, as amended by the Certificate of Amendment of Articles of Incorporation of PG&E Corporation, filed May 24, 2022 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2022 (File No. 1-12609), Exhibit 3.1)

3.2		Certificate of Determination of 6.000% Series A Mandatory Convertible Preferred Stock of PG&E Corporation, filed with the Secretary of State of the State of California and effective as of December 5, 2024 (incorporated by reference to PG&E Corporation’s Form 8-K dated December 2, 2024 (File No. 1‑12609), Exhibit 3.1)

3.3		Bylaws of PG&E Corporation, Amended and Restated as of December 12, 2024 (incorporated by reference to PG&E Corporation’s Form 8-K dated December 12, 2024 (File No. 1-12609), Exhibit 3.1)

3.4		Amended and Restated Articles of Incorporation of Pacific Gas and Electric Company, effective as of June 22, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 20, 2020 (File No. 1-2348), Exhibit 3.2)

3.5		Bylaws of Pacific Gas and Electric Company, Amended and Restated as of December 11, 2025 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated December 11, 2025 (File No. 1-2348), Exhibit 3.1)

4.1		Thirty-Fifth Supplemental Indenture, dated as of August 4, 2026, between Pacific Gas and Electric Company and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated July 27, 2026 (File No. 1-2348), Exhibit 4.1)

10.1		Amendment No. 1 to Credit Agreement, dated as of September 23, 2026, between Pacific Gas and Electric Company and Wells Fargo Bank, National Association, as administrative agent

10.2	*	PG&E Corporation 2010 Executive Stock Ownership Guidelines, as amended effective as of September 16, 2026


10.3	*	First Amendment to Loan Guarantee Agreement, dated as of October 16, 2026, between Pacific Gas and Electric Company and the U.S. Department of Energy, acting by and through the Secretary of Energy (redacted)

10.4	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Annual Restricted Stock Unit Award Agreement with Retirement Full Vesting, effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.4)

10.5	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Annual Performance Share Unit Award Agreement with Retirement Full Vesting, effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.5)

10.6	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Annual Restricted Stock Unit Award Agreement with Retirement Partial Vesting, as amended effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.6)

10.7	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Annual Performance Share Unit Award Agreement with Retirement Partial Vesting, as amended effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.7)

10.8	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Annual Restricted Stock Unit Award Agreement without Retirement Vesting, effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.8)

10.9	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Restricted Stock Unit Award Agreement with Retirement Partial Vesting, as amended effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.9)

10.10	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Restricted Stock Unit Award Agreement without Retirement Vesting, effective as of July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.10)

10.11	*	Form of PG&E Corporation 2021 Long-Term Incentive Plan Non-Annual Program-Specific Retention Restricted Stock Unit Award, as amended effective July 17, 2026 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2026 (File No. 1-12609), Exhibit 10.11)

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

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

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

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

101.INS		XBRL Instance Document

101.SC		XBRL Taxonomy Extension Schema Document

101.CA		XBRL Taxonomy Extension Calculation Linkbase Document

101.LA		XBRL Taxonomy Extension Labels Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

101.DE		XBRL Taxonomy Extension Definition Linkbase Document

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Management contract or compensatory agreement.

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

SIGNATURES

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


	PG&E CORPORATION

	/s/ CAROLYN J. BURKE
	Carolyn J. Burke Executive Vice President and Chief Financial Officer (duly authorized officer and principal financial officer)


	PACIFIC GAS AND ELECTRIC COMPANY

	/s/ STEPHANIE N. WILLIAMS
	Stephanie N. Williams Vice President, Chief Financial Officer, and Controller (duly authorized officer and principal financial officer)

Dated: October 21, 2026

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